UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One) | |
X | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF |
For the Fiscal Year Ended December 31, | |
OR | |
TRANSITION REPORT PURSUANT TO SECTION 13 | |
For the transition period from ____________ to ____________ |
Commission | Registrant, State of Incorporation, |
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| Address of Principal Executive Offices and Telephone Number | IRS Employer |
1-11299 | ENTERGY CORPORATION | 72-1229752 |
1-10764 | ENTERGY ARKANSAS, INC. | 71-0005900 |
1-27031 | ENTERGY GULF STATES, INC. | 74-0662730 |
1-8474 | ENTERGY LOUISIANA, INC. | 72-0245590 |
1-31508 | ENTERGY MISSISSIPPI, INC. | 64-0205830 |
0-5807 | ENTERGY NEW ORLEANS, INC. | 72-0273040 |
1-9067 | SYSTEM ENERGY RESOURCES, INC. | 72-0752777 |
Securities registered pursuant to Section 12(b) of the Act:
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| Name of Each Exchange |
Entergy Corporation | Common Stock, $0.01 Par Value - | New York Stock Exchange, Inc. |
Entergy Arkansas, |
| New York Stock Exchange, Inc. |
Entergy Gulf States, Inc. | Preferred Stock, Cumulative, $100 Par Value: |
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Entergy Gulf States Capital I | 8.75% Cumulative Quarterly Income Preferred | New York Stock Exchange, Inc. |
Entergy Louisiana, |
| New York Stock Exchange, Inc. |
Entergy Mississippi, Inc. | Mortgage Bonds, 6.0% Series due November 2032 | New York Stock Exchange, Inc. |
Securities registered pursuant to Section 12(g) of the Act:
Registrant | Title of Class |
Entergy Arkansas, Inc. | Preferred Stock, Cumulative, $100 Par Value |
Entergy Gulf States, Inc. | Preferred Stock, Cumulative, $100 Par Value |
Entergy Louisiana, Inc. | Preferred Stock, Cumulative, $100 Par Value |
Entergy Mississippi, Inc. | Preferred Stock, Cumulative, $100 Par Value |
Entergy New Orleans, Inc. | Preferred Stock, Cumulative, $100 Par Value |
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. YesÖ No ____
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. [Ö]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Yes | No | |
Entergy Corporation | Ö |
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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 2002,2004, was $9.4$12.7 billion based on the reported last sale price of $42.44$56.01 per share for such stock on the New York Stock Exchange on June 28, 2002.30, 2004. Entergy Corporation is directly or indirectly the sole holder of the common stock of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., and System Energy Resources, Inc.
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 9, 2003,13, 2005, are incorporated by reference into Parts I and III hereof.
TABLE OF CONTENTS
SEC Form 10-K | Page | |
Definitions | i | |
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Entergy's Business | Part I. Item 1. | 1 |
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Strategy | 3 | |
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Report of Management |
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Entergy Corporation and Subsidiaries | ||
Management's Financial Discussion and Analysis | Part II. Item 7. |
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Results of Operations |
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Liquidity and Capital Resources |
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Significant Factors and Known Trends |
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Critical Accounting Estimates |
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Selected Financial Data - Five-Year Comparison | Part II. Item 6. |
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Report of Independent |
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Consolidated Statements of Income For the Years Ended December 31, | Part II. Item 8. |
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Consolidated Statements of Cash Flows For the Years Ended December | Part II. Item 8. |
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Consolidated Balance Sheets, December 31, | Part II. Item 8. |
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Consolidated Statements of Retained Earnings, Comprehensive Income, | Part II. Item 8. |
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Notes to Consolidated Financial Statements | Part II. Item 8. |
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U.S. Utility | ||
| Part I. Item 1. |
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Customers |
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Electric Energy Sales |
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Retail Rate Regulation | 107 | |
Property and Other Generation Resources |
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Fuel Supply |
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Federal Regulation | 119 | |
Service Companies | 128 | |
Earnings Ratios | 128 | |
Non-Utility Nuclear | Part I. Item 1. | 129 |
Property | 129 | |
Energy and Capacity Sales | 129 | |
Fuel Supply | 130 | |
Other Business Activities | 131 | |
Energy Commodity Services | Part I. Item 1. | 131 |
Non-Nuclear Wholesale Assets Business | 132 | |
Entergy-Koch, L.P. | 132 | |
Regulation of Entergy's Business | Part I. Item 1. | 133 |
PUHCA | 133 | |
Federal Power Act | 133 | |
State Regulation | 134 | |
Regulation of the Nuclear Power Industry |
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Environmental Regulation |
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Litigation | 142 | |
Research Spending | 146 | |
Employees | 146 |
Entergy Arkansas, Inc. | ||
Management's Financial Discussion and Analysis | Part II. Item 7. |
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Results of Operations |
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Liquidity and Capital Resources |
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Significant Factors and Known Trends |
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Critical Accounting Estimates |
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Report of Independent |
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Income Statements For the Years Ended December 31, | Part II. Item 8. |
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Statements of Cash Flows For the Years Ended December 31, | Part II. Item 8. |
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Balance Sheets, December 31, | Part II. Item 8. |
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Statements of Retained Earnings for the Years Ended December 31, 2004, | Part II. Item 8. |
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Selected Financial Data - Five-Year Comparison | Part II. Item 6. |
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Entergy Gulf States, Inc. | ||
Management's Financial Discussion and Analysis | Part II. Item 7. |
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Results of Operations |
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Liquidity and Capital Resources |
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Significant Factors and Known Trends |
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Critical Accounting Estimates |
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Report of Independent |
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Income Statements For the Years Ended December 31, | Part II. Item 8. |
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Statements of Cash Flows For the Years Ended December 31, | Part II. Item 8. |
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Balance Sheets, December 31, | Part II. Item 8. |
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Statements of Retained Earnings and Comprehensive Income for the | Part II. Item 8. |
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Selected Financial Data - Five-Year Comparison | Part II. Item 6. |
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Entergy Louisiana, Inc. | ||
Management's Financial Discussion and Analysis | Part II. Item 7. |
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Results of Operations |
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Liquidity and Capital Resources |
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Significant Factors and Known Trends |
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Critical Accounting Estimates |
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Report of Independent |
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Income Statements For the Years Ended December 31, | Part II. Item 8. |
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Statements of Cash Flows For the Years Ended December 31, | Part II. Item 8. |
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Balance Sheets, December 31, | Part II. Item 8. |
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Statements of Retained Earnings for the Years Ended December 31, 2004, | Part II. Item 8. |
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Selected Financial Data - Five-Year Comparison | Part II. Item 6. |
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Entergy Mississippi, Inc. | ||
Management's Financial Discussion and Analysis | Part II. Item 7. |
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Results of Operations |
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Liquidity and Capital Resources |
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Significant Factors and Known Trends |
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Critical Accounting Estimates |
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Report of Independent |
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Income Statements For the Years Ended December 31, | Part II. Item 8. |
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Statements of Cash Flows For the Years Ended December 31, | Part II. Item 8. |
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Balance Sheets, December 31, | Part II. Item 8. |
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Statements of Retained Earnings for the Years Ended December 31, | Part II. Item 8. |
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Selected Financial Data - Five-Year Comparison | Part II. Item 6. |
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Entergy New Orleans, Inc. | ||
Management's Financial Discussion and Analysis | Part II. Item 7. |
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Results of Operations |
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Liquidity and Capital Resources |
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Significant Factors and Known Trends |
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Critical Accounting Estimates |
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Report of Independent |
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Statements of Operations For the Years Ended December 31, | Part II. Item 8. |
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Statements of Cash Flows For the Years Ended December 31, | Part II. Item 8. |
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Balance Sheets, December 31, | Part II. Item 8. |
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Statements of Retained Earnings for the Years Ended December 31, | Part II. Item 8. |
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Selected Financial Data - Five-Year Comparison | Part II. Item 6. |
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System Energy Resources, Inc. | ||
Management's Financial Discussion and Analysis | Part II. Item 7. |
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Results of Operations |
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Liquidity and Capital Resources |
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Significant Factors and Known Trends |
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Critical Accounting Estimates |
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Report of Independent |
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Income Statements For the Years Ended December 31, | Part II. Item 8. |
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Statements of Cash Flows For the Years Ended December 31, | Part II. Item 8. |
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Balance Sheets, December 31, | Part II. Item 8. |
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Statements of Retained Earnings for the Years Ended December 31, | Part II. Item 8. |
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Selected Financial Data - Five-Year Comparison | Part II. Item 6. |
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Notes to Respective Financial Statements for the Domestic Utility Companies | Part II. Item 8. |
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Properties | Part I. Item 2. |
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Legal Proceedings | Part I. Item 3. |
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Submission of Matters to a Vote of Security Holders | Part I. Item 4. |
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Directors and Executive Officers of Entergy Corporation | Part III. Item 10. |
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Market for Registrants' Common Equity and Related Stockholder Matters | Part II. Item 5. |
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Selected Financial Data | Part II. Item 6. |
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Management's Discussion and Analysis of Financial Condition and Results of | Part II. Item 7. |
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Quantitative and Qualitative Disclosures About Market Risk | Part II. Item 7A. |
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Financial Statements and Supplementary Data | Part II. Item 8. |
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Changes in and Disagreements with Accountants on Accounting and Financial | Part II. Item 9. |
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Controls and Procedures | Part II. Item 9A. | 353 |
Attestation Report of Registered Public Accounting Firm | Part II. Item 9A. | 354 |
Other Information | Part II. Item 9B. | 368 |
Directors and Executive Officers of the | Part III. Item 10. |
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Executive Compensation | Part III. Item 11. |
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Security Ownership of Certain Beneficial Owners and Management | Part III. Item 12. |
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Certain Relationships and Related Transactions | Part III. Item 13. |
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| Part IV. Item 14 |
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Exhibits, Financial Statement Schedules, and Reports on Form 8-K | Part IV. Item 15. |
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Signatures |
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Report of Independent |
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Index to Financial Statement Schedules | S-1 | |
Exhibit Index | E-1 | |
This combined Form 10-K is separately filed by Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, 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 registrant. 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 registrant, except for the Notes to the financial statements. The Entergy Corporation Notes to the financial statements are separately presented, but the Notes to the financial statements for the other registrants are combined. These two sets of Notes are marked by headers. All other Items are combined for the registrants. Item 1 is marked by a header to indicate where it applies only to Entergy Corporation and where it applies to one or more of the registrants.
FORWARD-LOOKING INFORMATION
From In this filing and from time to time, Entergy makes statements 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. Although Entergy believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct. Except to the extent required by the federal securities laws, Entergy undertakes 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, and there are factors that could cause actual results to differ materially from those expressed or implied in the statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:
DEFINITIONS
Certain abbreviations or acronyms used in the text and notes are defined below:
Abbreviation or AcronymTerm
| Term |
AFUDC |
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ALJ | Administrative Law Judge |
ANO 1 and 2 | Units 1 and 2 of Arkansas Nuclear One Steam Electric Generating Station (nuclear), owned by Entergy Arkansas |
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APSC | Arkansas Public Service Commission |
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Board | Board of Directors of Entergy Corporation |
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Cajun | Cajun Electric Power Cooperative, Inc. |
capacity factor | Actual plant output divided by maximum potential plant output for the period |
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City Council or Council | Council of the City of New Orleans, Louisiana |
CPI-U | Consumer Price Index - Urban |
DOE | United States Department of Energy |
domestic utility companies | Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, collectively |
EITF | FASB's Emerging Issues Task Force |
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Entergy | Entergy Corporation and its |
Entergy Corporation | Entergy Corporation, a Delaware corporation |
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Entergy-Koch | Entergy-Koch, |
EPA | United States Environmental Protection Agency |
| Entergy |
FASB | Financial Accounting Standards Board |
FEMA | Federal Emergency Management Agency |
FERC | Federal Energy Regulatory Commission |
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| Grand Gulf |
DEFINITIONS (Continued)
Abbreviation or AcronymTerm
| Unit No. 1 of Grand Gulf Steam Electric Generating Station (nuclear), 90% owned or leased by System Energy |
GWh |
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Independence | Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power |
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IRS | Internal Revenue Service |
ISO | Independent System Operator |
kV |
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kW |
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kWh |
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DEFINITIONS (Continued)
Abbreviation or Acronym | Term |
LDEQ | Louisiana Department of Environmental Quality |
LPSC | Louisiana Public Service Commission |
Mcf | 1,000 cubic feet of gas |
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MMBtu | One million British Thermal Units |
MPSC | Mississippi Public Service Commission |
MW | Megawatt(s), which equals one thousand kilowatt(s) |
MWh |
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Nelson Unit 6 | Unit No. 6 (coal) of the Nelson Steam Electric Generating Station, owned 70% by Entergy Gulf States |
Net debt ratio | Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents |
Net MW in operation | Installed capacity owned or operated |
Net revenue | Operating revenue net of fuel, fuel-related, and purchased power expenses; and other regulatory |
Non-Utility Nuclear | Entergy's business segment that owns and |
NRC | Nuclear Regulatory Commission |
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PPA | Purchased power agreement |
production cost | Cost in $/MMBtu associated with delivering gas, excluding the cost of the gas |
PRP | Potentially |
PUCT | Public Utility Commission of Texas |
PUHCA | Public Utility Holding Company Act of 1935, as amended |
PURPA | Public Utility Regulatory Policies Act of 1978 |
Ritchie Unit 2 | Unit 2 of the |
River Bend | River Bend Steam Electric Generating Station (nuclear) |
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SEC | Securities and Exchange Commission |
DEFINITIONS (Concluded)
Abbreviation or AcronymTerm
SFAS | Statement of Financial Accounting Standards as promulgated by the FASB |
SMEPA | South Mississippi Electric Power Agency, which owns a 10% interest in Grand Gulf |
spark spread | Dollar difference between electricity prices per unit and natural gas prices after assuming a conversion ratio for the number of natural gas units necessary to generate one unit of electricity |
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System Fuels | System Fuels, Inc. |
DEFINITIONS (Concluded)
Abbreviation or Acronym | Term |
TWh | Terawatt-hour(s), which equals one billion kilowatt-hours |
unit-contingent | Transaction under which power is supplied from a specific generation asset; if the specified generation asset is unavailable as a result of forced outage or unanticipated event or circumstance, the seller is not liable to the buyer for any damages resulting from the seller's failure to deliver power |
unit-contingent with | Transaction under which power is supplied from a specific generation asset; if the specified generation asset is unavailable as a result of forced outage or unanticipated event or circumstance, the seller is not liable to the buyer for any damages resulting from the seller's failure to deliver power unless the actual availability over a specified period of time is below an availability threshold specified in |
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 |
UK | The United Kingdom of Great Britain and Northern Ireland |
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Waterford 3 | Unit No. 3 (nuclear) of the Waterford Steam Electric Generating Station, 100% owned or leased by Entergy Louisiana |
weather-adjusted usage |
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White Bluff | White Bluff Steam Electric Generating Station, 57% owned by Entergy Arkansas |
ENTERGY'S BUSINESS
Entergy Corporation is an integrated energy company engaged primarily in electric power production and retail electric distribution operations, energy marketing and trading, and gas transportation.operations. Entergy owns and operates power plants with approximately 30,000 MW of electric generating capacity, and it is the second-largest nuclear power generator in the United States. Entergy delivers electricity to 2.62.7 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Through Entergy-Koch, Entergy is a leading provider of wholesale energy marketing and trading services, as well as an operator of natural gas pipeline and storage facilities. Entergy hadgenerated annual revenues of over $8$10 billion in 20022004 and more than 15,000had approximately 14,400 employees as of December 31, 2002.2004.
Entergy operates primarily through three business segments: U.S. Utility, Non-Utility Nuclear, and Energy Commodity Services.
Followingassets business sells to wholesale customers the electric power produced by power plants that it owns while it focuses on improving performance and exploring sales or restructuring opportunities for its power plants. Such opportunities are the percentages ofevaluated consistent with Entergy's consolidated revenues and net income generated by these segments and the percentage of totalmarket-based point-of-view. The non-nuclear wholesale assets held by them:
% of Revenue | % of Net Income | % of Total Assets | |||||||
Segment | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 |
U.S. Utility | 82 | 77 | 74 | 97 | 77 | 87 | 78 | 78 | 81 |
Non-Utility Nuclear | 14 | 8 | 3 | 32 | 17 | 7 | 17 | 13 | 9 |
Energy Commodity Services | 4 | 14 | 23 | (23) | 14 | 8 | 8 | 9 | 10 |
Parent & Other | - | 1 | - | (6) | (8) | (2) | (3) | - | - |
The net income figures in 2002 include a $238 million net of tax charge in the Energy Commodity Services segment. If this charge were excluded, the percentages would be 70% for U.S. Utility, 23% for Non-Utility Nuclear, 11% for Energy Commodity Services, and (4%) for Parent & Other.
Entergy's business has traditionally operated primarily through its regulated utility subsidiaries in its four-state service territory. Entergy has reshaped its non-utility business through the sale of its international electric distribution businesses in 1998, the growth of its non-utility nuclear business in the northeastern United States beginning in 1999, and the termination of itsterminated new greenfield power development businessactivity in 2002. With the start of the Entergy-Koch venture in early 2001, Entergy expanded its business opportunities into new areas. The trading activities of Entergy-Koch extend to various parts of the United States, as well as the United Kingdom, Western Europe, and Canada. Entergy-Koch's Gulf South Pipeline system covers the Gulf Coast region of the United States. Entergy's financial interest in the Entergy-Koch venture allows it to appoint four of the eight members of the general partner's board of directors. Operating decisions for Entergy-Koch are made by Entergy-Koch management.
OPERATING INFORMATION | ||||||||
For the Years Ended December 31, 2004, 2003, and 2002 | ||||||||
U.S. Utility | Non-Utility Nuclear | Energy Commodity Services | Entergy Consolidated (a) | |||||
(In Thousands) | ||||||||
2004 | ||||||||
Operating revenues | $8,142,808 | $1,341,852 | $216,450 | $10,123,724 | ||||
Operating expenses | $6,795,146 | $978,688 | $308,226 | $8,470,160 | ||||
Other income | $108,925 | $78,141 | ($44,727) | $124,416 | ||||
Interest and other charges | $383,032 | $53,657 | $15,560 | $479,023 | ||||
Income taxes | $406,864 | $142,620 | ($155,840) | $365,908 | ||||
Net income | $666,691 | $245,029 | $3,778 | $933,049 | ||||
2003 | ||||||||
Operating revenues | $7,584,857 | $1,274,983 | $184,888 | $9,194,920 | ||||
Operating expenses | $6,274,830 | $1,039,614 | $224,567 | $7,710,365 | ||||
Other income | ($35,965) | $33,997 | $337,334 | $325,238 | ||||
Interest and other charges | $419,111 | $34,460 | $15,193 | $506,326 | ||||
Income taxes | $341,044 | $88,619 | $105,903 | $490,074 | ||||
Cumulative effect of accounting change | ($21,333) | $154,512 | $3,895 | $137,074 | ||||
Net income | $492,574 | $300,799 | $180,454 | $950,467 | ||||
2002 | ||||||||
Operating revenues | $6,773,509 | $1,200,238 | $294,670 | $8,305,035 | ||||
Operating expenses | $5,434,694 | $868,288 | $769,834 | $7,163,314 | ||||
Other income | $47,603 | $48,572 | $249,678 | $347,753 | ||||
Interest and other charges | $465,703 | $47,291 | $61,632 | $572,464 | ||||
Income taxes | $313,752 | $132,726 | ($141,288) | $293,938 | ||||
Net income (loss) | $606,963 | $200,505 | ($145,830) | $623,072 | ||||
CASH FLOW INFORMATION | ||||||||
For the Years Ended December 31, 2004, 2003, and 2002 | ||||||||
U.S. Utility | Non-Utility Nuclear | Energy Commodity Services | Entergy Consolidated (a) | |||||
(In Thousands) | ||||||||
2004 | ||||||||
Net cash flow provided by operating activities | $2,207,876 | $414,518 | $479,919 | $2,929,319 | ||||
Net cash flow provided by (used in) investing activities | ($1,198,009) | ($386,023) | $248,612 | ($1,140,075) | ||||
Net cash flow used in financing activities | ($824,579) | ($37,894) | ($724,534) | ($1,671,859) | ||||
2003 | ||||||||
Net cash flow provided by (used in) operating activities | $1,675,069 | $182,524 | ($111,291) | $2,005,820 | ||||
Net cash flow used in investing activities | ($1,441,992) | ($184,913) | ($78,120) | ($1,783,130) | ||||
Net cash flow provided by (used in) financing activities | ($919,983) | ($6,672) | $166,165 | ($869,130) | ||||
2002 | ||||||||
Net cash flow provided by (used in) operating activities | $2,341,161 | $281,589 | ($3,714) | $2,181,703 | ||||
Net cash flow used in investing activities | ($1,020,087) | ($438,664) | ($760) | ($1,388,463) | ||||
Net cash flow provided by (used in) financing activities | ($688,201) | $176,162 | ($66,151) | ($212,610) | ||||
FINANCIAL POSITION INFORMATION | ||||||||
As of December 31, 2004 and 2003 | ||||||||
U.S. Utility | Non-Utility Nuclear | Energy Commodity Services | Entergy Consolidated (a) | |||||
(In Thousands) | ||||||||
2004 | ||||||||
Current assets | $2,323,801 | $590,580 | $1,282,578 | $3,108,118 | ||||
Other property and investments | $1,200,246 | $1,403,222 | $569,975 | $2,995,894 | ||||
Property, plant and equipment - net | $16,502,155 | $1,850,481 | $310,793 | $18,695,631 | ||||
Deferred debits and other assets | $2,911,035 | $687,321 | $60,632 | $3,511,134 | ||||
Current liabilities | $1,756,011 | $787,668 | $205,348 | $2,470,770 | ||||
Non-current liabilities | $15,214,095 | $1,694,090 | $279,730 | $17,543,320 | ||||
Shareholders' equity | $5,967,131 | $2,049,847 | $1,738,900 | $8,296,687 | ||||
2003 | ||||||||
Current assets | $2,117,260 | $542,837 | $466,132 | $2,919,244 | ||||
Other property and investments | $1,151,538 | $1,326,347 | $1,137,069 | $3,746,926 | ||||
Property, plant and equipment - net | $16,242,775 | $1,557,025 | $463,403 | $18,298,797 | ||||
Deferred debits and other assets | $2,890,741 | $745,568 | $10,317 | $3,562,421 | ||||
Current liabilities | $1,671,607 | $330,684 | $478,693 | $2,282,223 | ||||
Non-current liabilities | $15,309,482 | $1,891,805 | $41,450 | $17,568,329 | ||||
Shareholders' equity | $5,448,047 | $1,949,288 | $1,614,620 | $8,703,658 | ||||
(a) In addition to the 3 operating segments presented here, Entergy Consolidated also includes Entergy Corporation (parent company), other business activity, and intercompany eliminations. |
The following shows the principal subsidiaries and affiliates within Entergy's business segments. Companies that file reports and other information with the SEC under the Securities Exchange Act of 1934 are identified in bold-faced type.
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U. S. Utility | Non-Utility Nuclear | Energy Commodity Services | |||||||||||||
Entergy Arkansas, Inc. | Entergy Nuclear Operations, Inc. | Entergy-Koch, LP | Non-Nuclear Wholesale Assets | ||||||||||||
Entergy Gulf States, Inc. | Entergy Nuclear Finance, Inc. | (50% ownership) | |||||||||||||
Entergy Louisiana, Inc. | Entergy Nuclear Generation Co. (Pilgrim) | Entergy Power Development Corp. | |||||||||||||
Entergy Mississippi, Inc. | Entergy Nuclear FitzPatrick LLC | Entergy Asset Management, Inc. | |||||||||||||
Entergy New Orleans, Inc. | Entergy Nuclear Indian Point 2, LLC | Entergy Power, Inc. | |||||||||||||
System Energy Resources, Inc. | Entergy Nuclear Indian Point 3, LLC | ||||||||||||||
Entergy Operations, Inc. | Entergy Nuclear Vermont Yankee, LLC | ||||||||||||||
Entergy Services, Inc. | Entergy Nuclear, Inc. | ||||||||||||||
System Fuels, Inc. | Entergy Nuclear Fuels Company | ||||||||||||||
Entergy Nuclear Nebraska LLC |
TheU.S. Utility is Entergy's predominant business segment, with five wholly-owned retail electric utility subsidiaries: Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi,net income or loss, or total assets, and Entergy New Orleans. These companies generate, transmit, distribute,reports this business as part of All Other in its segment disclosures.
Strategy
Entergy aspires to achieve industry leading total shareholder returns by leveraging the scale and sell electric power to retailexpertise inherent in its core nuclear and wholesale customers primarily in Arkansas, Louisiana, Mississippi,utility operations. Entergy's scope includes electricity generation, transmission and Texas.
Entergy Gulf States and Entergy New Orleans also providedistribution as well as natural gas utility services to customers in and around Baton Rouge, Louisiana and New Orleans, Louisiana, respectively. Also included in the U.S. Utility is System Energy, a wholly-owned subsidiary that owns or leases 90 percent of Grand Gulf 1. System Energy sells all the power and capacity from Grand Gulf 1 at wholesale to four of the domestic utility companies. As a registered public utility holding company under the Public Utility Holding Company Act of 1935, Entergy and its subsidiaries are subject to the broad regulatory provisions of PUHCA. Rates and other activities of the domestic utility companies are each regulated by state utility commissions, or in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC as all of its transactions are at the wholesale level. Entergy's U.S. Utility continues to operate as a regulated monopoly as efforts toward deregulation in the jurisdictions it serves have either been delayed, abandoned, or not yet initiated.
The primary objective of the U.S. Utility is to provide reliable and cost-effective electricity and gas service while creating a work environment that provides the highest level of safety for its employees. Since 1998 the U.S. Utility has significantly improved key customer service, reliability, and safety metrics. The overall generation portfolio of the U.S. Utility, which is primarily made up of natural gas and nuclear generation, is consistent with Entergy's strong support for environmental stewardship.
TheNon-Utility Nuclear business andEnergy Commodity Services are referred to as Entergy's competitive businesses. These businesses, unlike the U.S. Utility, are not subject to cost-based rate regulation by state or local utility commissions. Primary oversight for these operations comes from the NRC and the FERC.
Entergy's Non-Utility Nuclear business is focused on acquiring, owning, operating, and selling power from nuclear power plants and providing operations and management services to nuclear power plants owned by other utilities in the United States. Non-Utility Nuclear sells all of its power to wholesale customers. Operations and management services, including decommissioning services, are provided through Entergy's wholly-owned subsidiary, Entergy Nuclear, Inc.
Entergy's Non-Utility Nuclear business currently owns assets located in the northeastern portion of the United States as shown on the map below:
The Energy Commodity Services segment includes the operations of Entergy-Koch (50% owned by Entergy) and Entergy's non-nuclear wholesale asset business. Entergy-Koch is engaged in two major businesses: energy commodity marketing and trading that includes power, gas, weather derivatives, emissions, and cross-commodities through Entergy-Koch Trading and gas transportation and storage through Gulf South Pipeline. Entergy's non-nuclear wholesale asset business owns and operates power plants capable of generating about 1,400 MW of electricity for sale in the wholesale market.
Strategy and Performance
Entergy's strategy is to create value by focusingdistribution. Entergy focuses on asset management and strong operational execution,excellence with a particularan emphasis on service reliability and nuclear excellence. Entergy continually evaluates its business position, with a view toward enhancing the company's scale, scope, and skill advantages. It applies a well-developed point of view of the marketplace and strong risk management to manage its asset portfolio and customer relationships. Entergy benchmarks its operational performance against industry and competitor standards on measures such as safety, reliability, customer service, sustainability, cost efficiency and cost efficiency.
The following graph compares the performancerisk management. Entergy also focuses on portfolio management to make periodic buy, build, hold, or sell decisions based upon its analytically-derived points of Entergy common stock to the S&P 500 Index and Philadelphia Utility Index (each ofview which includes Entergy) for the last five years:
Years ended December 31, | |||||||||||
1997 | 1998 | 1999 | 2000 | 2001 | 2002 | ||||||
Entergy | $100 | $109.62 | $94.45 | $161.91 | $154.58 | $185.90 | |||||
S&P 500 (2) | $100 | $128.58 | $155.63 | $141.46 | $124.66 | $97.12 | |||||
Philadelphia Utility Index (2) | $100 | $117.63 | $96.96 | $145.91 | $126.89 | $103.61 |
Selected Entergy financial data obtained from Entergy's consolidated financial statements for the past three years is reflected on the charts below.
A more detailed discussion of Entergy's operations is set forth below in"MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS."
Significant Business IssuesRate Regulation and Fuel-Cost Recovery The rates that the domestic utility companies and System Energy charge for their services are a very important item influencing Entergy's financial position, results of operations, and liquidity. SeeRate Regulation and Fuel-Cost Recoveryin"MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS"and "Rate Matters" in Part I, Item 1 for discussion of this issue.
Utility Restructuring
Utility restructuring in Entergy's retail service territories has either been delayed, abandoned, or not pursued; however, major changes are occurring in the wholesale and retail electric utility business, including in the transmission business. SeeUtility Restructuringin"MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS"for discussion of these issues.
Nuclear Matters
The domestic utility companies, System Energy, and the Non-Utility Nuclear subsidiaries own and operate, through affiliates, ten nuclear power plants. SeeNuclear Matters in"MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS"for discussion of the risks inherent in owning and operating nuclear power plants.
Price of Power Sales
The sale of capacity and energy from the power generation plants owned by the Non-Utility Nuclear business and the non-nuclear wholesale asset business is subject to fluctuations in thecontinuously updated as market price for power. SeeMarket and Credit Risksin"MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS"for a discussion of the market risk associated with these businesses.
Energy Trading
Entergy owns a 50% interest in Entergy-Koch. Entergy-Koch, through its Entergy-Koch Trading subsidiary, buys and sells natural gas, power, and other energy-related services and commodities, including weather derivatives. Prices of these commodities may fluctuate over relatively short periods of time and expose Entergy-Koch to commodity price risk. SeeMarket and Credit Risksin"MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS"for a discussion of the market risk associated with the energy trading business.
Financing
Entergy relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements and refinancing not satisfied by the cash flow from its operations. SeeLiquidity and Capital Resources in"MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS"for a discussion of these matters.
Litigation
Entergy and its subsidiaries are involved in the ordinary course of business in a substantial amount of employment, asbestos, hazardous material and other environmental and rate-related, proceedings and litigation, a significant portion of which originates in Louisiana, Mississippi, and Texas. Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment in these states poses a significant business risk. See "Litigation" below in Part I, Item 1 for additional discussion of significant litigation involving Entergy.
Other Regulation
In addition to the regulation of rates that the domestic utility companies and System Energy charge for sales of electric power, there are three additional primary areas of regulation: federal regulation of the utility business, regulation of nuclear power, and environmental regulation. The regulation of nuclear power and environmental regulation are discussed in detail in the description of theU.S. Utility BusinessandNon-Utility NuclearBusiness sections of Part I, Item 1.
PUHCA
The Public Utility Holding Company Act of 1935, as amended, regulates companies like Entergy Corporation that serve as holding companies to domestic operating utilities. Some of the more significant impacts of PUHCA are that it:
Entergy continues to support the broad industry effort to pass legislation in the United States Congress to repeal PUHCA and transfer certain aspects of the oversight of public utility holding companies from the SEC to FERC. Entergy believes that PUHCA inhibits its ability to compete in the evolving electric energy marketplace and largely duplicates the oversight activities otherwise performed by FERC, other federal regulators, and state and local regulators. In June 1995, the SEC adopted a report proposing options for the repeal or significant modification of PUHCA, which it continues to support.
Federal Power Act
The Federal Power Act regulates:
The Federal Power Act gives FERC jurisdiction over the rates charged by System Energy for Grand Gulf 1 capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over some of the rates charged by Entergy Arkansas and Entergy Gulf States. FERC also regulates the rates charged for intrasystem sales pursuant to the System Agreement.
Entergy Arkansas holds a FERC license for two hydroelectric projects totaling 70 MW of capacity that was to expire on February 28, 2003. In December 2002, FERC issued an order approving Entergy Arkansas' application to renew the license for these two facilities. The license gives Entergy Arkansas permission to operate the projects for another 50 years.
Employees
Employees are an integral part of Entergy's commitment to serving its customers. As of December 31, 2002, Entergy employed 15,601 people.
Approximately 5,100 employees are represented by the International Brotherhood of Electrical Workers Union, the Utility Workers Union of America, and the International Brotherhood of Teamsters Union.
conditions evolve.
Availability of SEC filings and other information on Entergy's website
Entergy's internet address is www.entergy.com. Entergy's annual reportreports on Form 10-K, for the year ended December 31, 2002, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to any of these reports, are available free of charge through Entergy's web site,website as soon as reasonably practicable after filing with the SEC. Financial presentations and news releases are also available through Entergy's website. Additionally, Entergy's Corporate Governance Guidelines, Board Committee Charters for the Corporate Governance, Audit, and Personnel Committees, and Entergy's Codes of Conduct are posted on Entergy's website. This information is also available in print to any shareholderinvestor that requests it.
In June 2004, Entergy's chief executive officer certified to the New York Stock Exchange that he was not aware of any violation by Entergy of the New York Stock Exchange corporate governance listing standards.
Part I, Item 1 is continued on page 97.
105.
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 herein. The financial statements are based on accounting principles generally accepted in the United States of America. Financial information included elsewhere in this report is consistent with the financial statements.
document. To meet their responsibilities with respect to financial information,this responsibility, management maintainsestablishes and enforcesmaintains a system of internal accounting controlscontrol designed to provide reasonable assurance on a cost-effective basis, as toregarding the integrity, objectivity,preparation and reliabilityfair presentation of the financial records, and as to the protection of assets.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 the training of personnel. This system is also tested by a comprehensive internal audit program.
Entergy management assesses the effectiveness of its internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.
TheAs a supplement to management's assessment, Entergy's independent auditors conduct an objective assessment of the degree to which management meets its responsibility for fairness of financial reporting and issue an attestation report on the adequacy of management's assessment. They evaluate Entergy's internal control over financial reporting and perform such tests and other procedures as they deem necessary to reach and express an opinion on the fairness of the financial statements.
In addition, the Audit Committee of the Board of Directors, composed solely of independent Directors, who are not employees of Entergy, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal accounting controls, and auditing and financial reporting matters. The Audit Committee appoints the independent auditors annually, and reviews with the independent auditors the scope and results of the audit effort. The Committee also meets periodically with the independent auditors and the chief internal auditor without management, providing free access to the Committee.
Independent public accountants provide an objectiveBased on management's assessment of internal controls using the degree to whichCOSO criteria, management meets its responsibility for fairness of financial reporting. They regularly evaluate the system of internal accounting controls and perform such tests and other procedures as they deem necessary to reach and express an opinion on the fairness of the financial statements.
Management believes that theseEntergy maintained effective internal control over financial reporting as of December 31, 2004. Management further believes that this assessment, combined with the policies and procedures noted above provide reasonable assurance that its operationsEntergy's financial statements are carried outfairly and accurately presented in accordance with a high standard of business conduct.generally accepted accounting principles.
J. WAYNE LEONARD |
| |
HUGH T. MCDONALD | JOSEPH F. DOMINO | |
E. RENAE CONLEY | CAROLYN C. SHANKS | |
DANIEL F. PACKER |
| |
THEODORE H. BUNTING, JR. | JAY A. LEWIS |
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Entergy Corporation is an investor-owned public utility holding company that operates primarily through three business segments.
Following are the percentages of Entergy's consolidated revenues and net income generated by these segments and the percentage of total assets held by them:
% of Revenue | % of Net Income | % of Total Assets | |||||||||||||||||||||||||
Segment | % of Revenue | % of Net Income | % of Total Assets | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | |||||||||||||||
2002 | 2001 | 2000 | 2002 (1) | 2001 | 2000 | 2002 | 2001 | 2000 | |||||||||||||||||||
U.S. Utility | 82 | 77 | 74 | 97 | 77 | 87 | 78 | 78 | 81 | 81 | 82 | 82 | 72 | 52 | 97 | 80 | 79 | 79 | |||||||||
Non-Utility Nuclear | 14 | 8 | 3 | 32 | 17 | 7 | 17 | 13 | 9 | 13 | 14 | 14 | 26 | 32 | 32 | 16 | 15 | 16 | |||||||||
Energy Commodity Services | 4 | 14 | 23 | (23) | 14 | 8 | 8 | 9 | 10 | 2 | 2 | 4 | - | 19 | (23) | 3 | 7 | 8 | |||||||||
Parent & Other | - | 1 | - | (6) | (8) | (2) | (3) | - | - | 4 | 2 | - | 2 | (3) | (6) | 1 | (1) | (3) |
(1) The net income figures in 2002 include a $238 million net of tax charge in the Energy Commodity Services segment. If this charge were excluded, the percentages would be 70% for U.S. Utility, 23% for Non-Utility Nuclear, 11% for Energy Commodity Services, and (4%) for Parent & Other.
Results of Operations
Earnings applicable to common stock for the years ended December 31, 2002, 2001,2004, 2003, and 20002002 by operating segment are as follows:
Operating Segment |
| 2004 |
| 2003 |
| 2002 |
|
| (In Thousands) | ||||
|
|
|
|
|
|
|
U.S. Utility |
| $643,408 |
| $469,050 |
| $583,251 |
Non-Utility Nuclear |
| 245,029 |
| 300,799 |
| 200,505 |
Energy Commodity Services |
| 3,481 |
| 180,454 |
| (145,830) |
Parent & Other |
| 17,606 |
| (23,360) |
| (38,566) |
Total |
| $909,524 |
| $926,943 |
| $599,360 |
Following is a discussion of Entergy's income before taxes according to the business segments listed above. Earnings for 2004 include a $97 million tax benefit that resulted from the sale of preferred stock and less than 1% of the common stock in a subsidiary in the non-nuclear wholesale assets business; and a $36 million net-of-tax impairment charge in the non-nuclear wholesale assets business, both of which are discussed below.
ResultsEarnings for 2003 include the $137.1 million net-of-tax cumulative effect of changes in accounting principle that increased earnings in the first quarter of 2003, almost entirely resulting from the implementation of SFAS 143. Earnings were negatively affected in the fourth quarter of 2003 by voluntary severance program expenses of $122.8 million net-of-tax. As part of an initiative to achieve productivity improvements with a goal of reducing costs, primarily in the Non-Utility Nuclear and U.S. Utility businesses, in the second half of 2003 Entergy offered a voluntary severance program to employees in various departments. Approximately 1,100 employees, including 650 employees in nuclear operations from the Non-Utility Nuclear and U.S. Utility businesses, accepted the offers.
Earnings for 2002 were negatively affected by net charges ($238.3 million after-tax)net-of-tax) reflecting the effect of Entergy's decision to discontinue additional greenfield power plant development and asset impairments resulting from the deteriorating economics of wholesale power markets principally in the United States and the United Kingdom. The net charges are discussed more fully below in the Energy Commodity Services discussion.
Entergy's income before taxes is discussed according to the business segments listed above. See Note 1211 to the consolidated financial statements for further discussion of Entergy's business segments and their financial results in 2002, 2001,2004, 2003, and 2000.2002.
Refer to"SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., ENTERGY GULF STATES, INC. AND SUBSIDIARIES, ENTERGY LOUISIANA, INC., ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., AND SYSTEM ENERGY RESOURCES, INC."SUBSIDIARIES" which accompany each company'saccompanies Entergy Corporation's consolidated financial statements in this report for further information with respect to operating statistics.
U.S. UtilityUTILITY
The increase in earnings for the U.S. Utility in 2002for 2004 from $550$469 million to $583$643 million was primarily due to the following:
The decrease in earnings for the U.S. Utility in 2001for 2003 from $587$583 million to $550$469 million was primarily due to:
Partially offsetting the decrease in earnings in 2003 were higher net revenue and lower interest charges.
Net Revenue
2004 Compared to 2003
Net revenue, which is Entergy's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2004 to 2003.
(In Millions) | ||
2003 net revenue | $4,214.5 | |
Volume/weather | 68.3 | |
Summer capacity charges | 17.4 | |
Base rates | 10.6 | |
Deferred fuel cost revisions | (46.3) | |
Price applied to unbilled sales | (19.3) | |
Other | (1.2) | |
2004 net revenue | $4,244.0 |
The volume/weather variance resulted primarily from increased usage, partially offset by the effect of milder weather on sales during 2004 compared to 2003. Billed usage increased a total of 2,261 GWh in the industrial and commercial sectors.
The summer capacity charges variance was due to the amortization in 2003 at Entergy Gulf States and Entergy Louisiana of deferred capacity charges for the summer of 2001. Entergy Gulf States' amortization began in June 2002 and ended in May 2003. Entergy Louisiana's amortization began in August 2002 and ended in July 2003.
Base rates increased net revenue due to a base rate increase at Entergy New Orleans that became effective in June 2003.
The deferred fuel cost revisions variance resulted primarily from a revision in 2003 to an unbilled sales pricing estimate to more closely align the fuel component of that pricing with expected recoverable fuel costs at Entergy Louisiana. Deferred fuel cost revisions also decreased net revenue due to a revision in 2004 to the estimate of fuel costs filed for recovery at Entergy Arkansas in the March 2004 energy cost recovery rider.
The price applied to unbilled sales variance resulted from a decrease in fuel price in 2004 caused primarily by the effect of nuclear plant outages in 2003 on average fuel costs.
Gross operating incomerevenues and increased interest charges, partially offset byregulatory credits
Gross operating revenues include an increase in interestfuel cost recovery revenues of $475 million and $18 million in electric and gas sales, respectively, primarily due to higher fuel rates in 2004 resulting from increases in the market prices of purchased power and natural gas. As such, this revenue increase is offset by increased fuel and purchased power expenses.
Other regulatory credits increased primarily due to the following:
2003 Compared to 2002
Net revenue, which is Entergy's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2003 to 2002.
(In Millions) | ||
2002 net revenue | $4,209.6 | |
Base rate increases | 66.2 | |
Base rate decreases | (23.3) | |
Deferred fuel cost revisions | 56.2 | |
Asset retirement obligation | 42.9 | |
Net wholesale revenue | 23.2 | |
March 2002 Ark. settlement agreement | (154.0) | |
Other | (6.3) | |
2003 net revenue | $4,214.5 |
Base rates increased net revenue due to base rate increases at Entergy Mississippi and Entergy New Orleans that became effective in January 2003 and June 2003, respectively. Entergy Gulf States implemented base rate decreases in its Louisiana jurisdiction effective June 2002 and January 2003. The January 2003 base rate decrease of $22.1 million had a minimal impact on net income due to a corresponding reduction in nuclear depreciation and decommissioning expenses associated with the change in accounting estimate to reflect an assumed extension of River Bend's useful life.
The deferred fuel cost revisions variance was due to a revised unbilled sales pricing estimate made in December 2002 and further revision of that estimate in the first quarter of 2003 to more closely align the fuel component of that pricing with expected recoverable fuel costs at Entergy Louisiana.
The asset retirement obligation variance was due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," adopted in January 2003. See"Critical Accounting Estimates - - Nuclear Decommissioning Costs" for more details on SFAS 143. The increase was offset by increased depreciation and decommissioning expenses and had an insignificant effect on net income.
Operating Income
2002 Compared to 2001
Operating income decreased by $43.6 millionThe increase in 2002net wholesale revenue was primarily due to:
The March 2002 settlement agreement variance reflects the absence in 2003 of the effect of recording the ice storm settlement approved by the APSC in 2002. This settlement resulted in previously deferred revenues at Entergy Arkansas per the transition cost account mechanism being recorded in net revenue in the second quarter of 2002. The decrease was offset by a corresponding decrease in other operation and maintenance expenses of $273.2 million. $159.9 million of this increase is offset in otherand had a minimal effect on net income.
Gross operating revenues and regulatory credits
Gross operating revenues include an increase in fuel cost recovery revenues of $682 million and relates$53 million in electric and gas sales, respectively, primarily due to ahigher fuel rates in 2003 resulting from increases in the market prices of purchased power and natural gas. As such, this revenue increase was offset by increased fuel and purchased power expenses.
Other regulatory credits decreased primarily due to the APSC-approved March 2002 settlement agreement mentioned above, which increased other regulatory credits in 2002 to offset other operation and 2001 earnings reviewmaintenance expenses of $159.9 million related to the December 2000 ice storms. The decrease was partially offset by the asset retirement obligation mentioned above, which increased other regulatory credits in 2003 to offset the increases in depreciation and decommissioning expenses.
Other Income Statement Variances
2004 Compared to 2003
Other operation and maintenance expenses decreased from $1.613 billion in 2003 to $1.569 billion in 2004 primarily due to voluntary severance program accruals of $99.8 million in 2003 partially offset by an increase of $30.5 million as a result of higher customer service support costs in 2004 and an increase of approximately $33 million as a result of higher benefits costs in 2004. Entergy expects benefit costs to continue to increase in 2005. See"Critical Accounting Estimates - - Pension and Other Retirement Benefits" and Note 10 to the consolidated financial statements for further discussion of benefit costs.
Depreciation and amortization expenses increased from $797.6 million in 2003 to $823.7 million in 2004 primarily due to higher depreciation of Grand Gulf due to a higher scheduled sale-leaseback principal payment in addition to an increase in plant in service.
Other income (deductions) changed from ($36.0 million) in 2003 to $108.9 million in 2004 primarily due to the following:
Interest on long-term debt decreased from $433.5 million in 2003 to $390.7 million in 2004 primarily due to the net retirement and refinancing of long-term debt in 2003 and the first six months of 2004. See Note 5 to the consolidated financial statements for details on long-term debt.
2003 Compared to 2002
Other operation and maintenance expenses decreased from $1.679 billion in 2002 to $1.613 billion in 2003 primarily due to decreased expenses at Entergy Arkansas. The March 2002 settlement agreement that became final in the second quarter of 2002, allowing Entergy Arkansas to recover a large majority of 2000 and 2001 ice storm repair expenses through the previously-collected transition cost account (TCA) amounts. The remainingamounts, increased Entergy Arkansas' expenses by $159.9 million in 2002. This increase in expenses in 2002 was offset by a regulatory credit resulting in no effect on net income. The decrease was partially offset by an increase of $99.8 million in benefit costs as a result of voluntary severance program accruals in 2003.
Decommissioning expense increased from $30.5 million in 2002 to $92.5 million in 2003 primarily due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations." The increase in decommissioning expense was offset by increases in other operationregulatory credits and maintenanceinterest and dividend income and had an insignificant effect on net income.
Depreciation and amortization expenses is explained below; and
Partially offsetting these decreases in operating income were the following:
dividend income and has an insignificant effect on net income.
In addition to the effect of the March 2002 settlement agreement, the increase in other operation and maintenance expenses was primarily due to:
Fuel recovery mechanisms at the domestic utility companies generally provide for the deferral of fuel and purchased power costs above the amounts included in existing rates. Operating revenues include a decrease in fuelcost recovery revenue of $897.4 million and $60.5 million related to electric sales and gas sales, respectively,2003 primarily due to lower fuel recovery factors resulting from decreases in the market prices of natural gas and purchased power in 2002. As such, this revenue decrease is offset by decreased fuel and purchased power expenses. Also contributing to the decrease in fuel cost recovery revenue was a lower fuel recovery surcharge in 2002 in the Texas jurisdiction of Entergy Gulf States.
2001 Compared to 2000
Operating income decreased $125.6 million in 2001 primarily due to:
Partially offsetting these decreases in operating income weresecond quarter of 2003 for the following:
River Bend abeyed plant costs. The decrease in other operation and maintenance expenses in 2001 was primarily due to:
Operating revenues include an increase in fuel cost recovery revenue of $462.7 million related to electric sales primarily due to increased fuel recovery factors at Entergy Arkansas, Entergy Gulf States in the Texas jurisdiction, and Entergy Mississippi, combined with higher fuel and purchased power costs recovered through fuel recovery mechanisms at Entergy Gulf States in the Louisiana jurisdiction and Entergy New Orleans due to the increased market prices of natural gas and purchased power early in 2001. As such, this revenue increase is offset by increased fuel and purchased power expenses.
Other Impacts on Results of Operations
2002 Compared to 2001
Results for the year ended December 31, 2002 for U.S. Utility were also affected by the following:
Interest on long-term debt decreased from $462.0 million which is explained below.
The decrease in interest income in 2002 was primarily due to:
The decrease in interest charges in 2002 is primarily due to:
NON-UTILITY NUCLEAR
2001 Compared to 2000
Results for the year ended December 31, 2001 for U.S. Utility were also affected by an increase in interest charges of $61.5 million primarily due to:
Non-Utility Nuclear
The increase in earnings in 2002 for Non-Utility Nuclear from $128 million to $201 million was primarily due to the operation of Indian Point 2 and Vermont Yankee, which were purchased in September 2001 and July 2002, respectively.
The increase in earnings in 2001 for Non-Utility Nuclear from $49 million to $128 million was primarily due to the operation of FitzPatrick and Indian Point 3 for a full year, as each was purchased in November 2000, and the operation of Indian Point 2, which was purchased in September 2001.
Following are key performance measures for Non-Utility Nuclear:
2002 | 2001 | 2000 | 2004 |
| 2003 |
| 2002 | |
|
|
|
|
| ||||
Net MW in operation at December 31 | 3,955 | 3,445 | 2,475 | 4,058 |
| 4,001 |
| 3,955 |
Average realized price per MWh | $41.26 |
| $39.38 |
| $40.07 | |||
Generation in GWh for the year | 29,953 | 22,614 | 7,171 | 32,524 |
| 32,379 |
| 29,953 |
Capacity factor for the year | 93% | 94% | 92% |
| 92% |
| 93% |
20022004 Compared to 20012003
The following fluctuationsdecrease in the results of operationsearnings for Non-Utility Nuclear in 2002 were primarily caused by the acquisitions of Indian Point 2 and Vermont Yankee (except as otherwise noted):
Partially offsetting this increase were the following:
20012003 Compared to 20002002
The following fluctuationsincrease in the results of operationsearnings for Non-Utility Nuclear in 2001 were primarily caused by the acquisition of FitzPatrick, Indian Point 3, and Indian Point 2:
ENERGY COMMODITY SERVICES
Sales of Entergy-Koch Businesses
In the fourth quarter of 2004, Entergy-Koch sold its energy trading and pipeline businesses to third parties. The sales came after a review of strategic alternatives for enhancing the value of Entergy-Koch, LP. Entergy received $862 million of cash distributions in 2004 from Entergy-Koch after the business sales, and Entergy ultimately expects to $394.5 million;
In the purchase agreements for the energy trading and the pipeline business sales, Entergy-Koch has agreed to indemnify the respective purchasers for certain potential losses relating to any breaches of the sellers' representations, warranties, and obligations under each of the purchase agreements. Entergy Corporation has guaranteed up to 50% of Entergy-Koch's indemnification obligations to the plants, increased $47.9 millionpurchasers. Entergy does not expect any material claims under these indemnification obligations, but to $81.1 million;
Results of Operations
2004 Compared to $40.1 million.
2003
Energy Commodity Services
The decrease in earnings for Energy Commodity Services in 2002 from $106$180.5 million to a $146$3.5 million loss was primarily due toto:
Partially offsetting the decrease in earnings is a tax benefit resulting from the sale of preferred stock and less than 1% of the common stock of Entergy Asset Management, an Entergy subsidiary. In December 2004, an Entergy subsidiary sold the stock to a third party for $29.75 million. The sale resulted in a capital loss for tax purposes of $370 million, producing a net tax benefit of $97 million that Entergy recorded in the fourth quarter of 2004.
2003 Compared to 2002
The increase in earnings for Energy Commodity Services in 20012003 from $55a $145.8 million loss to $106$180.5 million in earnings was primarily due to the strong performance of the trading and gas pipeline businesses of Entergy-Koch.
2002 Comparednet charges recorded to 2001
The decrease in earnings for Energy Commodity Servicesoperating expenses in 2002, was primarily dueas discussed below. Higher earnings from Entergy's investment in Entergy-Koch also contributed to the increase in earnings. The income from Entergy's investment in Entergy-Koch was $73 million higher in 2003 primarily as a result of higher earnings in its trading business.
In 2002, Entergy recorded charges to reflect the effect of Entergy's decision to discontinue additional greenfield power plant development and to reflect asset impairments resulting from the deteriorating economics of wholesale power markets principally in the United States and the United Kingdom. Entergy recordedThe net charges of $428.5 million ($238.3 million net of tax) to operating expenses. The net charges consistnet-of-tax) consisted of the following:
Also, in the first quarter of 2002, Energy Commodity Services sold its interests in projects in Argentina, Chile, and Peru for net proceeds of $135.5 million. After impairment provisions recorded for theseLatin Americaninterests in 2001, the net loss realized on the sale in 2002 is insignificant.
Revenues and fuel and purchased power expenses decreased for Energy Commodity Services by $1,075.8 million and $876.9 million, respectively, in 2002 primarily due to:
Following are key performance measures for Entergy-Koch's operations for 2002 and 2001:
2002 | 2001 | |||
Entergy-Koch Trading | ||||
Gas volatility | 61% | 72% | ||
Electricity volatility | 48% | 78% | ||
Gas marketed (BCF/D) (1) | 5.8 | 3.0 | ||
Electricity marketed (GWh) (1) | 408,038 | 180,893 | ||
Gain/loss days | 1.8 | 2.8 | ||
Gulf South Pipeline | ||||
Throughput (BCF/D) | 2.40 | 2.45 | ||
Production cost ($/MMBtu) | $0.094 | $0.093 |
Entergy accounts for its 50% share in Entergy-Koch under the equity method of accounting. Certain terms of the partnership arrangement allocate income from various sources, and the taxes on that income, on a significantly disproportionate basis through 2003. Losses and distributions from operations are allocated to the partners equally. Substantially all of Entergy-Koch's profits were allocated to Entergy in 2002. Effective January 1, 2004, a revaluation of Entergy-Koch's assets for legal capital account purposes will occur, and future profit allocations will change after the revaluation. The profit allocations other than for weather trading and international trading are expected to become equal, unless special allocations are necessary to equalize the partners' legal capital accounts. Profit allocations for weather trading and international trading remain disproportionate to the ownership interests. Earnings allocated under the terms of the partnership agreement constitute equity, n ot subject to reallocation, for the partners.PARENT & OTHER
20012004 Compared to 20002003
The increase in earnings for Energy Commodity Services in 2001 was primarily due to:
Partially offsetting the increase in earnings for Energy Commodity Services in 2001 was the following:
Revenues decreased for Energy Commodity Services by $983.3 million in 2001, primarily duetax benefits related to the contribution of substantially all of Entergy-Koch investment; and
2003 Compared to customers by the joint venture than provided previously by Entergy.2002
The decrease in revenues in 2001 was partially offset by an increase in operating revenues primarily due to an increase of $409.8 million from Highland Energy and an increase of $450.1 million from the Saltend and Damhead Creek plants. Highland Energy was acquired in June 2000, and the Saltend and Damhead Creek plants began commercial operation in late November 2000 and early 2001, respectively. Highland Energy was sold in the fourth quarter of 2001. The increase in revenues from Highland Energy, Damhead Creek, and Saltend is largely offset by increased fuel and purchased power expenses of $644.1 million and increased other operation and maintenance expenses of $94.6 million.
Entergy sold the Saltend plant in August 2001 and revenues include the $88.1 million ($57.2 million net of tax) gain on the sale.
Parent & Other
The loss from Parent & Other decreased in 20022003 from $58$38.6 million to $39$23.4 million primarily due to:
The loss from Parent & Other increased in 2001 from $11 million to $58 million primarily due to:
The increased loss in 2001 was partially offset by the write-down in 2000 of investments in Latin American projects to their estimated fair values.expense.
Income Taxes
The effective income tax rates for 2004, 2003, and 2002 2001, and 2000 were 32.1%28.2%, 38.3%37.9%, and 40.3%32.1%, respectively. See Note 3 to the consolidated financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates. The lower effective income tax rate in 2004 is primarily due to the tax benefits resulting from the Entergy Asset Management stock sale discussed above.
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 reduction in the debt to capital percentage forfrom 2002 to 2003 is primarily the result of reduced debt outstanding in the sale of Damhead CreekU.S. Utility and Non-Utility Nuclear businesses, and an increase in December 2002. Debt outstanding on the Damhead Creek facility was $458 million as of December 31, 2001.shareholders' equity, primarily due to increased retained earnings.
2002 | 2001 | 2000 | ||||
Net debt to net capital at the end of the year | 46.3% | 49.7% | 49.8% |
|
| 2004 |
| 2003 |
| 2002 |
|
|
|
|
|
|
|
Net debt to net capital at the end of the year |
| 44.7% |
| 45.3% |
| 47.7% |
Effect of subtracting cash from debt |
| 2.7% |
| 2.2% |
| 4.1% |
Debt to capital at the end of the year |
| 47.4% |
| 47.5% |
| 51.8% |
Net debt consists of gross debt less cash and cash equivalents. Gross debtDebt consists of notes payable, capital lease obligations, preferred stock with sinking fund, and long-term debt, including the currently maturing portion. Net capitalCapital consists of net debt, common shareholders' equity, and preferred stock without sinking fund. Net capital consists of capital less cash and securities.cash equivalents. The preferred stock with sinking fund is included in debt pursuant to SFAS 150, which Entergy implemented in the third quarter of 2003. The 2002 ratio does not reflect that type of security as debt, but does include it in net capital, which is how Entergy presented those securities prior to implementation of SFAS 150. Entergy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy's financial condition.
Long-term debt, including the currently maturing portion, makes up over 90% of Entergy's total debt outstanding. Following are Entergy's long-term debt principal maturities as of December 31, 20022003 and 2004 by operating segment. TheseThe figures below include principal payments on the Entergy Louisiana and System Energy sale-leaseback transactions, which are included in long-term debt on the balance sheet.
Long-term debt maturities |
| 2004 |
| 2005 |
| 2006 |
| 2007 |
| 2008-2009 |
| after 2009 |
|
| (In Millions) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Utility |
| $450 |
| $355 |
| $28 |
| $573 |
| $721 |
| $4,305 |
Non-Utility Nuclear |
| 74 |
| 72 |
| 76 |
| 80 |
| 40 |
| 173 |
Energy Commodity Services |
| - |
| - |
| - |
| - |
| - |
| - |
Parent and Other |
| - |
| 60 |
| - |
| - |
| 539 |
| 301 |
Total | $524 | $487 | $104 | $653 | $1,300 | $4,779 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Utility |
| - |
| $359 |
| $27 |
| $98 |
| $749 |
| $4,880 |
Non-Utility Nuclear |
| - |
| 77 |
| 76 |
| 80 |
| 40 |
| 173 |
Energy Commodity Services |
| - |
| - |
| - |
| - |
| - |
| - |
Parent and Other |
| - |
| 60 |
| - |
| 50 |
| 539 |
| 301 |
Total | - | $496 | $103 | $228 | $1,328 | $5,354 |
Long-term debt maturities (in millions) | 2003 | 2004 | 2005 | 2006-2007 | after 2007 | ||||
U. S. Utility | $1,111 | $855 | $470 | $466 | $3,751 | ||||
Non-Utility Nuclear | $87 | $91 | $95 | $205 | $205 | ||||
Energy Commodity Services | $79 | - | - | - | - | ||||
Parent and Other | - | $595 | - | - | $267 |
In the fourth quarter of 2002, the U.S. Utility issued $640 million of debt with maturities ranging from 2007 to 2032. Approximately $71 million of the proceeds of the debt issued in the fourth quarter were used to retire, in 2002, debt that was scheduled to mature in 2003, and the remainder will be used to meet certain 2003 maturities as they occur. Entergy Mississippi issued an additional $100 million of debt in January 2003 that matures in 2013. The proceeds will be used to repay, prior to maturity, debt of Entergy Mississippi that is scheduled to mature in 2003 and 2004. Note 75 to the consolidated financial statements provides more detail concerning long-term debt.
In May 2004, Entergy Corporation replaced its 364-day bank credit facility with two separate facilities, a new 364-day credit facility and a three-year credit facility. The three-year credit facility, which expires in May 2007, has a borrowing capacity of $965 million, of which $50 million was outstanding at December 31, 2004.
In December 2004, Entergy Corporation refinanced the 364-day bank credit facility by entering into a five-year credit facility. The Energy Commodity Services debtfive-year credit facility, which expires in December 2009, has a borrowing capacity of $500 million, none of which was paidoutstanding at maturity in January 2003 using money drawn on December 31, 2004.
Entergy also has the ability to issue letters of credit against the total borrowing capacity of both credit facilities, and $50 million of letters of credit had been issued against the three-year facility at December 31, 2004.
Entergy Corporation's 364-day credit facility.facilities require it to maintain a consolidated debt ratio of 65% or less of its total capitalization, and maintain an interest coverage ratio of 2 to 1. If Entergy fails to meet these limits, or if Entergy or the domestic utility companies default on other indebtedness or are in bankruptcy or insolvency proceedings, an acceleration of the credit facilities' maturity dates may occur.
Capital lease obligations, including nuclear fuel leases, are a minimal part of Entergy's overall capital structure, and are discussed further in Note 109 to the consolidated financial statements. Following are Entergy's payment obligations under those leases:
| 2005 |
| 2006 |
| 2007 |
| 2008-2009 |
| after 2009 |
| (In Millions) | ||||||||
Capital lease payments, including nuclear fuel leases |
|
|
|
|
|
|
|
|
|
2003 | 2004 | 2005 | 2006-2007 | after 2007 | |||||
Capital lease payments, including nuclear fuel leases (in millions) |
|
|
|
|
|
Notes payable, which include borrowings outstanding on credit facilities with original maturities of less than one year, were less than $1 million as of December 31, 2002. Entergy Corporation,2004. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy MississippiNew Orleans each have 364-day credit facilities available as follows:
|
| Amount of | Amount Drawn as of | |||
|
|
|
| |||
Entergy Arkansas |
| $ | - | |||
Entergy Louisiana |
| $15 million (a) | - | |||
Entergy Mississippi | May | $25 million | - | |||
Entergy New Orleans | April 2005 | $ | - |
Although the(a) The combined amount borrowed by Entergy Corporation credit line expires in May 2003,Louisiana and Entergy has the discretionary option to extend the period to repay the amount then outstanding for an additional 364-day term. Because of this option, which Entergy intends to exercise if it does not renew the credit line or obtain an alternative source of financing, the debt outstandingNew Orleans under the credit line is reflected in long-term debt on the balance sheet. The credit line is reflected as notes payablethese facilities at December 31, 2001.
any one time cannot exceed $15 million.
Operating Lease Obligations and Guarantees of Unconsolidated Obligations
In addition to the obligations listed above that are reflected on the balance sheet, Entergy has a minimal amount of operating leaseslease obligations and guarantees in support of unconsolidated obligations. Entergy's guarantees in support of unconsolidated obligations that are not reflected as liabilitieslikely to have a material effect on the balance sheet. These items are not on the balance sheet in accordance with generally accepted accounting principles.
Entergy's financial condition or results of operations. Following are Entergy's payment obligations as of December 31, 2004 on noncancelablenon-cancelable operating leases with a term over one year as of December 31, 2002:year:
2003 | 2004 | 2005 | 2006-2007 | after 2007 | |||||
Operating lease payments (in millions) | $98 | $91 | $73 | $98 | $140 |
| 2005 |
| 2006 |
| 2007 |
| 2008-2009 |
| after 2009 |
| (In Millions) | ||||||||
|
|
|
|
|
|
|
|
|
|
Operating lease payments | $99 |
| $86 |
| $69 |
| $100 |
| $210 |
The operating leases are discussed more thoroughly in Note 109 to the consolidated financial statements.
Summary of Contractual Obligations of Consolidated Entities
Contractual Obligations |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| after 2009 |
| Total |
|
| (In Millions) | ||||||||
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (1) |
| $496 |
| $331 |
| $1,328 |
| $5,354 |
| $7,509 |
Capital lease payments (2) |
| $136 |
| $146 |
| $2 |
| $3 |
| $287 |
Operating leases (2) |
| $99 |
| $155 |
| $100 |
| $210 |
| $564 |
Purchase obligations (3) |
| $1,160 |
| $1,402 |
| $962 |
| $1,156 |
| $4,680 |
(1) | Long-term debt is discussed in Note 5 to the consolidated financial statements. |
(2) | Capital lease payments include nuclear fuel leases. Lease obligations are discussed in Note 9 to the consolidated financial statements. |
(3) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Approximately 99% of the total pertains to fuel and purchased power obligations that are recovered in the normal course of business through various fuel cost recovery mechanisms in the U.S. Utility business. |
Entergy's guarantees of unconsolidated obligations outstanding as of December 31, 2002 total a maximum amount of $267.5 million. In August 2001, EntergyShaw entered into a turnkey construction agreement with an Entergy subsidiary, Entergy Power Ventures, L.P. (EPV), and with Northeast Texas Electric Cooperative, Inc. (NTEC), providing for the construction by EntergyShaw of a 550 MW electric generating station to be located in Harrison County, Texas. Entergy has guaranteed the obligations of EntergyShaw to construct the plant, which will be 70% owned by EPV. Entergy's maximum liability on the guarantee is $232.5 million. In additionone of the contracts transferred to Entergy-Koch by Entergy's power marketingthese contractual obligations, Entergy expects to contribute $185.9 million to its pension plans and trading business is backed by an Entergy Corporation guarantee authorized$63.3 million to other postretirement plans in the amount of $35 million.2005.
Capital Funds Agreement
Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:
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 20032005 through 2005 (in millions):2007:
Planned construction and capital investments |
| 2005 |
| 2006 |
| 2007 | |
|
|
| (In Millions) | ||||
|
|
|
|
|
|
|
|
Maintenance Capital: |
|
|
|
|
|
| |
| U.S. Utility |
| $734 |
| $699 |
| $763 |
| Non-Utility Nuclear |
| 72 |
| 72 |
| 60 |
| Energy Commodity Services |
| 3 |
| 4 |
| 6 |
| Parent and Other |
| 11 |
| 19 |
| 11 |
|
|
| 820 |
| 794 |
| 840 |
Capital Commitments: |
|
|
|
|
|
| |
| U.S. Utility |
| 571 |
| 349 |
| 201 |
| Non-Utility Nuclear |
| 90 |
| 67 |
| 43 |
| Energy Commodity Services |
| - |
| - |
| - |
| Parent and Other |
| - |
| - |
| - |
|
|
| 661 |
| 416 |
| 244 |
Total |
| $1,481 |
| $1,210 |
| $1,084 |
Planned construction and capital investment | 2003 | 2004 | 2005 | |||
U.S. Utility | $924 | $915 | $965 | |||
Non-Utility Nuclear | $201 | $142 | $109 | |||
Energy Commodity Services | $24 | $76 | $3 | |||
Other | $7 | $7 | $9 |
TheMaintenance Capital refers to amounts Entergy plans to spend on routine capital plan for the U.S. Utility primarily consistsprojects that are necessary to support reliability of spending for maintenance capital, supporting continued reliability improvements,its service, equipment, or systems and to support normal customer growth. Also included
Capital Commitments refers to non-routine capital investments for which Entergy is either contractually obligated, has Board-approval, or is otherwise required to make pursuant to a regulatory agreement or existing rule or law. Amounts reflected in this category include the replacementfollowing:
The capital plan for Non-Utility Nuclear primarily consists of spending for maintenance capital. Entergy also includes some spending for power uprate projectsengaging in the estimate.
The capital plantransaction. Hearings are scheduled for Energy Commodity Services primarily consistsMarch 2005. Assuming regulatory approval by the LPSC, Entergy Louisiana expects the Perryville acquisition to close in mid-2005.
The planned construction andFrom time to time, Entergy considers other capital investments do not include potentialas potentially being necessary or desirable in the future, including additional nuclear plant power uprates, generation supply assets, various transmission upgrades, environmental compliance expenditures, or investments in new businesses or assets. The estimatedBecause no contractual obligation, commitment, or Board-approval exists to pursue these investments, they are not included in Entergy's planned construction and capital investments. These potential investments are also subject to evaluation and approval in accordance with Entergy's policies before amounts may be spent. In addition, Entergy's capital spending plans do not include spending for transmission upgrades requested by merchant generators, other than projects currently underway.
Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, and the ability to access capital.
Dividends and Stock Repurchases
Declarations of dividends on Entergy's common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy's common stock dividends based upon Entergy's earnings, financial strength, and future investment opportunities. At its October 20022004 meeting, the Board increased Entergy's quarterly dividend per share by 6%20%, to $0.35.$0.54. In 2002,2004, Entergy paid $299approximately $428 million in cash dividends on its common stock.
In accordance with Entergy's stock option plans,stock-based compensation plan, Entergy periodically grants stock options to its employees, which may be exercised to obtain shares of Entergy's common stock. In orderAccording to reduce the potential increase in outstanding commonplan, these shares created bycan be newly issued shares, treasury stock, or shares purchased on the open market. Entergy's management has been authorized to repurchase on the open market shares up to an amount sufficient to fund the exercise of stock options,grants under the plans. In addition to this authority, the Board has approved a program under which Entergy plans to purchasewill repurchase up to 10 million shares$1.5 billion of its common stock through mid-2004 on2006. The amount of repurchases under the program may vary as a discretionary basis through open market purchasesresult of material changes in business results or privately negotiated transactions.capital spending, or as a result of material new investment opportunities. In 2004, Entergy repurchased 2,885,00016,631,800 shares of common stock under both programs for a total purchase price of $118.5 million in 2002.
System Energy Letters of Credit
System Energy had three-year letters of credit in place that were scheduled to expire in March 2003 securing certain of its obligations related to the sales/leaseback of a portion of Grand Gulf 1. System Energy replaced the letters of credit with new three-year letters of credit totaling approximately $192 million that are backed by cash collateral. System Energy used approximately $192 million in March 2003 to provide this cash collateral.
$1.018 billion.
PUHCA Restrictions on Uses of Capital
Entergy's ability to invest in domesticelectric wholesale generators and foreign generation businessesutility companies is subject to the SEC's regulations under PUHCA. As authorized by the SEC, Entergy is allowed to invest earnings in electric wholesale generators and foreign utility companies in an amount equal to 100% of its average consolidated retained earnings in domestic and foreign generation businesses.earnings. As of December 31, 2002,2004, Entergy's investments subject to this rule totaled $1.97$2.7 billion constituting 52.5%55.9% of Entergy's average consolidated retained earnings.
Entergy's ability to guarantee obligations of Entergy's non-utility subsidiaries is also limited by SEC regulations under PUHCA. In August 2000, the SEC issued an order, effective through December 31, 2005, that allows Entergy to issue up to $2 billion of guarantees for the benefit of its non-utility companies. In February 2005, Entergy requested that the SEC increase this limit to $4 billion.
Under PUHCA, the SEC imposes a limit equal to 15% of consolidated capitalization on the amount that may be invested in "energy-related" businesses without specific SEC approval. Entergy has made investments in energy-related businesses, including power marketing and trading. Entergy's available capacity to make additional investments at December 31, 20022004 was approximately $1.8$1.9 billion.
Sources of Capital
Entergy's sources to meet its capital requirements and to fund potential investments include:
The majority of Entergy's internally generated funds come from the domestic utility companies and System Energy.U.S. Utility. Circumstances such as weather patterns, price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the level of internally generated funds in the future. In the following section, Entergy's cash flow activity for the previous three years is discussed.
Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation's subsidiaries restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2002,2004, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $296.1$394.9 million and $36.2$68.5 million, respectively. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation.
Short-term borrowings All debt and common and preferred stock issuances by the domestic utility companies and System Energy includingrequire prior regulatory approval and their preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. The domestic utility companies and System Energy have sufficient capacity under these tests to meet foreseeable capital needs.
The short-term borrowings under the intra-company money pool,of Entergy's subsidiaries are limited to amounts authorized by the SEC. The current limits authorized are effective through November 30, 2007. In addition to borrowing from commercial banks, Entergy's subsidiaries are authorized under the SEC order to borrow from Entergy's money pool. The money pool is an inter-company borrowing arrangement designed to reduce Entergy's subsidiaries' dependence on external short-term borrowings. Borrowings from the money pool and external borrowings combined may not exceed the SEC authorized limits. As of December 31, 2004, Entergy's subsidiaries' aggregate authorized limit was $1.6 billion and the aggregate outstanding borrowing from the money pool was $151.6 million. There were no borrowings outstanding from external sources. Under the SEC order authorizing the short-term borrowing limits,and without further SEC authorization, the domestic utility companies and System Energy cannot incurissue new short-term indebtedness ifunless (a) Entergy Corporation and the issuer'sissuer each maintain common equity would comprise less thanof at least 30% of its capital. In addition, this order restrictscapital and (b) with the exception of money pool borrowings, the debt security to be issued (if rated) and all outstanding securities of the issuer and Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, or System Energy from issuing long-term debt unlessCorporation that debt willare rated must be rated as investment grade. See Note 4 to the consolidated financial statements for further discussion of Entergy's short-term borrowing limits.
The short and long-term securities issuances of Entergy Corporation also are limited to amounts authorized by the SEC. Under its current SEC order, and without further SEC authorization, Entergy Corporation cannot incur additional indebtedness or issue other securities unless (a) Entergy Corporation and each of its public utility subsidiaries maintain common equity ratios of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of Entergy Corporation that are rated, are rated investment grade.
The long-term securities issuances of Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and System Energy also are limited to amounts authorized by the SEC. Under the current SEC orders of Entergy Gulf States, Entergy Louisiana, and Entergy Mississippi, and without further SEC authorization, the issuer cannot incur additional indebtedness or issue other securities unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of the issuer (other than preferred stock of Entergy Gulf States), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade.
Cash Flow Activity
As shown in Entergy's Statements of Cash Flows, cash flows for the years ended December 31, 2002, 2001,2004, 2003, and 20002002 were as follows:
2002 | 2001 | 2000 | 2004 | 2003 | 2002 | ||||||||
(In Millions) | (In Millions) | ||||||||||||
Cash and cash equivalents at beginning of period | $ 752 | $ 1,382 | $ 1,214 | Cash and cash equivalents at beginning of period | $692 | $1,335 | $752 | ||||||
Cash flow provided by (used in): | Cash flow provided by (used in): | ||||||||||||
Operating activities | 2,181 | 2,216 | 1,968 | ||||||||||
Investing activities | (1,388) | (2,224) | (1,814) | ||||||||||
Financing activities | (213) | (622) | 20 | ||||||||||
Operating activities | 2,929 | 2,006 | 2,181 | ||||||||||
Investing activities | (1,140) | (1,783) | (1,388) | ||||||||||
Financing activities | (1,672) | (869) | (213) | ||||||||||
Effect of exchange rates on cash and cash equivalents | 3 | - | (6) | Effect of exchange rates on cash and cash equivalents | (1) | 3 | 3 | ||||||
Net increase (decrease) in cash and cash equivalents | 583 | (630) | 168 | ||||||||||
Net increase (decrease) in cash and cash equivalents | 116 | (643) | 583 | ||||||||||
Cash and cash equivalents at end of period | $ 1,335 | $ 752 | $ 1,382 | Cash and cash equivalents at end of period | $808 | $692 | $1,335 |
Operating Cash Flow Activity
20022004 Compared to 20012003
Entergy's cash flow provided by operating activities increased in 2004 primarily due to the following:
As discussed in Note 3 to the consolidated financial statements, in 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The cash benefit from the method change was $74 million on a consolidated basis in 2004. This accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. As of December 31, 2004, Entergy has a consolidated net operating loss (NOL) carryforward for tax purposes of $2.9 billion, principally resulting from the change in tax accounting method related to cost of goods sold. If the tax accounting method change is sustained, Entergy expects to fully utilize the NOL carryforward through 2006.
2003 Compared to 2002
Entergy's cash flow provided by operating activities decreased slightly in 20022003 primarily due to:
to the following:
Partially offsetting the decrease in cash flow in 2003 was an increase due to the parent company providing $209 million in operating cash flow in 2003 compared to using $439 million in 2002 primarily resulted fromdue to the payment that Entergy Corporation made to Entergy Louisiana in 2002 pursuant to the tax accounting election made by Entergy Louisiana that is discussed below.
Louisiana.
2001 Compared to 2000
Entergy's consolidated net cash flow provided by operating activities increased in 2001 primarily due to:
These increases were partially offset by a decrease of $129 million in cash provided by the U.S. Utility and net cash used of $128 million in 2001 compared to net cash provided of $64.3 million in 2000 by the Energy Commodity Services segment. The Energy Commodity Services segment includes the non-nuclear wholesale assets business and the Entergy-Koch joint venture. In 2001, the non-nuclear wholesale assets business used $73 million of net cash in operating activities; in 2000, the non-nuclear wholesale assets business provided $37 million of operating cash flow. This fluctuation is primarily due to a net loss, excluding the gain on the sale of the Saltend plant, generated in 2001 compared with net income generated in 2000. Entergy's investment in Entergy-Koch used $55 million of net cash in operating activities in 2001 compared with power marketing and trading providing $27 million of ope rating cash flow in 2000. This fluctuation is primarily because, although income from this activity was higher in 2001, Entergy did not receive dividends from Entergy-Koch, as the joint venture retained capital for business opportunities.
Entergy Louisiana Tax Election
In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts. The most significant of these is the contract to purchase power from the Vidalia project (the contract is discussed in Note 98 to the consolidated financial statements). The new tax accounting method has provided a cumulative cash flow benefit of approximately $867$790 million through 2002,2004, which is expected to reverse in the years 20032005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. Approximately half of the consolidated cash flow benefit of the election occurred in 2001 and the remainder occurred in 2002. In accordance with Entergy's intercompany tax allocation agreement, the cash flow benefit for Entergy Louisiana occurred in the fourth quarter of 2002.
In a September 2002 settlement of an LPSC proceeding that concerned the Vidalia contract, the LPSC approved Entergy Louisiana's proposed treatment of the regulatory impact of the tax accounting election. In general, the settlement permits Entergy Louisiana to keep a portion of the tax benefit in exchange for bearing the risk associated with sustaining the tax treatment. The LPSC settlement divided the term of the Vidalia contract into two segments: 2002-122002-2012 and 2013-31.2013-2031. During the first eight years of the 2002-122002-2012 segment, Entergy Louisiana agreed to credit rates by flowing through its fuel adjustment calculation $11 million each year, beginning monthly in October 2002. Entergy Louisiana must credit rates in this way and by this amount even if Entergy Louisiana is unable to sustain the tax deduction. Entergy Louisiana also must credit rates by $11 million each year for an additional two yea rsyears unless either the tax accounting method elected is retroactively repealed or the InternalInter nal Revenue Service denies the entire deduction related to the tax accounting method. Entergy Louisiana agreed to credit ratepayers additional amounts unless the tax accounting election is not sustained if it is challenged. During 2013-2031, Entergy Louisiana and its ratepayers would share the remaining benefits of this tax accounting election.
Investing Activities
20022004 Compared to 20012003
Net cash used in investing activities decreased by $836 million in 20022004 primarily due to the following:
Partially offsetting$50 million for other regulatory investments related to fuel cost under-recovery. See Note 1 to the decrease in net cash used in investing activities were the following:
20012003 Compared to 20002002
Net cash used in investing activities increased by $410in 2003 primarily due to the following:
net proceeds from sales of businesses in 2002.
Partially offsetting these uses of cash, contributionsapproximately $172 million of approximately $414 million in connection with the formation of Entergy-Koch in 2001.
Partially offsetting the increase in net cash used in investing activities were the following:
during 2003.
Financing Activities
20022004 Compared to 20012003
FinancingNet cash used in financing activities used $409increased in 2004 primarily due to the following:
Offsetting the factors that caused an increase in cash used in financing activities in 2004 were the following:
2003 Compared to 2002
Net cash used in financing activities increased in 2003 primarily due to:
to the following:
The items causing cash used to increase in 2003 were partially offset by the following:
In a non-cash transaction in 2002, long-term debt was reduced by $488 million in the sale of the Damhead Creek plant when the purchaser assumed the Damhead Creek debt along with the acquisition of the plant.
2001 Compared to 2000
Financing activities used cash in 2001 compared to providing a small amount of cash in 2000 primarily due to:
Partially offsetting the increase in cash used in 2001 were the following:
Significant Factors and Known Trends
Following are discussions of significant factors and known trends affecting Entergy's business, including rate regulation and fuel-cost recovery, federal regulation, market and credit risks, and nuclear matters.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that the domestic utility companies and System Energy charge for their services are an important item influencing Entergy's financial position, results of operations, and liquidity. These companies are closely regulated and the rates charged to their customers are determined in regulatory proceedings, except for a portion of Entergy Gulf States' operations. 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. The status of material retail rate proceedings areis summarized below and described in more detail in Note 2 to the consolidated financial statements.
Company |
| Authorized | Pending Proceedings/Events | |
Entergy Arkansas | 11.0% | No base rate cases are pending. Transition cost | ||
Entergy Gulf | 10.95% | Base rates | ||
Entergy Gulf | 11.1% |
| In December 2003, the LPSC | |
Entergy Louisiana | 9.7%-
|
| In January 2004, Entergy | |
Entergy Mississippi |
| 9.3%- |
| An annual formula rate plan is in place. |
Entergy New |
|
| The midpoint ROE of the electric and gas plans is 11.25%, with a target equity component of the capital structure of 42%. Entergy New Orleans made a formula rate plan filing in April 2004. The City Council ordered that electric and gas rates remain unchanged from levels set in 2003. Entergy New Orleans will file its formula rate plan for the year ended December 31, 2004 by May 1, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in | |
System Energy | 10.94% | ROE approved by July 2001 FERC order. No cases pending before FERC. |
(1) | Entergy Louisiana's formula rate plan expired with the 2001 test year. Under the expired formula, if Entergy Louisiana earned outside of the bandwidth range, rates would be adjusted on a prospective basis. If earnings were above the bandwidth range, rates would be reduced by 60 percent of the amount necessary to bring earnings down to the top of the bandwidth, and if earnings were below the bandwidth range, rates would be increased by 60 percent of the corresponding shortfall. |
(2) | Under Mississippi law and Entergy Mississippi's formula rate plan, if Entergy Mississippi's earned ROE is above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's rates are reduced by 50 percent of the difference between the earned ROE and the top of the bandwidth. In such circumstance, Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the point halfway between such earned ROE and the top of the bandwidth - - Entergy Mississippi's retail rates are set at that halfway-point ROE level. (Before the comparison is made of the earned ROE to the bandwidth, the bandwidth can be adjusted for performance measures by as much as 1%. Rates are adjusted pursuant to Entergy Mississippi's formula rate plan on a prospective basis only.) In the situation where Entergy Mississippi's earned ROE is not above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the top of the range-of-no-change at the top of the bandwidth. If earnings are below the bandwidth range, rates are increased by 50 percent of the difference between the earned ROE and the bottom of the bandwidth. Under the provisions of Entergy Mississippi's formula rate plan, each annual formula rate plan filing incorporates a revised calculation of the benchmark ROE. |
(3) | If Entergy New Orleans earns outside the bandwidth range, rates will be adjusted on a prospective basis. Under the gas formula rate plan, if earnings are above the bandwidth range, rates are reduced by 100 percent of the overage, and if below, increased by 100 percent of the shortfall. In addition, if the ROE falls between 11.5% and 12.25%, rates are reduced by 60 percent of the difference (between 11.5% and 12.25%), and if the ROE falls between 10.25% and 11%, rates are increased by 40 percent of the difference (between 10.25% and 11%). Under the electric formula rate plan, rates are adjusted accordingly by 100 percent of the amount of any overage or shortfall. Entergy New Orleans may earn up to 13.25% under the electric formula rate plan provided that the increase is caused by its share of energy cost savings under the generation performance-based recovery plan. |
In addition to the regulatory scrutiny connected with base rate proceedings, the domestic utility companies' fuel and purchased power costs recovered from customers are subject to regulatory scrutiny. The domestic utility companies' significant fuel and purchased power cost proceedings are described in Note 2 to the consolidated financial statements.
Federal Regulation
The FERC regulates wholesale rates (including Entergy intrasystem sales pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy's sales of capacity and energy from Grand Gulf 1 to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement.
System Agreement Litigation
The domestic utility companies historically have historically engaged in the coordinated planning, construction, and operation of generating and transmission facilities under the terms of an agreement called the System Agreement that has been approved by the FERC. Litigation involving the System Agreement has been initiatedis being pursued by the LPSC at both the FERC and City Council.before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies in their execution of the System Agreement, and seek support for local regulatory authority over System Agreement issues. Entergy believes that any changes inRegarding the allocation of costs would not have a material effect on Entergy's financial condition because any changes should result in similar rate changes for retail customers.proceeding at the LPSC, Entergy further believes that state and local regulators are pre-emptedpreempted by federal law from reviewing and deciding System Agreement issues for themselves. An unrelated case currently pending between the LPSC and Entergy Louisiana raisesraised the question of whether a state regulator is pre-emptedpreempted by federal law from reviewing and interpreting FERCF ERC rate schedules that are part of the System Agreement, and from subsequently enforcing that interpretation. The LPSC interpreted a System Agreement rate schedule in the unrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed.affirmed the LPSC's decision. In January 2003, the U.S. Supreme Court grantedruled in Entergy Louisiana's request for a writ of certiorari for purposes of reviewingfavor and reversed the decisiondecisions of the LPSC and the Louisiana Supreme Court.
In February 2004, a FERC ALJ issued an Initial Decision in the LPSC-initiated proceeding at the FERC. The Initial Decision decided some issues in favor of the relief sought by the LPSC, and decided some issues against the relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they would be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method.
If the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average. If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility compan ies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.
An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu duri ng the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:
| Average Annual | ||
(In Millions) | (In Millions) | ||
Entergy Arkansas | $154 to $281 | $215 | |
Entergy Gulf States | ($130) to ($15) | ($63) | |
Entergy Louisiana | ($199) to ($98) | ($141) | |
Entergy Mississippi | ($16) to $8 | $1 | |
Entergy New Orleans | ($17) to ($5) | ($12) |
Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. The timing of recovery of these costs in rates could be the subject of additional proceedings at the APSC and elsewhere, however, and a delay in full recovery of any increased allocation of production costs could result in additional financing requirements. Although the outcome and timing of the FERC, APSC, and other proceedings cannot predictbe predicted at this time, Entergy does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation.
In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC ALJ's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the ALJ's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; an d states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate.
In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the ALJ's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations.
In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Lou isiana, as well as the named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity.
Transmission
In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs.
In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations.
Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences.
In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the petition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005.
In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion of th e proposal currently scheduled for August 2005.
FERC's Supply Margin Assessment
In November 2001, FERC issued an order that established a new generation market power screen (called Supply Margin Assessment) for purposes of evaluating a utility's request for market-based rate authority, applied that new screen to the Entergy System (among others), determined that Entergy and the others failed the screen within their respective control areas, and ordered these utilities to implement certain mitigation measures as a condition to their continued ability to buy and sell at market-based rates. Among other things, the mitigation measures would require that Entergy transact at cost-based rates when it sells in the hourly wholesale market within its control area. Entergy requested rehearing of the order, and FERC delayed the implementation of certain mitigation measures until such time as it had the opportunity to consider the rehearing request. In June 2003, the FERC proposed and ultimately adopted new market behavior rules and tariff provisions that would be applied to any market-based sale. Entergy modified its market-based rate tariffs to reflect the new provisions but requested rehearing of FERC's order.
In April 2004, the FERC issued its Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy. In its April 2004 order, the FERC established a new interim generation market power analysis that will consider two indicative market power screens: (1) the pivotal supplier screen that is designed to measure an applicant's market power based on the applicant's share of uncommitted capacity at the time of the control area market's annual peak demand; and (2) the market share screen that is designed to evaluate an applicant's market share of uncommitted capacity on a seasonal basis. An integrated utility's native load obligation will be reflected in both screens; however, the proxy for native load obligation differs between the screens. For the uncommitted pivotal supplier screen, the proxy for native load is the average of the daily native load peaks during the month in which the annual peak load day occurs; for the uncommitted market share screen the prox y for native load is the minimum peak load day for each season. In the event an applicant fails either of these screens, there will be a rebuttable presumption that market power exists. The applicant will then have the opportunity to either: (1) submit a more detailed market power analysis that reflects market prices and measures an applicant's "economic capacity" and "available economic capacity" under the "delivered price test;" or (2) propose case-specific mitigation tailored to the applicant's specific circumstances or adopt cost-based rates for sales within the applicant's control area.
In its April 2004 order, the FERC also: (1) determined that transmission market power and the need to employ an independent entity to operate and administer an applicant's OASIS site is more properly considered in other proceedings, to the extent appropriate, and would not be considered in evaluating an applicant's generation market power for purposes of granting market-based rate authority; and (2) eliminated the exemption from the generation market power analysis for sales within an RTO/ISO that had approved market monitoring. Several parties, including Entergy, filed for rehearing of the April 2004 order. Among other things, Entergy argued that the market share screen is overly conservative and overstates vertically integrated utilities' ability to exercise market power.
In July 2004, the FERC issued an order on rehearing reaffirming the use of the pivotal supplier and market share screens and clarified certain instructions for performing such analysis. With regard to the delivered price test analysis, the FERC declined to make a determination on whether an applicant's native load obligations will be reflected when evaluating an applicant's generation market power, but instead indicated that it would evaluate the arguments of both the applicant and intervenors as to which measure (one with or without native load obligations) more accurately reflects market conditions. Entergy appealed the April 2004 and July 2004 orders to the United States Court of Appeals for the District of Columbia Circuit. In February 2005, the D.C. Circuit granted the FERC's motion to dismiss Entergy's appeal on the grounds that Entergy's claims were premature. The D.C. Circuit found that Entergy's petition was premature because the D.C. Circuit was not yet in a position to evalu ate the manner in which the FERC will apply its new market power tests or whether the tests will have adverse consequences for Entergy. Thus, the D.C. Circuit did not rule on the merits of Entergy's appeal.
Entergy filed with the FERC its generation market power analysis pursuant to the two indicative screens in August 2004. Entergy's analysis indicated that it passed the pivotal supplier screen for all relevant geographical regions, but failed the market share screen within its control area. At the same time, Entergy submitted the results of the delivered price test for Entergy, which indicate that Entergy does not have market power in any wholesale market when Entergy's native load obligations are reflected.
In December 2004, the FERC issued an order pursuant to Section 206 of the Federal Power Act: (1) finding that Entergy failed the market share screen; (2) indicating that the FERC is continuing to review the delivered price test analysis submitted by Entergy; (3) establishing a refund effective date for Entergy's market-based wholesale sales within its control area; and (4) indicating that the FERC believes that it can reach a decision concerning Entergy's market-based rate authority by the second quarter of 2005.
If the FERC were to revoke Entergy's or the domestic utility companies' market-based rate authority for wholesale sales within the Entergy control area, these entities would be limited to making wholesale sales pursuant to cost-based rate schedules approved by the FERC. The wholesale sales of the domestic utility companies and their affiliates, including Entergy's non-nuclear wholesale assets business, within the Entergy control area could either be cost-justified or are of such a limited amount that management does not believe that the revocation of their market-based rate authority would have a material effect on the financial results of Entergy. Because Entergy believes that it does not possess market power and that the FERC's tests are flawed, Entergy intends to vigorously defend its market-based rate authority.
The FERC has also initiated a rulemaking proceeding to address, among other things, whether the FERC should retain or modify its existing four-prong test for evaluating market-based rate applications (i.e., whether the applicant has generation or transmission market power, whether the applicant can erect barriers to entry, and whether there are affiliate abuse or reciprocal dealing concerns), and whether the FERC should adopt different approaches for affiliate transactions. The FERC has held a series of technical conferences to discuss these issues. Additionally, in February 2005 the FERC adopted revised reporting obligations for changes in status that apply to public utilities authorized to make wholesale sales of power at market-based rates. The FERC determined to replace the current triennial reporting requirement with more detailed guidelines concerning the types of events that will trigger a reporting obligation and the timing or outcomeand format for such reports. The new rules will become part of all existing market-based rate tariffs during March 2005.
Interconnection Orders
The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy.
In addition, Entergy Louisiana was recently directed, effective as of March 2001, to provide transmission credits, with interest, associated with a specific generator that asserted to the FERC that it retained in its contract for interconnection a right to execute the latest form of Entergy's standard interconnection agreement in lieu of its existing contract, which thereby would apply FERC's most recent interconnection cost allocation policies to that generator. Following an ALJ's Initial Decision and an order affirming such decision by FERC, approximately $15 million in expenses and tax obligations previously paid by the generator have been ordered refunded in the form of transmission credits, to be utilized over time and applied to Entergy transmission service bills incurred after March 2001. Entergy has sought rehearing of the FERC's order.
To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these proceedings.costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators.
Available Flowgate Capacity Proceeding
On December 17, 2004, the FERC issued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised in a FERC audit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC pro gram, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory.
Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy.
Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the AFC proceeding is currently scheduled to commence in August 2005.
Federal Legislation
Federal legislation intended to facilitate wholesale competition in the electric power industry has been seriously considered by the United States Congress for the past several years. In the last Congress, both the House and Senate passed separate versions of comprehensive energy legislation, negotiated a conference package, and fell two votes short of bringing the conferenced bill up for a vote in the Senate. The bill contained electricity provisions that would, among other things, allow for participant funding of transmission interconnections and upgrades, repeal PUHCA, repeal or modify PURPA, enact a mechanism for establishing enforceable reliability standards, provide the FERC with new authority over utility mergers and acquisitions, and codify the FERC's authority over market-based rates. It is expected that the United States House and Senate will again craft and consider energy legislation in the 109th Congr ess.
Market and Credit Risks
Market risk is the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Entergy is exposed to the following significant market risks:
Entergy is 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. Where it is a significant consideration, counterparty credit risk is addressed in the discussions that follow.
Commodity Price Risk
Power Generation
The sale of electricity from the power generation plants owned by Entergy's Non-Utility Nuclear business and Energy Commodity Services, unless otherwise contracted, is subject to the fluctuation of market power prices. Entergy's Non-Utility Nuclear business has entered into power purchase agreements (PPAs)PPAs and other contracts to sell the power produced by its power plants at prices established in the PPAs. Entergy continues to pursue opportunities to extend the existing PPAs and to enter into new PPAs with other parties. Following is a summary of the amount of Entergy'sthe Non-Utility Nuclear business' and Energy Commodity Services' output that is currently sold forward under physical or financial contracts at fixed prices:
2003 |
| 2004 |
| 2005 |
| 2006 |
| 2007 | |
Non-Utility Nuclear: |
|
|
|
|
|
|
|
|
|
% of planned generation sold forward | 100% |
| 92% |
| 25% |
| 11% |
| 9% |
Planned generation (GWh) | 33,317 |
| 33,361 |
| 34,006 |
| 34,613 |
| 34,300 |
Average price per MWh | $37.06 |
| $38.36 |
| $35.94 |
| $31.97 |
| $31.42 |
Energy Commodity Services: |
|
|
|
|
|
|
|
|
|
% of planned generation sold forward | 38% |
| 18% |
| 22% |
| 19% |
| 21% |
Planned generation (GWh) | 3,124 |
| 3,249 |
| 3,820 |
| 3,494 |
| 3,618 |
Contracted spark spread per MWh | $11.70 |
| $10.63 |
| $10.62 |
| $9.69 |
| $9.68 |
2005 | 2006 | 2007 | 2008 | 2009 | |||||||
Non-Utility Nuclear: | |||||||||||
Percent of planned generation sold forward: | |||||||||||
Unit-contingent | 36% | 20% | 17% | 1% | 0% | ||||||
Unit-contingent with availability guarantees | 54% | 52% | 38% | 25% | 0% | ||||||
Firm liquidated damages | 4% | 4% | 2% | 0% | 0% | ||||||
Total | 94% | 76% | 57% | 26% | 0% | ||||||
Planned generation (TWh) | 34 | 35 | 34 | 34 | 35 | ||||||
Average contracted price per MWh | $39 | $41 | $42 | $44 | N/A |
The Vermont Yankee acquisition included a 10-year PPA under which the former owners will buy the power produced by the plant, which is through the expiration in 2012 of the current operating license for the plant. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward annually,monthly, beginning in 2006,November 2005, if power market prices drop below the PPA prices. Accordingly, because the price is not fixed, the table above does not report power from that plant as sold forward after November 2005.
Under the PPAsA sale of power on a unit contingent basis coupled with NYPAan availability guarantee provides for the outputpayment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power from Indian Point 3as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. To date, Entergy has not incurred any payment obligation to any power purchaser pursuant to an availability guarantee. All of Entergy's outstanding availability guarantees provide for dollar limits on Entergy's maximum liability under such guarantees.
Some of the agreements to sell the power produced by Entergy's Non-Utility Nuclear power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary may be required to provide collateral based upon the difference between the current market and FitzPatrick,contracted power prices in the regions where the Non-Utility Nuclear business is obligatedsells its power. The primary form of the collateral to produce atsatisfy these requirements would be an average capacity factorEntergy Corporation guaranty. Cash and letters of 85% with a financial true-up payment to NYPA should NYPA's cost to purchase power due to an output shortfall be higher than the PPAs' price. The calculationcredit are also acceptable forms of any true-up payments iscollateral. At December 31, 2004, based on two two-year periods. Forpower prices at that time, Entergy had in place as collateral $545.5 million of Entergy Corporation guarantees and $47.5 million of letters of credit. In the first period, which ran through November 20, 2002, Indian Point 3 and FitzPatrick operated at 95% and 97%, respectively,event of a decrease in Entergy Corporation's credit rating to specified levels below investment grade, Entergy may be required to replace Entergy Corporation guarantees with cash or letters of c redit under the true-up formula. Credits of up to 5% reflecting period one generation above 85% can be used to offset any output shortfalls in the second period, which runs through theendsome of the PPAsagreements.
In addition to selling the power produced by its plants, the Non-Utility Nuclear business sells installed capacity to load-serving distribution companies in order for those companies to meet requirements placed on them by the ISO in their area. Following is a summary of the amount of the Non-Utility Nuclear business' installed capacity that is currently sold forward, and the blended amount of the Non-Utility Nuclear business' planned generation output and installed capacity that is currently sold forward:
2005 | 2006 | 2007 | 2008 | 2009 | |||||||
Non-Utility Nuclear: | |||||||||||
Percent of capacity sold forward: | |||||||||||
Bundled capacity and energy contracts | 13% | 13% | 13% | 13% | 13% | ||||||
Capacity contracts | 58% | 67% | 36% | 22% | 10% | ||||||
Total | 71% | 80% | 49% | 35% | 23% | ||||||
Planned net MW in operation | 4,155 | 4,200 | 4,200 | 4,200 | 4,200 | ||||||
Average capacity contract price per kW per month | $1.2 | $1.1 | $1.1 | $1.0 | $0.9 | ||||||
Blended Capacity and Energy (based on revenues) | |||||||||||
% of planned generation and capacity sold forward | 93% | 87% | 65% | 36% | 12% | ||||||
Average contract revenue per MWh | $40 | $42 | $43 | $44 | $43 |
As of December 31, 2004.
2004, approximately 99% of Entergy's counterparties to Non-Utility Nuclear's energy and capacity contracts have investment grade credit ratings.
Following is a summary of the amount of Energy Commodity Services' output and installed capacity that is currently sold forward under physical or financial contracts at fixed prices:
2005 | 2006 | 2007 | 2008 | 2009 | ||||||
Energy Commodity Services: | ||||||||||
Capacity | ||||||||||
Planned MW in operation | 1,578 | 1,578 | 1,578 | 1,578 | 1,578 | |||||
% of capacity sold forward | 44% | 33% | 29% | 29% | 19% | |||||
Energy | ||||||||||
Planned generation (TWh) | 3 | 3 | 3 | 3 | 4 | |||||
% of planned generation sold forward | 69% | 54% | 45% | 45% | 35% | |||||
Blended Capacity and Energy (based on revenues) | ||||||||||
% of planned energy and capacity sold forward | 63% | 44% | 38% | 39% | 22% | |||||
Average contract revenue per MWh | $24 | $24 | $28 | $28 | $21 |
Entergy continually monitors industry trends in order to determine whether asset impairments or other losses could result from a decline in value, or cancellation, of merchant power projects, and records provisions for impairments and losses accordingly.
Marketing and Trading
The earnings As discussed in "Results of Entergy's Energy Commodity Services segment are exposed to commodity price market risks primarily through Entergy's 50%-owned, unconsolidated investmentOperations" above, in Entergy-Koch. Entergy-Koch Trading (EKT) uses value-at-risk models as one measure2004 Entergy determined that the value of the market risk of a loss in fair value for EKT's natural gas andWarren power trading portfolio. Actual future gains and losses in portfolios will differ from those estimated based upon actual fluctuations in market rates, operating exposures, and the timing thereof, and changes in the portfolio of derivative financial instruments during the year.
To manage its portfolio, EKT enters into various derivative and contractual transactions in accordance with the policy approvedplant owned by the trading committee ofnon-nuclear wholesale assets business was impaired, and recorded the governing board of Entergy-Koch. The trading portfolio consists of physical and financial natural gas and power as well as other energy and weather-related contracts. These contracts take many forms, including futures, forwards, swaps, and options.
Characteristics of EKT's value-at-risk method andappropriate provision for the use of that method are as follows:
Value-at-risk is used in conjunction with stress testing, position reporting, and profit and loss reporting in order to measure and control the risk inherent in the trading and mark-to-market portfolios.
EKT estimates its value-at-risk using a model based on J.P. Morgan's Risk Metrics methodology combined with a Monte Carlo simulation approach.
EKT estimates its daily value-at-risk for natural gas and power using a 97.5% confidence level. EKT's daily value-at-risk is a measure that indicates that, if prices moved against the positions, the loss in neutralizing the portfolio would not be expected to exceed the calculated value-at-risk.
EKT seeks to limit the daily value-at-risk on any given day to a certain dollar amount approved by the trading committee.
EKT's value-at-risk measures, which it calls Daily Earnings at Risk (DE@R), for its trading portfolio were as follows:
|
| 2002 |
| 2001 |
|
|
|
|
|
|
|
DE@R at end of period |
| $15.2 million |
| $5.5 million |
|
Average DE@R for the period |
| $10.8 million |
| $6.4 million |
|
EKT's DE@R increased in 2002 compared to 2001 as a result of an increase in the size of the position held and an increase in the volatility of natural gas prices in the latter part of the year.
For all derivative and contractual transactions, EKT is exposed to losses in the event of nonperformance by counterparties to these transactions. Relevant considerations when assessing EKT's credit risk exposure include:
EKT's operations are primarily concentrated in the energy industry.
EKT's trade receivables and other financial instruments are predominantly with energy, utility, and financial services related companies, as well as other trading companies in the U.S., UK, and Western Europe.
EKT maintains credit policies, which its management believes minimize overall credit risk.
Prospective and existing customers are reviewed for creditworthiness based upon pre-established standards, with customers not meeting minimum standards providing various secured payment terms, including the posting of cash collateral.
EKT also has master netting agreements in place. These agreements allow EKT to offset cash and non-cash gains and losses arising from derivative instruments with the same counterparty. EKT's policy is to have such master netting agreements in place with significant counterparties.
Based on EKT's policies, risk exposures, and valuation adjustments related to credit, EKT does not anticipate a material adverse effect on its financial position as a result of counterparty nonperformance. As of December 31, 2002 approximately 86% of EKT's counterparty credit exposure is associated with companies that have at least investment grade credit ratings.
Following are EKT's mark-to-market assets (liabilities) and the period within which the assets (liabilities) would be realized (paid) in cash if they are held to maturity and market prices are unchanged:
|
2003
2004
2005 - 2006
Total
(In Millions)
Prices actively quoted
$45.0
$45.1
($20.2)
$69.9
Prices provided by other sources
24.4
3.3
1.9
29.6
Prices based on models
(13.3)
1.3
3.4
(8.6)
Total
$56.1
$49.7
($14.9)
$90.9
Following is a roll-forward of the change in the fair value of EKT's mark-to-market contracts during 2002 (in millions):
2002
Fair value of contracts at December 31, 2001
$106
Fair value of contracts settled during the year
(347)
Initial recorded value of new contracts entered into during the year
7
Net option premiums received during the year
(78)
Change in fair value of contracts attributable to market movements during the year
403
Net change in contracts outstanding during the year
(15)
Fair value of contracts at December 31, 2002
$91
loss.
Foreign Currency Exchange Rate Risk
Entergy Gulf States, System Fuels, and Entergy's Non-Utility Nuclear business enter into foreign currency forward contracts to hedge the Euro-denominated payments due under certain purchase contracts. The notional amounts of the foreign currency forward contracts are 249.595.5 million Euro and the forward currency rates range from .8624.8641 to .9664.1.33020. The maturities of these forward contracts depend on the purchase contract payment dates and range in time from January 20032005 to January 2007. The mark-to-market valuation of the forward contracts at December 31, 20022004 was a net asset of $38.9$28.1 million. The counterparty banks obligated on 233.0 million Euro of the notional amount of these agreements are rated by Standard & Poor's Rating Services at AA on their senior debt obligations as of December 31, 2002. The counterparty bank obligated on 16.5 million Euro of the notional amount of these agreements is rated by Standard & Poor's Rating Services at A+ on its senior debt obligations as of December 31, 2002.2004.
Interest Rate and Equity Price Risk - Decommissioning Trust Funds
9; Entergy's nuclear decommissioning trust funds are exposed to fluctuations in equity prices and interest rates. The NRC requires Entergy to maintain trusts to fund the costs of decommissioning ANO 1, ANO 2, River Bend, Waterford 3, Grand Gulf, 1, Pilgrim, Indian Point 1 and 2, and Vermont Yankee (NYPA currently retains the decommissioning trusts and liabilities for Indian Point 3 and FitzPatrick). The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that exposure of the various funds to market fluctuations will not affect theEntergy's financial results of operations foras it relates to the ANO 1 and 2, River Bend, Grand Gulf, 1, and Waterford 3 trust funds because of the application of regulatory accounting principles. The Pilgrim, Indian Point 1 and 2, and Vermont Yankee trust funds collectively hold approximately $841 mi llion$952 million of fixed-rate, fixed-income securities as of December 31, 2002.2004. These securities have an average couponcoup on rate of approximately 6.0%5.4%, an average duration of approximately 5.2 years, and an average maturity of approximately 8.37.9 years. The Pilgrim, Indian Point 1 and 2, and Vermont Yankee trust funds also collectively hold equity securities worth approximately $358$450 million as of December 31, 2002.2004. These securities are generally held in funds that are designed to approximate or somewhat exceed the return of the Standard & Poor's 500 Index, and a relatively small percentage of the securities are held in a fund intended to replicate the return of the Wilshire 4500 Index. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 915 to the consolidated financial statements.
Utility Restructuring
Major changes are occurring in the wholesale and retail electric utility business, including in the electric transmission business. In Entergy's U.S. Utility service territory, movement to retail competition either has not occurred, has been significantly delayed, or has been abandoned. At FERC, the pace of restructuring at the wholesale level has begun but has also been delayed. It is too early to predict the ultimate effects of changes in U.S. energy markets. Restructuring issues are complex and are continually affected by events at the national, regional, state, and local levels. These changes may result, in the long-term, in fundamental changes in the way traditional integrated utilities and holding company systems, like the Entergy system, conduct their business. Some of these changes may be positive for Entergy, while others may not be.
In the long-term, these changes may result in increased costs associated with utility unbundling of services or functions and transitioning in new organizational structures and ways of conducting business. It is possible that the new organizational structures that may be required will result in lost economies of scale, less beneficial cost sharing arrangements within utility holding company systems, and, in some cases, greater difficulty and cost in accessing capital. Furthermore, these changes could result in early refinancing of debt, the reorganization of debt, or other obligations between newly formed companies and Entergy. As a result of federal and state "codes of conduct" and affiliate transaction rules, adopted as part of restructuring, new non-utility affiliates in Entergy's system may be precluded from, or limited in, doing business with affiliated electric market participants, or have prices set at the lower of cost or market. In addition, regulators may impose limits on (price caps), rather than have the market set, wholesale energy prices. There are a number of other changes that may result from electric business competition and unbundling, including, but not limited to, changes to labor relations, management and staffing, structure of operations, environmental compliance responsibility, and other aspects of the utility business.
Transmission
In 2000, FERC issued an order encouraging electric utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations). These organizations were to be operational by December 15, 2001, but delays have occurred as utility companies and federal and state regulators work to resolve various issues related to the establishment of RTOs.
Entergy's domestic utility companies are participating with other transmission owners within the southeastern United States to establish an RTO, the proposed SeTrans RTO. In October 2002, FERC issued a declaratory order approving certain central aspects of the SeTrans RTO proposal. Because of retail regulatory concerns regarding RTOs, certain retail regulators ordered the domestic utility companies to evaluate the costs and benefits associated with establishing such entities. The Southeastern Association of Regulatory Utility Commissions commissioned a separate cost-benefit study that was intended to evaluate similar issues for the entire Southeast, including the region that would be covered by the proposed SeTrans RTO. Both cost-benefit studies concluded that an RTO, if properly structured (e.g., locational marginal prices to manage congestion, participant funding for expansion cost), can provide benef its for the customers of the domestic utility companies. However, a number of important issues relating to the design of the transmission tariffs and the terms of the proposed SeTrans RTO remain to be finalized and approved by regulators. Until this process is complete, Entergy cannot predict the impact that RTO developments will have on its financial condition, results of operations, or liquidity. Entergy does not expect the SeTrans RTO to become operational before the end of 2004.
Retail
Only in the Texas portion of Entergy Gulf States' service territory has there been significant retail open access activity, but implementation has been delayed in that territory. Entergy does not expect that retail open access within the context of a functional FERC-approved RTO is likely to begin for Entergy Gulf States before the end of 2004. Entergy Gulf States has recently filed a proposal with the PUCT for an interim solution to begin retail open access on January 1, 2004, or otherwise delay retail open access until at least 2007. While the PUCT has approved a basic business separation plan for Entergy Gulf States in Texas, several other proceedings necessary to implement retail open access are still pending in Texas. In addition, the LPSC has not approved certain matters needed for retail open access to begin in Texas. Delay in the start of retail open access may delay or jeopardize th e regulatory approvals needed to comply with Texas, Louisiana, and federal law and may therefore have an adverse effect on Entergy. Retail open access legislation has not been enacted in the other jurisdictions in Entergy's service territory, except for in Arkansas, where it was recently repealed.
Nuclear Matters
The domestic utility companies, System Energy, and Non-Utility Nuclear subsidiaries own and operate through affiliates, ten nuclear power generating units.units and the shutdown Indian Point 1 nuclear reactor. Entergy 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, 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 shutdownshut-down of any of Entergy's nuclear plants, Entergy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
Concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel, in particular in the areanortheastern United States, which is where Entergy's Indian Pointthe Non-Utility Nuclear units are located, which are discussed in more detail below.located. These concerns have led to, and are expected to continue to lead to, various proposals to federal regulators as well as governing bodies in some localities where Entergy owns nuclear plants for legislative and regulatory changes that could lead to the shut downshut-down of nuclear units, denial of license extension applications, municipalization of nuclear units, restrictions on nuclear units as a result of unavailability of sites for nuclear fuel disposal, or other adverse effects on owning and operating nuclear power plants. Entergy believes that its generating units are in compliance with NRC requirements and intends toEntergy vigorously respondresponds to these concerns and proposals.
Groups of concerned citizens and local public officials have raised concerns about safety issues associated with Entergy's Indian Point power plants located in New York. They argue that Indian Point's security measures and emergency plans do not provide reasonable assurance to protect the public health and safety. The NRC has legal jurisdiction over these matters. In a decision that became final on December 13, 2002, the NRC denied a petition filed by Riverkeeper, Inc. asking the NRC to order Entergy to suspend operations, revoke the operating license or adopt other measures, including a temporary shutdown of Indian Point 2 and Indian Point 3. The NRC noted that after September 11, 2001, it ordered enhanced security measures at all nuclear facilities and found that as a result of the collective measures taken since September 11, 2001, the security at Indian Point provides adequate protection of public health and safety. The NRC further found that the existing emergency response plans are flexible enough to respond to a wide variety of adverse conditions, including a terrorist attack, and that the current spent fuel storage system adequately protects the public health and safety. Riverkeeper has petitioned the United States Court of Appeals for the Second Circuit for review of this final action of the NRC. In order to prevail, Riverkeeper must show that the NRC has violated the Atomic Energy Act, abused its discretion, and has completely abdicated its statutory duty regarding this matter. Entergy believes that the action of the NRC was based upon a thorough and thoughtful review of the law and the facts and that the NRC decision will be affirmed by the court.
In addition, certain concerns are being raised regarding the adequacy of the emergency response plans for Indian Point. These matters initially must be reviewed by the Federal Emergency Management Agency ("FEMA"). Jurisdiction as to the overall adequacy of emergency planning and preparedness for Indian Point lies with the NRC. Entergy believes that the emergency response plans for Indian Point are in compliance with NRC requirements and thus adequately protect public health and safety.
A January 2003 consultant's draft report prepared for the State of New York to review emergency preparedness around Indian Point concluded generically that federal emergency planning regulations and guidelines were not adequate to cope with new threats of terrorism. This conclusion was based in part on the view that radiation releases, including those caused by terrorist events, could be faster and larger than those for which the emergency plans were designed. As a result, even if emergency planning for Indian Point were to comply fully with all federal regulations and guidelines, this criticism in the report would stand. There were other plant-specific criticisms in the report. For these reasons, the report concluded that emergency planning for Indian Point is not adequate at this time. In March 2003, a final report was issued which reached similar conclusions. The NRC in reacting to the draft report observed that current emergency plans are already designed to cope with significant radiation releases regardless of cause and stated that it was reviewing the draft report's findings to determine if the emergency plans require modification.
A February 2003, report issued by FEMA Region II evaluated a September 2002 exercise and related activities for the ten-mile emergency planning zone around Indian Point. The report identified no deficiencies with respect to the exercise. The report did conclude that in the absence of corrected and updated state and county plans, FEMA could not provide "reasonable assurance" that appropriate measures can be taken in the event of a radiological emergency. If the state provided this information and a schedule of corrective actions by May 2, 2003, the report stated that FEMA would reevaluate this decision. If corrective actions are not taken, FEMA Region II indicated that (a) it would notify FEMA headquarters that assurance cannot be provided regarding the adequacy of the plans to protect the health and safety of the public and (b) FEMA headquarters would notify the NRC and Governor of New York of the same. The notice from FEMA to the NRC would begin corrective action periods. If corrective action were not taken by the end of these periods, the NRC must determine whether there is reasonable assurance regarding the adequacy of plans to protect the health and safety of the public. If the NRC determines that there is not such assurance, it has the authority to order the Indian Point plants to shut down.
Entergy is interacting with New York state and county officials, FEMA, NRC and other federal agencies to make additional improvements to the emergency response plans that may be warranted and to further assure them as to the adequacy of the plans. Entergy will vigorously oppose all attempts to shut down the Indian Point plants.
The Westchester County Executive announced his proposal to acquire Indian Point by purchase or condemnation and has announced an intention to commission a feasibility study regarding municipalization of Indian Point. At this time, considering the financial and legal impediments that the County would face in implementing this proposal, it is improbable that the County could condemn or municipalize Indian Point.
Litigation
Entergy and its subsidiaries are involved in the ordinary course of business in a substantial amount of employment, commercial, asbestos, hazardous material, and other environmental and rate-related proceedings and litigation, a significant portion of which originates in Louisiana, Mississippi, and Texas.litigation. Entergy uses legal and appropriate means to contest vigorously litigation threatened or filed against it, but the litigation environment in these states poses a significant business risk.
risk to Entergy.
Critical Accounting Estimates
The preparation of Entergy's financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical accounting estimates because they are based on assumptions and measurements that involve an unusuala high degree of uncertainty, and there is the potential that differentfor future changes in the assumptions and measurements that could produce estimates that are significantly different than those recorded inwould have a material effect on the presentation of Entergy's financial statements.position or results of operations.
Nuclear Decommissioning Costs
Entergy owns a significant number of nuclear generation facilities in both its U.S. Utility and Non-Utility Nuclear business units. Regulations require that these facilities be decommissionedEntergy to decommission its nuclear power plants after theeach facility is taken out of service, and funds aremoney is collected and deposited in trust funds during the facilities' operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facilities. Note 9 to the consolidated financial statements contains details regarding Entergy's most recent studies and the obligations recorded by Entergy related to decommissioning. The following key assumptions have a significant effect on these estimates:
Cost Escalation Factors - Entergy's decommissioning revenue requirement studies include an assumption that decommissioning costs will escalate over present cost levels by annual factors ranging from 3.0%approximately CPI-U to 5.5%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11.0%.
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. The expiration of the plant's operating license is typically used for this purpose, or an assumption could be made that the plant will be relicensed and operate for some time beyond the original license term. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore" status for later decommissioning, as permitted by applicable regulations.
While the impacteffect of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can significantly decreasepossibly change the present value of these obligations.
Spent Fuel Disposal - Federal regulations require the Department of EnergyDOE to provide a permanent repository for the storage of spent nuclear fuel, and recent legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. However, untilUntil this 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 can have a significant impacteffect (as much as 16% of estimated decommissioning costs). Entergy's decommissioning studies include cost estimates for spent fuel storage, except for ANO 1 and 2. A study including these costs for ANO 1 and 2 is currently underway.storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
Technology and Regulation - To date, there is limited practical experience in the U.S.United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant impacteffect on cost estimates. The impacteffect of these potential changes is not presently determinable. Entergy's decommissioning cost studies assume current technologies and regulations.
The implications of these estimates vary significantly between Entergy's U.S. Utility and Non-Utility Nuclear businesses. Separate discussions of these implications by business unit follow.
U.S. Utility
Entergy collects substantially all of the projected costs of decommissioning the nuclear facilities in its U.S. Utility business unit through rates charged to customers, except for portions of River Bend, which is discussed in more detail below. The amounts collected through rates, which are based upon decommissioning cost studies, are deposited in decommissioning trust funds. These collections plus earnings on the trust fund investments are generally estimated to be sufficient to fund the future decommissioning costs. Accordingly, U.S. Utility decommissioning costs have no impact on Entergy's earnings, as accrued costs are offset by earnings on trust funds and collections from customers. For the U.S. Utility segment, if decommissioning cost study estimates were changed and approved by regulators, collections from customers would also change.
Approximately half of River Bend is not currently subject to cost-based ratemaking. When Entergy Gulf States obtained the 30% share of River Bend formerly owned by Cajun, Entergy Gulf States obtained decommissioning trust funds of $132 million, which have since grown to almost $150 million. Entergy Gulf States believes that these funds will be sufficient to cover the costs of decommissioning this portion of River Bend, and no further collections or deposits are being made for these costs. Additionally, under the Deregulated Asset Plan in the Louisiana jurisdiction of Entergy Gulf States, a portion of River Bend (approximately 16% of its total capacity) is excluded from rate base, and no amounts have been or are being collected for decommissioning for this portion of the plant.
In the U.S. Utility business unit, the obligations recorded by Entergy for decommissioning are classified either as a component of accumulated depreciation (ANO 1 and 2, Waterford 3, and the regulated portion of River Bend) or as a deferred credit (System Energy and the nonregulated portion of River Bend) in the line item entitled "Decommissioning." The amounts recorded for these obligations are comprised of collections from customers and earnings on the trust funds. The classification and recording of these obligations will change with the implementation of SFAS 143, which is discussed in more detail below.
Non-Utility Nuclear
In conjunction with the purchase of Entergy's Non-Utility Nuclear facilities, Entergy assumed the decommissioning obligations and received the related decommissioning trust funds (except for the NYPA acquisition, in which NYPA retained the decommissioning obligations for the Indian Point 3 and FitzPatrick units). Based on decommissioning cost studies and expected plant operation lives, Entergy believes that the amounts in the trust funds will be sufficient to fund future decommissioning costs without additional deposits from Entergy.
As Entergy has assumed these decommissioning obligations without any further external source of funding, changes in estimates of decommissioning costs for these units will have a direct impact on Entergy's financial position and results of operations. Upon purchase of the plants, Entergy recorded obligations that were equivalent to the amounts initially received in the decommissioning trust funds. These obligations are recorded as deferred credits in the line item entitled "Decommissioning." These obligations are accreted at implicit discount rates that are determined based upon the estimated costs of decommissioning. The accounting for these obligations will change with the implementation of SFAS 143, which is discussed in more detail below.
SFAS 143
Entergy implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy's asset retirement obligations, and the measurement and recording of Entergy's decommissioning obligations outlined above will changechanged significantly with the implementation of SFAS 143. The most significant differences in the measurement of these obligations are outlined below:
Recording of full obligation - SFAS 143 requires that the fair value of an asset retirement obligation be recorded when it is incurred. This will causecaused the recorded decommissioning obligation in Entergy's U.S. Utility business to increase significantly, as Entergy had previously only recorded this obligation as the related costs were collected from customers, and as earnings were recorded on the related trust funds.
Fair value approach - SFAS 143 requires that these obligations be measured using a fair value approach. Among other things, this entails the assumption that the costs will be incurred by a third party and will therefore include appropriate profit margins and risk premiums. Entergy's decommissioning studies to date havehad been based on Entergy performing the work, and havedid not includedinclude any such margins or premiums. Inclusion of these items increases cost estimates.
Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted, risk-free rate. This will result in significant decreases in Entergy's decommissioning obligations in the Non-Utility Nuclear business, as this discount rate is higher than the implicit rates utilized by Entergy in accounting for these obligations through December 31, 2002.
The net effect of implementing this standard, to the extent that it was not recorded as regulatory assets or liabilities, will be recognized as a cumulative effect of an accounting change in Entergy's 2003 statement of income. Implementation will have the following effect on Entergy's financial statements:
The net effectstatements of implementing this standardSFAS 143 for the U.S. Utility and Non-Utility Nuclear businesses follows:
For the Non-Utility Nuclear business, the implementation of SFAS 143 is expected to resultin 2003 resulted in a decrease in liabilities of $595 million due to reductions in 2003decommissioning liabilities, a decrease in assets of approximately $520$340 million, including a decrease in electric plant in service of $315 million, and an increase in earnings of $155 million net-of-tax as a result of the discounting methodology required by SFAS 143. Assets are expected to decrease in 2003 by approximately $360 million. Earnings are expected to increase by approximately $160 million as a result of a one-time cumulative effect of accounting change.
Also, Entergy expectsbeginning in 2003 Entergy's earnings for the Non-Utility Nuclear business tohave an increase by approximately $15of $18 million after-tax over the current level because of the change in accretion of the liability and depreciation of the associated costs.adjusted plant costs from the 2002 levels. This effect will gradually decrease over future years.years as the accretion of the liability increases. Management expects that applying SFAS 143 post-implementation will have a minimal effect on ongoing earnings for the U.S. Utility business.
In the first quarter of 2004, Entergy Arkansas recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for ANO 1 and 2 as a result of revised decommissioning costs and changes in assumptions regarding the timing of when the decommissioning of the plants will begin. The revised estimate resulted in a $107.7 million reduction in its decommissioning liability, along with a $19.5 million reduction in utility plant and an $88.2 million reduction in the related regulatory asset.
In the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected an expected life extension for the plant. The revised estimate resulted in a $116.8 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $40.1 million reduction in the related regulatory asset, and a regulatory liability of $17.7 million. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million.
In the third quarter of 2004, Entergy's Non-Utility Nuclear business recorded a reduction of $20.3 million in its decommissioning cost liability to reflect changes in assumptions regarding the timing of when the decommissioning of a plant will begin. Entergy considered the assumptions as part of recent studies evaluating the economic effect of the plant in its region. The revised estimate resulted in miscellaneous income of $20.3 million, reflecting the excess of the reduction in the liability over the amount of undepreciated asset retirement cost recorded at the time of adoption of SFAS 143.
Unbilled Revenue
As discussed in Note 1 to the consolidated 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, including fuel price. 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 including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptio ns regarding price such as the fuel cost recovery mechanism.
Impairment of Long-lived Assets
Entergy has significant investments in long-lived assets in all of its segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment whenever there are indications that impairments may exist. This evaluation involves a significant degree of estimation and uncertainty, and these estimates are particularly important in Entergy's U.S. Utility and Energy Commodity Services segments. In the U.S. Utility segment, portions of River Bend and Grand Gulf are not included in rate base, which could reduce the revenue that would otherwise be recovered for the applicable portions of those units' generation. In the Energy Commodity Services segment, Entergy's investments in merchant generation assets are subject to impairment if adverse market conditions arise.
In order to determine if Entergy should recognize an impairment of a long-lived asset that is to be held and used, accounting standards require that the sum of the expected undiscounted future cash flows from the asset be compared to the asset's carrying value. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded; if such cash flows are less than the carrying value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.
These estimates are based on a number of key assumptions, including:
Future power and fuel prices - Electricity and gas prices have been very volatile in recent years, and this volatility is expected to continue for some time.continue. This volatility necessarily increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows. There is currently an oversupply of electricity throughout the U.S., including much of Entergy's service territory, and it is necessary to project economic growth and other macroeconomic factors in order to project when this oversupply will cease and prices will rise. Similarly, gas prices have been volatile as a result of recent fluctuations in both supply and demand, and projecting future trends in these prices is difficult.
Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, the market for such assets is volatile and the value of individual assets is impacted by factors unique to those assets.
Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant impact on operations could cause a significant change in these assumptions.
The carrying value of Entergy's nonregulated portions of River Bend and Grand Gulf approximates $1.2 billion at December 31, 2002. To date, Entergy's impairment tests have not required an impairment to be recorded for these assets.
Due to the oversupply of power that existed throughout the U.S. and the UK in 2002, and the resulting decreases in spark spreads, consistent with Entergy's point of view, Entergy's impairment tests indicated that a number of impairments were required to be recognized in 2002 in the Energy Commodity Services segment. These impairments, which were also accompanied by other charges related to the restructuring of Entergy's independent power business, are further detailed in Note 1211 to the consolidated financial statements.
Mark-to-market Accounting
As required by generally accepted accounting principles,In 2004, Entergy and Entergy-Koch mark-to-market commodity instruments held by them for trading and risk management purposes that are considered derivatives under SFAS 133 or energy trading contracts under EITF 98-10. Becauserecorded a charge of approximately $55 million ($36 million net-of-tax) as a result of an impairment of the significant estimates and uncertainties inherent in mark-to-market accounting, this method is considered a critical accounting estimate for the Energy Commodity Services segment. Examples of commodity instruments that are marked to market include:
commodity futures, options, swaps, and forwards that are expected to be net settled; and
power sales agreements that do not involve delivery of power from Entergy's power plants.
Conversely, commodity contracts that are not considered derivatives or energy trading contracts, generally because they involve physical delivery of a commodity to the purchaser, are not marked to market. Examples of commodity contracts that are not marked to market include:
the PPAs for Entergy's Non-Utility Nuclear plants;
capacity purchases and sales by the U.S. Utility companies; and
forward contracts that will result in physical delivery.
Fair value estimates of the commodity instrumentsWarren Power plant. Entergy concluded that are marked to market are made at discrete pointsthe value of the plant, which is owned in timethe non-nuclear wholesale assets business, was impaired. Entergy reached this conclusion based on relevant market information. Market quotes are usedvaluation studies prepared in determining fair value whenever they are available. When market quotes are not available (e.g., of a long-dated commodity contract), other information is used, including transactional data and internally developed models. Fair value estimates based on these other methodologies are necessarily subjective in nature and involve uncertainties and matters of significant judgment. These uncertainties include projections of macroeconomic trends and future commodity prices, including supply and demand levels and future price volatility. The impact of these uncertainties, however, is lessened by the relatively short-term nature of the mark-to-market positions held by Entergy and EKT.
In addition, the EITF reached a consensus to rescind Issue No. 98-10 effective January 1, 2003. Rescinding Issue No. 98-10 will result in some energy-related contracts being accounted for on an accrual basis that were previously accounted for on a mark-to-market basis. Contracts that meet the provisions of SFAS 133 to qualify as derivatives will be marked-to-market in accordanceconnection with the guidanceEntergy Asset Management stock sale discussed above in SFAS 133. Contracts such as capacity, transportation, storage, tolling, and full requirements contracts that are based on physical assets and do not meet the provisions"Results of SFAS 133 to qualify as derivatives will be accounted for using accrual accounting. Energy commodity inventories held by trading companies such as physical natural gas will be accounted for at the lower of cost or market. The adoption of the consensus will have minimal cumulative and ongoing earnings effects for Entergy's Energy Comm odity Services business.
Operations."
Pension and Other Postretirement Benefits
Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 1110 to the consolidated financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate for the U.S. Utility and Non-Utility Nuclear segments.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
Discount rates used in determining the future benefit obligations;
Projected health care cost trend rates;
Expected long-term rate of return on plan assets; and
Rate of increase in future compensation levels.
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and poorworse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt.debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 7.5% in 2000 and 2001 to 6.75% in 2002.2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rates fromrate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to a range10% increase in 2001 of 8%health care costs in 2005 gradually decreasing to 5% toeach successive year, until it reaches a range4.5% annual increase in 2002 of 10% gradually decreasing to 4.5%.health care costs in 2011 and beyond.
In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities and 35%4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities and 49% fixed income securities. Based on recent market trends, Entergy decreasedreduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 9% in 2000 and 2001 to 8.75% for 2002.2002 and 2003 to 8.5% in 2004. The trend of reduced inflation caused Entergy to reduce its assumed rate of increase in future compensation levels from 4.6% in 2000 and 2001used to calculate benefit obligations was 3.25% in 2002.
2002, 2003, and 2004.
Cost Sensitivity
The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (in thousands):
|
| Change in Assumption |
| Impact on 2002 |
| Impact on Projected Benefit Obligation |
| Change in |
| Impact on 2004 |
| Impact on Projected |
|
| Increase/(Decrease) |
| Increase/(Decrease) | ||||||||
|
|
|
|
|
| |||||||
Discount rate |
| (0.25%) |
| $3,043 |
| $70,313 |
| (0.25%) |
| $10,268 |
| $94,903 |
Rate of return on plan assets |
| (0.25%) |
| $4,335 |
| - |
| (0.25%) |
| $4,388 |
| - |
Rate of increase in compensation |
| 0.25% |
| $2,376 |
| $15,556 |
| 0.25% |
| $4,928 |
| $29,134 |
The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (in thousands):
|
|
|
| Impact on 2002 Postretirement Benefit Cost |
| Impact on Accumulated Postretirement Benefit Obligation |
|
|
|
|
| Impact on Accumulated |
|
| Increase/(Decrease) |
| Increase/(Decrease) | ||||||||
|
|
|
|
|
| |||||||
Health care cost trend |
| 0.25% |
| $3,379 |
| $20,900 |
| 0.25% |
| $4,150 |
| $23,892 |
Discount rate |
| (0.25%) |
| $2,105 |
| $24,348 |
| (0.25%) |
| $2,715 |
| $28,719 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
In accordance with SFAS No. 87, "Employers' Accounting for Pensions," 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 cost 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, Entergy smoothesaccounts for the impacteffect of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87.
Costs and Funding
In 2002,2004, Entergy's total pension cost was $38 million and funding was $13$98 million. Taking into account asset performance and the changes made in the actuarial assumptions, Entergy does not anticipate 2003anticipates 2005 pension cost to be materially different from 2002.increase to $117 million due to decreases in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. Pension funding was $73 million for 20032004 and in 2005 is anticipatedprojected to be $39$186 million. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, offset by the Pension Funding Equity Act relief passed in April 2004.
Due to negative pension plan asset returns over the past several years, Entergy's accumulated benefit obligation at December 31, 2004, 2003, and 2002 exceeded plan assets. As a result, Entergy was required to recognize an additional minimum pension liability of $208.1as prescribed by SFAS 87. At December 31, 2004, Entergy increased its additional minimum pension liability to $244 million ($175218 million net of related pension assets) as prescribed by SFAS 87. This resulted in a charge to otherfrom $180 million ($149 million net of related pension assets) at December 31, 2003. Other comprehensive income of $11decreased to $6.6 million at December 31, 2004 from $9.3 million at December 31, 2003, after reductions for the unrecognized prior service cost, amounts recoverable in rates, and taxes. Net income for 2004, 2003, and 2002 was not affected.
Total postretirement health care and life insurance benefit costs for Entergy in 20022004 were $81 million. Because$86 million, including $23 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy expects 2005 postretirement health care and life insurance benefit costs to approximate $96 million, including a numberprojected $27 million in savings due to the estimated effect of factors, includingfuture Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the increaseddecrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate Entergy expects 2003 costsused to approximate $108 million.calculate benefit obligations.
Other Contingencies
Entergy, as a company with multi-state domestic utility operations, and which also had investments in international projects, is subject to a number of federal, state, and international laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.
Environmental
Entergy must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. Under these various laws and regulations, Entergy could incur substantial costs to restore properties consistent with the various standards. Entergy conducts studies to determine the extent of any required remediation and has recorded reserves based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites could be identified which require environmental remediation for which Entergy could be liable. The amounts of environmental reserves recorded can be significantly affected by the following external events or conditions:
Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.
The identification of additional sites 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.
Litigation
Entergy has been named as defendant in a number of lawsuits involving employment, ratepayer, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably estimable, or remote and records reserves for cases which have a probable likelihood of loss and can be estimated. Notes 2 and 98 to the consolidated financial statements include more detail on ratepayer and other lawsuits and management's assessment of the adequacy of reserves recorded for these matters. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, however, the ultimate outcome of the litigation Entergy is exposed to has the potential to materially affect the results of operations of Entergy, or its operating company subsidiaries.
Sales Warranty and Tax Reserves
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 reserves 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. Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued in the financial statements. Entergy does not expect a material adverse effect on earnings from these matters.
ENTERGY CORPORATION AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON(Page left blank intentionally)
ENTERGY CORPORATION AND SUBSIDIARIES | ENTERGY CORPORATION AND SUBSIDIARIES | ||||||||||||||
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | ||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | |||||||||||
2002 | 2001 | 2000 | 1999 | 1998(1) | (In Thousands, Except Percentages and Per Share Amounts) | ||||||||||
(In Thousands, Except Percentages and Per Share Amounts) | |||||||||||||||
Operating revenues | $ 8,305,035 | $ 9,620,899 | $ 10,022,129 | $ 8,765,635 | $11,494,772 | $10,123,724 | $9,194,920 | $8,305,035 | $9,620,899 | $10,022,129 | |||||
Income before cumulative |
|
|
|
|
| $933,049 | $813,393 | $623,072 | $727,025 | $710,915 | |||||
Earnings per share before |
|
|
|
|
| ||||||||||
Earnings per share before cumulative effect of accounting change | |||||||||||||||
Basic | $4.01 | $3.48 | $2.69 | $3.18 | $3.00 | ||||||||||
Diluted | $3.93 | $3.42 | $2.64 | $3.13 | $2.97 | ||||||||||
Dividends declared per share | $ 1.34 | $ 1.28 | $ 1.22 | $ 1.20 | $ 1.50 | $1.89 | $1.60 | $1.34 | $1.28 | $1.22 | |||||
Return on average common equity | 7.85% | 10.04% | 9.62% | 7.77% | 10.71% | ||||||||||
Return on common equity | 10.70% | 11.21% | 7.85% | 10.04% | 9.62% | ||||||||||
Book value per share, year-end | $ 35.24 | $ 33.78 | $ 31.89 | $ 29.78 | $ 28.82 | $38.25 | $38.02 | $35.24 | $33.78 | $31.89 | |||||
Total assets | $26,947,969 | $25,910,311 | $ 25,451,896 | $22,969,940 | $22,836,694 | $28,310,777 | $28,527,388 | $27,504,366 | $25,910,311 | $25,451,896 | |||||
Long-term obligations (2) | $ 7,482,269 | $ 7,743,298 | $ 8,214,724 | $ 7,252,697 | $ 7,349,349 | ||||||||||
Long-term obligations (1) | $7,180,291 | $7,497,690 | $7,488,919 | $7,743,298 | $8,214,724 | ||||||||||
|
|
|
|
|
| ||||||||||
(1) Includes long-term debt (excluding currently maturing debt), preferred stock with sinking fund, and noncurrent capital lease obligations. | (1) Includes long-term debt (excluding currently maturing debt), preferred stock with sinking fund, and noncurrent capital lease obligations. | ||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | |||||||||||
(Dollars In Millions) | |||||||||||||||
Electric Operating Revenues: | |||||||||||||||
Residential | $2,842 | $2,683 | $2,440 | $2,613 | $2,525 | ||||||||||
Commercial | 2,045 | 1,882 | 1,673 | 1,860 | 1,700 | ||||||||||
Industrial | 2,311 | 2,082 | 1,850 | 2,299 | 2,177 | ||||||||||
Governmental | 200 | 195 | 179 | 205 | 185 | ||||||||||
Total retail | 7,398 | 6,842 | 6,142 | 6,977 | 6,587 | ||||||||||
Sales for resale | 390 | 371 | 330 | 395 | 424 | ||||||||||
Other (1) | 145 | 184 | 174 | (127) | 209 | ||||||||||
Total | $7,933 | $7,397 | $6,646 | $7,245 | $7,220 | ||||||||||
Billed Electric Energy Sales (GWh): | |||||||||||||||
Residential | 32,897 | 32,817 | 32,581 | 31,080 | 31,998 | ||||||||||
Commercial | 26,468 | 25,863 | 25,354 | 24,706 | 24,657 | ||||||||||
Industrial | 40,293 | 38,637 | 41,018 | 41,577 | 43,956 | ||||||||||
Governmental | 2,568 | 2,651 | 2,678 | 2,593 | 2,605 | ||||||||||
Total retail | 102,226 | 99,968 | 101,631 | 99,956 | 103,216 | ||||||||||
Sales for resale | 8,623 | 9,248 | 9,828 | 8,896 | 9,794 | ||||||||||
Total | 110,849 | 109,216 | 111,459 | 108,852 | 113,010 | ||||||||||
(1) 2001 includes the effect of a reserve for rate refund at System Energy. | |||||||||||||||
(1) Includes the effects of the sales of London Electricity and CitiPower in December 1998.
(2) Includes long-term debt (excluding currently maturing debt), preferred stock with sinking fund, preferred securities of subsidiary trusts and partnership, and noncurrent capital lease obligations.
INDEPENDENT AUDITORS' REPORT
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Entergy Corporation:
We have audited the accompanying consolidated balance sheets of Entergy Corporation and subsidiaries (the "Corporation") as of December 31, 20022004 and 2001,2003, and the related consolidated statements of income; of retained earnings, comprehensive income, and paid-in capital; and of cash flows for each of the three years in the period ended December 31, 2002.2004. 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 did not audit the financial statements of Entergy-Koch, LP, the Corporation's investment in which is accounted for by the use of the equity method. The Corporation's equity in earnings of unconsolidated equity affiliates for the year ended December 31, 2003 includes $180,110,000 for Entergy Koch, LP, which earnings were audited by other auditors whose report (which as to 2003 included an explanatory paragraph concerning a change in accounting for inventory held for trading purposes and energy trading contracts not qualifying as derivatives) has been furnished to us, and our opinion for the year ended December 31, 2003, insofar as it relates to the amount audited by other auditors included for such company, is based solely on the report of such other auditors.
We conducted our audits in accordance with auditingthe standards generally accepted inof the United States of America.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 and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and subsidiaries as of December 31, 20022004 and 2001,2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002,2004 in conformity with accounting principles generally accepted in the United States of America.
As discussed in NoteNotes 1, 5 and 8 to the Form 10-K consolidated financial statements, Entergy Corporation adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 142 "Goodwill and Other Intangible Assets" in 2002143,Accounting for Asset Retirement Obligations, and Statement of Financial Accounting Standards Board Interpretation No. 133 "Accounting for Derivative Instruments46,Consolidation of Variable Interest Entities, in 2003, and Hedging Activities"SFAS No. 142,Goodwill and Other Intangible Assets, in 2001.2002.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Corporation's internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control - - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Corporation's internal control over financial reporting and an unqualified opinion on the effectiveness of the Corporation's internal control over financial reporting.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 8, 2005
February 21, 2003
ENTERGY CORPORATION AND SUBSIDIARIES | ||||||
CONSOLIDATED STATEMENTS OF INCOME | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands, Except Share Data) | ||||||
OPERATING REVENUES | ||||||
Domestic electric | $7,932,577 | $7,397,175 | $6,646,414 | |||
Natural gas | 208,499 | 186,176 | 125,353 | |||
Competitive businesses | 1,982,648 | 1,611,569 | 1,533,268 | |||
TOTAL | 10,123,724 | 9,194,920 | 8,305,035 | |||
OPERATING EXPENSES | ||||||
Operating and Maintenance: | ||||||
Fuel, fuel-related expenses, and | ||||||
gas purchased for resale | 2,488,208 | 1,987,217 | 2,154,596 | |||
Purchased power | 2,092,922 | 1,728,526 | 833,829 | |||
Nuclear refueling outage expenses | 166,072 | 159,995 | 105,592 | |||
Provisions for turbine commitments, asset impairments | ||||||
and restructuring charges | 55,000 | (7,743) | 428,456 | |||
Other operation and maintenance | 2,303,561 | 2,453,869 | 2,486,617 | |||
Decommissioning | 149,529 | 146,100 | 76,417 | |||
Taxes other than income taxes | 409,886 | 405,659 | 380,462 | |||
Depreciation and amortization | 895,593 | 850,503 | 839,181 | |||
Other regulatory credits - net | (90,611) | (13,761) | (141,836) | |||
TOTAL | 8,470,160 | 7,710,365 | 7,163,314 | |||
OPERATING INCOME | 1,653,564 | 1,484,555 | 1,141,721 | |||
OTHER INCOME | ||||||
Allowance for equity funds used during construction | 39,582 | 42,710 | 31,658 | |||
Interest and dividend income | 109,809 | 87,386 | 118,325 | |||
Equity in earnings (loss) of unconsolidated equity affiliates | (78,727) | 271,647 | 183,878 | |||
Miscellaneous - net | 53,752 | (76,505) | 13,892 | |||
TOTAL | 124,416 | 325,238 | 347,753 | |||
INTEREST AND OTHER CHARGES | ||||||
Interest on long-term debt | 463,384 | 485,964 | 526,442 | |||
Other interest - net | 41,380 | 53,553 | 70,560 | |||
Allowance for borrowed funds used during construction | (25,741) | (33,191) | (24,538) | |||
TOTAL | 479,023 | 506,326 | 572,464 | |||
INCOME BEFORE INCOME TAXES AND | ||||||
CUMULATIVE EFFECT OF ACCOUNTING CHANGES | 1,298,957 | 1,303,467 | 917,010 | |||
Income taxes | 365,908 | 490,074 | 293,938 | |||
INCOME BEFORE CUMULATIVE EFFECT | ||||||
OF ACCOUNTING CHANGES | 933,049 | 813,393 | 623,072 | |||
CUMULATIVE EFFECT OF ACCOUNTING | ||||||
CHANGES (net of income taxes of $89,925) | - - | 137,074 | - - | |||
CONSOLIDATED NET INCOME | 933,049 | 950,467 | 623,072 | |||
Preferred dividend requirements and other | 23,525 | 23,524 | 23,712 | |||
EARNINGS APPLICABLE TO | ||||||
COMMON STOCK | $909,524 | $926,943 | $599,360 | |||
Earnings per average common share before cumulative | ||||||
effect of accounting changes: | ||||||
Basic | $4.01 | $3.48 | $2.69 | |||
Diluted | $3.93 | $3.42 | $2.64 | |||
Earnings per average common share: | ||||||
Basic | $4.01 | $4.09 | $2.69 | |||
Diluted | $3.93 | $4.01 | $2.64 | |||
Dividends declared per common share | $1.89 | $1.60 | $1.34 | |||
Average number of common shares outstanding: | ||||||
Basic | 226,863,758 | 226,804,370 | 223,047,431 | |||
Diluted | 231,193,686 | 231,146,040 | 227,303,103 | |||
See Notes to Consolidated Financial Statements. | ||||||
ENTERGY CORPORATION AND SUBSIDIARIES | ||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
OPERATING ACTIVITIES | ||||||
Consolidated net income | $933,049 | $950,467 | $623,072 | |||
Adjustments to reconcile consolidated net income to net cash flow | ||||||
provided by operating activities: | ||||||
Reserve for regulatory adjustments | 33,533 | 13,090 | 18,848 | |||
Other regulatory credits - net | (90,611) | (13,761) | (141,836) | |||
Depreciation, amortization, and decommissioning | 1,045,122 | 996,603 | 915,597 | |||
Deferred income taxes and investment tax credits | 275,458 | 1,189,531 | (256,664) | |||
Cumulative effect of accounting changes | - | (137,074) | - | |||
Equity in earnings (loss) of unconsolidated equity affiliates - net of dividends | 608,141 | (176,036) | (181,878) | |||
Provisions for turbine commitments, asset impairments, and restructuring charges | 55,000 | (7,743) | 428,456 | |||
Changes in working capital: | ||||||
Receivables | (210,419) | (140,612) | (43,957) | |||
Fuel inventory | (16,769) | (14,015) | 1,030 | |||
Accounts payable | 95,306 | (60,164) | 286,230 | |||
Taxes accrued | 75,055 | (882,446) | 462,956 | |||
Interest accrued | 5,269 | (35,837) | 7,209 | |||
Deferred fuel | 213,627 | (33,874) | 156,181 | |||
Other working capital accounts | 41,008 | 16,809 | (286,232) | |||
Provision for estimated losses and reserves | (18,041) | 196,619 | 10,533 | |||
Changes in other regulatory assets | 48,626 | 22,671 | 71,132 | |||
Other | (164,035) | 121,592 | 111,026 | |||
Net cash flow provided by operating activities | 2,929,319 | 2,005,820 | 2,181,703 | |||
INVESTING ACTIVITIES | ||||||
Construction/capital expenditures | (1,410,610) | (1,568,943) | (1,530,301) | |||
Allowance for equity funds used during construction | 39,582 | 42,710 | 31,658 | |||
Nuclear fuel purchases | (238,170) | (224,308) | (250,309) | |||
Proceeds from sale/leaseback of nuclear fuel | 109,988 | 150,135 | 183,664 | |||
Proceeds from sale of assets and businesses | 75,430 | 25,987 | 215,088 | |||
Investment in nonutility properties | (6,420) | (71,438) | (216,956) | |||
Decrease in other investments | 383,498 | 172,187 | 38,964 | |||
Changes in other temporary investments | 50,000 | (50,000) | 150,000 | |||
Decommissioning trust contributions and realized change in trust assets | (89,807) | (91,518) | (84,914) | |||
Other regulatory investments | (53,566) | (156,446) | (39,390) | |||
Other | - | (11,496) | 114,033 | |||
Net cash flow used in investing activities | (1,140,075) | (1,783,130) | (1,388,463) | |||
See Notes to Consolidated Financial Statements. | ||||||
ENTERGY CORPORATION AND SUBSIDIARIES | ||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
FINANCING ACTIVITIES | ||||||
Proceeds from the issuance of: | ||||||
Long-term debt | 1,059,824 | 2,221,164 | 1,197,330 | |||
Common stock and treasury stock | 170,237 | 217,521 | 130,061 | |||
Retirement of long-term debt | (1,478,894) | (2,409,917) | (1,341,274) | |||
Repurchase of common stock | (1,017,996) | (8,135) | (118,499) | |||
Redemption of preferred stock | (3,450) | (3,450) | (1,858) | |||
Changes in credit line borrowings - net | 49,846 | (499,975) | 244,333 | |||
Dividends paid: | ||||||
Common stock | (427,901) | (362,814) | (298,991) | |||
Preferred stock | (23,525) | (23,524) | (23,712) | |||
Net cash flow used in financing activities | (1,671,859) | (869,130) | (212,610) | |||
Effect of exchange rates on cash and cash equivalents | (1,882) | 3,345 | 3,125 | |||
Net increase (decrease) in cash and cash equivalents | 115,503 | (643,095) | 583,755 | |||
Cash and cash equivalents at beginning of period | 692,233 | 1,335,328 | 751,573 | |||
Cash and cash equivalents at end of period | $807,736 | $692,233 | $1,335,328 | |||
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||
Cash paid during the period for: | ||||||
Interest - net of amount capitalized | $477,768 | $552,017 | $633,931 | |||
Income taxes | $28,241 | $188,709 | $57,856 | |||
Noncash investing and financing activities: | ||||||
Debt assumed by the Damhead Creek purchaser | - | - | $488,432 | |||
Decommissioning trust funds acquired in nuclear power plant acquisitions | - | - | $310,000 | |||
Long-term debt refunded with proceeds from | ||||||
long-term debt issued in prior period | - | - | ($47,000) | |||
See Notes to Consolidated Financial Statements. | ||||||
ENTERGY CORPORATION AND SUBSIDIARIES | ||||
CONSOLIDATED BALANCE SHEETS | ||||
ASSETS | ||||
December 31, | ||||
2004 | 2003 | |||
(In Thousands) | ||||
CURRENT ASSETS | ||||
Cash and cash equivalents: | ||||
Cash | $79,136 | $115,112 | ||
Temporary cash investments - at cost, | ||||
which approximates market | 728,600 | 576,813 | ||
Special deposits | - | 308 | ||
Total cash and cash equivalents | 807,736 | 692,233 | ||
Other temporary investments | - | 50,000 | ||
Notes receivable | 3,092 | 1,730 | ||
Accounts receivable: | ||||
Customer | 435,191 | 398,091 | ||
Allowance for doubtful accounts | (23,758) | (25,976) | ||
Other | 342,289 | 246,824 | ||
Accrued unbilled revenues | 460,039 | 384,860 | ||
Total receivables | 1,213,761 | 1,003,799 | ||
Deferred fuel costs | 85,911 | 245,973 | ||
Accumulated deferred income taxes | 76,899 | - | ||
Fuel inventory - at average cost | 127,251 | 110,482 | ||
Materials and supplies - at average cost | 569,407 | 548,921 | ||
Deferred nuclear refueling outage costs | 107,782 | 138,836 | ||
Prepayments and other | 116,279 | 127,270 | ||
TOTAL | 3,108,118 | 2,919,244 | ||
OTHER PROPERTY AND INVESTMENTS | ||||
Investment in affiliates - at equity | 231,779 | 1,053,328 | ||
Decommissioning trust funds | 2,453,406 | 2,278,533 | ||
Non-utility property - at cost (less accumulated depreciation) | 219,717 | 262,384 | ||
Other | 90,992 | 152,681 | ||
TOTAL | 2,995,894 | 3,746,926 | ||
PROPERTY, PLANT AND EQUIPMENT | ||||
Electric | 29,053,340 | 28,035,899 | ||
Property under capital lease | 738,554 | 751,815 | ||
Natural gas | 262,787 | 236,622 | ||
Construction work in progress | 1,197,551 | 1,380,982 | ||
Nuclear fuel under capital lease | 262,469 | 278,683 | ||
Nuclear fuel | 320,813 | 234,421 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT | 31,835,514 | 30,918,422 | ||
Less - accumulated depreciation and amortization | 13,139,883 | 12,619,625 | ||
PROPERTY, PLANT AND EQUIPMENT - NET | 18,695,631 | 18,298,797 | ||
DEFERRED DEBITS AND OTHER ASSETS | ||||
Regulatory assets: | ||||
SFAS 109 regulatory asset - net | 746,413 | 830,539 | ||
Other regulatory assets | 1,429,261 | 1,398,323 | ||
Long-term receivables | 39,417 | 20,886 | ||
Goodwill | 377,172 | 377,172 | ||
Other | 918,871 | 935,501 | ||
TOTAL | 3,511,134 | 3,562,421 | ||
TOTAL ASSETS | $28,310,777 | $28,527,388 | ||
See Notes to Consolidated Financial Statements. | ||||
ENTERGY CORPORATION AND SUBSIDIARIES | ||||
CONSOLIDATED BALANCE SHEETS | ||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||
December 31, | ||||
2004 | 2003 | |||
(In Thousands) | ||||
CURRENT LIABILITIES | ||||
Currently maturing long-term debt | $492,564 | $524,372 | ||
Notes payable | 193 | 351 | ||
Accounts payable | 896,528 | 796,572 | ||
Customer deposits | 222,320 | 199,620 | ||
Taxes accrued | 224,011 | 224,926 | ||
Accumulated deferred income taxes | - | 22,963 | ||
Nuclear refueling outage costs | - | 8,238 | ||
Interest accrued | 144,478 | 139,603 | ||
Obligations under capital leases | 133,847 | 159,978 | ||
Other | 218,442 | 145,453 | ||
TOTAL | 2,332,383 | 2,222,076 | ||
NON-CURRENT LIABILITIES | ||||
Accumulated deferred income taxes and taxes accrued | 5,067,381 | 4,779,513 | ||
Accumulated deferred investment tax credits | 399,228 | 420,248 | ||
Obligations under capital leases | 146,060 | 153,898 | ||
Other regulatory liabilities | 329,767 | 291,239 | ||
Decommissioning and retirement cost liabilities | 2,066,277 | 2,215,490 | ||
Transition to competition | 79,101 | 79,098 | ||
Regulatory reserves | 103,061 | 69,528 | ||
Accumulated provisions | 549,914 | 506,960 | ||
Long-term debt | 7,016,831 | 7,322,940 | ||
Preferred stock with sinking fund | 17,400 | 20,852 | ||
Other | 1,541,331 | 1,407,551 | ||
TOTAL | 17,316,351 | 17,267,317 | ||
Commitments and Contingencies | ||||
Preferred stock without sinking fund | 365,356 | 334,337 | ||
SHAREHOLDERS' EQUITY | ||||
Common stock, $.01 par value, authorized 500,000,000 | ||||
shares; issued 248,174,087 shares in 2004 and in 2003 | 2,482 | 2,482 | ||
Paid-in capital | 4,835,375 | 4,767,615 | ||
Retained earnings | 4,984,302 | 4,502,508 | ||
Accumulated other comprehensive loss | (93,453) | (7,795) | ||
Less - treasury stock, at cost (31,345,028 shares in 2004 and | ||||
19,276,445 shares in 2003) | 1,432,019 | 561,152 | ||
TOTAL | 8,296,687 | 8,703,658 | ||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $28,310,777 | $28,527,388 | ||
See Notes to Consolidated Financial Statements. | ||||
ENTERGY CORPORATION AND SUBSIDIARIES | ||||||||||||||
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS, COMPREHENSIVE INCOME, AND PAID-IN CAPITAL | ||||||||||||||
For the Years Ended December 31, | ||||||||||||||
2004 | 2003 | 2002 | ||||||||||||
(In Thousands) | ||||||||||||||
RETAINED EARNINGS | ||||||||||||||
Retained Earnings - Beginning of period | $4,502,508 | $3,938,693 | $3,638,448 | |||||||||||
Add: Earnings applicable to common stock | 909,524 | $909,524 | 926,943 | $926,943 | 599,360 | $599,360 | ||||||||
Deduct: | ||||||||||||||
Dividends declared on common stock | 427,740 | 362,941 | 299,031 | |||||||||||
Capital stock and other expenses | (10) | 187 | 84 | |||||||||||
Total | 427,730 | 363,128 | 299,115 | |||||||||||
Retained Earnings - End of period | $4,984,302 | $4,502,508 | $3,938,693 | |||||||||||
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Net of taxes): | ||||||||||||||
Balance at beginning of period: | ||||||||||||||
Accumulated derivative instrument fair value changes | ($25,811) | $17,313 | ($17,973) | |||||||||||
Other accumulated comprehensive income (loss) items | 18,016 | (39,673) | (70,821) | |||||||||||
Total | (7,795) | (22,360) | (88,794) | |||||||||||
Net derivative instrument fair value changes | ||||||||||||||
arising during the period | (115,600) | (115,600) | (43,124) | (43,124) | 35,286 | 35,286 | ||||||||
Foreign currency translation | 1,882 | 1,882 | 4,169 | 4,169 | 65,948 | (15,487) | ||||||||
Minimum pension liability | 2,762 | 2,762 | 1,153 | 1,153 | (10,489) | (10,489) | ||||||||
Net unrealized investment gains (losses) | 25,298 | 25,298 | 52,367 | 52,367 | (24,311) | (24,311) | ||||||||
Balance at end of period: | ||||||||||||||
Accumulated derivative instrument fair value changes | (141,411) | (25,811) | 17,313 | |||||||||||
Other accumulated comprehensive income (loss) items | 47,958 | 18,016 | (39,673) | |||||||||||
Total | ($93,453) | ($7,795) | ($22,360) | |||||||||||
Comprehensive Income | $823,866 | $941,508 | $584,359 | |||||||||||
PAID-IN CAPITAL | ||||||||||||||
Paid-in Capital - Beginning of period | $4,767,615 | $4,666,753 | $4,662,704 | |||||||||||
Add: | ||||||||||||||
Common stock issuances related to stock plans | 67,760 | 100,862 | 4,049 | |||||||||||
Paid-in Capital - End of period | $4,835,375 | $4,767,615 | $4,666,753 | |||||||||||
See Notes to Consolidated Financial Statements. |
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ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2002 2001 2000 (In Thousands, Except Share Data) OPERATING REVENUES Domestic electric $6,646,414 $7,244,827 $7,219,686 Natural gas 125,353 185,902 165,872 Competitive businesses 1,533,268 2,190,170 2,636,571 ---------- ---------- ---------- TOTAL 8,305,035 9,620,899 10,022,129 ---------- ---------- ---------- OPERATING EXPENSES Operating and Maintenance: Fuel, fuel-related expenses, and gas purchased for resale 2,154,596 3,681,677 2,645,835 Purchased power 832,334 1,021,432 2,662,881 Nuclear refueling outage expenses 105,592 89,145 70,511 Provision for turbine commitments, asset impairments and restructuring charges 428,456 - - Other operation and maintenance 2,488,112 2,151,742 1,943,814 Decommissioning 30,458 3,189 39,484 Taxes other than income taxes 380,462 399,849 370,344 Depreciation and amortization 839,181 721,033 746,125 Other regulatory charges (credits) - net (141,836) (20,510) 34,073 ---------- ---------- ---------- TOTAL 7,117,355 8,047,557 8,513,067 ---------- ---------- ---------- OPERATING INCOME 1,187,680 1,573,342 1,509,062 ---------- ---------- ---------- OTHER INCOME Allowance for equity funds used during construction 31,658 26,209 32,022 Gain on sale of assets - net 6,612 5,226 2,340 Interest and dividend income 118,325 159,805 163,050 Equity in earnings of unconsolidated equity affiliates 183,878 162,882 13,715 Miscellaneous - net 7,280 (4,769) 27,077 ---------- ---------- ---------- TOTAL 347,753 349,353 238,204 ---------- ---------- ---------- INTEREST AND OTHER CHARGES Interest on long-term debt 507,604 544,920 477,071 Other interest - net 116,519 197,638 85,635 Distributions on preferred securities of subsidiaries 18,838 18,838 18,838 Allowance for borrowed funds used during construction (24,538) (21,419) (24,114) ---------- ---------- ---------- TOTAL 618,423 739,977 557,430 ---------- ---------- ---------- INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE 917,010 1,182,718 1,189,836 Income taxes 293,938 455,693 478,921 ---------- ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 623,072 727,025 710,915 CUMULATIVE EFFECT OF ACCOUNTING CHANGE (net of income taxes of $10,064) - 23,482 - ---------- ---------- ---------- CONSOLIDATED NET INCOME 623,072 750,507 710,915 Preferred dividend requirements and other 23,712 24,311 31,621 ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $599,360 $726,196 $679,294 ========== ========== ========== Earnings per average common share before cumulative effect of accounting change: Basic $2.69 $3.18 $3.00 Diluted $2.64 $3.13 $2.97 Earnings per average common share: Basic $2.69 $3.29 $3.00 Diluted $2.64 $3.23 $2.97 Dividends declared per common share $1.34 $1.28 $1.22 Average number of common shares outstanding: Basic 223,047,431 220,944,270 226,580,449 Diluted 227,303,103 224,733,662 228,541,307 See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING ACTIVITIES Consolidated net income $623,072 $750,507 $710,915 Noncash items included in net income: Reserve for regulatory adjustments 18,848 (359,199) 18,482 Other regulatory charges (credits) - net (141,836) (20,510) 34,073 Depreciation, amortization, and decommissioning 869,638 724,222 785,609 Deferred income taxes and investment tax credits (256,664) 87,752 124,457 Allowance for equity funds used during construction (31,658) (26,209) (32,022) Cumulative effect of accounting change - (23,482) - Gain on sale of assets - net (6,612) (5,226) (2,340) Equity in undistributed earnings of subsidiaries and unconsolidated affiliates (181,878) (150,799) (13,715) Provision for turbine commitments and asset impairments 428,456 - - Changes in working capital (net of effects from acquisitions and dispositions): Receivables (43,957) 302,230 (437,146) Fuel inventory 1,030 (3,419) (20,447) Accounts payable 286,230 (415,160) 543,606 Taxes accrued 462,956 486,676 20,871 Interest accrued 7,209 17,287 45,789 Deferred fuel 156,181 495,007 (38,001) Other working capital accounts (286,232) (39,978) 102,336 Provision for estimated losses and reserves 10,533 19,093 6,019 Changes in other regulatory assets 71,132 119,215 (66,903) Other 195,255 257,541 186,264 ---------- ---------- ---------- Net cash flow provided by operating activities 2,181,703 2,215,548 1,967,847 ---------- ---------- ---------- INVESTING ACTIVITIES Construction/capital expenditures (1,530,301) (1,380,417) (1,493,717) Allowance for equity funds used during construction 31,658 26,209 32,022 Nuclear fuel purchases (250,309) (130,670) (121,127) Proceeds from sale/leaseback of nuclear fuel 183,664 71,964 117,154 Proceeds from sale of assets and businesses 215,088 784,282 61,519 Investment in nonutility properties (216,956) (647,015) (222,119) Decrease (increase) in other investments 38,964 (631,975) (15,943) Changes in other temporary investments - net 150,000 (150,000) 321,351 Decommissioning trust contributions and realized change in trust assets (84,914) (95,571) (63,805) Other regulatory investments (39,390) (3,460) (385,331) Other 114,033 (68,067) (44,016) ---------- ---------- ---------- Net cash flow used in investing activities (1,388,463) (2,224,720) (1,814,012) ---------- ---------- ---------- See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002 2001 2000 (In Thousands) FINANCING ACTIVITIES Proceeds from the issuance of: Long-term debt 1,197,330 682,402 904,522 Common stock 130,061 64,345 41,908 Retirement of long-term debt (1,341,274) (962,112) (181,329) Repurchase of common stock (118,499) (36,895) (550,206) Redemption of preferred stock (1,858) (39,574) (157,658) Changes in short-term borrowings - net 244,333 (37,004) 267,000 Dividends paid: Common stock (298,991) (269,122) (271,019) Preferred stock (23,712) (24,044) (32,400) ---------- ---------- ---------- Net cash flow provided by (used in) financing activities (212,610) (622,004) 20,818 ---------- ---------- ---------- Effect of exchange rates on cash and cash equivalents 3,125 325 (5,948) ---------- ---------- ---------- Net increase (decrease) in cash and cash equivalents 583,755 (630,851) 168,705 Cash and cash equivalents at beginning of period 751,573 1,382,424 1,213,719 ---------- ---------- ---------- Cash and cash equivalents at end of period $1,335,328 $751,573 $1,382,424 ========== ========== ========== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid (received) during the period for: Interest - net of amount capitalized $633,931 $708,748 $505,414 Income taxes $57,856 ($113,466) $345,361 Noncash investing and financing activities: Debt assumed by the Damhead Creek purchaser $488,432 - - Decommissioning trust funds acquired in nuclear power plant acquisitions $310,000 $430,000 - Change in unrealized depreciation of decommissioning trust assets ($72,982) ($34,517) ($11,577) Long-term debt refunded with proceeds from long-term debt issued in prior period ($47,000) - - Proceeds from long-term debt issued for the purpose of refunding prior long-term debt - $47,000 - Acquisition of Indian Point 3 and FitzPatrick Fair value of assets acquired - - $917,667 Initial cash paid at closing - - $50,000 Liabilities assumed and notes issued to seller - - $867,667 See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS December 31, 2002 2001 (In Thousands) CURRENT ASSETS Cash and cash equivalents: Cash $169,788 $129,866 Temporary cash investments - at cost, which approximates market 1,165,260 618,327 Special deposits 280 3,380 ----------- ----------- Total cash and cash equivalents 1,335,328 751,573 ----------- ----------- Other temporary investments - 150,000 Notes receivable 2,078 2,137 Accounts receivable: Customer 323,215 294,799 Allowance for doubtful accounts (27,285) (28,355) Other 244,621 295,771 Accrued unbilled revenues 319,133 268,680 ----------- ----------- Total receivables 859,684 830,895 ----------- ----------- Deferred fuel costs 55,653 172,444 Accumulated deferred income taxes - 6,488 Fuel inventory - at average cost 96,467 97,497 Materials and supplies - at average cost 525,900 460,644 Deferred nuclear refueling outage costs 163,646 79,755 Prepayments and other 166,827 205,097 ----------- ----------- TOTAL 3,205,583 2,756,530 ----------- ----------- OTHER PROPERTY AND INVESTMENTS Investment in affiliates - at equity 824,209 766,103 Decommissioning trust funds 2,069,198 1,775,950 Non-utility property - at cost (less accumulated depreciation) 297,294 295,616 Other 270,889 495,542 ----------- ----------- TOTAL 3,461,590 3,333,211 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT Electric 26,789,538 26,359,676 Property under capital lease 746,624 753,310 Natural gas 209,969 201,841 Construction work in progress 1,232,891 882,829 Nuclear fuel under capital lease 259,433 265,464 Nuclear fuel 263,609 232,387 ----------- ----------- TOTAL PROPERTY, PLANT AND EQUIPMENT 29,502,064 28,695,507 Less - accumulated depreciation and amortization 12,307,112 11,805,578 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT - NET 17,194,952 16,889,929 ----------- ----------- DEFERRED DEBITS AND OTHER ASSETS Regulatory assets: SFAS 109 regulatory asset - net 844,105 946,126 Unamortized loss on reacquired debt 155,161 166,546 Other regulatory assets 738,328 707,439 Long-term receivables 24,703 28,083 Goodwill 377,172 377,172 Other 946,375 705,275 ----------- ----------- TOTAL 3,085,844 2,930,641 ----------- ----------- TOTAL ASSETS $26,947,969 $25,910,311 =========== =========== See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS LIABILITIES AND SHAREHOLDERS' EQUITY December 31, 2002 2001 (In Thousands) CURRENT LIABILITIES Currently maturing long-term debt $1,191,320 $682,771 Notes payable 351 351,018 Accounts payable 855,446 592,529 Customer deposits 198,442 188,230 Taxes accrued 385,315 550,133 Accumulated deferred income taxes 26,468 - Nuclear refueling outage costs 14,244 2,080 Interest accrued 175,440 192,420 Obligations under capital leases 153,822 149,352 Other 171,341 396,616 ----------- ----------- TOTAL 3,172,189 3,105,149 ----------- ----------- DEFERRED CREDITS AND OTHER LIABILITIES Accumulated deferred income taxes and taxes accrued 4,250,800 3,974,664 Accumulated deferred investment tax credits 447,925 471,090 Obligations under capital leases 155,943 181,085 Other regulatory liabilities 185,579 135,878 Decommissioning 1,565,997 1,194,333 Transition to competition 79,098 231,512 Regulatory reserves 56,438 37,591 Accumulated provisions 389,868 425,399 Other 1,145,232 801,040 ----------- ----------- TOTAL 8,276,880 7,452,592 ----------- ----------- Long-term debt 7,086,999 7,321,028 Preferred stock with sinking fund 24,327 26,185 Preferred stock without sinking fund 334,337 334,337 Company-obligated mandatorily redeemable preferred securities of subsidiary trusts holding solely junior subordinated deferrable debentures 215,000 215,000 SHAREHOLDERS' EQUITY Common stock, $.01 par value, authorized 500,000,000 shares; issued 248,174,087 shares in 2002 and in 2001 2,482 2,482 Paid-in capital 4,666,753 4,662,704 Retained earnings 3,938,693 3,638,448 Accumulated other comprehensive loss (22,360) (88,794) Less - treasury stock, at cost (25,752,410 shares in 2002 and 27,441,384 shares in 2001) 747,331 758,820 ----------- ----------- TOTAL 7,838,237 7,456,020 ----------- ----------- Commitments and Contingencies TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $26,947,969 $25,910,311 =========== =========== See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS, COMPREHENSIVE INCOME, AND PAID-IN CAPITAL For the Years Ended December 31, 2002 2001 2000 (In Thousands) RETAINED EARNINGS Retained Earnings - Beginning of period $3,638,448 $3,190,639 $2,786,467 Add: Earnings applicable to common stock 599,360 $599,360 726,196 $726,196 679,294 $679,294 Deduct: Dividends declared on common stock 299,031 278,342 275,929 Capital stock and other expenses 84 45 (807) ---------- ---------- ---------- Total 299,115 278,387 275,122 ---------- ---------- ---------- Retained Earnings - End of period $3,938,693 $3,638,448 $3,190,639 ========== ========== ========== ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Net of taxes): Balance at beginning of period: Accumulated derivative instrument fair value changes ($17,973) $- $- Other accumulated comprehensive (loss) items (70,821) (75,033) (73,805) ---------- ---------- ---------- Total (88,794) (75,033) (73,805) ---------- ---------- ---------- Cumulative effect to January 1, 2001 of accounting change regarding fair value of derivative instruments - (18,021) - Net derivative instrument fair value changes arising during the period 35,286 35,286 48 48 - - Foreign currency translation adjustments 65,948 (15,487) 4,615 4,615 (5,216) (5,216) Minimum pension liability adjustment (10,489) (10,489) - - - - Net unrealized investment gains (losses) (24,311) (24,311) (403) (403) 3,988 3,988 ---------- ---------- ---------- Balance at end of period: Accumulated derivative instrument fair value changes 17,313 (17,973) - Other accumulated comprehensive (loss) items (39,673) (70,821) (75,033) ---------- ---------- ---------- Total ($22,360) ($88,794) ($75,033) ========== -------- ========== -------- ========== -------- Comprehensive Income $584,359 $730,456 $678,066 ======== ======== ======== PAID-IN CAPITAL Paid-in Capital - Beginning of period $4,662,704 $4,660,483 $4,636,163 Add: Common stock issuances related to stock plans 4,049 2,221 24,320 ---------- ---------- ---------- Paid-in Capital - End of period $4,666,753 $4,662,704 $4,660,483 ========== ========== ========== See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying consolidated financial statements include the accounts of Entergy Corporation and its direct and indirect subsidiaries. As required by generally accepted accounting principles, certainall significant intercompany transactions have been eliminated in the consolidated financial statements. The domestic utility companies and System Energy maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications, with no effect on net income or shareholders' equity.
Use of Estimates in the Preparation of Financial Statements
The preparation of Entergy Corporation's consolidated financial statements, in conformity with generally accepted accounting principles, requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. 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
The domestic utility companies generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, including the City of New Orleans, Mississippi, and Texas. Entergy Gulf States distributes gas to retail customers in and around Baton Rouge, Louisiana and Entergy New Orleans distributes gas to retail customers in the City of New Orleans. Entergy's Non-Utility Nuclear and Energy Commodity Services segments derive almost all of their revenue from sales of electric power generated by plants owned by them.
System Energy's operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf 1. The capital costs are computed by allowing a return on System Energy's common equity funds allocable to its net investment in Grand Gulf 1, plus System Energy's effective interest cost for its debt allocable to its investment in Grand Gulf 1. System Energy's 1995 rate proceeding that was resolved in 2001 is discussed in Note 2 to the consolidated financial statements.
Entergy recognizes revenue from electric power and gas sales when it delivers power or gas to its customers. To the extent that deliveries have occurred but a bill has not been issued, the domestic utility companies accrue an estimate of the revenues for energy delivered since the latest billings. Entergy calculates 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 the domestic utility companies' various jurisdictions. Each month the estimated unbilled revenue amounts are recorded as revenue and a 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 so recorded and reversed.
The domestic utility companies' rate schedules include either fuel adjustment clauses or fixed fuel factors, both of which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Because the fuel adjustment clause mechanism allows monthly adjustments to recover fuel costs, Entergy Louisiana, Entergy New Orleans, and the Louisiana portion of Entergy Gulf States include a component of fuel cost recovery in their unbilled revenue calculations. 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. Effective January 2001, Entergy Mississippi's fuel factor includes an energy cost rider that is adjusted quarterly. As discussed in Note 2 to the consolidated financial statements, the MPSC approved Entergy Mississippi's deferral of the refund of over-recoveries for the third quarte r of 2004 that would have been refunded in the first quarter of 2005. The deferred amount plus carrying charges will be refunded in the second and third quarters of 2005. In the case of Entergy Arkansas and the Texas portion of Entergy Gulf States, their fuel under-recoveries are treated as regulatory investments in the cash flow statements because those companies are allowed by their regulatory jurisdictions to recover the fuel cost regulatory asset over longer than a twelve-month period, and the companies earn a carrying charge on the under-recovered balances.
System Energy's operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy's common equity funds allocable to its net investment in Grand Gulf, plus System Energy's effective interest cost for its debt allocable to its investment in Grand Gulf.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. For the domestic utility companies and System Energy, the original cost of plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the domestic utility companies' and System Energy's plant is subject to mortgage liens.
Electric plant includes the portions of Grand Gulf 1 and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions.
Net property, plant, and equipment by business segment and functional category, as of December 31, 20022004 and 2001,2003, is shown below (in millions):below:
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| Energy |
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| (In Millions) | ||||||||
Production |
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|
Nuclear |
| $7,308 |
| $5,987 |
| $1,321 |
| $- |
| $- |
Other |
| 1,533 |
| 1,228 |
| - |
| 305 |
| - |
Transmission |
| 2,182 |
| 2,182 |
| - |
| - |
| - |
Distribution |
| 4,672 |
| 4,672 |
| - |
| - |
| - |
Other |
| 1,123 |
| 1,115 |
| - |
| - |
| 8 |
Construction work in progress |
| 1,198 |
| 924 |
| 244 |
| 2 |
| 28 |
Nuclear fuel (leased and owned) |
| 583 |
| 297 |
| 286 |
| - |
| - |
Asset retirement obligation |
| 97 |
| 97 |
| - |
| - |
| - |
Property, plant, and equipment - net |
| $18,696 |
| $16,502 |
| $1,851 |
| $307 |
| $36 |
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| Energy |
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| (In Millions) | ||||||||
Production |
|
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|
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|
|
|
|
|
|
Nuclear |
| $7,056 |
| $6,112 |
| $944 |
| $- |
| $- |
Other |
| 1,816 |
| 1,359 |
| - |
| 457 |
| - |
Transmission |
| 2,067 |
| 2,067 |
| - |
| - |
| - |
Distribution |
| 4,231 |
| 4,231 |
| - |
| - |
| - |
Other |
| 1,079 |
| 1,069 |
| - |
| - |
| 10 |
Construction work in progress |
| 1,381 |
| 954 |
| 398 |
| - |
| 29 |
Nuclear fuel (leased and owned) |
| 513 |
| 298 |
| 215 |
| - |
| - |
Asset retirement obligation |
| 156 |
| 155 |
| - |
| 1 |
| - |
Property, plant, and equipment - net |
| $18,299 |
| $16,245 |
| $1,557 |
| $458 |
| $39 |
(1) This is reflected in accumulated depreciation and amortization on the balance sheet. The decommissioning liabilities related to Grand Gulf 1, Pilgrim, Indian Point 2, Vermont Yankee, and the 30% of River Bend previously owned by Cajun are reflected in the applicable balance sheets in "Deferred Credits and Other Liabilities - Decommissioning."
Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation rates on average depreciable property approximated 2.8% in 2004 and 2003, and 2.9% in 2002, 2001, and 2000.2002. Included in these rates are the depreciation rates on average depreciable utility property of 2.7% in 2004 and 2.8% in 20022003 and 2001 and 2.9% in 20002002 and the depreciation rates on average depreciable non-utility property of 3.8% in 2002, 4.5%2004, 3.3% in 2001,2003, and 3.5%4.0% in 2000.2002.
Non-utility property - at cost (less accumulated depreciation) is reported net of accumulated depreciation of $152.8 million and $145.2 million as of December 31, 2004 and 2003, respectively.
Jointly-Owned Generating Stations
Certain Entergy subsidiaries jointly own electric generating facilities with third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2002,2004, the subsidiaries' investment and accumulated depreciation in each of these generating stations were as follows:
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| Total |
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| (In Millions) | ||
U.S. Utility: |
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| |||||
Grand Gulf | Unit 1 |
| Nuclear |
| 1,270 |
| 90.00% (2) |
| $3,702 |
| $1,780 |
Independence | Units 1 and 2 |
| Coal |
| 1,630 |
| 47.90% |
| $462 |
| $249 |
White Bluff | Units 1 and 2 |
| Coal |
| 1,635 |
| 57.00% |
| $428 |
| $264 |
Roy S. Nelson | Unit 6 |
| Coal |
| 550 |
| 60.90% |
| $403 |
| $241 |
Big Cajun 2 | Unit 3 |
| Coal |
| 575 |
| 42.00% |
| $233 |
| $128 |
Energy Commodity Services: | |||||||||||
Harrison County |
|
| Gas |
| 550 |
| 61.00% |
| $209 |
| $7 |
Warren | Gas | 300 | 75.00% | $24 | $9 |
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| Total |
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| |
Grand Gulf | Unit 1 | Nuclear | 1,282 | 90.00%(2) | $3,587 | $1,515 |
Independence | Units 1 and 2 | Coal | 1,657 | 47.90% | 457 | 228 |
White Bluff | Units 1 and 2 | Coal | 1,620 | 57.00% | 418 | 244 |
Roy S. Nelson | Unit 6 | Coal | 550 | 70.00% | 404 | 227 |
Big Cajun 2 | Unit 3 | Coal | 575 | 42.00% | 229 | 119 |
Harrison County, Texas | Gas | 550 (3) | 70.00% | 191 | - |
(1) | "Total Megawatt Capability" is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. |
(2) | Includes an 11.5% leasehold interest held by System Energy. System Energy's Grand Gulf lease obligations are discussed in Note 9 to the consolidated financial statements. |
1. " Total Megawatt Capability" is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
Goodwill
Entergy implemented SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. The implementation of SFAS 142 resulted in the cessation of Entergy's amortization of the remaining plant acquisition adjustment recorded in conjunction with its acquisition of Entergy Gulf States. Goodwill is now subject to impairment testing. The following table is a reconciliation of reported earnings applicable to common stock to earnings applicable to common stock without goodwill amortization for the years ended December 31, 2002, 2001, and 2000:
Nuclear Refueling Outage Costs
Entergy records nuclear refueling outage costs in accordance with regulatory treatment and the matching principle. These refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line. Except for the River Bend plant, the costs are deferred during the outage and amortized over the period to the next outage. In accordance with the regulatory treatment of the River Bend plant, River Bend's costs are accrued in advance and included in the cost of service used to establish retail rates. Entergy Gulf States relieves the accrualaccrued liability when it incurs costs during the next River Bend outage.
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 in the U.S. Utility segment. Although AFUDC increases both the plant balance and earnings, it is realized in cash through depreciation provisions included in rates.
Entergy Corporation and the majority of its subsidiaries file a U.S.United States consolidated federal income tax return. Income taxes are allocated to the subsidiaries in proportion to their contribution to consolidated taxable income. SEC regulations require that no Entergy subsidiary pay more taxes than it would have paid if a separate income tax return had been filed. In accordance with SFAS 109, "Accounting for Income Taxes," deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities, and for certain credits available for carryforward.
Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted.
Investment tax credits are deferred and amortized based upon the average useful life of the related property, in accordance with ratemaking treatment.
Earnings per Share
The following table presents Entergy's basic and diluted earnings per share (EPS) calculation included on the consolidated income statement:
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| For the Years Ended December 31, | ||||||||||||||
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| 2004 |
| 2003 |
| 2002 | ||||||||||
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| $/share |
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| $/share |
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| $/share | ||||
Income before cumulative effect of accounting change |
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Average number of common shares outstanding - basic |
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Average dilutive effect of: |
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Stock Options (1) |
| 4.3 |
| (0.075) |
| 4.1 |
| (0.062) |
| 3.9 |
| (0.046) | ||||
Equity Awards |
| - |
| - |
| 0.2 |
| (0.004) |
| 0.4 |
| (0.005) | ||||
Average number of common shares outstanding - diluted |
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Earnings applicable to common stock |
| $909.5 |
|
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| $926.9 |
|
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| $599.4 |
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Average number of common shares outstanding - basic |
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Average dilutive effect of: |
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Stock Options (1) |
| 4.3 |
| (0.075) |
| 4.1 |
| (0.073) |
| 3.9 |
| (0.046) | ||||
Equity Awards |
| - |
| - |
| 0.2 |
| (0.004) |
| 0.4 |
| (0.005) | ||||
Average number of common shares outstanding - diluted |
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(1) Options to purchase approximately 109,897 and 148,500 shares of common stock at various prices were outstanding at the end of 2002 and 2001, respectively, that were not included in the computation of dilutedearnings per share because the exercise prices were greater than the average market price of the common shares at the end of each of the years presented. At the end of 2000, all outstanding options, totaling 11,468,316, were included in the computation of diluted earnings per share as a result of the average market price of the common shares being greater than the exercise prices.
(1) | Options to purchase approximately 3,319 common stock shares in 2004, 15,231 common stock shares in 2003, and 109,897 common stock shares in 2002 at various prices were outstanding at the end of those years that were not included in the computation of diluted earnings per share because the exercise prices were greater than the common share average market price at the end of each of the years presented. |
Stock-based Compensation Plans
Entergy has two plans that grantgrants stock options to key employees of the Entergy subsidiaries, which areis described more fully in Note 57 to the consolidated financial statements. Prior to 2003, Entergy appliesapplied the recognition and measurement principles of APB Opinion 25, "Accounting for Stock Issued to Employees," and related Interpretations in accounting for those plans. No stock-based employee compensation expense is reflected in 2002 net income as all options granted under thosethe plans have an exercise price equal to the market value of the underlying common stock on the date of grant. BeginningEffective January 1, 2003, Entergy will prospectively applyadopted the fair value based method of accounting for stock options prescribed by SFAS 123, "Accounting for Stock-Based Compensation." Entergy expectsAwards under Entergy's plans vest over three years. Therefore, the effectcost related to stock-based employee compensation included in the determination of applyingnet income for 2004 and 2003 is less than that which would have been recognized if the fair value based method had been applied to be insignificant to its resultsall awards since the original effective date of operations. The effect is less than may be indicated by the pro forma presentation below because Entergy expects prospectively to grant fewer stock options than in recent years, and because the fair value method is being applied prospectively.SFAS 123. The following table illustrates the effect on net income and earnings per share if Entergy would have historically applied the fair value based method of accounting to stock-based employee compensation.
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| For the Years Ended December 31, | ||||
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| 2004 |
| 2003 |
| 2002 |
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| (In Thousands, Except Per Share Data) | ||||
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Earnings applicable to common stock |
| $909,524 |
| $926,943 |
| $599,360 |
Add back: Stock-based compensation expense included in earnings applicable to common stock, net |
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Deduct: Total stock-based employee compensation |
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Pro forma earnings applicable to common stock |
| $897,997 |
| $905,243 |
| $571,250 |
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Earnings per average common share: |
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Basic |
| $4.01 |
| $4.09 |
| $2.69 |
Basic - pro forma |
| $3.96 |
| $3.99 |
| $2.56 |
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Diluted |
| $3.93 |
| $4.01 |
| $2.64 |
Diluted - pro forma |
| $3.88 |
| $3.92 |
| $2.51 |
Application of SFAS 71
The domestic utility companies and System Energy currently account for the effects of regulation pursuant to SFAS 71, "Accounting for the Effects of Certain Types of Regulation." This statement applies to the financial statements of a rate-regulated enterprise that meetmeets three criteria. The enterprise must have rates that (i) are approved by a body empowered to set rates that bind customers (its regulator); (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. If an enterprise meets these criteria, it 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 cost scosts are reflected as regulatory assets in the accompanying financial statements. A significant majority ofo f Entergy's regulatory assets, net of related regulatory and deferred tax liabilities, earn a return on investment during their recovery periods. SFAS 71 requires that rate-regulated enterprises assess the probability of recovering their regulatory assets at each balance sheet date. 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.
SFAS 101, "Accounting for the Discontinuation of Application of FASB Statement No. 71," specifies how an enterprise that ceases to meet the criteria for application of SFAS 71 for all or part of its operations should report that event in its financial statements. In general, SFAS 101 requires that the enterprise report the discontinuation of the application of SFAS 71 by eliminating from its balance sheet all regulatory assets and liabilities related to the applicable segment. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs and therefore no longer qualifies for SFAS 71 accounting, it is possible that an impairment may exist that could require further write-offs of plant assets.
EITF 97-4: "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101" specifies that SFAS 71 should be discontinued at a date no later than when the effects of a transition to competition plan for all or a portion of the entity subject to such plan are reasonably determinable. Additionally, EITF 97-4 promulgates that regulatory assets to be recovered through cash flows derived from another portion of the entity that continues to apply SFAS 71 should not be written off; rather, they should be considered regulatory assets of the segment that will continue to apply SFAS 71.
See Note 2 to the consolidated financial statements for discussion of transition to competition activity in the retail regulatory jurisdictions served by the domestic utility companies. Only Texas has a currently enacted retail open access law, but Entergy believes that significant issues remain to be addressed by regulators, and the enacted law does not provide sufficient detail to reasonably determine the impact on Entergy Gulf States' regulated operations.
Cash and Cash Equivalents
Entergy considers all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at date of purchase to be cash equivalents. Investments with original maturities of more than three months are classified as other temporary investments on the balance sheet.
Investments
Entergy applies the provisions of SFAS 115, "Accounting for Investments for Certain Debt and Equity Securities," in accounting for investments in decommissioning trust funds. As a result, Entergy records the decommissioning trust funds at their fair value on the consolidated balance sheet. As of December 31, 2002 and 2001, the fair valueBecause of the securities heldability of the domestic utility companies and System Energy to recover decommissioning costs in such funds differs from the amounts deposited plus the earnings on the deposits by ($24) millionrates and $93 million, respectively. Inin accordance with the regulatory treatment for decommissioning trust funds, the domestic utility companies and System Energy have recorded an offsetting amount of unrealized gains/(losses) on investment securities in accumulated depreciation.other regulatory liabilities/assets. For the nonregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. System Energy's offsetting amount of unrealized gains/(losses) on investment securities is in other regulatory liabilities.
Decommissioning trust funds for Pilgrim, Indian Point 2, and Vermont Yankee do not receive regulatory treatment. Accordingly, unrealized gains and losses recorded on the assetsasse ts in these trust funds are recognized as a separatein the accumulated other comprehensive income component of shareholders' equity because these assets are classified as available for sale. See Note 15 to the consolidated financial statements for details on the decommissioning trust funds.
Equity Method Investees
Entergy owns investments that are accounted for under the equity method of accounting because Entergy's ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of earnings or losses of the investee based on the change during the period in the estimated liquidation value of the investment, assuming that the investee's assets were to be liquidated at book value. The equity earnings for Entergy-Koch, LP recorded by Entergy are dictated by the terms of the partnership agreement in accordance with the hypothetical liquidation at book value (HLBV) method. In accordance with the HLBV method, earnings are allocated to members based on what each partner would receive from their capital account if, hypothetically, liquidation were to occur at the balance sheet date and amounts distributed were based on recorded book values. Entergy discontinues the recognition of losses on equity investmentsinves tments when its share of losses equals or exceeds its carrying amount of investee plus any advances made or commitments to provide additional financial support. See Note 1312 to the consolidated financial statements for additional information regarding Entergy's equity method investments.
Derivative Financial Instruments and Commodity Derivatives
Entergy implemented SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" on January 1, 2001. The statement Activities,"requires that all derivatives be recognized in the balance sheet, either as assets or liabilities, at fair value.value, unless they meet the normal purchase, normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and if it is, the type of hedge transaction.
For cash-flow hedge transactions in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transaction, changes in the fair value of the derivative instrument are reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income are reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portions of all hedges are recognized in current-period earnings.
Contracts for commodities that will be delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, are not classified as derivatives. These contracts are exempted under the normal purchase, normal sales criteria of SFAS 133. 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.
Effective January 1, 2001,For other contracts for commodities in which Entergy recordedis hedging the variability of cash flows related to a net-of-tax cumulative-effect-type adjustmentvariable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of approximately $18.0 million reducingsuch 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 to recognize, at fair value, all derivative instruments that are designatedreclassified as cash-flow hedging instruments, primarily interest rate swaps and foreign currency forward contracts related to Entergy's competitive businesses. Effective October 1, 2001, Entergy recorded an additional net-of-tax cumulative-effect-type adjustment that increased net income by approximately $23.5 million. This adjustment resulted from the implementation of an interpretation of SFAS 133 that requires fuel supply agreements with volumetric optionality to be classified as derivative instruments. The agreement that resultedearnings in the adjustment isperiods in which earnings are affected by the Energy Commodity Services segment and was disposedvariability of the cash flows of the hedged item. The ineffective portions of all hedges are recognized in the Damhead Creek sale in December 2002.current-period earnings.
Impairment of Long-Lived Assets
Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets. See Note 1211 to the consolidated financial statements for a discussion of current year asset impairments recognized by Entergy in the Energy Commodity Services segment.2002 and 2004.
River Bend AFUDC
The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Gulf States 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 over the estimated remaining economic life of River Bend.
Transition to Competition Liabilities
In conjunction with electric utility industry restructuring activity in Texas, regulatory mechanisms were established to mitigate potential stranded costs. Texas restructuring legislation allowsallowed depreciation on transmission and distribution assets to be directed toward generation assets. The liability recorded as a result of this mechanism is classified as "transition to competition" deferred credits.credits on the balance sheet.
Reacquired Debt
The premiums and costs associated with reacquired debt of the domestic utility companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States) are being amortized over the life of the related new issuances, in accordance with ratemaking treatment.
Foreign Currency Translation
All assets and liabilities of Entergy's foreign subsidiaries are translated into U.S. dollars at the exchange rate in effect at the end of the period. Revenues and expenses are translated at average exchange rates prevailing during the period. The resulting translation adjustments are reflected in a separate component of shareholders' equity. Current exchange rates are used for U.S. dollar disclosures of future obligations denominated in foreign currencies.
New Accounting PronouncementPronouncements
During 2004, Entergy adopted the provisions of FSP 106-2, "Accounting and Disclosure Requirements Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003," which is discussed further in Note 10 to the consolidated financial statements. Entergy also adopted FSP 109-1, "Application of FASB Statement No. 109,Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004" and FSP 109-2, "Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision Within the American Jobs Creation Act of 2004" which are further discussed in Note 3 to the consolidated financial statements.
SFAS 123R, "Share-Based Payment" was issued in December of 2004 and is effective for Entergy at the beginning of the third quarter in 2005. SFAS 123R requires all employers to account for share-based payments at fair value and also provides guidance on determining the assumptions to estimate fair value. SFAS 123R also provides guidance on how to account for differences in the amounts of deferred taxes initially recorded when the options are recorded as expense and the amount of expense deducted on a company's tax return when the options are actually exercised. Entergy began voluntarily expensing its stock options effective January 1, 2003 in accordance with SFAS 148, "Stock-Based Compensation - Transition and Disclosure." Entergy is in the process of evaluating the reporting and disclosure issues resulting from the adoption of SFAS 123R but does not expect the effect of the adoption of this standard to be material to Entergy's financial position or results of operations.
SFAS 151, "Inventory Costs - an amendment of ARB No. 43, Chapter 4" and SFAS 153, "Exchanges of Nonmonetary Assets", were also issued during the fourth quarter of 2004 and are effective for Entergy in 2006 and 2005, respectively. Entergy does not expect the impact of the adoption of these standards to be material.
During 2003, Entergy adopted the provisions of the following accounting standards: SFAS 143, "Accounting for Asset Retirement Obligations," which was implementedis discussed further in Note 8 to the consolidated financial statements; FIN 46, Consolidation of Variable Interest Entities," which is discussed further in Note 5 to the consolidated financial statements; and SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS 150, which became effective July 1, 2003, requires mandatorily redeemable financial instruments to be classified and treated as liabilities in the first quarterpresentation of 2003, requires the recordingfinancial position and results of liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets. These liabilities will be recorded at their fair values (which are likely to be 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.operations. The asset retirement obligation will be accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives of the assets. The netonly effect of implementing this standardSFAS 150 for Entergy is the inclusion of long-term debt and preferred stock with sinking fund under the liabilities caption in Entergy's regulated utilities will be recorded asbalance sheet. Entergy's results of operations and cash flows were not affected by SFAS 150.
During 2003, Entergy also adopted the provisions of the following accounting standards: EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities"; SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" and related interpretations by the Derivatives Implementation Group, and FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees Including Indirect Guarantees of Indebtedness of Others". The adoption of these standards did not have a regulatory asset or liability, with n o resulting impactmaterial effect on Entergy's net income. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking is expected to decrease earnings by approximately $25 million as a result of a one-time cumulative effect of accounting change. For the Non-Utility Nuclear business, the implementation of SFAS 143 is expected to result in a decrease in liabilities of approximately $520 million as a result of the discounting methodology required by SFAS 143, assets are expected to decrease in 2003 by approximately $360 million, and earnings are expected to increase by approximately $160 million as a result of a one-time cumulative effect of accounting change.
financial statements.
NOTE 2. RATE AND REGULATORY MATTERS
Electric Industry Restructuring and the Continued Application of SFAS 71
Although Arkansas and Texas enacted retail open access laws, the retail open access law in Arkansas has now been repealed. Retail open access in Entergy Gulf States' service territory in Texas has been delayed. Entergy believes that significant issues remain to be addressed by regulators, and the enacted law in Texas does not provide sufficient detail to allow Entergy Gulf States to reasonably determine the impact on Entergy Gulf States' regulated operations. Entergy therefore continues to apply regulatory accounting principles to the retail operations of all of the domestic utility companies. Following is a summary of the status of retail open access in the domestic utility companies' retail service territories.
Jurisdiction | Status of Retail Open Access | % of Entergy's | ||
Arkansas | Retail open access |
| 11.6% | |
Texas |
| In July 2004, the PUCT effectively rejected Entergy Gulf States' proposal to implement retail open access in its service territory. In February 2005, bills were submitted in the Texas Legislature that would specify that retail open access will not commence in Entergy Gulf States' |
| 11.8% |
Louisiana |
| 34.1% | ||
Mississippi | The MPSC has recommended not pursuing open access at this time. |
| 10.9% | |
New Orleans | The Council has taken no action on Entergy New Orleans' proposal filed in 1997. |
| 4.5% |
Texas
Retail open access commenced in portions of Texas on January 1, 2002. The staff ofAs ordered by the PUCT, filed a petition to delay retail open access in Entergy Gulf States' service area, andJanuary 2003 Entergy Gulf States reached a settlement agreement with the PUCT to delay retail open access until at least September 15, 2002. In September 2002, the PUCT ordered Entergy Gulf States to file on January 24, 2003 afiled its proposal for an interim solution (retail open access without a FERC-approved RTO) if it appears by January 15, 2003 that a FERC-approved RTO will not be functional by January 1, 2004. On January 24, 2003, Entergy Gulf States filed its proposal,, which among other elements, includes:included:
After considering the proposal, in an April 2003 order the PUCT is expectedset forth a sequence of proceedings and activities designed to consider this proposal on March 21, 2003.
initiate an interim solution. These proceedings and activities included initiating a proceeding to certify an independent organization to administer market protocols and ensure nondiscriminatory access to transmission and distribution systems.
This proposal takes into account that other regulatory approvals, including thatIn July 2004 the PUCT denied Entergy's application to certify Entergy's transmission organization as an independent organization under Texas law. In its order, the PUCT also ordered: the cessation of efforts to develop an interim solution for retail open access in Entergy Gulf States' Texas service territory, termination of the pilot project in that territory, and a delay in retail open access in that territory until either a FERC-approved RTO is in place or some other independent transmission entity is certified under Texas law. Several parties have appealed the termination of the pilot program aspect of the order, claiming the issue was not properly a part of the proceeding.
In February 2005, bills were submitted in the Texas Legislature that would clarify that Entergy Gulf States is no longer subject to a rate freeze and specify that retail open access will not commence in Entergy Gulf States' Texas service territory until the PUCT certifies a power region.
Louisiana
In November 2001, the LPSC decided not to move forward with retail open access for any customers at this time. The LPSC instead directed its staff to hold collaborative group meetings concerning open access from time to time, and to have the SEC, are necessary priorLPSC staff monitor developments in neighboring states and to report to the LPSC regarding the progress of retail access developments in those states. In September 2004, in response to a study funded by certain industrial customers that evaluated a limited industrial-only retail choice program, the LPSC asked the LPSC staff to solicit comments and obtain information from utilities, customers, and other interested parties concerning the potential costs and benefits of a limited choice program, the impact of such a program on other customers, as well as issues such as stranded costs and transmission service. Comments from interested parties were filed with the LPSC on January 1, 2004.14, 2005. The LPSC has not established a procedural framework for consi deration of the comments. At this time, it is not certain what further action, if any, the LPSC might take in response to the information it received.
Regulatory Assets
Other Regulatory Assets
The domestic utility companies and System Energy are subject to the provisions of SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. In addition to the regulatory assets that are specifically disclosed on the face of the balance sheets, the table below provides detail of "Other regulatory assets" that are included on the balance sheets as of December 31, 20022004 and 2001 (in millions).2003:
2004 | 2003 | |||
(In Millions) | ||||
Asset Retirement Obligation - recovery dependent upon timing of decommissioning |
|
| ||
Deferred fuel - non-current - recovered through rate riders when rates are |
|
| ||
Depreciation re-direct - recovery begins at start of retail open access (Note 1) | 79.1 | 79.1 | ||
DOE Decommissioning and Decontamination Fees - recovered through fuel rates until |
|
| ||
Low-level radwaste - recovery timing dependent upon pending lawsuit | 19.4 | 19.4 | ||
Pension costs (Note 10) | 207.3 | 134.0 | ||
Postretirement benefits - recovered through 2013 (Note 10) | 19.1 | 21.5 | ||
Provision for storm damages - recovered through cost of service | 124.5 | 123.3 | ||
Removal costs - recovered through depreciation rates (Note 8) | 53.2 | 45.6 | ||
Resource planning - recovery timing will be determined by the LPSC in a base rate |
|
| ||
River Bend AFUDC - recovered through August 2025 (Note 1) | 37.5 | 39.4 | ||
Sale-leaseback deferral - recovered through June 2014 (Note 9) | 127.3 | 131.7 | ||
Spindletop gas storage facility - recovered through December 2032 | 42.3 | 38.0 | ||
Unamortized loss on reaquired debt - recovered over term of debt | 169.9 | 164.4 | ||
Other - various | 97.0 | 70.1 | ||
Total | $1,429.3 | $1,398.3 |
Deferred fuel costs
The domestic utility companies are allowed to recover certain fuel and purchased power costs through fuel mechanisms included in electric rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is recorded as "Deferred fuel costs" on the domestic utility companies' financial statements. The table below shows the amount of deferred fuel costs as of December 31, 20022004 and 20012003 that has beenEntergy expects to recover or will be recovered or (refunded)(refund) through the fuel mechanisms of the domestic utility companies.companies, subject to subsequent regulatory review.
2002 | 2001 | |
(In Millions) | ||
EntergyArkansas | $ (42.6 ) |
| 2004 |
| 2003 |
| (In Millions) | ||
|
|
|
|
Entergy Arkansas | $7.4 |
| $10.6 |
Entergy Gulf States | $90.1 |
| $118.4 |
Entergy Louisiana | $8.7 |
| $30.6 |
Entergy Mississippi | ($22.8) |
| $89.1 |
Entergy New Orleans | $2.6 |
| ($2.7) |
$ 17.2
Entergy Gulf States
$ 100.6
$ 126.7
Entergy Louisiana
$ (25.6 )
$ (67.5 )
Entergy Mississippi
$ 38.2
$ 106.2
Entergy New Orleans
$ (14.9 )
$ (10.2 )
Entergy Arkansas
Entergy Arkansas' rate schedules include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve monthtwelve-month period commencing on April 1 of each year to develop an annual energy cost rate. The energy cost rate includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year.
As a result of reduced fuel and purchased power costs in 2001 and the accumulated over-recovery of 2001 energy costs, Entergy Arkansas decreased the energy cost rate effective April 2002. In September 2002,March 2004, Entergy Arkansas filed andwith the APSC approved an interim revision to theits energy cost rate effective October 2002 through March 2003. Entergy Arkansas reduced the energy cost rate to offset the accumulated over-recovery of energy costs through June 2002 and the projected over-recovery through December 2002. The revised energy cost rate will be effective through March 2003 when the annual energy cost rate redetermination will be filedrecovery rider for the period April 20032004 through March 2004.2005. The filed energy cost rate, which accounts for 12 percent of a typical residential customer's bill using 1,000 kWh per month, increased 16 percent due primarily to the elimination of a credit contained in the prior year's rate to refund previously over-recovered fuel costs. Also included in the current year's energy cost calculation is a decrease in rates of $3.9 million as a result of the operation of a revised energy allocation method between the retail and wholesale sectors resulting from the APSC's approval of a life-of-resources power purchase agreement with Entergy New Orleans.
Entergy Gulf States (Texas)
In the Texas jurisdiction, Entergy Gulf States' rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, not recovered in base rates. Under the current methodology, semi-annual revisions of the fixed fuel factor aremay be made in March and September based on the market price of natural gas. Entergy Gulf States will likely continue to use this methodology until the start of retail open access.access, which has been delayed. The amounts collected under Entergy Gulf States' fixed fuel factor and any interim surcharge implemented until the date retail open access commences are subject to fuel reconciliation proceedings before the PUCT. In the Texas jurisdiction, Entergy Gulf States' deferred electric fuel costs are $91.8$78.6 million as of December 31, 2002,2004, which includesinclude the following:
| ||
(In Millions) | ||
| ||
Items to be addressed as part of unbundling | $29.0 | |
Imputed capacity charges | $ | |
Other | $ |
The PUCT has ordered that the imputed capacity charges be excluded from fuel rates and therefore recovered through base rates. It is uncertain, however, when or ifEntergy Gulf States filed a baseretail electric rate case and fuel proceeding beforewith the PUCT will be initiated. Thein August 2004. As discussed below, the PUCT dismissed the rate case and fuel reconciliation proceeding in October 2004 indicating that Entergy Gulf States is still subject to a rate freeze based on the current PUCT-approved settlement agreement delayingstipulating that a rate freeze would remain in effect until retail open access commenced in Texas requires aEntergy Gulf States' service territory, unless the rate freeze duringis lifted by the delay period. If Entergy Gulf States goes to retail open access withoutPUCT prior thereto. Without a Texas base rate proceeding, it is possible that Entergy Gulf States will not be allowed to recover these imputed capacity charges.charges in Texas retail rates in the future. Entergy Gulf States believes the PUCT has misinterpreted the settlement and has appealed the PUCT order to the Travis County District Court and also intends to pursue other available remedies as discussed above in"Electric Industry Restructuring and the Continued Application of SFAS 71." The dismissal of the rate case does not preclude Entergy Gulf States from seeking the reconciliation of fuel and purchased power costs of $288 million incurred from September 2003 through March 2004 when, at the appropriate time, similar costs are reconciled in the future.
In January 2001, Entergy Gulf States filed with the PUCT a fuel reconciliation case covering the period from March 1999 through August 2000. Entergy Gulf States was reconciling approximately $583.0$583 million of fuel and purchased power costs. As part of this filing, Entergy Gulf States requested authority to collect $28.0$28 million, plus interest, of under-recovered fuel and purchased power costs. The PUCT decided inIn August 2002, to reducethe PUCT reduced Entergy Gulf States' request to approximately $6.3 million, including interest through July 31, 2002. Approximately $4.7 million of the total reduction to the requested surcharge relates to nuclear fuel costs that the PUCT deferred ruling on at thisthat time. In October 2002, Entergy Gulf States appealed the PUCT's final order in Texas District Court. In its appeal, Entergy Gulf States is challenging the PUCT's disallowance of approximately $4.2 million related to imputed capacity costs and its disallowance related to costs for energy delivered from the 30% non-regulatednon-regulate d share of River Bend. No assurance can be given asThe case was argued before the Travis County Texas District Court in August 2003 and the Travis County District Court judge affirmed the PUCT's order. In October 2003, Entergy Gulf States appealed this decision to the final outcomeCourt of this proceeding.Appeals. Oral argument before the appellate court occurred in September 2004 and the matter is still pending.
In September 2002,2003, Entergy Gulf States filed an application with the PUCT forto implement an $87.3 million interim fuel surcharge, to collect $53.9 million, including interest, and $6.3 million from the January 2001 fuel reconciliation proceeding discussed above, ofto collect under-recovered fuel and purchased power expenses incurred from MarchSeptember 2002 through August 2002.2003. Hearings were held in October 2003 and the PUCT issued an order in December 2003 allowing for the recovery of $87 million. The surcharge was collected over a twelve-month period that began in January 2004.
In March 2004, Entergy Gulf States filed with the PUCT authorized collectiona fuel reconciliation case covering the period September 2000 through August 2003. Entergy Gulf States is reconciling $1.43 billion of fuel and purchased power costs on a Texas retail basis. This amount includes $8.6 million of under-recovered costs that Entergy Gulf States is asking to reconcile and roll into its fuel over/under-recovery balance to be addressed in the amounts requestednext appropriate fuel proceeding. This case involves imputed capacity and River Bend payment issues similar to those decided adversely in the January 2001 proceeding, discussed above, which is now on appeal. On January 31, 2005, the ALJs issued a Proposal for Decision that recommends disallowing $10.7 million (excluding interest) related to these two issues. A final PUCT decision is expected in the first quarter of 2005.
In September 2004, Entergy Gulf States filed an application with the PUCT to implement a $27.8 million interim fuel surcharge, including interest, to collect under-recovered fuel and purchased power expenses incurred from September 2003 through July 2004. Entergy Gulf States proposed to collect the surcharge over an 11-montha six-month period beginning in February 2003. ExpensesJanuary 2005. In December 2004, the PUCT approved the surcharge consistent with Entergy Gulf States' request. Amounts collected through thisthough the interim fuel surcharge, withwhich will be implemented over the exception of expenses already reconciled in prior proceedings,six-month period commencing January 2005, are subject to reviewfinal reconciliation in a future fuel reconciliation proceeding.
Entergy Gulf States Entergy Louisiana,(Louisiana) and Entergy New OrleansLouisiana
TheIn Louisiana, jurisdiction of Entergy Gulf States Entergy Louisiana, and Entergy New OrleansLouisiana recover electric fuel and purchased power costs on a two-month lag. Thefor the upcoming month based upon the level of such costs from the prior month. In Louisiana, jurisdiction of Entergy Gulf States' and Entergy New Orleans'purchased gas rate schedulesadjustments include estimates for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations.reconciliations of actual fuel costs incurred with fuel cost revenues billed to customers.
In August 2000, the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Louisiana pursuant to a November 1997 LPSC general order. The time period that is the subject of the audit is January 1, 2000 through December 31, 2001. In September 2003, the LPSC staff issued its audit report and recommended a disallowance with regard to one item. The issue relates to the alleged failure to uprate Waterford 3 in a timely manner, a claim that also has been raised in the summer 2001, 2002, and 2003 purchased power proceedings. The LPSC staff has submitted several requests for information fromquantified the possible disallowance as between $7.6 and $14 million. Entergy Louisiana and it is expected thatnotified the LPSC staffthat it will issue its audit reportcontest the recommendation. The procedural schedule in the springcase has been suspended. A status conference for the purpose of 2003, following whichestablishing a new procedural schedule will be established.set when the current hearings in the Power Purchase Agreement proceedings at the FERC are concluded. The FERC hear ings in that matter concluded in November 2004. If the LPSC approves the proposed settlement discussed below under"Retail Rate Proceedings", the issue of a proposed imprudence disallowance relating to the uprate will be resolved and will no longer be at issue in this proceeding.
In January 2003, the LPSC openedauthorized its staff to initiate a docketproceeding to investigateaudit the fuel adjustment clause practicesfilings of Entergy Gulf States and its affiliates.affiliates pursuant to a November 1997 LPSC general order. The investigationaudit will include a review of the reasonableness of charges flowed by Entergy Gulf States through its fuel adjustment clause in Louisiana for the period subsequent to 1994. No assurance can be given at this time as toJanuary 1, 1995 through December 31, 2002. Discovery is underway, but a detailed procedural schedule extending beyond the timing or outcome of this proceeding.discovery stage has not yet been established, and the LPSC staff has not yet issued its audit report.
Entergy Mississippi
Entergy Mississippi's rate schedules include an energy cost recovery rider which is adjusted quarterly to reflect accumulated over- or under-recoveries from the second prior quarter. In May 2003, Entergy Mississippi filed and the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Under the MPSC's order, Entergy Mississippi deferred until 2004 the collection of fuel under-recoveries for the first and second quarters of 2003 that would have been collected in the third and fourth quarters of 2003, respectively. The deferred fuel balances asamount of December 31, 2002 and 2001 reflect$77.6 million plus carrying charges was collected through the 24-monthenergy cost recovery of $136.7 million of under-recoveriesrider over a twelve-month period that began in January 2001 as2004.
In January 2005, the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Entergy Mississippi's fuel over-recoveries for the third quarter of 2004 of $21.3 million will be deferred from the first quarter 2005 energy cost recovery rider adjustment calculation. The deferred amount of $21.3 million plus carrying charges will be refunded through the energy cost recovery rider in the second and third quarters of 2005.
Entergy New Orleans
Entergy New Orleans' electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations, including carrying charges. Entergy New Orleans' gas rate schedules include estimates for the MPSC.billing month adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations, including carrying charges. In June and November 2004, the City Council passed resolutions implementing a package of measures developed by Entergy New Orleans and the Council Advisors to protect customers from potential gas price spikes during the 2004 - 2005 winter heating season. These measures include: maintaining Entergy New Orleans' financial hedging plan for its purchase of wholesale gas, and deferral of collection of up to $6.2 million of gas costs associated with a cap on the purchased gas adjustment in November and December 200 4 and in the event that the average residential customer's gas bill were to exceed a threshold level. The deferrals resulting from these caps will receive accelerated recovery over a seven-month period beginning in April 2005.
In November 2004, the City Council directed Entergy New Orleans to confer with the Council Advisors regarding possible modification of the current gas cost collection mechanism in order to address concerns regarding its fluctuations particularly during the winter heating season.
Retail Rate Proceedings
Filings with the APSC (Entergy Arkansas)
March 2002 Settlement Agreement
In May 2002, the APSC approved a settlement agreement submitted by EntergyNo significant retail rate proceedings are pending in Arkansas the APSC staff, and the Arkansas Attorney General. Provisions of the agreement are discussed below under "Retail Rates," "Transition Cost Account," and "December 2000 Ice Storm Cost Recovery."
Retail Rates
As discussed in "December 2000 Ice Storm Cost Recovery" below, Entergy Arkansas was scheduled to file a general rate proceeding in February 2002, in which Entergy Arkansas would have sought an increase in rates. The March 2002 settlement agreement states, however, that Entergy Arkansas will not file an application seeking to increase base rates prior to January 2003.
Transition Cost Account
A 1997 settlement provided for the collection of earnings in excess of an 11% return on equity in a transition cost account (TCA) to offset stranded costs if retail open access were implemented. In May 2002, Entergy Arkansas filed its 2001 earnings evaluation report with the APSC. In June 2002, the APSC approved a contribution of $5.9 million to the TCA. A principal provision in the March 2002 settlement agreement was to offset $137.4 million of ice storm recovery costs with the TCA on a rate class basis. In accordance with the settlement agreement and following the APSC's approval of the 2001 earnings review, Entergy Arkansas filed to return $18.1 million of the TCA to certain large general service class customers that paid more into the TCA than their allocation of storm costs. The APSC approved the return of funds to the large general service customer class in the form of refund checks in Aug ust 2002. As part of the implementation of the March 2002 settlement agreement provisions, the TCA procedure ceased with the 2001 earnings evaluation.
December 2000 Ice Storm Cost Recovery
In mid- and late December 2000, two separate ice storms left 226,000 and 212,500 Entergy Arkansas customers, respectively, without electric power in its service area. Entergy Arkansas filed a proposal to recover costs plus carrying charges associated with power restoration caused by the ice storms. In an order issued in June 2001, the APSC decided not to give final approval to Entergy's proposed storm cost recovery rider outside of a fully developed cost-of-service study in a general rate proceeding. The APSC action resulted in the deferral in 2001 of storm damage costs expensed in 2000 as reflected in Entergy Arkansas' financial statements.
Entergy Arkansas filed its final storm damage cost determination, which reflected costs of approximately $195 million. In the March 2002 settlement, the parties agreed that $153 million of the ice storm costs would be classified as incremental ice storm expenses that can be offset against the TCA, and any excess of ice storm costs over the amount available in the TCA would be deferred and amortized over 30 years, although such excess costs were not allowed to be included as a separate component of rate base. The allocated ice storm expenses exceeded the available TCA funds by $15.8 million and was recorded as a regulatory asset in June 2002. Of the remaining ice storm costs, $32.2 million will be addressed throughestablished ratemaking procedures, including $22.2 millionclassified as capital additions. $3.8 million of the ice storm costs will not be recovered through rates.
at this time.
Filings with the PUCT and Texas Cities
(Entergy Gulf States)
Retail Rates
Entergy Gulf States is operating in Texas under the terms of a June 1999December 2001 settlement agreement.agreement approved by the PUCT. The settlement provided for a base rate freezerates that hashave remained in effect during the delay in the implementation of retail open access in Entergy Gulf States' Texas service territory. In view of the PUCT order in July 2004 to further delay retail open access in the Texas service territory, Entergy Gulf States filed a retail electric rate case and fuel reconciliation proceeding with the PUCT in August 2004 seeking the following:
In addition, Entergy Gulf States' fuel reconciliation filing made in conjunction with the base rate case sought to reconcile approximately $288 million in fuel and purchased power costs incurred during the period September 2003 through March 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case and fuel reconciliation proceeding indicating that Entergy Gulf States is still subject to a rate freeze based on a PUCT-approved agreement in 2001 stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless the rate freeze is lifted by the PUCT prior thereto. Entergy Gulf States believes the PUCT has misinterpreted the settlement and has appealed the PUCT order to the Travis County District Court and intends to pursue other available remedies.
In February 2005, bills were submitted in the Texas Legislature that would clarify that Entergy Gulf States is no longer subject to a rate freeze and specify that retail open access will not commence in Entergy Gulf States' Texas service territory until the PUCT certifies a power region.
Recovery of River Bend Costs
In March 1998, the PUCT disallowed recovery of $1.4 billion of company-wide abeyed River Bend plant costs, which have been held in abeyance since 1988. Entergy Gulf States appealed the PUCT's decision on this matter to the Travis County District Court in Texas. A 1999 settlement agreement limits potential recovery of the remaining plant asset to $115 million as of January 1, 2002, less depreciation after that date. Entergy Gulf States accordingly reduced the value of the plant asset in 1999. Entergy Gulf States has also agreed in a subsequent settlement that it will not seek recovery of the abeyed plant costs through any additional charge to Texas ratepayers. In an interim order approving this agreement, however, the PUCT recognized that any additional River Bend investment found prudent, subject to the $115 million cap, could be used as an offset against stranded benefits, shoul d legislation be passed requiring Entergy Gulf States to return stranded benefits to retail customers.
In April 2002, the Travis County District Court issued an order affirming the PUCT's order on remand disallowing recovery of the abeyed plant costs. Entergy Gulf States has appealed this ruling to the Third District Court of Appeals. TheIn July 2003, the Third District Court of Appeals heard oral argumentunanimously affirmed the judgment of the Travis County District Court. After considering the progress of the proceeding in November 2002 but has not yet issuedlight of the decision of the Court of Appeals, Entergy Gulf States accrued for the loss that would be associated with a final, decision.non-appealable decision disallowing the abeyed plant costs. The financial statement impactnet carrying value of the retail rate settlement agreement on the remaining abeyed plant costs will ultimately depend on several factors, includingwas $107.7 million at the possible discontinuancetime of SFAS 71 accounting treatment forthe Court of Appeals decision. Accrual of the $107.7 million loss was recorded in the second quarter of 2003 as miscellaneous other income (deductions) and reduced net income by $65.6 million after-tax. In September 2004, the Texas generation business, the determination of the market value of generation assets,Supreme Court denied Entergy Gulf States' petition for review, and any future legislation in Texas addressing the pass-through or sharing of any stranded benefits with Texas ratepayers. While Entergy Gulf States expects to prevail in its lawsuit, no assurance can be given that additional reserves or write-offs will not be required infiled a motion for rehearing. In February 2005, the future.
Texas Supreme Court denied the motion for rehearing, and the proceeding is now final.
Filings with the LPSC
Proposed Settlement
In September 2004, the LPSC consolidated various dockets that were the subject of settlement discussions between the LPSC staff and Entergy Gulf States and Entergy Louisiana. The LPSC directed its staff to continue the settlement discussions and submit any proposed settlement to the LPSC for its consideration. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement that currently includes an offer to refund $76 million to Entergy Gulf States' Louisiana customers, with no immediate change in current base rates and to refund $14 million to Entergy Louisiana's customers. If the LPSC approves the proposed settlement, Entergy Gulf States will be regulated under a three-year formula rate plan that, among other provisions, establishes an ROE mid-point of 10.65% and permits Entergy Gulf States to recover incremental capacity costs without filing a traditional base rate proceeding. The sett lement resolves all issues in, and will result in the dismissal of, Entergy Gulf States' fourth, fifth, sixth, seventh, and eighth annual earnings reviews, Entergy Gulf States' ninth post-merger earnings review and revenue requirement analysis, a fuel review for Entergy Gulf States, dockets established to consider issues concerning power purchases for both Entergy Gulf States and Entergy Louisiana for the summers of 2001, 2002, 2003, and 2004, and a docket concerning retail issues arising under the Entergy System Agreement. The settlement does not include the System Agreement case pending at FERC. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.
Annual Earnings Reviews (Entergy Gulf States)
In May 2002, Entergy Gulf States filed its ninth and last required post-merger analysis with the LPSC. The filing included an earnings review filing for the 2001 test year that resulted in a rate decrease of $11.5 million, which was implemented effective June 2002. In its latest testimony, in December 2003, the LPSC staff recommended a rate refund of $30.6 million and a prospective rate reduction of approximately $50 million. Hearings concluded in May 2004. Should the LPSC approve the proposed settlement discussed above, the ninth post-merger analysis would be resolved.
In December 2002, the LPSC approved a settlement between Entergy Gulf States and the LPSC staff pursuant to which Entergy Gulf States agreed to make a base rate refund of $16.3 million, including interest, and to implement a $22.1 million prospective base rate reduction effective January 2003. The settlement discharged any potential liability relatingfor claims that relate to remaining issues that arose in Entergy Gulf States' fourth, fifth, sixth, seventh, and eighth post-merger earnings reviews.reviews, with the exception of certain issues related to the calculation of the River Bend Deregulated Asset Plan percentage. Entergy Gulf States made the refund in February 2003. Should the LPSC approve the proposed settlement discussed above, the outstanding issue in these proceedings would be resolved.
Retail Rates
(Entergy Louisiana)
In addition to resolving and discharging all liability associatedJanuary 2004, Entergy Louisiana made a rate filing with the fourth through eighth earnings reviews, the settlement provides that Entergy Gulf States shall be authorized to continue to reflect in ratesLPSC requesting a ROE of 11.1% until a different ROE is authorized by a final resolution disposing of all issues in the proceeding that was commenced with Entergy Gulf States' May 2002 filing.
In May 2002, Entergy Gulf States filed its ninth and last required post-merger analysis with the LPSC. The filing included an earnings review filing for the 2001 test year that resulted in a rate decrease of $11.5 million, which was implemented effective June 2002. The filing also contained a prospective revenue requirement study based on the 2001 test year that shows that a prospectivebase rate increase of approximately $21.7$167 million. In that filing, Entergy Louisiana noted that approximately $73 million would be appropriate. Both components of the base rate increase was attributable to the acquisition of a generating station and certain power purchase agreements that, based on current natural gas prices, would produce fuel and purchased power savings for customers that substantially mitigate the impact of the requested base rate increase. The filing are subjectalso requested an allowed ROE of 11.4%. Entergy Louisiana's previously authorized ROE mid-point currently in effect is 10.5%. Hearings concluded in December 2004. Based on the evidence submitted at the hearing, the LPSC staff is recommending approximately a $7 million base rate increase. The LPSC staff proposed the implementation of a formula rate plan that includes a provision for the recovery of incremental capacity costs, including those related to reviewthe proposed Perryvil le acquisition, without filing a traditional base rate proceeding. A decision by the LPSC and may resultis expected in changes in rates other than those sought in the filing. A procedural schedule has been adopted and hearings are scheduled for October 2003.
Formula Rate Plan Filings (Entergy Louisiana)
In July 2002, the LPSC approved a settlement between Entergy Louisiana and the LPSC Staff in Entergy Louisiana's 2000 and 2001 formula rate plan proceedings. Entergy Louisiana agreedmid- to a $5 million rate reduction effective August 2001. The prospective rate reduction was implemented beginning in August 2002 and the refund for the retroactive period occurred in September 2002. As part of the settlement, Entergy Louisiana's current rates, including its previously authorized ROE midpoint of 10.5%, remain in effect until changed pursuant to a new formula rate plan filing or a revenue requirement analysis to be filed by June 30, 2003.
In May 1997, Entergy Louisiana made its second annual performance-based formula rate plan filing with the LPSC for the 1996 test year. This filing resulted in a rate reduction of approximately $54.5 million, which was implemented in July 1997. At the same time, rates were reduced by an additional $0.7 million and by an additional $2.9 million effective March 1998. Upon completion of the hearing process in December 1998, the LPSC issued an order requiring an additional rate reduction and refund based upon the LPSC's contention that it could interpret and enforce a FERC rate schedule. The resulting amounts were not quantified, although they are expected to be immaterial. Entergy Louisiana appealed this order and obtained a preliminary injunction pending a final decisionlate-March 2005 on appeal. The Louisiana Supreme Court rendered a non-unanimous decision in April 2002 affirming the LPSC's order. Ente rgy Louisiana filed with the U.S. Supreme Court an application for writ of certiorari, which application was supported by an amicus curiae brief filed on behalf of the United States of America by the Solicitor General and the General Counsel and Solicitor for the FERC. The U.S. Supreme Court granted certiorari in January 2003, and the case will be argued during the last week of April 2003.
these issues.
Filings with the MPSC
(Entergy Mississippi)
Formula Rate Plan Filings
Pursuant to Entergy Mississippi's annual performance-based formula rate plan filing for the 2001 test year, the MPSC approved a stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi. The stipulation provided for a $1.95 million rate increase effective in May 2002.
In August 2002, Entergy Mississippi filedis operating under a rate case with the MPSC requesting a $68.8 million rate increase effective January 2003. Entergy Mississippi requested this increase as a result of capital investments and operation and maintenance expenditures necessary to replace and maintain aging electric facilities and to improve reliability and customer service. In December 2002 order issued by the MPSC issued a final order approving a joint stipulation entered into by Entergy Mississippi and the Mississippi Public Utilities Staff in October 2002. The final order results in a $48.2 million rate increase, or about a 5.3% increase in overall retail revenues, which is based on an ROE of 11.75%.MPSC. The order endorsed a new power management rider schedule designed to more efficiently collect capacity portions of purchased power costs. Also, the order provides for improvements in the return on equity formula and more robust performance measures forEntergyforEntergy Mississippi's formula rate plan. Under the provisions of Entergy Mississippi's formula rate plan, a bandwidth is placed around the order,benchmark ROE, and if Entergy Mississippi earns outside of the bandwidth (as well as outside of a range-of-no-change at each edge of the bandwidth), then Entergy Mississippi's rates will makebe adjusted, though on a prospective basis only. Under Mississippi law and Entergy Mississippi's formula rate plan, however, if Entergy Mississippi's earned ROE is above the top of the range-of-no-change at the top of the formula rate plan bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the point halfway between such earned ROE and the top of the bandwidth; and Entergy Mississippi's retail rates are set at that halfway-point ROE level. In the situation where Entergy Mississippi's earned ROE is not above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the top of the range-of-no-change at the top of the bandwidth.
Entergy Mississippi made its nextannual formula rate plan filing duringwith the MPSC in March 2004.
2004 based on a 2003 test year. In April 2004, the MPSC approved a joint stipulation entered into between the Mississippi Public Utilities Staff and Entergy Mississippi that provides for no change in rates based on a performance adjusted return on common equity mid-point of 10.77%, establishing an allowed regulatory earnings range of 9.3% to 12.2%.
Filings with the Council
(Entergy New Orleans)
Rate Proceedings
In May 2002,2003, the City Council approved a resolution allowing for a total increase of $30.2 million in electric and gas base rates effective June 1, 2003. In April 2004, Entergy New Orleans filed a cost of service study and revenue requirement filingmade filings with the City Council foras required by the 2001 test year. The filing indicated that a revenue deficiency existsearnings review process prescribed by the Gas and that a $28.9 million electric rate increase and a $15.3 million gas rate increase are appropriate. Additionally, Entergy New Orleans has proposed a $6.0 million public benefit fund. The City Council has established a procedural schedule for consideration of the filing and hearings are scheduled to begin in May 2003. The procedural schedule provides for the City Council's decision with respect to Entergy New Orleans' filing by June 15, 2003. On March 13, 2003, Entergy New Orleans and the Advisors to the City Council presented to the City Council an agreement in principle that, ifElectric Formula Rate Plans approved by the City Council would resolve the proceeding. The agreement in principle, if approved by2003. In August 2004, the City Council would result in a $30.2 million base rate increase forapproved an unopposed settlement among Entergy New Orleans. A procedural schedule forOrleans, the City Council's consideration ofCouncil Advisors, and the agreementintervenors in principle has not been established.connection with the Gas and Electric Formula Rate Plans. In accordance with the resolution approving the settlement agreement, Entergy New Orleans' gas and electric base rates will remain at their current level untilunchanged from the earlier of a decisionlevels set in the proceeding or June 15,May 2003.
Natural Gas
In a The resolution adopted in August 2001, the City Council ordered Entergy New Orleans to account for $36defer $3.9 million of certain natural gasrelating to voluntary severance plan costs chargedallocated to its electric operations and $1.0 million allocated to its gas distribution customers from July 1997 through May 2001. The resolution suggests that refunds mayoperations, which amounts were accrued on its books in 2003, and to record on its books regulatory assets in those amounts to be due to the gas distribution customers ifamortized over five years effective January 2004. Entergy New Orleans cannot account satisfactorily for these costs. Entergy New Orleans filedalso was ordered to defer $6.0 million of fossil plant maintenance e xpense incurred in 2003 and to record on its books a responseregulatory asset in that amount to the City Council in September 2001, which is still being evaluated by the City Council. Entergy New Orleans has documentedbe amortized over a full reconciliation for the natural gas costs during that period. Entergy New Orleans has filed for a hearing on this matter. The presentation made to the City Council on March 13, 2003 regarding the agreement in principle that would resolve Entergy New Orleans' rate proceeding also included proposed terms for resolution of this proceeding, if approved by the City Council. A procedural schedule for consideration of the agreement has not been established. The ultimate outcome of the proceeding cannot be predicted at this time.
five-year period effective January 2003.
Fuel Adjustment Clause Litigation
In April 1999, a group of ratepayers filed a complaint against Entergy New Orleans, Entergy Corporation, Entergy Services, and Entergy Power in state court in Orleans Parish purportedly on behalf of all Entergy New Orleans ratepayers. The plaintiffs seek treble damages for alleged injuries arising from the defendants' alleged violations of Louisiana's antitrust laws in connection with certain costs passed on to ratepayers in Entergy New Orleans' fuel adjustment filings with the City Council. In particular, plaintiffs allege that Entergy New Orleans improperly included certain costs in the calculation of fuel charges and that Entergy New Orleans imprudently purchased high-cost fuel from other Entergy affiliates. Plaintiffs allege that Entergy New Orleans and the other defendant Entergy companies conspired to make these purchases to the detriment of Entergy New Orleans' r atepayersratepayers and to the benefit of Entergy's shareholders, in violation of Louisiana's antitrust laws. Plaintiffs also seekse ek to recover interest and attorneys' fees. Entergy filed exceptions to the plaintiffs' allegations, asserting, among other things, that jurisdiction over these issues rests with the City Council and FERC. In March 2004, the plaintiffs supplemented and amended their petition. If necessary, at the appropriate time, Entergy will also raise its defenses to the antitrust claims. At present, theThe suit in state court ishas been stayed by stipulation of the parties.parties pending a decision by the City Council in the proceeding discussed in the next paragraph.
Plaintiffs also filed this complaint with the City Council in order to initiate a review by the City Council of the plaintiffs' allegations and to force restitution to ratepayers of all costs they allege were improperly and imprudently included in the fuel adjustment filings. Testimony was filed on behalf of the plaintiffs in this proceeding in April 2000 and has been supplemented. The testimony, as supplemented, asserts,asserting, among other things, that Entergy New Orleans and other defendants have engaged in fuel procurement and power purchasing practices and included costs in Entergy New Orleans' fuel adjustment that could have resulted in Entergy New Orleans customers being overcharged by more than $100 million over a period of years. In June 2001, the City Council's advisors filed testimony on these issues in which they allege that Entergy New Orleans ratepayers may have been overcharged by more than $32 million, the vast majority of which is reflected in the plaintiffs' claim. However, it is not clear precisely what periods and damages are being alleged in the proceeding. Entergy intends to defend this matter vigorously, both in court and before the City Council. Hearings were held in February and March 2002. The parties have submitted post-hearing briefs and the matter has been submitted toIn February 2004, the City Council forapproved a decision. In October 2002,resolution that resulted in a refund to customers of $11.3 million, including interest, during the plaintiffs filed a motion to re-openmonths of June through September 2004. The resolution concludes, among other things, that the evidentiary record does not support an allegation tha t Entergy New Orleans' actions or inactions, either alone or in concert with Entergy or any of its affiliates, constituted a misrepresentation or a suppression of the alternative, a motiontruth made in order to obtain an unjust advantage of Entergy New Orleans, or to cause loss, inconvenience, or harm to its ratepayers. Management believes that it has adequately provided for a new trial seeking to re-open the record to accept certain testimony filed byliability associated with this proceeding. The plaintiffs have appealed the City Council advisors in a separate proceeding at the FERC. The ultimate outcome of the lawsuit and the City Council proceeding cannot be predicted at this time.
System Energy's 1995 Rate Proceeding
System Energy applied to FERC in May 1995 for a rate increase, and implemented the increase in December 1995. The request sought changes to System Energy's rate schedule, including increases in the revenue requirement associated with decommissioning costs, the depreciation rate, and the rate of return on common equity. The request proposed a 13% return on common equity. In July 2000, FERC approved a rate of return of 10.58% for the period December 1995resolution to the date of FERC's decision, and prospectively adjusted the rate of return to 10.94% from the date of FERC's decision. FERC's decision also changed other aspects of System Energy's proposed rate schedule, including the depreciation rate and decommissioning costs and their methodology. FERC accepted System Energy's compliance tariffstate court in November 2001. System Energy made refunds to the domestic utility companies in December 2001.
In accordance with regulatory accounting principles, during the pendency of the case, System Energy recorded reserves for potential refunds against its revenues. Upon the order becoming final, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans and System Energy recorded entries to spread the impacts of FERC's order to the various revenue, expense, asset, and liability accounts affected, as if the order had been in place since commencement of the case in 1995. System Energy also recorded an additional reserve amount against its revenue, to adjust its estimate of the impact of the order, and recorded additional interest expense on that reserve. System Energy also recorded reductions in its depreciation and its decommissioning expenses to reflect the lower levels in FERC's order, and reduced tax expense affected by the order.
Entergy Arkansas refunded $54.3 million, including interest, through the issuance of refund checks in March 2002 as approved by the APSC.
Entergy Louisiana refunded $4.9 million, including interest, to its customers through a creditParish. Oral argument on the September 2002 bills as approved by the LPSC.
Entergy Mississippi's allocation of the proposed System Energy wholesale rate increaseplaintiffs' appeal was $21.6 million annually. In July 1995, Entergy Mississippi filed a schedule with the MPSC that deferred the retail recovery of the System Energy rate increase. The deferral plan, which was approved by the MPSC, began in December 1995, the effective date of the System Energy rate increase, and was effective until the issuance of the final order by FERC. Entergy Mississippi revised the deferral plan two times during the pendency of the System Energy proceeding. As a result of the final resolution of the FERC order and in accordance with Entergy Mississippi's second revised deferral plan, refunds to Entergy Mississippi from System Energy, including interest, have been credited against deferral balances and a refund of the remaining $14.8 million in excess of the deferr al balances were included as credits to the amounts billed to Entergy Mississippi's customers in October 2001 through September 2002 under its Grand Gulf Riders.
Entergy New Orleans' allocation of the proposed System Energy wholesale rate increase was $11.1 million annually. In February 1996, Entergy New Orleans filed a plan with the Council to defer 50% of the amount of the System Energy rate increase. In December 2001, the Council approved a refund to customers. The total amount of the refund to Entergy New Orleans' customers was $43 million. In anticipation of the FERC order, Entergy New Orleans advanced the refunding of $10 millionconducted in February 2001 to customers to assist with unexpected high energy bills. The total refund was also reduced by an additional $6 million which was used for the establishment of a public benefits and payments assistance program. The remaining $27 million was refunded through the issuance of refund checks during the first quarter of 2002.
FERC Settlement
In November 1994, FERC approved an agreement settling a long-standing dispute involving income tax allocation procedures of System Energy. In accordance with the agreement, System Energy has been refunding a total of approximately $62 million, plus interest, to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans through June 2004. System Energy also reclassified from utility plant to other deferred debits approximately $81 million of other Grand Gulf 1 costs. Although such costs are excluded from rate base, System Energy is amortizing and recovering these costs over a 10-year period. Interest on the $62 million refund and the loss of the return on the $81 million of other Grand Gulf 1 costs is reducing Entergy's and System Energy's net income by approximately $10 million annually.
2005.
NOTE 3. INCOME TAXES
Income tax expenses for 2002, 2001,2004, 2003, and 20002002 consist of the following (in thousands):following:
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
Current: | ||||||
Federal (a)(b) | $54,380 |
| ($731,129) | $510,109 | ||
Foreign | (2,231) |
| 8,284 | (3,295) | ||
State (a)(b) | 38,301 |
| 23,396 |
| 43,788 | |
Total (a)(b) | 90,450 | (699,449) | 550,602 | |||
Deferred -- net | 296,445 |
| 1,307,092 | (233,532) | ||
Investment tax credit |
| |||||
adjustments -- net | (20,987) |
| (27,644) |
| (23,132) | |
Recorded income tax expense | $365,908 | $579,999 | $293,938 |
(a) | The actual cash taxes paid were $28,241 in 2004, $188,709 in 2003, and $57,856 in 2002. Entergy Louisiana's mark-to-market tax accounting election significantly reduced taxes paid in 2002. In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts. The most significant of these is the contract to purchase power from the Vidalia project (the contract is discussed in Note 8 to the consolidated financial statements). The new tax accounting method has provided a cumulative cash flow benefit of approximately $790 million through 2004, which is expected to reverse in the years 2005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. Approximately half of the consolidated cash flow benefit of the election occurred in 2001 and the remainder occurred in 2002. |
(b) | In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $2.95 billion deduction on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. On a consolidated basis, a $74 million cash tax benefit was realized in 2004. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. |
(a) The actual cash taxes paid/(received) were $57,856 in 2002, ($113,466) in 2001, and $345,361 in 2000. Entergy Louisiana's mark to market tax accounting election has significantly reduced taxes paid in 2001 and 2002. For a more detailed discussion of the tax accounting election, see the discussion of Entergy Louisiana Tax Accounting Election in Management's Financial Discussion and Analysis section.
Total income taxes differ from the amounts computed by applying the statutory income tax rate to income before taxes. The reasons for the differences for the years 2004, 2003, and 2002 2001,are:
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
Computed at statutory rate (35%) | $454,635 | $535,663 | $320,954 | |||
Increases (reductions) in tax | ||||||
resulting from: | ||||||
State income taxes net of | ||||||
federal income tax effect | 36,185 | 54,024 | 44,835 | |||
Regulatory differences- | ||||||
utility plant items | 41,240 | 52,638 | 29,774 | |||
Amortization of investment | ||||||
tax credits | (20,596) | (24,364) | (22,294) | |||
EAM capital loss | (86,426) | - | - | |||
Flow-through/permanent | ||||||
differences | (42,902) | (30,221) | (38,197) | |||
US tax on foreign income | 2,014 | 7,888 | (28,416) | |||
Other -- net | (18,242) | (15,629) | (12,718) | |||
Total income taxes | $365,908 | $579,999 | $293,938 | |||
Effective Income Tax Rate | 28.2% | 37.9% | 32.1% |
The EAM capital loss is a tax benefit resulting from the sale of preferred stock and 2000 are (in thousands):less than 1% of the common stock of Entergy Asset Management, an Entergy subsidiary. In December 2004, an Entergy subsidiary sold the stock to a third party for $29.75 million. The sale resulted in a capital loss for tax purposes of $370 million, producing a federal and state net tax benefit of $97 million that Entergy recorded in the fourth quarter of 2004. Entergy has established a contingency provision in its financial statements that management believes will sufficiently cover the risk associated with this issue.
Significant components of net deferred and noncurrent accrued tax liabilities as of December 31, 20022004 and 20012003 are as follows (in thousands):follows:
2004 | 2003 | |||
(In Thousands) | ||||
Deferred and Noncurrent Accrued Tax Liabilities: | ||||
Net regulatory liabilities | ($978,815) | ($1,072,898) | ||
Plant-related basis differences | (4,699,803) | (3,574,593) | ||
Power purchase agreements | (972,348) | (945,495) | ||
Nuclear decommissioning | (545,109) | (519,028) | ||
Other | (346,993) | (379,875) | ||
Total | (7,543,068) | (6,491,889) | ||
Deferred Tax Assets: | ||||
Accumulated deferred investment | ||||
tax credit | 133,979 | 141,723 | ||
Capital losses | 134,688 | 92,423 | ||
Net operating loss carryforwards | 1,201,006 | 129,122 | ||
Sale and leaseback | 227,155 | 223,134 | ||
Unbilled/deferred revenues | 28,741 | 18,983 | ||
Pension-related items | 247,662 | 204,083 | ||
Reserve for regulatory adjustments | 131,112 | 138,933 | ||
Customer deposits | 107,652 | 108,591 | ||
Nuclear decommissioning | 158,796 | 272,551 | ||
Other | 225,659 | 399,080 | ||
Valuation allowance | (43,864) | (39,210) | ||
Total | 2,552,586 | 1,689,413 | ||
| ||||
Net deferred and noncurrent accrued tax liability | ($4,990,482) | ($4,802,476) |
AtDecember 31, 2004, Entergy had $342.4 million in net realized federal capital loss carryforwards that will expire as follows: $103.8 million in 2007, $10.6 million in 2008, and $228.0 million in 2009.
At December 31, 2004, Entergy had federal net operating loss carryforwards of $2.9 billion. If the federal net operating loss carryforwards are not utilized, they will expire in the years 2023 through 2024.
At December 31, 2004, Entergy had state net operating loss carryforwards of $3.5 billion, primarily resulting from Entergy Louisiana's mark-to-market tax election and the change in method of accounting for tax purposes related to cost of goods sold, as discussed above. If the state net operating loss carryforwards are not utilized, they will expire in the years 2008 through 2019.
The 20022004 and 2003 valuation allowance isallowances are provided against UK capital loss and UK net operating loss carryforwards, whichand certain state net operating loss carryforwards. The UK losses can be utilized against future UK taxable income. For UK tax purposes, these carryforwards do not expire.
On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was enacted. The 2001 valuation allowance is provided primarily againstAct promotes domestic production and investing activities by providing a number of tax incentives including a temporary incentive to repatriate accumulated foreign earnings, subject to certain limitations, by providing an 85% dividends received deduction for certain repatriated earnings and also providing a tax credit carryforwards,deduction of up to 9% of qualifying production activities. In 2004, Entergy repatriated $64 million of accumulated foreign earnings, which can be utilized against future United States taxes on foreign source income. If these carryforwards are not utilized, they will expire between 2002 and 2006.
resulted in approximately $16.1 million of tax benefit. At December 31, 2002,2004, Entergy had $11.2has approximately $7.4 million of indefinitely reinvested undistributed earnings from subsidiary companies outside the U.S. Upon distribution ofUnited States that are being considered for repatriation. If these earnings are repatriated in accordance with the Act, the repatriation would result in approximately $1.5 million of income tax expense. In accordance with FSP 109-1, which was issued by the FASB to address the accounting for the impacts of the Act, the allowable production tax credit will be treated as a special deduction in the formperiod in which it is deducted rather than treated as a tax rate change during 2004 which is the period in which the Act was signed into law. The adoption of dividends or otherwise, Entergy could be subjectFSP 109-1 and FSP 109-2, also issued by the FASB to U.S. income taxes (subject to foreign tax credits) and withholding taxes payable to various foreign countries.
address the accounting for the repatriation provisions of the Act, did not have a material effect on Entergy's financial statements.
NOTE 4. LINES OF CREDIT AND RELATED SHORT-TERM BORROWINGS
Entergy Corporation has in place two separate revolving credit facilities, a 364-day bank5-year credit facility withand a 3-year credit facility. The 5-year credit facility, which expires in December 2009, has a borrowing capacity of $1.450 billion,$500 million, none of which $535was outstanding at December 31, 2004. The 3-year credit facility, which expires in May 2007, has a borrowing capacity of $965 million, of which $50 million was outstanding as ofat December 31, 2002. The weighted-average interest rate on Entergy's outstanding borrowings under this2004. Entergy also has the ability to issue letters of credit against the total borrowing capacity of both credit facilities, and $50 million had been issued against the 3-year facility as ofat December 31, 2002 and 2001 was 2.5% and 3.2%, respectively.2004. The commitment fee for this facilitythese facilities is currently 0.20%0.13% of the line amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior debt ratings of the domestic utility companies.
Although the Entergy Corporation credit facility expires in May 2003, Entergy has the discretionary option to extend the period to repay the amount then outstanding for an additional 364-day term. Because of this option, which Entergy intends to exercise if it does not renew the credit line or obtain an alternative source of financing, the debt outstanding under the credit line is reflected in long-term debt on the balance sheet. The credit line is reflected as notes payable at December 31, 2001. Entergy Corporation's facility requiresfacilities require it to maintain a consolidated debt ratio of 65% or less of its total capitalization.capitalization, and maintain an interest coverage ratio of 2 to 1. If Entergy's debt ratio exceeds this limit,Entergy fails to meet these limits, or if Entergy or the domestic utility companies default on other credit facilitiesindebtedness or are in bankruptcy or insolvency proceedings, an acceleration of the facility's maturity date may occur.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans each have 364-day credit facilities available as follows:
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| Amount of | Amount Drawn as | |||
Entergy Arkansas | April 2005 | $85 million | - | |||
Entergy Louisiana | April 2005 | $15 million(a) | - | |||
Entergy Mississippi | May 2005 | $25 million | - | |||
Entergy New Orleans | April 2005 | $14 million(a) | - |
The 364-day credit facilities have variable interest rates and the average commitment fee is 0.13%. The Entergy Arkansas facility requires it to maintain total shareholder's equity of at least 25% of its total assets.
The short-term borrowings of Entergy's subsidiaries are limited to amounts authorized by the SEC. The current limits authorized are effective through November 30, 2004.2007. In addition to borrowing from commercial banks, Entergy's subsidiaries are authorized under the SEC order to borrow from the Entergy System Money Pool (money pool).Entergy's money pool. The money pool is an inter-company borrowing arrangement designed to reduce Entergy's subsidiaries' dependence on external short-term borrowings. Borrowings from the money pool and external borrowings combined may not exceed the SEC authorized limits. As of December 31, 2002,2004, Entergy's subsidiaries' aggregate authorized limit was $1.6 billion and the aggregate outstanding borrowing from the money pool was $61.5$151.6 million. There were no borrowings outstanding from external sources. Under the SEC order and without further SEC authorization, the domestic utility companies and System Energy cannot issue new short-term indebtedness unless (a) Entergy and the borrower each mainta in common equity of at least 30% of its capital and, (b) with the exception of money pool borrowings, the debt security to be issued (if rated) and all outstanding securities of the issuer and Entergy Corporation that are rated must be rated investment grade. There is further discussion of commitments for long-term financing arrangements in Note 5 to the consolidated financial statements.
The short-term securities issuances of Entergy Corporation also are limited to amounts authorized by the SEC. Under its current SEC order and without further SEC authorization, Entergy Corporation cannot incur additional indebtedness or issue other securities unless (a) it and each of its public utility subsidiaries maintain a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of Entergy Corporation that are rated are rated investment grade.
NOTE 5. LONG - TERM DEBT
Long-term debt as of December 31, 2004 and 2003 consisted of:
2004 | 2003 | ||
(In Thousands) | |||
Mortgage Bonds: | |||
8.25% Series due April 2004 - Entergy Gulf States | $- | $292,000 | |
6.2% Series due May 2004 - Entergy Mississippi | - | 75,000 | |
6.125% Series due July 2005 - Entergy Arkansas | 100,000 | 100,000 | |
8.125% Series due July 2005 - Entergy New Orleans | 30,000 | 30,000 | |
6.77% Series due August 2005 - Entergy Gulf States | 98,000 | 98,000 | |
Libor + 0.90% Series due June 2007 - Entergy Gulf States | - | 275,000 | |
4.875% Series due October 2007 - System Energy | 70,000 | 70,000 | |
5.2% Series due December 2007 - Entergy Gulf States | - | 200,000 | |
6.5% Series due March 2008 - Entergy Louisiana | - | 115,000 | |
4.35% Series due April 2008 - Entergy Mississippi | 100,000 | 100,000 | |
6.45% Series due April 2008 - Entergy Mississippi | - | 80,000 | |
3.6% Series due June 2008 - Entergy Gulf States | 325,000 | 325,000 | |
3.875% Series due August 2008 - Entergy New Orleans | 30,000 | 30,000 | |
Libor + 0.40% Series due December 2009 - Entergy Gulf States | 225,000 | - | |
4.65% Series due May 2011 - Entergy Mississippi | 80,000 | - | |
4.875% Series due November 2011 - Entergy Gulf States | 200,000 | - | |
140,000 | 140,000 | ||
5.15% Series due February 2013 - Entergy Mississippi | 100,000 | 100,000 | |
5.25% Series due August 2013 - Entergy New Orleans | 70,000 | 70,000 | |
5.09% Series due November 2014 - Entergy Louisiana | 115,000 | - | |
5.6% Series due December 2014 - Entergy Gulf States | 50,000 | - | |
5.25% Series due August 2015 - Entergy Gulf States | 200,000 | 200,000 | |
6.75% Series due October 2017 - Entergy New Orleans | 25,000 | 25,000 | |
5.4% Series due May 2018 - Entergy Arkansas | 150,000 | 150,000 | |
4.95% Series due June 2018 - Entergy Mississippi | 95,000 | 95,000 | |
5.0% Series due July 2018 - Entergy Arkansas | 115,000 | 115,000 | |
5.5% Series due April 2019 - Entergy Louisiana | 100,000 | - | |
8.0% Series due March 2023 - Entergy New Orleans | - | 45,000 | |
7.7% Series due July 2023 - Entergy Mississippi | - | 60,000 | |
7.55% Series due September 2023 - Entergy New Orleans | - | 30,000 | |
7.0% Series due October 2023 - Entergy Arkansas | 175,000 | 175,000 | |
5.6% Series due September 2024 - Entergy New Orleans | 35,000 | - | |
5.65% Series due September 2029 - Entergy New Orleans | 40,000 | - | |
6.7% Series due April 2032 - Entergy Arkansas | 100,000 | 100,000 | |
7.6% Series due April 2032 - Entergy Louisiana | 150,000 | 150,000 | |
6.0% Series due November 2032 - Entergy Arkansas | 100,000 | 100,000 | |
6.0% Series due November 2032 - Entergy Mississippi | 75,000 | 75,000 | |
7.25% Series due December 2032 - Entergy Mississippi | 100,000 | 100,000 | |
5.9% Series due June 2033 - Entergy Arkansas | 100,000 | 100,000 | |
6.20% Series due July 2033 - Entergy Gulf States | 240,000 | 240,000 | |
6.25% Series due April 2034 - Entergy Mississippi | 100,000 | - | |
6.4% Series due October 2034 - Entergy Louisiana | 70,000 | - | |
6.38% Series due November 2034 - Entergy Arkansas | 60,000 | - | |
Total mortgage bonds | $3,763,000 | $3,860,000 |
2004 | 2003 | ||
(In Thousands) | |||
Governmental Bonds (a): | |||
5.45% Series due 2010, Calcasieu Parish - Louisiana | $22,095 | $22,095 | |
6.75% Series due 2012, Calcasieu Parish - Louisiana | 48,285 | 48,285 | |
6.7% Series due 2013, Pointe Coupee Parish - Louisiana | 17,450 | 17,450 | |
5.7% Series due 2014, Iberville Parish - Louisiana | 21,600 | 21,600 | |
7.7% Series due 2014, West Feliciana Parish - Louisiana | 94,000 | 94,000 | |
5.8% Series due 2015, West Feliciana Parish - Louisiana | 28,400 | 28,400 | |
7.0% Series due 2015, West Feliciana Parish - Louisiana | 39,000 | 39,000 | |
7.5% Series due 2015, West Feliciana Parish - Louisiana | 41,600 | 41,600 | |
9.0% Series due 2015, West Feliciana Parish - Louisiana | 45,000 | 45,000 | |
5.8% Series due 2016, West Feliciana Parish - Louisiana | 20,000 | 20,000 | |
6.3% Series due 2016, Pope County - - Arkansas (h) | 19,500 | 19,500 | |
5.6% Series due 2017, Jefferson County - Arkansas | 45,500 | 45,500 | |
6.3% Series due 2018, Jefferson County - - Arkansas (h) | 9,200 | 9,200 | |
6.3% Series due 2020, Pope County - - Arkansas | 120,000 | 120,000 | |
6.25% Series due 2021, Independence County - - Arkansas (h) | 45,000 | 45,000 | |
7.5% Series due 2021, St. Charles Parish - - Louisiana (h) | 50,000 | 50,000 | |
5.875% Series due 2022, Mississippi Business Finance Corp. | 216,000 | 216,000 | |
5.9% Series due 2022, Mississippi Business Finance Corp. | 102,975 | 102,975 | |
7.0% Series due 2022, Warren County - Mississippi | - | 8,095 | |
7.0% Series due 2022, Washington County - Mississippi | - | 7,935 | |
7.0% Series due 2022, St. Charles Parish - - Louisiana (h) | 24,000 | 24,000 | |
7.05% Series due 2022, St. Charles Parish - - Louisiana (h) | 20,000 | 20,000 | |
Auction Rate due 2022, Independence County - - Mississippi (h) | 30,000 | 30,000 | |
4.6% Series due 2022, Mississippi Business Finance Corp. | 16,030 | - | |
5.95% Series due 2023, St. Charles Parish - - Louisiana (h) | 25,000 | 25,000 | |
6.2% Series due 2023, St. Charles Parish - - Louisiana (h) | 33,000 | 33,000 | |
6.875% Series due 2024, St. Charles Parish - - Louisiana (h) | 20,400 | 20,400 | |
6.375% Series due 2025, St. Charles Parish - Louisiana | 16,770 | 16,770 | |
7.3% Series due 2025, Claiborne County - Mississippi | - | 7,625 | |
6.2% Series due 2026, Claiborne County - Mississippi | 90,000 | 90,000 | |
5.05% Series due 2028, Pope County - Arkansas (b) | 47,000 | 47,000 | |
5.65% Series due 2028, West Feliciana Parish - Louisiana (c) | - | 62,000 | |
6.6% Series due 2028, West Feliciana Parish - Louisiana | 40,000 | 40,000 | |
5.35% Series due 2029, St. Charles Parish - - Louisiana (i) | - | - | |
Auction Rate due 2030, St. Charles Parish - - Louisiana (h) | 60,000 | 60,000 | |
4.9% Series due 2030, St. Charles Parish - Louisiana (d) (e) | 55,000 | 55,000 | |
Total governmental bonds | 1,462,805 | 1,532,430 | |
Other Long-Term Debt: | |||
Note Payable to NYPA, non-interest bearing, 4.8% implicit rate | $445,605 | $514,708 | |
3 year Bank Credit Facility (Entergy Corporation and Subsidiaries, | 50,000 | - | |
Bank term loan, Entergy Corporation, avg rate 2.98%, due 2005 | 60,000 | 60,000 | |
Bank term loan, Entergy Corporation, avg rate 3.08%, due 2008 | 35,000 | 35,000 | |
6.17% Notes due March 2008, Entergy Corporation | 72,000 | 72,000 | |
6.23% Notes due March 2008, Entergy Corporation | 15,000 | 15,000 | |
6.13% Notes due September 2008, Entergy Corporation | 150,000 | 150,000 |
| 2004 | 2003 | |
(In Thousands) | |||
Other Long-Term Debt (continued): | |||
7.75% Notes due December 2009, Entergy Corporation | 267,000 | 267,000 | |
6.58% Notes due May 2010, Entergy Corporation | 75,000 | 75,000 | |
6.9% Notes due November 2010, Entergy Corporation | 140,000 | 140,000 | |
7.06% Notes due March 2011, Entergy Corporation | 86,000 | 86,000 | |
Long-term DOE Obligation (f) | 156,332 | 154,409 | |
Waterford 3 Lease Obligation | 247,725 | 262,534 | |
Grand Gulf Lease Obligation | 397,119 | 403,468 | |
Unamortized Premium and Discount - Net | (10,277) | (11,853) | |
8.5% Junior Subordinated Deferrable Interest Debentures | - | 61,856 | |
8.75% Junior Subordinated Deferrable Interest Debentures | 87,629 | 87,629 | |
9.0% Junior Subordinated Deferrable Interest Debentures | - | 72,165 | |
Other | 9,457 | 9,966 | |
Total Long-Term Debt | 7,509,395 | 7,847,312 | |
Less Amount Due Within One Year | 492,564 | 524,372 | |
Long-Term Debt Excluding Amount Due Within One Year | $7,016,831 | $7,322,940 | |
Fair Value of Long-Term Debt (g) | $6,614,211 | $7,123,706 |
(a) | Consists of pollution control revenue bonds and environmental revenue bonds. |
(b) | The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on September 1, 2005 and can then be remarketed. |
(c) | The bonds had a mandatory tender date of September 1, 2004. Entergy Gulf States purchased the bonds from the holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time. |
(d) | On June 1, 2002, Entergy Louisiana remarketed $55 million St. Charles Parish Pollution Control Revenue Refunding Bonds due 2030, resetting the interest rate to 4.9% through May 2005. |
(e) | The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on June 1, 2005 and can then be remarketed. |
(f) | 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. |
(g) | The fair value excludes lease obligations and long-term DOE obligations, and includes debt due within one year. It is determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. |
(h) | The bonds are secured by a series of collateral first mortgage bonds. |
(i) | The bonds in the principal amount of $110.95 million had a mandatory tender date of October 1, 2003. Entergy Louisiana purchased the bonds from the holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time. |
The annual long-term debt maturities (excluding lease obligations) for debt outstanding as of December 31, 2004, for the next five years are as follows:
(In Thousands) | |
|
|
2005 | $467,298 |
2006 | $75,896 |
2007 | $199,539 |
2008 | $747,246 |
2009 | $512,584 |
In November 2000, Entergy's Non-Utility Nuclear business purchased the FitzPatrick and Indian Point 3 power plants in a seller-financed transaction. Entergy Arkansas,issued notes to NYPA with seven annual installments of approximately $108 million commencing one year from the date of the closing, and eight annual installments of $20 million commencing eight years from the date of the closing. These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%. In accordance with the purchase agreement with NYPA, the purchase of Indian Point 2 in 2001 resulted in Entergy's Non-Utility Nuclear business 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, and is included in the note payable to NYPA balance above. In July 2003, a payment of $102 million was made prior to maturity on the note payable to NYPA. Under a provision in a letter of credit supporting these notes, if certain of the domestic utility companies or System Energy were to default on other indebtedness, Entergy could be required to post collateral to support the letter of credit.
Covenants in the Entergy Corporation notes require it to maintain a consolidated debt ratio of 65% or less of its total capitalization. If Entergy's debt ratio exceeds this limit, or if Entergy or certain of the domestic utility companies default on other indebtedness or are in bankruptcy or insolvency proceedings, an acceleration of the notes' maturity dates may occur.
The long-term securities issuances of Entergy Corporation, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and System Energy also are limited to amounts authorized by the SEC. Under its current SEC order, and without further authorization, Entergy Corporation cannot incur additional indebtedness or issue other securities unless (a) it and each of its public utility subsidiaries maintain a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of Entergy Corporation that are rated, are rated investment grade by at least one nationally recognized statistical rating agency. Under their current SEC orders, and without further authorization, Entergy Gulf States, Entergy Louisiana, and Entergy Mississippi each have 364-day credit facilities availablecannot incur additional indebtedness or issue other securities unless (a) the issuer and Entergy Corporation maintains a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all outstanding s ecurities of the issuer (other than preferred stock of Entergy Gulf States), as follows:well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade.
Junior Subordinated Deferrable Interest Debentures and Implementation of FIN 46
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The facilities haveEntergy implemented FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" effective December 31, 2003. FIN 46 requires existing unconsolidated variable interest ratesentities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among their investors. Variable interest entities (VIEs), generally, are entities that do not have sufficient equity to permit the entity to finance its operations without additional financial support from its equity interest holders and/or the group of equity interest holders are collectively not able to exercise control over the entity. The primary beneficiary is the party that absorbs a majority of the entity's expected losses, receives a majority of its expected residual returns, or both as a result of holding the variable interest. A company may have an interest in a VIE through ownership or other contractual rights or obligations.
Entergy Louisiana Capital I, Entergy Arkansas Capital I, and Entergy Gulf States Capital I (Trusts) were established as financing subsidiaries of Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States, respectively, (the parent company or companies, collectively) for the purposes of issuing common and preferred securities. The Trusts issued Cumulative Quarterly Income Preferred Securities (Preferred Securities) to the public and issued common securities to their parent companies. Proceeds from such issues were used to purchase junior subordinated deferrable interest debentures (Debentures) from the parent company. The Debentures held by each Trust are its only assets. Each Trust uses interest payments received on the Debentures owned by it to make cash distributions on the Preferred Securities and common securities. The parent companies fully and unconditionally guaranteed payment of distributions on the Preferred Securities issued by the respective Trusts. Prior to the app lication of FIN 46, each parent company consolidated its interest in its Trust. Because each parent company's share of expected losses of its Trust is limited to its investment in its Trust, the parent companies are not considered the primary beneficiaries and therefore de-consolidated their interest in the Trusts upon application of FIN 46 with no significant impacts to the financial statements. The parent companies' investment in the Trusts and the average commitment fee is 0.13%.Debentures issued by each parent company are included in Other Property and Investments and Long-Term Debt, respectively.
Capital Funds Agreement
Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:
NOTE 5.6. PREFERRED AND COMMON STOCK
Preferred Stock
The number of shares authorized and outstanding and dollar value of preferred stock and minority interest for Entergy Corporation subsidiaries as of December 31, 20022004 and 20012003 are presented below. Only the Entergy Gulf States series "with sinking fund" contain mandatory redemption requirements. All other series of the U.S. Utility are redeemable at Entergy's option.
Shares | Shares | |||||||||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |||||||
Entergy Corporation | (Dollars in Thousands) | |||||||||||
U.S. Utility: | ||||||||||||
Preferred Stock without sinking fund: | ||||||||||||
Entergy Arkansas, 4.32%-7.88% Series | 1,613,500 | 1,613,500 | 1,613,500 | 1,613,500 | $116,350 | $116,350 | ||||||
Entergy Gulf States, 4.20%-7.56% Series | 473,268 | 473,268 | 473,268 | 473,268 | 47,327 | 47,327 | ||||||
Entergy Louisiana, 4.16%-8.00% Series | 2,115,000 | 2,115,000 | 2,115,000 | 2,115,000 | 100,500 | 100,500 | ||||||
Entergy Mississippi, 4.36%-8.36% Series | 503,807 | 503,807 | 503,807 | 503,807 | 50,381 | 50,381 | ||||||
Entergy New Orleans, 4.36%-5.56% Series | 197,798 | 197,798 | 197,798 | 197,798 | 19,780 | 19,780 | ||||||
Total U. S. Utility Preferred Stock without sinking fund | 4,903,373 | 4,903,373 | 4,903,373 | 4,903,373 | 334,337 | 334,337 | ||||||
Energy Commodity Services: | ||||||||||||
Preferred Stock without sinking fund: | ||||||||||||
Entergy Asset Management, 11.50% rate | 1,000,000 | - | 297,376 | - | 29,738 | - | ||||||
Other | - | - | - | - | 1,281 | - | ||||||
Total Preferred Stock without sinking fund | 5,903,373 | 4,903,373 | 5,200,749 | 4,903,373 | $365,356 | $334,337 | ||||||
U.S. Utility: | ||||||||||||
Preferred Stock with sinking fund: | ||||||||||||
Entergy Gulf States, Adjustable | ||||||||||||
Rate 7.0% (a) | 174,000 | 208,520 | 174,000 | 208,520 | $17,400 | $20,852 | ||||||
Total Preferred Stock with sinking fund | 174,000 | 208,520 | 174,000 | 208,520 | $17,400 | $20,852 | ||||||
Fair Value of Preferred Stock with | ||||||||||||
sinking fund (b) | $15,286 | $15,354 |
(a) | Represents weighted-average annualized rate for 2004 and 2003. |
(b) | Fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. There is additional disclosure of fair value of financial instruments in Note 14 to the consolidated financial statements. |
All outstanding preferred stock is cumulative.
Entergy Gulf States' preferred stock with sinking fund retirements were 34,500 shares in 2004 and 2003, and 18,579 shares in 2002. Entergy Gulf States has annual sinking fund requirements of $3.45 million through 20072009 for its preferred stock outstanding.
NOTE 7. COMMON EQUITY
Common Stock
Treasury Stock
Treasury stock activity for Entergy for 20022004 and 2001:2003 is as follows:
2004 | 2003 | |||||||
Treasury Shares |
| Treasury Shares |
| |||||
(In Thousands) | (In Thousands) | |||||||
Beginning Balance, January 1 | 19,276,445 | $561,152 | 25,752,410 | $747,331 | ||||
Repurchases | 16,631,800 | 1,017,996 | 155,000 | 8,135 | ||||
Issuances: | ||||||||
Employee Stock-Based Compensation Plans |
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Directors' Plan | (7,320) | (252) | (8,870) | (257) | ||||
Ending Balance, December 31 | 31,345,028 | $1,432,019 | 19,276,445 | $561,152 |
Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors' Plan), the Equity Ownership Plan of Entergy Corporation and Subsidiaries (Equity Ownership Plan), 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 number of shares of Entergy Corporation common stock.
Equity Compensation Plan Information
Entergy has two plans that grantgrants stock options, equity awards, and incentive awards to key employees of the Entergy subsidiaries. Thesubsidiaries under the Equity Ownership Plan which is a shareholder-approved stock-based compensation plan. The Equity Awards Plan is a Board-approved stock-based compensation plan. Stock options are granted at exercise prices not less than market value on the date of grant. The majority of options granted in 2002, 2001,2004, 2003, and 20002002 will become exercisable in equal amounts on each of the first three anniversaries of the date of grant. OptionsUnless they are forfeited previously under the terms of the grant, options expire ten years after the date of the grant if they are not exercised within ten years from the date of the grant.exercised.
Beginning in 2001, Entergy began grantinggrants most of the equity awards and incentive awards earned under its stock benefit plans in the form of performance units, which are equal to the cash value of shares of Entergy Corporation common stock at the time of payment. In addition to the potential for equivalent share appreciation or depreciation, performance units will earn the cash equivalent of the dividends paid during the performance period applicable to each plan. The amount of performance units awarded will not reduce the amount of securities remaining under the current authorizations. The costs of equity and incentive awards, given either as company stock or performance units, are charged to income over the period of the grant or restricted period, as appropriate. In 2004, 2003, and 2002, 2001, and 2000, $28$47 million, $14$45 million, and $17$28 million, respectively, was charged to compensation expense.
Entergy was assisted by external valuation firms to determine the fair value of the stock option grants made in 2004 and 2003. The fair value applied to these grants was an average of two firms' option valuations, which included adjustments for factors such as lack of marketability, stock retention requirements, and regulatory restrictions on exercisability. In 2002, the fair value of each option grant iswas estimated on the date of grant using the Black-Scholes option-pricing model, with the followingwithout any such adjustments. The stock option weighted-average assumptions:assumptions used in determining the fair values were as follows:
2002 | 2001 | 2000 | 2004 |
| 2003 |
| 2002 | |
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Stock price volatility | 27.2% | 26.3% | 24.4% | 23.1% |
| 26.3% |
| 27.2% |
Expected term in years | 5 | 6.3 |
| 6.2 |
| 5.0 | ||
Risk-free interest rate | 4.2% | 4.9% | 6.6% | 3.2% |
| 3.3% |
| 4.2% |
Dividend yield | 3.2% | 3.4% | 5.2% | 3.3% |
| 3.3% |
| 3.2% |
Dividend payment | $1.32 | $1.26 | $1.20 | $1.80 |
| $1.40 |
| $1.32 |
Stock option transactions are summarized as follows:
| 2004 |
| 2003 |
| 2002 | |||
| Number | Average |
| Number | Average |
| Number | Average |
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Beginning-of-year balance | 15,429,383 | $38.64 |
| 19,943,114 | $35.85 |
| 17,316,816 | $31.06 |
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Options granted | 1,898,098 | $58.63 |
| 2,936,236 | $44.98 |
| 8,168,025 | $41.72 |
Options exercised | (4,541,053) | $38.07 |
| (6,927,000) | $33.12 |
| (4,877,688) | $28.62 |
Options forfeited/expired | (476,351) | $39.94 |
| (522,967) | $40.98 |
| (664,039) | $36.36 |
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End-of-year balance | 12,310,077 | $41.88 |
| 15,429,383 | $38.64 |
| 19,943,114 | $35.85 |
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Options exercisable at year-end | 7,162,884 | $37.25 |
| 6,153,043 | $34.82 |
| 4,837,511 | $31.39 |
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Weighted-average fair value of | $7.76 |
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| $6.86 |
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| $9.22 |
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The following table summarizes information about stock options outstanding as of December 31, 2002:
During the first quarter of 2003, an additional 7,196,699 options became exercisable with a weighted-average exercise price of $34.71.
Entergy sponsors the Savings Plan of Entergy Corporation and Subsidiaries (Savings Plan). The Savings Plan is a defined contribution plan covering eligible employees of Entergy and its subsidiaries. The Savings Plan provides that the employing Entergy subsidiary may:
Entergy's subsidiaries contributed $29.6 million in 2002, $25.4 million in 2001, and $16.1 million in 2000 to the Savings Plan.
NOTE 6. COMPANY-OBLIGATED REDEEMABLE PREFERRED SECURITIES
Entergy Louisiana Capital I, Entergy Arkansas Capital I, and Entergy Gulf States Capital I (Trusts) were established as financing subsidiaries of Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States, respectively, for the purpose of issuing common and preferred securities. The Trusts issue Cumulative Quarterly Income Preferred Securities (Preferred Securities) to the public and issue common securities to their parent companies. Proceeds from such issues are used to purchase junior subordinated deferrable interest debentures (Debentures) from the parent company. The Debentures held by each Trust are its only assets. Each Trust uses interest payments received on the Debentures owned by it to make cash distributions on the Preferred Securities.
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The Preferred Securities of the Trusts mature in the years 2045 and 2046. The Preferred Securities are currently redeemable at 100% of their principal amount at the option of Entergy Louisiana, Entergy Arkansas, or Entergy Gulf States. Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States have, pursuant to certain agreements, fully and unconditionally guaranteed payment of distributions on the Preferred Securities issued by their respective Trusts. Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States are the owners of all of the common securities of their individual Trusts, which constitute 3% of each Trust's total capital.
NOTE 7. LONG - TERM DEBT
Long-term debt as of December 31, 2002 and 2001 consisted of:
The annual long-term debt maturities (excluding lease obligations) and annual cash sinking fund requirements for debt outstanding as of December 31, 2002, for the next five years are as follows (in thousands):2004:
2003 | $1,150,786 |
2004 | $925,005 |
2005 | $540,372 |
2006 | $139,952 |
2007 | $475,288 |
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| Options Outstanding |
| Options Exercisable | ||||||
Range of |
| As of |
| Weighted-Avg. |
| Weighted- |
| Number |
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$23 - $33.99 |
| 1,674,430 |
| 5.0 |
| $26.28 |
| 1,674,430 |
| $26.28 |
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$34 - $44.99 |
| 8,547,519 |
| 7.1 |
| $41.09 |
| 5,195,493 |
| $39.95 |
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$45 - $55.99 |
| 230,445 |
| 5.6 |
| $49.61 |
| 222,378 |
| $49.68 |
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$56 - $67.99 |
| 1,857,683 |
| 9.1 |
| $58.64 |
| 70,583 |
| $59.67 |
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$23 - $67.99 |
| 12,310,077 |
| 7.1 |
| $41.88 |
| 7,162,884 |
| $37.25 |
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Retained Earnings and Dividend Restrictions
Not included are other sinking fund requirements of approximately $30.2 million annually, which may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements.
In December 2002, when the Damhead Creek project was sold, the buyer of the project assumed all obligations under the Damhead Creek credit facilities and the Damhead Creek interest rate swap agreements.
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 resulted in Entergy's Non-Utility Nuclear business 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.
Covenants in the Entergy Corporation 7.75% notes require it to maintain a consolidated debt ratio of 65% or less of its total capitalization. If Entergy's debt ratio exceeds this limit, or if Entergy or certain of the domestic utility companies default on other credit facilities or are in bankruptcy or insolvency proceedings, an acceleration of the facility's maturity may occur.
In January 2003, Entergy paid in full, at maturity, the outstanding debt relating to the Top of Iowa wind project.
Capital Funds Agreement
Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:
NOTE 8. DIVIDEND RESTRICTIONS
Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation's subsidiaries restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2002,2004, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $296.1$394.9 million and $36.2$68.5 million, respectively. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. In 2002,2004, Entergy Corporation received dividend payments totaling $618.4$825 million from subsidiaries. In addition,
Investments in affiliates that are not controlled by Entergy Louisiana repurchased $120Corporation, but over which it has significant influence, are accounted for using the equity method. Entergy's retained earnings for 2003 included $472 million of undistributed earnings of equity method investees. Due to the receipt of dividends from Entergy-Koch, LP after the sale of its common shares from Entergy Corporationenergy trading and pipeline businesses in 2002.
2004, there were no undistributed earnings in Entergy's retained earnings at December 31, 2004. Equity method investments are discussed in Note 12 to the consolidated financial statements.
NOTE 9.8. COMMITMENTS AND CONTINGENCIES
Entergy is involved in a number of legal, tax, and regulatory proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of its business. While management is unable to predict the outcome of such proceedings, management does not believe that the ultimate resolution of these matters will have a material adverse effect on Entergy's results of operations, cash flows, or financial condition.
Capital Requirements and Financing
Entergy plans to spend approximately $3.4 billion on construction and other capital investments during 2003-2005. This plan reflects capital required to support existing businesses as well as the approval by the Board of the ANO 1 steam generator replacement project. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints, business opportunities, market volatility, economic trends, and the ability to access capital. Entergy's estimated construction and other capital expenditures by year for 2003-2005 are as follows (in millions):
Planned construction and capital investment | 2003 | 2004 | 2005 | |||
U.S. Utility | $924 | $915 | $965 | |||
Non-Utility Nuclear | $201 | $142 | $109 | |||
Energy Commodity Services | $24 | $76 | $3 | |||
Other | $7 | $7 | $9 |
�� The U.S. Utility will focus its planned spending on projects that will support continued reliability improvements and customer growth.
Non-Utility Nuclear will focus its planned spending on routine construction projects and power uprates.
Energy Commodity Services expenditures will primarily be on a merchant power plant project currently under construction and a $73 million cash contribution to Entergy-Koch in January 2004.
The planned construction and capital investments do not include potential investments in new businesses or assets.
Entergy will also require $2.6 billion during the period 2003-2005 to meet long-term debt and preferred stock maturities and cash sinking fund requirements. Entergy plans to meet these requirements primarily with internally generated funds and cash on hand, supplemented by proceeds from the issuance of debt and outstanding credit facilities. In the fourth quarter of 2002, the U.S. Utility issued $640 million of debt with maturities ranging from 2007 to 2032. Approximately $71 million of the proceeds of the debt issued in the fourth quarter were used to retire, in 2002, debt that was scheduled to mature in 2003, and the remainder will be used to meet certain 2003 maturities as they occur. Entergy Mississippi issued an additional $100 million of debt in January 2003 that matures in 2013. The proceeds will be used to repay, prior to maturity, debt of Entergy Mississippi that is scheduled to mature in 2003 and 2004. Certain domestic utility companies may also continue the reacquisition or refinancing of all or a portion of certain outstanding series of preferred stock and long-term debt.
Sales Warranties and IndemnitiesVidalia Purchased Power Agreement
In the CitiPower sales transaction, Entergy or its subsidiaries made certain warranties to the purchaser. These warranties include representations regarding litigation, accuracy of financial accounts, and the adequacy of existing tax provisions. The purchasers of CitiPower have asserted notice of claims against Entergy under the terms of the Tax Warranty Deed dated November 23, 1998 between them and Entergy. The Tax Warranty Deed includes a reservation of rights relating to a potential liability in the event of an adverse tax ruling. In November 2002, the Australian Taxation Office assessed CitiPower for taxes for the years 1997 through 1999. Management believes it has adequately provided for the ultimate resolution of this matter.
In the Saltend sales transaction, Entergy or its subsidiaries made certain warranties to the purchasers relating primarily to the performance of certain remedial work on the facility and the assumption of responsibility for certain contingent liabilities. Entergy believes that it has provided adequately for the warranties as of December 31, 2002.
Power Purchase Agreements
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 $147.7 million in 2004, $112.6 million in 2003, and $104.2 million in 2002, $86.0 million in 2001, and $58.6 million in 2000.2002. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $79.5$125.3 million in 2003,2005, and a total of $2.7$3.5 billion for the years 20042006 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 monthly rates by $11 million each year for up to ten years, beginning in October 2002.
The provisions of the settlement also provide that the LPSC shall not recognize or use Entergy Louisiana's use of the cash benefits from the tax treatment in setting any of Entergy Louisiana's rates. Therefore, to the extent Entergy Louisiana's use of the proceeds would ordinarily have reduced its rate base, no change in rate base shall be reflected for ratemaking purposes.
Nuclear Insurance
Third Party Liability Insurance
The Price-Anderson Act limitsprovides insurance for the public liabilityin the event of a nuclear power plant owner foraccident. The costs of this insurance are borne by the nuclear power industry. Originally passed by Congress in 1957 and most recently amended in 1988, the Price-Anderson Act requires nuclear power plants to show evidence of financial protection in the event of a single nuclear incident to approximately $9.5 billion. Protection for this liabilityaccident. This protection must consist of two levels:
Currently, 104 nuclear reactors are participating in the Price-Anderson Secondary Financial Protection program which responds upon the exhaustion- 103 operating reactors and one closed reactor that still stores used nuclear fuel on site. The product of ANI coverage). Under the assessment program, the maximum payment requirement for eachretrospective premium assessment to the nuclear incident would be $88.1 million per reactor, payable at a ratepower industry and the number of nuclear power reactors provides over $10 m illion per licensed reactor per incident per year. Entergy has ten licensed reactors, with five eachbillion in insurance coverage to compensate the public in the U.S. Utility segmentevent of a nuclear power reactor accident.
Entergy owns and operates ten of the Non-Utility Nuclear segment. As a co-licenseenuclear power reactors, and owns the shutdown Indian Point 1 reactor (10% of Grand Gulf 1 with System Energy, SMEPAis owned by a non-affiliated company which would share on a pro-rata basis in 10%any retrospective premium assessment under the Price-Anderson Act).
An additional but temporary contingent liability exists for all nuclear power reactor owners because of this obligation. In addition, each owner/licensee of Entergy's ten nuclear units participates in a private insurance program that provides coverage for worker tort claims filed forprevious Nuclear Worker Tort (long-term bodily injury caused by exposure to nuclear radiation exposure.while employed at a nuclear power plant) insurance program that was in place from 1988 to 1998. The program provides for a maximum premium assessment of approximatelyexposure to each reactor is $3 million for each licensed reactor inand will only be applied if such claims exceed the event that losses exceedprogram's accumulated reserve funds. This contingent premium assessment feature will expire with the Nuclear Worker Tort program's expiration, which is scheduled for 2008.
Property Insurance
Entergy's nuclear owner/licensee subsidiaries are also members of certain mutual insurance programscompanies that provide coverage for property damage coverage, including decontamination and premature decommissioning expense, to the members' nuclear generating plants. These programs are underwritten by Nuclear Electric Insurance Limited (NEIL). As of December 31, 2002,2004, Entergy was insured against such losses up to $2.3per the following structures:
U.S. Utility Plants (ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3)
Note: ANO 1 and 2 share in the Primary Layer with one policy in common.
Non-Utility Nuclear Plants (Indian Point 2 and 3, FitzPatrick, Pilgrim, and Vermont Yankee which are insured forYankee)
Note: Indian Point 2 and 3 share in property damages.the Primary Layer with one policy in common.
In addition, the Non-Utility Nuclear plants are also covered under NEIL's Accidental Outage Coverage program. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL property damage loss, subject to a deductible. The following summarizes this coverage as of December 31, 2004:
Indian Point 2 and 3
FitzPatrick and Pilgrim (each plant has an individual policy with the noted parameters)
Vermont Yankee
Entergy's U.S. Utility nuclear owner/licensee subsidiaries are members of the NEIL insurance program that covers certain replacement power and business interruption costs incurred due to prolonged nuclear unit outages.plants have significantly less or no accidental outage coverage. Under the property damage and replacement power/business interruptionaccidental outage insurance programs, these Entergy subsidiarie snuclear plants could be subject to assessments ifshould losses exceed the accumulated funds available to the insurers.from NEIL. As of December 31, 2002,2004, the maximum amounts of such possible assessments per occurrence were $81.4$50.8 million for the U.S. Utility segmentplants and $95.3$68.9 million for the Non-Utility Nuclear segment.plants.
Entergy maintains property insurance for each of its nuclear units in excess of the NRC's minimum requirement of $1.06 billion per site for nuclear power plant licensees of $1.06 billion per site.licensees. NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.
Effective November 15, 2001, inIn the event that one or more acts of domestically-sponsored terrorism cause accidentalcauses property damage under one or more ofor all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first accidental 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 sourcesources applicable to such losses.
Spent Nuclear Fuel
Entergy's nuclear owner/licensee subsidiaries provide for the estimated future disposal costs There is no aggregate limit involving one or more acts 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 will furnish disposal service 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 Entergy company that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2002 of $153 million for the one-time fee. 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 h ave been or will be made in applications to regulatory authorities.
Entergy's Non-Utility Nuclear business has accepted assignment of the Pilgrim, FitzPatrick, Indian Point 3, Indian Point 2, and Vermont Yankee 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.
Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. After twenty years of study, the DOE, in February 2002, formally recommended, and President Bush approved, Yucca Mountain, Nevada as the permanent spent fuel repository. DOE will now proceed with the licensing and, if the license is granted by the NRC, eventual construction of the repository will begin and receipt of spent fuel may begin as early as approximately 2010. Considerable 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, future expenditures will be required to increase spent fuel storage capacity at Entergy's nuclear plant sites.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are responsible for their own spent fuel storage. Current on-site spent fuel storage capacity at Grand Gulf 1 and River Bend is estimated to be sufficient until approximately 2006 and 2004, respectively, at which time dry cask storage facilities will be placed into service. The spent fuel pool at Waterford 3 was recently expanded through the replacement of the existing storage racks with higher density storage racks. This expansion should provide sufficient storage for Waterford 3 until after 2010. An ANO storage facility using dry casks began operation in 1996 and has been expanded since and will be further expanded as needed. The spent fuel storage facility at Pilgrim is licensed to provide enough storage capacity until approximately 2012. The first dry spent fuel storage casks were loaded at FitzPa trick in 2002, and further casks will be loaded there as needed. Indian Point and Vermont Yankee currently have sufficient spent fuel storage capacity until approximately 2004 and 2006, respectively, at which time planned additional dry cask storage capacity are to begin operation.
foreign-sponsored terrorism.
Nuclear Decommissioning and Other Retirement Costs
Total approved decommissioning costs for rate recovery purposes as of December 31, 2002, for Entergy Arkansas', Entergy Gulf States', Entergy Louisiana's, and System Energy's nuclear power plants, excluding SMEPA's share of Grand Gulf 1, are as follows:
Entergy has been recording decommissioning liabilities for these plants as the estimated decommissioning costs are collected from customers or as earnings on the trust funds are realized. Effective January 1, 2003, Entergy adopted SFAS 143, "Accounting for Asset Retirement Obligations.Obligations," which was implemented effective January 1, 2003, requires the recording of liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets. For Entergy, these asset retirement obligations consist of its liability for decommissioning its nuclear power plants.
These liabilities are recorded at their fair values (which is 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 amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives of the assets. The net effect of implementing SFAS 143 for the rate-regulated business of the domestic utility companies and System Energy was recorded as a regulatory asset, with no resulting impact on Entergy's net income. Entergy recorded these regulatory assets because existing rate mechanisms in each jurisdiction are based on the principle that Entergy will recover all ultimate costs of decommissioning from customers.
Upon implementation of SFAS 143 in 2003, assets and liabilities increased $1.1 billion for the U.S. Utility segment as a result of recording the asset retirement obligations at their fair values of $1.1 billion as determined under SFAS 143, increasing utility plant by $287 million, reducing accumulated depreciation by $361 million, and recording the related regulatory assets of $422 million. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking decreased earnings by $21 million net-of-tax as a result of a one-time cumulative effect of accounting change. In accordance with ratemaking treatment and as required by SFAS 71, the depreciation provisions for the domestic utility companies and System Energy include a component for removal costs that are not asset retirement obligations under SFAS 143. In accordance with regulatory accounting principles, Entergy has recorded a regulatory asset for certain of this statement will resultits domestic utility companies and Syste m Energy of $86.9 million as of December 31, 2004 and $72.4 million as of December 31, 2003 to reflect an estimate of incurred but uncollected removal costs previously recorded as a component of accumulated depreciation. The decommissioning and retirement cost liability for certain of the domestic utility companies and System Energy includes a regulatory liability of $34.6 million as of December 31, 2004 and $26.8 million as of December 31, 2003 representing an estimate of collected but not yet incurred removal costs. For the Non-Utility Nuclear business, the implementation of SFAS 143 resulted in a differentdecrease in liabilities of $595 million due to reductions in decommissioning liabilities, a decrease in assets of $340 million, including a decrease in electric plant in service of $315 million, and an increase in earnings in 2003 of $155 million net-of-tax as a result of a one-time cumulative effect of accounting change.
The cumulative decommissioning liabilities and expenses recorded in 2004 by Entergy were as follows:
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| Change in Cash Flow Estimate |
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| (In Millions) | ||||||||
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U.S. Utility | $1,504.1 |
| $98.0 |
| ($274.1) |
| - |
| $1,328.0 |
Non-Utility Nuclear | $710.4 |
| $57.6 |
| ($20.3) |
| ($9.4) |
| $738.3 |
In addition, an insignificant amount of decommissioning costs being recorded than under the method described above in use prior to December 31, 2002. Entergy expects to adjust for financial reporting purposes this different level of decommissioning expense to the level previously being recorded through the use of regulatory assets/regulatory liabilities for a substantial portion of the decommissioningremoval costs associated with non-nuclear power plants are also included in the units listed above. The decommissioning liabilities recorded are discussed below.
Decommissioning costs recovered in rates are deposited in trust fundsline item on the balance sheet. Entergy periodically reviews and reported at market value based upon market quotes or as determined by widely used pricing services. These trust fund assets largely offset the accumulatedupdates estimated decommissioning liability that is recorded as accumulated depreciation for Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana, and are recorded as deferred credits for System Energy and Entergy's Non-Utility Nuclear business. The liability associated with the trust funds received from Cajun with the transfer of Cajun's 30% share of River Bend is also recorded as a deferred credit by Entergy Gulf States.costs. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment.
During 2004, Entergy periodically reviews and updates estimatedupdated decommissioning costs. Entergy is presently under-recovering decommissioning costs for ANO 1, ANO 2, Grand Gulf 1, Waterford 3, and the Louisiana-regulated share of River Bend. Under-recovery for Grand Gulf 1 and Waterford 3 is based on the existence of more recent estimates reflecting higher costs. Under-recovery of ANO 1, ANO 2, and River Bend is based on suspension of decommissioning collections under the assumption that the lives of those plants have been or will be extended.
In June 2001, Entergy Arkansas received notification from the NRC of approval for a renewed operating license authorizing operations at ANO 1 through May 2034. In October 2000, the APSC ordered Entergy Arkansas to reflect 20-year license extensions in its determination of the ANO 1 and ANO 2 decommissioning revenue requirements for rates to be effective January 1, 2001. Entergy Arkansas will not make additional contributions to the trust funds in 2003cost studies for ANO 1 and ANO 2 based onand River Bend.
In December 2002,the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected an expected life extension for the plant. The revised estimate resulted in a $166.4 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $49.6 million reduction in non-utility property, a $40.1 million reduction in the related regulatory asset, and the LPSC reached a settlementregulatory liability of $17.7 million. For the fourth through eighth post-merger earnings reviews. Among other things, the settlement includes suspension of collections for decommissioning the Louisiana-regulated portion of River Bend beginning January 1, 2003 based upon an assumption thatnot subject to cost-based ratemaking, the operating license and the useful life of River Bend will be extended. According to the settlement agreement,revised estimate resulted in the eventelimination of the asset retirement cost that the NRC formally notifies Entergy that the decommissioning funding for River Bend is or would become inadequate, Entergy Gulf States would be permitted recognition in rates of decommissioning expense at a level sufficient to address reasonably the NRC's concern as expressed in the notification. The decommissioning liability for the 30% share of River Bend formerly owned by Cajun was fully funded by a transfer of $132 million to the River Bend D ecommissioning Trusthad been recorded at the completiontime of Cajun's bankruptcy proceedings.
Entergy Louisiana prepared a decommissioning cost update for Waterford 3 in 1999 and produced a revised decommissioning cost updateadoption of $481.5 million. This cost update was filedSFAS 143 with the LPSC inremainder recorded as miscellaneous other income of $27.7 million.
In the third quarter of 2000.
System Energy included updated2004, Entergy's Non-Utility Nuclear business recorded a reduction of $20.3 million in decommissioning costs (based onliability to reflect changes in assumptions regarding the updated 1994 study)timing of when decommissioning of a plant will begin. Entergy considered the assumptions as part of recent studies evaluating the economic effect of the plant in its 1995 rate increase filing with FERC. Rates requestedregion. The revised estimate resulted in this proceeding were placed into effect in December 1995, subject to refund. In July 2000, FERC issued an order approving a lower decommissioning cost than what was requested by System Energymiscellaneous other income of $20.3 million, reflecting the excess of the reduction in the 1995 filing. System Energy adjusted its collection toliability over the FERC-approved levelamount of $341 million inundepreciated asset retirement cost recorded at the third quartertime of 2001. A 1999 decommissioning cost updateadoption of $540.8 million for System Energy's 90% share of Grand Gulf 1 has not yet been filed with FERC.SFAS 143.
If Entergy had applied SFAS 143 during prior periods, the following impacts would have resulted:
As part of the Pilgrim, Indian Point 1 and 2, and Vermont Yankee purchases, the previous owners transferred decommissioning trust funds, along with the liability to decommission the plants, to Entergy. Entergy believes that the decommissioning trust funds will be adequate to cover future decommissioning costs for these plants without any additional deposits to the trusts.
Year Ended | ||
Earnings applicable to common stock - as reported | $599,360 | |
Pro forma effect of SFAS 143 | $14,119 | |
Earnings applicable to common stock - pro forma | $613,479 | |
Basic earnings per average common share - as reported | $2.69 | |
Pro forma effect of SFAS 143 | $0.06 | |
Basic earnings per average common share - pro forma | $2.75 | |
Diluted earnings per average common share - as reported | $2.64 | |
Pro forma effect of SFAS 143 | $0.06 | |
Diluted earnings per average common share - pro forma | $2.70 |
For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liability. NYPA and Entergy executed decommissioning agreements, which specify their decommissioning obligations. NYPA has the right to require Entergy to assume the decommissioning liability provided that it assigns the corresponding decommissioning trust, up to a specified level, to Entergy. If the decommissioning liability is retained by NYPA, Entergy will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. Entergy believes that the amounts available to it under either scenario are sufficient to cover the future decommissioning costs without any additional contributions to the trusts.
Entergy maintains decommissioning trust funds that are committed to meeting the costs of decommissioning the nuclear power plants. The provisionsfair values of SFAS 143 will also be applicable to the non-regulated nuclear units beginning in 2003. Refer to Note 1 to the consolidated financial statements for a discussion of the effect of SFAS 143 on Entergy.
The cumulative liabilities and decommissioning expenses recorded in 2002 by Entergy were as follows:
follows:
In 2000, ANO's decommissioning expense was $3.8 million. River Bend's decommissioning expense was $6.2 million in both 2001 and 2000, and Waterford 3's decommissioning expense was $10.4 million for both years. Grand Gulf 1's 2001 decommissioning expense, which included the effect of the FERC-ordered refund, was ($23.8 million); its 2000 decommissioning expense was $18.9 million. Pilgrim's decommissioning expense was $20.1 million in 2001 and $19.2 million in 2000. In 2001, Indian Point 1 & 2's decommissioning expense was $5.3 million.
| Decommissioning |
| Regulatory |
| (In Millions) | ||
|
|
|
|
U.S. Utility | $1,052.0 |
| $380.1 |
Non-Utility Nuclear | $1,401.6 |
| - |
The Energy Policy Act of 1992 contains a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning (D&D) of the DOE's past uranium enrichment operations. Annual assessments (in 2002 dollars), which will be adjusted annually for inflation, are for 15 years andin 2004 were $4.2$4.4 million for Entergy Arkansas, $1.0$1.1 million for Entergy Gulf States, $1.6 million for Entergy Louisiana, and $1.6$1.8 million for System Energy. The Energy in 2002.Policy Act calls for cessation of annual D&D assessments not later than October 24, 2007. At December 31, 2002, four2004, two years of assessments were remaining. D&D fees are included in other current liabilities and other non-current liabilities and, as of December 31, 2002,2004, recorded liabilities were $16.7$8.8 million for Entergy Arkansas, $4.0$1.9 million for Entergy Gulf States, $6.4$3.3 million for Entergy Louisiana, and $6.3$3.3 million for System Energy. Regulatory assets in the financial statements offset these liabilities, with the exception of Entergy Gulf States' 30% non-regulated portion. FERC requires that utilities treat these assessments as costs of fuel as theyThese assess ments are amortized and recover these costsrecovered through rates in the same manner as other fuel costs.
Income Taxes
Entergy is currently under audit by the IRS with respect to tax returns for tax periods subsequent to 1995 and through 2001, and is subject to audit by the IRS and other taxing authorities for subsequent tax periods. The amount and timing of any tax assessments resulting from these audits are uncertain, and could have a material effect on Entergy's financial position and results of operations. Entergy believes that the contingency provisions established in its financial statements will sufficiently cover the risk associated with tax matters. Certain material audit matters as to which management believes there is a reasonable possibility of a future tax assessment are discussed below. See Note 3 to the consolidated financial statements for additional discussion of income taxes.
Foreign Tax Credits
In July 1997, the UK government enacted the Windfall Tax, which was a one-time tax imposed on formerly government-owned companies in regulated industries. The Windfall Tax applied to companies that the government had previously privatized in the telecommunication, airport operation, gas, water, electricity, and railway industries. London Electricity, the UK public limited company purchased and subsequently sold by Entergy, was subject to the UK Windfall Tax. Entergy fulfilled its obligation with respect to the tax in 1997 and 1998. In subsequent tax years, Entergy reported a foreign tax credit for the UK Windfall Tax that London Electricity paid. Entergy has claimed a net tax benefit of $152 million related to this foreign tax credit.
During 2004, the IRS proposed to disallow this foreign tax credit. Entergy disagreed with the position of the IRS and protested the disallowance of the credit to the Office of IRS Appeals. Entergy expects to receive a Notice of Deficiency in 2005 for this item, and plans to vigorously contest this matter. The amount at issue including tax and interest as of December 31, 2004 is $195 million. Entergy believes that the contingency provision established in its financial statements will sufficiently cover the risk associated with this dispute.
Depreciable Property Lives
During the years 1997 through 2004, Entergy subsidiaries, Entergy Services, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy Resources reflected changes in tax depreciation methods with respect to certain types of depreciable property (e.g. street lighting, billing meters, and various generation plant equipment). The cumulative effect of these changes results in additional depreciation deductions generating a cash flow benefit of approximately $152 million as of December 31, 2004. The related IRS interest exposure if the deduction is ultimately disallowed is $44 million at December 31, 2004. This benefit reverses over time and will also fluctuate with each year's addition to those types of assets. Due to the temporary nature of the tax benefit, the potential interest charge represents the total net earnings exposure of Entergy.
For the years under audit, 1996-2001, the IRS challenged Entergy's classification of these assets and proposed adjustments to the depreciation deductions taken. Entergy disagrees with the position of the IRS and has protested the disallowance of these deductions to the Office of IRS Appeals. Entergy expects to receive a Notice of Deficiency in 2005 for this item, and plans to vigorously contest this matter. Entergy believes that the contingency provision established in its financial statements sufficiently covers the risk associated with this item.
Mark to Market of Certain Power Contracts
In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts. The most significant of these is the contract to purchase power from the Vidalia hydroelectric project. The new tax accounting method has provided a cumulative cash flow benefit of approximately $790 million as of December 31, 2004. The related IRS interest exposure is $93 million at December 31, 2004. This benefit is expected to reverse in the years 2005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. Due to the temporary nature of the tax benefit, the potential interest charge represents Entergy's net earnings exposure. Entergy Louisiana's 2001 tax return is currently under examination by the IRS, though no adjustments have yet been proposed with respect to the mark to market election. Entergy believes that the contingency p rovision established in its financial statements will sufficiently cover the risk associated with this issue.
CashPoint Bankruptcy
In 2003 the domestic utility companies entered an agreement with CashPoint Network Services (CashPoint) under which CashPoint was to manage a network of payment agents through which Entergy's utility customers could pay their bills. The payment agent system allows customers to pay their bills at various commercial or governmental locations, rather than sending payments by mail. Approximately one-third of Entergy's utility customers use payment agents.
On April 19, 2004, CashPoint failed to pay funds due to the domestic utility companies that had been collected through payment agents. The domestic utility companies then obtained a temporary restraining order from the Civil District Court for the Parish of Orleans, State of Louisiana, enjoining CashPoint from distributing funds belonging to Entergy, except by paying those funds to Entergy. On April 22, 2004, a petition for involuntary Chapter 7 bankruptcy was filed against CashPoint by other creditors in the United States Bankruptcy Court for the Southern District of New York. In response to these events, the domestic utility companies expanded an existing contract with another company to manage all of their payment agents. The domestic utility companies filed proofs of claim in the CashPoint bankruptcy proceeding in September 2004. Although Entergy cannot precisely determine at this time the amount that CashPoint owes to the domestic utility companies that may not be repaid, it has accrued an estimate of loss based on current information. If no cash is repaid to the domestic utility companies, an event Entergy does not believe is likely, the current estimate of maximum exposure to loss is approximately $25 million.
Employment Litigation
Entergy Corporation and certain subsidiaries are defendants in numerous lawsuits filed by former employees asserting that they were wrongfully terminated and/or discriminated against on the basis of age, race, sex, and/or sex.other protected characteristics. Entergy Corporation and these subsidiaries are vigorously defending these suits and deny any liability to the plaintiffs. Nevertheless, no assurance can be given as to the outcome of these cases.
NOTE 10.9. LEASES
General
As of December 31, 2002,2004, Entergy had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities (excluding nuclear fuel leases and the Grand Gulf 1 and Waterford 3 sale and leaseback transactions) with minimum lease payments as follows:
|
| Operating |
| Capital |
|
| (In Thousands) | ||
|
|
| ||
2005 |
| $99,246 |
| $9,660 |
2006 |
| 85,769 |
| 5,724 |
2007 |
| 68,557 |
| 3,438 |
2008 |
| 55,155 |
| 1,754 |
2009 |
| 45,240 |
| 237 |
Years thereafter |
| 210,474 |
| 2,606 |
Minimum lease payments |
| 564,441 |
| 23,419 |
Less: Amount representing interest |
| - |
| 3,388 |
Present value of net minimum lease payments |
| $564,441 |
| $20,031 |
Total rental expenses for all leases (excluding nuclear fuel leases and the Grand Gulf 1 and Waterford 3 sale and leaseback transactions) amounted to $60.1$81.3 million in 2002, $65.12004, $84.3 million in 2001,2003, and $53.3$92.2 million in 2000.2002.
Nuclear Fuel Leases
As of December 31, 2002,2004, arrangements to lease nuclear fuel existed in an aggregate amount up to $140$150 million for Entergy Arkansas, $105 million for Entergy Gulf States, $80 million for each of Entergy Gulf States and Entergy Louisiana, and $95$110 million for System Energy. As of December 31, 2002,2004, the unrecovered cost base of nuclear fuel leases amounted to approximately $88.1$93.9 million for Entergy Arkansas, $41.4$71.2 million for Entergy Gulf States, $50.9$31.7 million for Entergy Louisiana, and $79.0$65.6 million for System Energy. The lessors finance the acquisition and ownership of nuclear fuel through loans made under revolving credit agreements, the issuance of commercial paper, and the issuance of intermediate-term notes. The credit agreements for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy each have a termination datesdate of November 2003, November 2003, December 2004, and November 2003, respectively. Such ter minationOctober 30, 2006. The termination dates may be extended from time to time with the consent of the lenders. The intermediate-term notes issued pursuant to these fuel lease arrangementsa rrangements have varying maturities through MarchFebruary 15, 2006.2009. It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. However, if such additional financing cannot be arranged, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations.obligations in accordance with the fuel lease.
Lease payments are based on nuclear fuel use. The total nuclear fuel lease payments (principal and interest) as well as the separate interest component charged to operations by the domestic utility companies and System Energy were $146.6 million (including interest of $12.8 million) in 2004, $142.0 million (including interest of $11.8 million) in 2003, and $137.8 million (including interest of $11.3 million) in 2002, $149.3 million (including interest of $17.2 million) in 2001, and $158.7 million (including interest of $19.9 million) in 2000.2002.
Sale and Leaseback Transactions
Waterford 3 Lease Obligations
In 1989, Entergy Louisiana sold and leased back 9.3% of its interest in Waterford 3 for the aggregate sum of $353.6 million. The lease has an approximate term of 28 years. The lessors financed the sale-leaseback through the issuance of Waterford 3 Secured Lease Obligation Bonds. The lease payments made by Entergy Louisiana are sufficient to service the debt.
In 1994, Entergy Louisiana did not exercise its option to repurchase the 9.3% interest in Waterford 3. As a result, Entergy Louisiana issued $208.2 million of non-interest bearing first mortgage bonds as collateral for the equity portion of certain amounts payable under the lease.
In 1997, the lessors refinanced the outstanding bonds used to finance the purchase of Waterford 3 at lower interest rates, which reduced the annual lease payments.
Upon the occurrence of certain events, Entergy Louisiana may be obligated to assume the outstanding bonds used to finance the purchase of 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 (including preferred stock) 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, 2002,2004, Entergy Louisiana's total equity capital (including preferred stock) was 46.28%51.33% of adjusted capitalization and its fixed charge coverage ratio for 20022004 was 3.14.3.76.
As of December 31, 2002,2004 Entergy Louisiana had future minimum lease payments (reflecting an overall implicit rate of 7.45%) in connection with the Waterford 3 sale and leaseback transactions, which are recorded as long-term debt, as follows (in thousands):follows:
(In Thousands) | ||
2005 | $14,554 | |
2006 | 18,261 | |
2007 | 18,754 | |
2008 | 22,606 | |
2009 | 32,452 | |
Years thereafter | 334,062 | |
Total | 440,689 | |
Less: Amount representing interest | 192,964 | |
Present value of net minimum lease payments | $247,725 |
Grand Gulf 1 Lease Obligations
In December 1988, System Energy sold 11.5% of its undivided ownership interest in Grand Gulf 1 for the aggregate sum of $500 million. Subsequently, System Energy leased back its interest in the unit for a term of 26-1/2 years. System Energy has the option of terminating the lease and repurchasing the 11.5% interest in the unit at certain intervals during the lease. Furthermore, at the end of the lease term, System Energy has the option of renewing the lease or repurchasing the 11.5% interest in Grand Gulf.
In May 2004 System Energy caused the Grand Gulf 1.lessors to refinance the outstanding bonds that they had issued to finance the purchase of their undivided interest in Grand Gulf. The refinancing is at a lower interest rate, and System Energy's lease payments have been reduced to reflect the lower interest costs.
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 recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and is recording this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance at the end of the lease term. The amount of this net regulatory asset was $79.5$75.4 million and $88.7$83.2 million as of December 31, 20022004 and 2001, respect ively.2003, respectively.
As of December 31, 2002,2004 System Energy had future minimum lease payments (reflecting an implicit rate of 7.02%5.01%), which are recorded as long-term debt as follows (in thousands):follows:
(In Thousands) | ||
2005 | $45,423 | |
2006 | 46,019 | |
2007 | 46,552 | |
2008 | 47,128 | |
2009 | 47,760 | |
Years thereafter | 302,402 | |
Total | 535,284 | |
Less: Amount representing interest | 138,165 | |
Present value of net minimum lease payments | $397,119 |
NOTE 11.10. RETIREMENT, AND OTHER POSTRETIREMENT BENEFITS,
AND DEFINED CONTRIBUTION PLANS
Pension Plans
Entergy has seven pension plans covering substantially all of its employees: "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." Except for the Entergy Corporation Retirement Plan III, the pension plans are noncontributory and provide pension benefits that are based on employees' credited service and compensation during the final years before retirement.retirement. The Entergy Corporation Retirement Plan III includes a mandatory employee contribution of 3% of earnings during the first 10 years of plan participation, and allows volunt aryvoluntary contributions from 1% to 10% of earnings for a limited groupgrou p of employees. Entergy Corporation and its subsidiaries fund pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. As of December 31, 2002,2004 and 2003, Entergy recognized an additional minimum pension liability for the excess of the accumulated benefit obligation over the fair market value of plan assets. In accordance with FASBSFAS 87, an offsetting intangible asset, up to the amount of any unrecognized prior service cost, was also recorded, with the remaining offset to the liability recorded as a regulatory asset reflective of the recovery mechanism for pension costs in Entergy's jurisdictions.jurisdictions or to other comprehensive income for Entergy's non-regulated business. Entergy's domestic utility companies' and System Energy's pension costs are recovered from customers as a component of cost of service i nin each of its jurisdictions. Entergy uses a December 31 measurement date for its pension plans.
Components of Net Pension Cost
Total 2002, 2001,2004, 2003, and 20002002 pension costs of Entergy Corporation and its subsidiaries, including amounts capitalized, included the following components (in thousands):components:
|
| 2004 |
| 2003 |
| 2002 |
|
| (In Thousands) | ||||
|
|
|
|
|
|
|
Service cost - benefits earned |
| $76,946 |
| $70,337 |
| $56,947 |
Interest cost on projected |
| 148,092 |
| 134,403 |
| 128,387 |
Expected return on assets |
| (153,584) |
| (155,460) |
| (158,202) |
Amortization of transition asset |
| (763) |
| (763) |
| (763) |
Amortization of prior service cost |
| 5,143 |
| 5,886 |
| 5,993 |
Recognized net loss |
| 21,687 |
| 6,399 |
| 5,504 |
Curtailment loss |
| - |
| 14,864 |
| - |
Special termination benefits |
| - |
| 32,006 |
| - |
Net pension costs |
| $97,521 |
| $107,672 |
| $37,866 |
The funded status of Entergy's pension plansPensionObligations, Plan Assets, Funded Status, Amounts Not Yet Recognized and Recognized in the Balance Sheet as of December 31, 20022004 and 2001 was (in thousands)2003:
December 31, | ||||
2004 | 2003 | |||
(In Thousands) | ||||
Change in Projected Benefit Obligation (PBO) | ||||
Balance at beginning of year | $2,349,565 | $1,992,207 | ||
Service cost | 76,946 | 70,337 | ||
Interest cost | 148,092 | 134,403 | ||
Amendments | 3,709 | 227 | ||
Actuarial loss | 171,146 | 205,949 | ||
Benefits paid | (117,234) | (97,574) | ||
Employee contributions | 1,212 | 1,059 | ||
Curtailment loss | - | 10,951 | ||
Special termination benefits | - | 32,006 | ||
Balance at end of year | $2,633,436 | $2,349,565 | ||
Change in Plan Assets | ||||
Fair value of assets at beginning of year | $1,744,975 | $1,451,802 | ||
Actual return on plan assets | 170,964 | 355,043 | ||
Employer contributions | 72,825 | 34,645 | ||
Employee contributions | 1,212 | 1,059 | ||
Benefits paid | (117,234) | (97,574) | ||
Fair value of assets at end of year | $1,872,742 | $1,744,975 | ||
Funded status | ($760,694) | ($604,590) | ||
Amounts not yet recognized in the balance sheet | ||||
Unrecognized transition asset | (662) | (1,426) | ||
Unrecognized prior service cost | 29,053 | 30,467 | ||
Unrecognized net loss | 542,391 | 410,321 | ||
Accrued pension cost recognized in the balance sheet | ($189,912) | ($165,228) | ||
Amounts recognized in the balance sheet | ||||
Accrued pension cost | ($189,912) | ($165,228) | ||
Additional minimum pension liability | (244,280) | (180,212) | ||
Intangible asset | 26,167 | 30,832 | ||
Accumulated other comprehensive income | 10,781 | 15,359 | ||
Regulatory asset | 207,332 | 13,021 | ||
Net amount recognized | ($189,912) | ($165,228) |
Other Postretirement Benefits
Entergy also currently provides health care and life insurance benefits for retired employees. Substantially all domestic employees may become eligible for these benefits if they reach retirement age while still working for Entergy. Entergy uses a December 31 measurement date for its postretirement benefit plans.
Effective January 1, 1993, Entergy adopted SFAS 106, which required a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. At January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $241.4 million for Entergy (other than Entergy Gulf States) and $128 million for Entergy Gulf States. Such obligations are being amortized over a 20-year period that began in 1993.
Entergy Arkansas, For the portion of Entergy Gulf States regulated bymost part, the PUCT, Entergy Mississippi,domestic utilities and Entergy New Orleans have received regulatory approval toSystem Energy recover SFAS 106 costs through rates. Entergy Arkansas began recoveryfrom customers and are required to fund postretirement benefits collected in 1998, pursuantrates to an APSC order. This order also allowed Entergy Arkansas to amortize a regulatory asset (representing the difference between SFAS 106 costsexternal trust.
Components of Net Postretirement Benefit Cost
Total 2004, 2003, and cash expenditures for other postretirement benefits incurred for a five-year period that began January 1, 1993) over a 15-year period that began in January 1998.
The LPSC ordered the portion of Entergy Gulf States regulated by the LPSC and Entergy Louisiana to continue the use of the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions. However, the LPSC retains the flexibility to examine individual companies' accounting for postretirement benefits to determine if special exceptions to this order are warranted.
Pursuant to regulatory directives, Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, the portion of Entergy Gulf States regulated by the PUCT, and System Energy fund postretirement benefit obligations collected in rates. System Energy is funding on behalf of Entergy Operations postretirement benefits associated with Grand Gulf 1. Entergy Louisiana and Entergy Gulf States continue to recover a portion of these benefits regulated by the LPSC and FERC on a pay-as-you-go basis. The assets of the various postretirement benefit plans other than pensions include common stocks, fixed-income securities, and a money market fund.
Total 2002 2001, and 2000 other postretirement benefit costs of Entergy Corporation and its subsidiaries, including amounts capitalized and deferred, included the following components (in thousands):components:
| 2004 | 2003 | 2002 | |||
(In Thousands) | ||||||
Service cost - benefits earned |
|
|
| |||
Interest cost on APBO | 53,801 | 52,746 | 44,819 | |||
Expected return on assets | (18,825) | (15,810) | (14,066) | |||
Amortization of transition obligation | 9,429 | 15,193 | 17,874 | |||
Amortization of prior service cost | (5,222) | (925) | 992 | |||
Recognized net (gain)/loss | 15,546 | 12,369 | 1,874 | |||
Curtailment loss | - | 57,958 | - | |||
Special termination benefits | - | 5,444 | - | |||
Net other postretirement benefit cost | $85,676 | $164,774 | $80,692 |
The funded status of Entergy's other postretirement benefit plansOther Postretirement BenefitObligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet as of December 31, 20022004 and 20012003:
December 31, | ||||
2004 | 2003 | |||
(In Thousands) | ||||
Change in APBO | ||||
Balance at beginning of year | $941,803 | $799,506 | ||
Service cost | 30,947 | 37,799 | ||
Interest cost | 53,801 | 52,746 | ||
Actuarial loss | 73,890 | 115,966 | ||
Benefits paid | (66,456) | (48,379) | ||
Plan Amendments (a) | (60,231) | (84,722) | ||
Plan participant contributions | 9,312 | 7,074 | ||
Curtailments | - | 56,369 | ||
Special termination benefits | - | 5,444 | ||
Balance at end of year | $983,066 | $941,803 | ||
Change in Plan Assets | ||||
Fair value of assets at beginning of year | $227,446 | $182,692 | ||
Actual return on plan assets | 15,550 | 22,794 | ||
Employer contributions | 63,399 | 63,265 | ||
Plan participant contributions | 9,312 | 7,074 | ||
Benefits paid | (66,455) | (48,379) | ||
Fair value of assets at end of year | $249,252 | $227,446 | ||
Funded status | ($733,814) | ($714,357) | ||
Amounts not yet recognized in the balance sheet | ||||
Unrecognized transition obligation | 5,594 | 44,815 | ||
Unrecognized prior service cost | (39,560) | (20,746) | ||
Unrecognized net loss | 391,940 | 336,005 | ||
Accrued other postretirement benefit cost recognized in |
|
|
(a) | Reflects plan design changes, including a change in the participation assumption for the majority of non-bargaining employees effective August 1, 2003 and certain bargaining employees and additional non-bargaining employees effective January 1, 2004. |
Pension and Other Postretirement Plans' Assets
Entergy's pension and postretirement plans weighted-average asset allocations by asset category at December 31, 2004 and 2003 are as follows:
| Pension |
| Postretirement | ||||
| 2004 |
| 2003 |
| 2004 |
| 2003 |
|
|
|
|
|
|
|
|
Domestic Equity Securities | 46% |
| 56% |
| 38% |
| 37% |
International Equity Securities | 21% |
| 14% |
| 14% |
| 0% |
Fixed-Income Securities | 31% |
| 28% |
| 47% |
| 60% |
Other | 2% |
| 2% |
| 1% |
| 3% |
Entergy'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 study, Entergy formulates assumptions (or hires a consultant to provide such analysis) about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes. The future market assumptions used in the optimization study are determined by examining historical market characteristics of the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period.
The optimization analysis utilized in Entergy's latest study produced the following approved asset class target allocations.
| Pension |
| Postretirement |
|
|
|
|
Domestic Equity Securities | 45% |
| 37% |
International Equity Securities | 20% |
| 14% |
Fixed-Income Securities | 31% |
| 49% |
Other (Cash and GACs) | 4% |
| 0% |
These allocation percentages combined with each asset class' expected investment return produced an aggregate return expectation for the five years following the study of 7.6% for pension assets, 5.4% for taxable postretirement assets, and 7.2% for non-taxable postretirement assets. These returns are not inconsistent with Entergy's disclosed expected pre-tax return on assets of 8.50% over the life of the respective liabilities.
Since precise allocation targets are inefficient to manage security investments, the following ranges were established to produce an acceptable economically efficient plan to manage to targets:
Pension | Postretirement | ||
Domestic Equity Securities | 45% to 55% | 32% to 42% | |
International Equity Securities | 15% to 25% | 9% to 19% | |
Fixed-Income Securities | 25% to 35% | 44% to 54% | |
Other | 0% to 10% | 0% to 5% |
Accumulated Pension Benefit Obligation
The accumulated benefit obligation for Entergy's pension plans was (in thousands):$2.3 billion and $2.1 billion at December 31, 2004 and 2003, respectively.
Estimated Future Benefit Payments
Based upon the assumptions used to measure the company's pension and postretirement benefit obligation at December 31, 2004, and including pension and postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid over the next ten years will be as follows:
| Estimated Future Benefits Payments | ||
| Pension |
| Postretirement |
| (In Thousands) | ||
Year(s) |
| ||
2005 | $115,203 |
| $60,932 |
2006 | $116,894 |
| $59,761 |
2007 | $119,092 |
| $62,392 |
2008 | $122,728 |
| $64,381 |
2009 | $127,877 |
| $66,444 |
2010 - 2014 | $780,295 |
| $360,191 |
Contributions
Entergy expects to contribute $185.9 million (excluding about $1.2 million in employee contributions) to its pension plans and $63.3 million to other postretirement plans in 2005.
Additional Information
The change in the minimum pension liability included in other comprehensive income and regulatory assets was as follows for 2004 and 2003:
| 2004 |
| 2003 |
| (In Thousands) | ||
Increase/(decrease) in the minimum pension liability included in: |
| ||
Other comprehensive income | ($4,578) |
| ($1,639) |
Regulatory assets | $73,311 |
| ($23,768) |
Actuarial Assumptions
The assumed health care cost trend rate used in measuring the APBO of Entergy was 10% for 2003,2005, gradually decreasing each successive year until it reaches 4.5% in 20092011 and beyond. The assumed health care cost trend rate used in measuring the Net Other Postretirement Benefit Cost of Entergy was 10% for 2004, gradually decreasing each successive year until it reaches 4.5% in 2010 and beyond. A one percentage point increasechange in the assumed health care cost trend rate for 20022004 would have increased the APBO and the sum of the service cost and interest cost of Entergy as of December 31, 2002, by approximately $87.8 million and $10.6 million, respectively. A one percentage point decrease in the assumed health care cost trend rate for 2002 would have decreased the APBO and the sum of the service cost and interest cost of Entergy as of December 31, 2002, by approximately $79.8 million and $9.4 million, respectively.following effects:
| 1 Percentage Point Increase |
| 1 Percentage Point Decrease | |||||
|
|
| Impact on the |
|
|
| Impact on the | |
Increase (Decrease) | ||||||||
|
|
|
|
|
|
|
| |
Entergy Corporation | $99,271 |
| $11,587 |
| ($89,801) |
| ($10,061) |
The significant actuarial assumptions used in determining the pension PBO and the SFAS 106 APBO for 2002, 2001,2004, 2003, and 20002002 were as follows:
| 2004 |
| 2003 |
| 2002 |
Weighted-average discount rate: |
|
|
|
|
|
Pension | 6.00% |
| 6.25% |
| 6.75% |
Other postretirement | 6.00% |
| 6.71% |
| 6.75% |
Weighted-average rate of increase |
|
|
|
|
|
Expected long-term rate of |
|
|
|
|
|
Taxable assets | 5.50% |
| 5.50% |
| 5.50% |
Non-taxable assets | 8.50% |
| 8.75% |
| 8.75% |
The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2004, 2003, and 2002 were as follows:
. | 2004 |
| 2003 |
| 2002 |
|
|
|
|
|
|
Weighted-average discount rate | |||||
Pension | 6.25% |
| 6.75% |
| 7.50% |
Other postretirement | 6.71% | 6.75% | 7.50% | ||
Weighted-average rate of increase |
|
|
|
|
|
Expected long-term rate of |
|
|
|
|
|
Taxable assets | 5.50% |
| 5.50% |
| 5.50% |
Non-taxable assets | 8.75% |
| 8.75% |
| 9.00% |
Entergy's remaining pension transition assets are being amortized over the greater of the remaining service period of active participants or 15 years ending in 2005, and its SFAS 106 transition obligations are being amortized over 20 years.years ending in 2012.
Voluntary Severance Program
As part of an initiative to achieve productivity improvements with a goal of reducing costs, primarily in the Non-Utility Nuclear and U.S. Utility businesses, in the second half of 2003 Entergy offered a voluntary severance program to employees in various departments. Approximately 1,100 employees, including 650 employees in nuclear operations from the Non-Utility Nuclear and U.S. Utility businesses, accepted the offers. As a result of this program, in the fourth quarter 2003 Entergy recorded additional pension and postretirement costs (including amounts capitalized) of $110.3 million for special termination benefits and plan curtailment charges. These amounts are included in the net pension cost and net postretirement benefit cost for the year ended December 31, 2003.
Medicare Prescription Drug, Improvement and Modernization Act of 2003
In December 2003, the President signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 into law. The Act introduces a prescription drug benefit cost under Medicare (Part D), starting in 2006, as well as federal subsidy to employers who provide a retiree prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
At December 2003, specific authoritative guidance on the accounting for the federal subsidy was pending. As allowed by Financial Accounting Standards Board Staff Position No. FAS 106-1, Entergy elected to record an estimate of the effects of the Act in accounting for its postretirement benefit plans at December 31, 2003, under SFAS 106 and in providing disclosures required by SFAS No. 132 (revised 2003), Employers' Disclosures about Pensions and Other Postretirement Benefits. At December 31, 2003, based on actuarial analysis of prescription drug benefits, estimated future Medicare subsidies were expected to reduce the December 31, 2003 Accumulated Postretirement Benefit Obligation by $56 million. For the year ended December 31, 2003, the impact of the Act on net postretirement benefit cost was immaterial, as it reflected only one month's impact of the Act.
In 2004, Entergy continued to record an estimate of the effects the Act in accounting for its postretirement benefit plans. In mid-2004, the Financial Accounting Standards Board issued Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which was effective for Entergy's June 30, 2004 interim reporting.
In August 2004, the Centers for Medicare and Medicaid Services issued proposed regulations to implement the new Medicare law. A ruling from the Centers for Medicare and Medicaid Services was issued in late January 2005 with final guidance expected later this year.
The actuarially estimated effect of future Medicare subsidies reduced the December 31, 2003 and 2004 Accumulated Postretirement Benefit Obligation by $128 million and $161 million, respectively, and reduced the 2004 other postretirement benefit cost by $23.3 million.
Defined Contribution Plans
Entergy sponsors the Savings Plan of Entergy Corporation and Subsidiaries (System Savings Plan). The System Savings Plan is a defined contribution plan covering eligible employees of Entergy and its subsidiaries. Through January 31, 2004, the System Savings Plan provided that the employing Entergy subsidiary:
Effective February 1, 2004, the employing Entergy subsidiary began making matching contributions for non-bargaining employees to the System Savings Plan in an amount equal to 70% of the participants' basic contributions, up to 6% of their eligible earnings. The 70% match is allocated to investments as directed by the employee.
Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries II (established in 2001), the Savings Plan of Entergy Corporation and Subsidiaries III (established in 2002), and the Savings Plan of Entergy Corporation and Subsidiaries V (established in 2002). The plans are defined contribution plans that cover eligible employees, as defined by each plan, of Entergy and its subsidiaries. The employing Entergy subsidiary makes matching contributions equal to 50% of the participants' participating contributions for each of these plans. Effective September 30, 2004, employees participating in the Savings Plan of Entergy Corporation and Subsidiaries III (Savings Plan III) were transferred into the System Savings Plan and Savings Plan III was terminated.
Entergy's subsidiaries' contributions to defined contribution plans collectively were $32.9 million in 2004, $31.5 million in 2003, and $29.6 million in 2002. The majority of the contributions were to the System Savings Plan.
NOTE 12.11. BUSINESS SEGMENT INFORMATION
Entergy's reportable segments as of December 31, 20022004 are U.S. Utility, Non-Utility Nuclear, and Energy Commodity Services. U.S. Utility generates, transmits, distributes, and sells electric power in portions of Arkansas, Louisiana, Mississippi, and Texas, and provides natural gas utility service in portions of Louisiana. Non-Utility Nuclear owns and operates five nuclear power plants and is primarily focused on selling electric power produced by those plants to wholesale customers. Energy Commodity Services is focused primarily on providingincludes Entergy-Koch, LP and Entergy's non-nuclear wholesale assets business. Entergy-Koch engaged in two major businesses: energy commodity marketing and trading through Entergy-Koch Trading, and gas transportation and storage services through Gulf South Pipeline. Entergy-Koch L.P. Energy Commodity Services also includessold both of these businesses in the fourth quarter of 2004, and Entergy-Koch is no longer an operating entity. The non-nuclear wholesale assets a participant inbusiness sells to wholesale customers the wholesaleelectric power generation business in North Americaproduce d by power plants that it owns while it focuses on improving performance and Europe.exploring sales or restructuring opportunities for its power plants. Such opportunities are evaluated consistent with Entergy's market-based point-of-view. Results from Entergy-Koch are reported as equity in earnings of unconsolidated equity affiliates in the fin ancialfinancial statements. Entergy's operating segments are strategic business units managed separately due to their different operating and regulatory environments. Entergy's chief operating decision maker is its Office of the Chief Executive, which consists of its highest-ranking officers.
"All"All Other" includes the parent company, Entergy Corporation, and other business activity, including the Competitive Retail Services business, which has higher revenues in 2004 as its number of customers has increased, and earnings on the proceeds of sales of previously ownedpreviously-owned businesses.
Entergy's segment financial information is as follows (in thousands):
follows:
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| Energy |
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|
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| (In Thousands) | ||||||||||
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|
|
Operating revenues | $8,142,808 |
| $1,341,852 |
| $216,450 |
| $486,804 |
| ($64,190) |
| $10,123,724 |
Deprec., amort. & decomm. | $915,667 |
| $106,408 |
| $16,311 |
| $6,736 |
| $- |
| $1,045,122 |
Interest income | $40,831 |
| $63,569 |
| $17,875 |
| $42,729 |
| ($55,195) |
| $109,809 |
Equity in loss of |
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|
|
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|
|
Interest charges | $383,032 |
| $53,657 |
| $15,560 |
| $81,916 |
| ($55,142) |
| $479,023 |
Income taxes (credits) | $406,864 |
| $142,620 |
| ($155,840) |
| ($27,736) |
| $- |
| $365,908 |
Net income | $666,691 |
| $245,029 |
| $3,778 |
| $17,606 |
| ($55) |
| $933,049 |
Total assets | $22,937,237 |
| $4,531,604 |
| $2,223,961 |
| $199,233 |
| ($1,581,258) |
| $28,310,777 |
Investment in affiliates - at equity | $207 |
| $- |
| $512,571 |
| $- |
| ($280,999) |
| $231,779 |
Cash paid for long-lived asset additions |
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| Energy |
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| (In Thousands) | ||||||||||
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Operating revenues | $7,584,857 |
| $1,274,983 |
| $184,888 |
| $188,228 |
| ($38,036) |
| $9,194,920 |
Deprec., amort. & decomm. | $890,092 |
| $87,825 |
| $13,681 |
| $5,005 |
| $- |
| $996,603 |
Interest income | $43,035 |
| $36,874 |
| $18,128 |
| $27,575 |
| ($38,226) |
| $87,386 |
Equity in earnings (loss) of |
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Interest charges | $419,111 |
| $34,460 |
| $15,193 |
| $75,787 |
| ($38,225) |
| $506,326 |
Income taxes (credits) | $341,044 |
| $88,619 |
| $105,903 |
| ($45,492) |
| $- |
| $490,074 |
Cumulative effect of accounting change |
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Net income (loss) | $492,574 |
| $300,799 |
| $180,454 |
| ($23,360) |
| $- |
| $950,467 |
Total assets | $22,402,314 |
| $4,171,777 |
| $2,076,921 |
| $1,495,903 |
| ($1,619,527) |
| $28,527,388 |
Investment in affiliates - at equity | $211 |
| $- |
| $1,081,462 |
| $- |
| ($28,345) |
| $1,053,328 |
Cash paid for long-lived asset additions |
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| Energy |
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| (In Thousands) | ||||||||||
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Operating revenues | $6,773,509 |
| $1,200,238 |
| $294,670 |
| $40,729 |
| ($4,111) |
| $8,305,035 |
Deprec., amort. & decomm. | $800,257 |
| $88,733 |
| $21,465 |
| $5,143 |
| $- |
| $915,598 |
Interest income | $23,231 |
| $71,262 |
| $26,140 |
| $35,433 |
| ($37,741) |
| $118,325 |
Equity in earnings (loss) of | ($2) |
| $- |
| $183,880 |
| $- |
| $- |
| $183,878 |
Interest charges | $465,703 |
| $47,291 |
| $61,632 |
| $35,579 |
| ($37,741) |
| $572,464 |
Income taxes (credits) | $313,752 |
| $132,726 |
| ($141,288) |
| ($11,252) |
| $- |
| $293,938 |
Net income (loss) | $606,963 |
| $200,505 |
| ($145,830) |
| ($38,566) |
| $- |
| $623,072 |
Total assets | $21,630,523 |
| $4,482,308 |
| $2,167,472 |
| $1,327,354 |
| ($2,103,291) |
| $27,504,366 |
Investment in affiliates - at equity | $214 |
| $- |
| $823,995 |
| $- |
| $- |
| $824,209 |
Cash paid for long-lived asset additions | $1,131,734 |
| $169,756 |
| $210,297 |
| $18,514 |
| $- |
| $1,530,301 |
Businesses marked with * are referred to as the "competitive businesses," with the exception of the parent company, Entergy Corporation.Corporation, which is included in "All Other." Eliminations are primarily intersegment activity. Substantially all of Entergy's recorded asset for goodwill is in its U.S. Utility segment.
In the fourth quarter 2004, Entergy recorded a charge of approximately $55 million ($36 million net-of-tax) as a result of an impairment of the value of the Warren Power plant. Entergy concluded that the value of the plant, which is owned in the non-nuclear wholesale assets business, was impaired. Entergy reached this conclusion based on valuation studies prepared in connection with the sale of preferred stock in a subsidiary in the non-nuclear wholesale assets business.
Energy Commodity Services' net loss for the year ended December 31, 2002 includes net charges of $428.5 million to operating expenses ($238.3 million net of tax)net-of-tax). These charges reflect the effect of Entergy's decision to discontinue additional greenfield power plant development and the asset impairments resulting from the deteriorating economics of wholesale power markets in the United States and the United Kingdom. The net charges consist of the following:
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| Paid in |
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| (In Millions) |
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| ||
Fixed asset impairments |
| $22.5 |
| $- |
| $22.5 |
| $- |
Sublease losses |
| 10.7 |
| 5.6 |
| - |
| 5.1 |
Severance and related costs |
| 5.9 |
| 5.9 |
| - |
| - |
Total |
| $39.1 |
| $11.5 |
| $22.5 |
| $5.1 |
Geographic Areas
The following table shows Entergy's domestic and foreign operating revenues forFor the years ended December 31, (in thousands):2004 and 2003, Entergy derived less than 1% of its revenue from outside of the United States. For the year ended December 31, 2002 Entergy derived 3% of its revenue from outside of the United States.
2002 | 2001 | 2000 | |
Domestic | $8,051,992 | $9,098,861 | $9,950,229 |
Foreign | 253,043 | 522,038 | 71,900 |
Consolidated | $8,305,035 | $9,620,899 | $10,022,129 |
Long-lived assets asAs of December 31, were as follows (in thousands):2004 and 2003 Entergy had almost no long-lived assets located outside of the United States.
2002 | 2001 | 2000 | |
Domestic | $17,194,179 | $16,468,059 | $15,425,915 |
Foreign | 773 | 421,870 | 1,019,831 |
Consolidated | $17,194,952 | $16,889,929 | $16,445,746 |
NOTE 13.12. EQUITY METHOD INVESTMENTS
As of December 31, 2004, Entergy owns investments in the following companies that it accounts for under the equity method of accounting: Entergy-Koch, LP (in which Entergy holds a 50% member interest), a company engaged in two major businesses: energy commodity trading, which includes power, gas, weather derivatives, emissions, and cross-commodities, and gas transportation and storage; RS Cogen LLC (in which Entergy holds a 50% member interest), a co-generation project that provides power on an industrial and merchant basis in the Lake Charles, Louisiana area; EntergyShaw LLC (in which Entergy holds a 50% member interest), a company which provides management, engineering, procurement, construction, and commissioning services for electric power plants; and Crete Energy Ventures, LLC (in which Entergy holds a 50% member interest), a merchant power plant located in Crete, Illinois.
Company | Ownership | Description | ||
Entergy-Koch, LP | 50% partnership interest | Engaged in two major businesses: energy commodity marketing and trading through Entergy-Koch Trading, and gas transportation and storage through Gulf South Pipeline. Entergy-Koch sold both of these businesses in the fourth quarter of 2004, and Entergy-Koch is no longer an operating entity. | ||
RS Cogen LLC | 50% member interest | Co-generation project that produces power and steam on an industrial and merchant basis in the Lake Charles, Louisiana area. | ||
Top Deer | 50% member interest | Wind-powered electric generation joint venture. |
Following is a reconciliation of Ent ergy'sEntergy's investments in equity affiliates (in thousands):affiliates:
2004 | 2003 | 2002 | ||||||||||
2002 | 2001 | 2000 | (In Thousands) | |||||||||
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Beginning of year | $766,103 | $136,487 | $117,378 | $1,053,328 | $824,209 | $766,103 | ||||||
Additional investments | 36,372 | 471,102 | 25,943 | 157,020 | 4,668 | 36,372 | ||||||
Income from the investments | 205,340 | 180,956 | 13,715 | |||||||||
Dividends received | (73,902) | (21,191) | (20,468) | |||||||||
Currency translation adjustments | - | 138 | (891) | |||||||||
Income (loss) from the investments | (78,727) | 271,647 | 183,878 | |||||||||
Other income | 6,232 | 45,583 | 21,462 | |||||||||
Distributions received | (888,260) | (105,142) | (73,902) | |||||||||
Dispositions and other adjustments | (109,704) | (1,389) | 810 | (17,814) | 12,363 | (109,704) | ||||||
End of year | $824,209 | $766,103 | $136,487 | $231,779 | $1,053,328 | $824,209 |
The following is a summary of combined financial information reported by Entergy's equity method investees (in thousands):
investees:
| 2004 | 2003 | 2002 | |||||||||
| (In Thousands) | |||||||||||
2002 | 2001 | 2000 | ||||||||||
Income Statement Items |
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| |||||||||
Operating revenues | $551,853 | $693,400 | $200,026 | |||||||||
Operating revenues |
| $270,177 |
| $585,404 |
| $551,853 | ||||||
Operating income |
| ($111,535) |
| $207,301 |
| $159,342 | ||||||
Net income |
| $739,858 (1) |
| $172,595 |
| $68,095 | ||||||
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Balance Sheet Items | ||||||||||||
Current assets | $2,334,133 | $2,969,132 | ||||||||||
Current assets |
| $540,386 |
| $2,576,630 |
| |||||||
Noncurrent assets |
| $418,038 |
| $1,675,334 |
| |||||||
Current liabilities |
| $180,009 |
| $1,757,663 |
| |||||||
Noncurrent liabilities |
| $463,899 |
| $1,166,540 |
|
Two(1) Includes gains recorded by Entergy-Koch on the sales of the unconsolidated 50/50 joint ventures, Entergy-Kochits energy trading and RS Cogen, have obtained debt financing for their operations. As of December 31, 2002, the debt financing outstanding for those two entities totals $818 million, which is included in the liability figures given above. This debt is nonrecourse to Entergy.pipeline businesses.
Related-party transactions and guarantees
During 20022004, 2003, and 2001,2002, Entergy procured various services from Entergy-Koch consisting primarily of pipeline transportation services for natural gas and risk management services for electricity and natural gas. The total cost of such services in 20022004, 2003, and 20012002 was approximately $9.5 million, $15.9 million, and $11.2 million, respectively. In 2003, Entergy Louisiana and $7.8Entergy New Orleans entered purchase power agreements with RS Cogen, and purchased a total of $26.0 million respectively.of capacity and energy from RS Cogen in 2003. In 2004, Entergy Louisiana and Entergy New Orleans purchased a total of $43.6 million of capacity and energy from RS Cogen. Entergy's operating transactions with its other equity method investees were not material in 2002, 2001,2004, 2003, or 2000.2002.
OneIn the purchase agreements for its energy trading and the pipeline business sales, Entergy-Koch has agreed to indemnify the respective purchasers for certain potential losses relating to any breaches of the contracts transferredsellers' representations, warranties, and obligations under each of the purchase agreements. Entergy Corporation has guaranteed up to Entergy-Koch by Entergy's power marketing50% of Entergy-Koch's indemnification obligations to the purchasers. Entergy does not expect any material claims under these indemnification obligations, but to the extent that any are asserted and trading business is backed bypaid, the gain that Entergy expects to record in 2006 may be reduced.
During the fourth quarter of 2004, an Entergy Corporation guarantee authorized insubsidiary purchased from a commercial bank holder $16.3 million of RS Cogen subordinated indebtedness, due October 2017, bearing interest at LIBOR plus 4.50%. The debt was purchased at a discount of approximately $2.4 million that will be amortized over the amount of $35 million. The guarantee term is through the expirationremaining life of the underlying contract, which ends in 2018.
EntergyShaw is currently constructing the Harrison County project for Entergy. Entergy has guaranteed the obligations of EntergyShaw to construct the plant, and Entergy's maximum liability on the guarantee is $232.5 million. The project is expected to be completed in 2003.
debt.
NOTE 14.13. ACQUISITIONS AND DISPOSITIONS
Asset Acquisitions
Vermont Yankee
In July 2002, Entergy's Non-Utility Nuclear business purchased the 510 MW Vermont Yankee nuclear power plant located in Vernon, Vermont, from Vermont Yankee Nuclear Power Corporation for $180 million. Entergy received the plant, nuclear fuel, inventories, and related real estate. The liability to decommission the plant, as well as related decommissioning trust funds of approximately $310 million, was also transferred to Entergy. The acquisition included a 10-year power purchase agreement (PPA) under which the former owners will buy the power produced by the plant, which is through the expiration of the current operating license for the plant. The PPA includes an adjustment clause wherewhich provides that the prices specified in the PPA will be adjusted downward annually, beginning in 2006,December 2005, if power market prices drop below the PPA prices.
The acquisition was accounted for using the purchase method. The results of operations of Vermont Yankee subsequent to the purchase date have been included in Entergy's consolidated results of operations. The purchase price has been preliminarily allocated to the assets acquired and liabilities assumed based on their estimated fair values on the purchase date. The allocation was based on preliminary information and the final allocation may differ, although management does not expect the difference to be material.
Indian Point 2
In September 2001, Entergy's Non-Utility Nuclear business acquired the 970 MW Indian Point 2 nuclear power plant located in Westchester County, New York from Consolidated Edison. Entergy paid approximately $600 million in cash at the closing of the purchase and received the plant, nuclear fuel, materials and supplies, a purchase power agreement (PPA), and assumed certain liabilities. On the second anniversary of the Indian Point 2 acquisition, Entergy's nuclear business will also begin to pay NYPA $10 million per year for up to 10 years in accordance with the Indian Point 3 purchase agreement. Under the PPA, Consolidated Edison will purchase 100% of Indian Point 2's output through 2004. Consolidated Edison transferred a $430 million decommissioning trust fund, along with the liability to decommission Indian Point 2 and Indian Point 1, to Entergy. Entergy acquired Indian Point 1 in the transaction, a plant that has been shut down and in safe storage since the 1970s.
The acquisition was accounted for using the purchase method. The results of operations of Indian Point 2 subsequent to the purchase date have been included in Entergy's consolidated results of operations. The purchase price has been allocated to the acquired assets, including identifiable intangible assets, and liabilities assumed based on their estimated fair values on the purchase date. Intangible assets are being amortized straight-line over the remaining life of the plant.
Indian Point 3 and FitzPatrick
In November 2000, Entergy's Non-Utility Nuclear business acquired from NYPA the 825 MW James A. FitzPatrick nuclear power plant near Oswego, New York, and the 980 MW Indian Point 3 nuclear power plant located in Westchester County, New York, in exchange for $50 million at closing and notes to NYPA with payments totaling $906 million. Entergy will also be required to make certain additional payments to NYPA in the event that the plants' license lives are extended.
The acquisition encompassed the nuclear plants, materials and supplies, and nuclear fuel, as well as the assumption of $124 million in liabilities. The purchase agreement provides that NYPA will purchase a substantial majority of the output of the units at specified prices through 2004. The purchase agreement also provides that NYPA will retain the decommissioning obligations and related trust funds through the original license expiration date (approximately 2015). At that time, NYPA is required either to transfer the decommissioning liability to Entergy along with a specified amount in the decommissioning trust funds, or to retain Entergy to perform decommissioning services for a specified price that may be limited by the amount in the trust. In the purchase price allocation, Entergy recorded an asset representing its estimate of the net present value of the decommissioning contract obta ined in the acquisition, based on an independent decommissioning cost study and other projections. The asset increases by monthly accretion based on the discount rate used to determine the original net present value. Entergy records the monthly accretion as interest income.
The acquisition was accounted for using the purchase method. The results of operations of Indian Point 3 and FitzPatrick subsequent to the purchase date have been included in Entergy's consolidated statements of income. The purchase price has been allocated to the acquired assets, including identifiable intangible assets, and liabilities assumed based on their estimated fair values on the purchase date. Intangible assets are being amortized straight-line over the remaining lives of the plants.
Asset Dispositions
Entergy-Koch Businesses
In the fourth quarter of 2004, Entergy-Koch sold its energy trading and pipeline businesses to third parties. The sales came after a review of strategic alternatives for enhancing the value of Entergy-Koch, LP. Entergy received $862 million of cash distributions in 2004 from Entergy-Koch after the business sales, and Entergy ultimately expects to receive total net cash distributions exceeding $1 billion, comprised of the after-tax cash from the distributions of the sales proceeds and the eventual liquidation of Entergy-Koch. Entergy currently expects the net cash distributions that it will receive will exceed its equity investment in Entergy-Koch, and expects to record a $60 million net-of-tax gain when it receives the remaining cash distributions, which it expects will occur in 2006.
Other
In January 2004, Entergy sold its 50% interest in the Crete project, which is a 320MW power plant located in Illinois, and realized an insignificant gain on the sale.
In the fourth quarter of 2004, Entergy sold undivided interests in the Warren Power and the Harrison County plants at a price that approximated book value.
In the first quarter of 2002, Entergy sold its interests in projects in Argentina, Chile, and Peru for net proceeds of $135.5 million. After impairment provisions recorded for these Latin American interests in 2001, the net loss realized on the sale in 2002 iswas insignificant.
In August 2002, Entergy sold its interest in projects under development in Spain for a realized gain on the sale of $25.7 million. In December 2002, Entergy sold its 800 MW Damhead Creek power plant forin the UK resulting in an after-tax gain on the saleincrease in net income of $31.4 million. The Damhead Creek buyer assumed all market and regulatory risks associated with the facility.
In August 2001, Entergy sold the Saltend plant for a cash payment of approximately $800 million. Entergy's gain on the sale was approximately $88.1 million ($57.2 million after tax). In the sales transaction, Entergy or its subsidiaries made certain warranties to the purchasers relating primarily to the performance of certain remedial work on the facility and the assumption of responsibility for certain contingent liabilities. Entergy believes that it has provided adequate reserves for the warranties as of December 31, 2002.
NOTE 15.14. RISK MANAGEMENT AND FAIR VALUES
Market and Commodity Risks
In the normal course of business, Entergy is exposed to a number of market and commodity risks. Market risk is the potential loss that Entergy may incur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Entergy is subject to a number of commodity and market risks, including:
Type of Risk | Primary Affected Segments | |
Power price risk | All reportable segments | |
Fuel price risk | All reportable segments | |
Foreign currency exchange rate risk | All reportable segments | |
Equity price and interest rate risk - investments | U.S. Utility, Non-Utility Nuclear |
Entergy manages these risks through both contractual arrangements and derivatives. Contractual risk management tools include long-term power and fuel purchase agreements, capacity contracts, and tolling agreements. Entergy also uses a variety of commodity and financial derivatives, including natural gas and electricity futures, forwards, swaps, and options,options; foreign currency forwards,forwards; and interest rate swaps as a part of its overall risk management strategy. Except for the energy trading activities conducted through December 2004 by the Energy Commodity Services segment,Entergy-Koch, Entergy enters into derivatives only to manage natural risks inherent in its physical or financial assets or liabilities.
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. 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 per iods.periods. These policies, including related risk limits, are regularly assessed to ensure theirthei r appropriateness given Entergy's objectives.
Hedging Derivatives
Entergy classifies substantially all of the following types of derivative instruments held by its consolidated businesses as cash flow hedges:
Instrument | Business Segment | |
Natural gas and electricity futures and forwards | Non-Utility Nuclear, Energy Commodity | |
Foreign currency forwards | U.S. Utility, Non-Utility Nuclear |
Cash flow hedges with net unrealized gainslosses of approximately $21$99 million at December 31, 20022004 are scheduled to mature during 2003. Gains2005. Net losses totaling approximately $4.3$13 million were realized during 20022004 on the maturity of cash flow hedges. A substantial majority of these unrealizedUnrealized gains or losses result from hedging power output at the Non-Utility Nuclear power stations and realized gains resulted from foreign currency hedges related to Euro-denominated nuclear fuel acquisition contracts, andacquisitions. The related gains or losses from hedging power are included in revenues when realized. The realized gains or losses from foreign currency transactions are included in the capitalized cost of nuclearcapitalized fuel. The maximum length of time over which Entergy is currently hedging the variability in future cash flows for forecasted transactions at December 31, 20022004 is approximately fivefour years. The ineffective portion of the change in the value of Entergy's cash flow hedges during 20022004 was insignificant.
Other Derivatives
Entergy also holds derivative instruments such as natural gas and electricity options and forwards that are not accounted for as hedges. These instruments are entered into to optimize asset values or limit risks.
Fair Values
Commodity Instruments
Fair value estimates of Energy Commodity Services' commodity instruments are made at discrete points in time based on relevant market information. Market quotes are used in determining fair value whenever they are available. When market quotes are not available (e.g., in the case of a long-dated commodity contract), other information is used, including transactional data and internally developed models. Fair value estimates based on these other methodologies are necessarily subjective in nature and involve uncertainties and matters of significant judgment. Therefore, actual results may differ from these estimates. At December 31, 2002 and 2001, the fair values of Energy Commodity Services' energy-related commodity contracts accounted for on a mark-to-market basis were as follows:
2002 | 2001 | ||||||
Assets | Liabilities | Assets | Liabilities | ||||
(In Thousands) | |||||||
Consolidated subsidiaries | $4,071 | $8,395 | $59,996 | $18,882 | |||
Equity method investees (1) | $754,678 | $663,765 | $774,509 | $667,752 |
(1)As required by equity method accounting principles, only Entergy's net investment in these investees is reflected in its balance sheet, and these assets and liabilities are not reflected in Entergy's balance sheet. See Note 13 to the consolidated financial statements for more information on Entergy's equity method investees.
Following are the cumulative periods in which the net mark-to-market assets would be realized in cash if they are held to maturity and market prices are unchanged:
Maturities and Sources for Fair Value of Trading Contracts at December 31, 2002 | 2003 | 2004 | 2005 - 2006 | Total | ||||||||||
(In Millions) | ||||||||||||||
Prices actively quoted | $45.0 | $45.1 | ($20.2) | $69.9 | ||||||||||
Prices provided by other sources | 24.4 | 3.3 | 1.9 | 29.6 | ||||||||||
Prices based on models | (13.3) | 1.3 | 3.4 | (8.6) | ||||||||||
Total | $56.1 | $49.7 | ($14.9) | $90.9 |
Financial Instruments
The estimated fair value of Entergy's financial instruments is determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. The estimated fair value of derivative financial instruments is based on market quotes. Considerable judgment is required in developing some of the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. In addition, gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not necessarily accrue to the benefit or detriment of stockholders.
Entergy considers the carrying amounts of most of its 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. Additional information regarding financial instruments and their fair values is included in Notes 5 6, and 76 to the consolidated financial statements.
NOTE 15. DECOMMISSIONING TRUST FUNDS
Entergy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held at December 31, 2004 and 2003 are summarized as follows:
2004 | Fair | Total | Total | |||
(In Millions) | ||||||
Equity | $995 | $166 | $17 | |||
Debt Securities | 1,457 | 33 | 6 | |||
Total | $2,452 | $199 | $23 | |||
2003 | ||||||
Equity | $896 | $81 | $11 | |||
Debt Securities | 1,383 | 27 | 3 | |||
Total | $2,279 | $108 | $14 |
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 at December 31, 2004:
Equity Securities | Debt Securities | |||||||
Fair | Gross | Fair | Gross | |||||
(In Millions) | ||||||||
Less than 12 months | $29 | $2 | $334 | $5 | ||||
More than 12 months | 115 | 15 | 37 | 1 | ||||
Total | $144 | $17 | $371 | $6 |
Entergy evaluates these unrealized gains and losses at the end of each period to determine whether an other than temporary impairment has occurred. This analysis considers the length of time that a security has been in a loss position, the current performance of that security, and whether decommissioning costs are recovered in rates. Due to the regulatory treatment of decommissioning collections and trust fund earnings, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy record regulatory assets or liabilities for unrealized gains and losses on trust investments. For the unregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains or losses in other deferred credits. No significant impairments were recorded in 2004 and 2003 as a result of these evaluations.
The fair value of debt securities, summarized by contractual maturities, at December 31, 2004 is as follows:
Fair | ||
(In Millions) | ||
less than 1 year | $134 | |
1 year - 5 years | 592 | |
5 years - 10 years | 425 | |
10 years - 15 years | 158 | |
15 years - 20 years | 60 | |
20 years+ | 88 | |
Total | $1,457 |
During the year ended December 31, 2004, the proceeds from the dispositions of securities amounted to $37 million with gross gains of $0.7 million and gross losses of $0.7 million, which were reclassified out of other comprehensive income into earnings during the period.
NOTE 16. QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating results for the four quarters of 20022004 and 20012003 were:
Operating | Operating | Net | Operating |
| Operating |
| Net | |||
2002: | (In Thousands) | |||||||||
| (In Thousands) | |||||||||
2004: |
| |||||||||
First Quarter | $1,860,834 | $(45,675) | $(72,983) | $2,251,549 |
| $378,834 |
| $213,016 | ||
Second Quarter | 2,096,581 | 496,154 | 247,585 | $2,485,097 |
| $494,312 |
| $271,011 | ||
Third Quarter | 2,468,875 | 663,689 | 366,800 | $2,963,581 |
| $571,472 |
| $288,047 | ||
Fourth Quarter | 1,878,745 | 73,512 | 81,670 | $2,423,497 |
| $208,946 |
| $160,975 | ||
2001: | ||||||||||
|
|
|
|
| ||||||
2003: |
|
|
|
|
| |||||
First Quarter | $2,652,427 | $360,967 | $160,871 | $2,037,723 |
| $363,403 |
| $400,923(a) | ||
Second Quarter | 2,506,275 | 480,549 | 245,583 | $2,353,909 |
| $461,576 |
| $211,517 | ||
Third Quarter | 2,576,889 | 607,656 | 317,454 | $2,700,125 |
| $619,005 |
| $371,650 | ||
Fourth Quarter | 1,885,308 | 124,170 | 26,599 (a) | $2,103,163 |
| $40,571 |
| ($33,623) |
(a) | Net income before the cumulative effect of accounting changes for the first quarter 2003 was $258,001. |
Earnings per Average Common Share
2004 | 2003 | ||||||
Basic | Diluted | Basic | Diluted | ||||
First Quarter | $0.90 | $0.88 | $1.77(b) | $1.73(b) | |||
Second Quarter | $1.16 | $1.14 | $0.91 | $0.89 | |||
Third Quarter | $1.24 | $1.22 | $1.60 | $1.57 | |||
Fourth Quarter | $0.71 | $0.69 | ($0.19) | ($0.18) |
2002 | 2001 | |||
Basic | Diluted | Basic | Diluted | |
First Quarter | $(0.36) | $(0.36) | $0.70 | $0.69 |
Second Quarter | $1.08 | $1.06 | $1.08 | $1.06 |
Third Quarter | $1.61 | $1.59 | $1.41 | $1.39 |
Fourth Quarter | $0.36 | $0.35 | $0.10 (b) | $0.09 (b) |
(b) | Basic and diluted earnings per average common share before the cumulative effect of accounting changes for the first quarter of 2003 were $1.13 and $1.10, respectively. |
ENTERGY'S BUSINESS (continued)
U.S. Utility
The U.S. Utility is Entergy's largest business segment, with five wholly-owned domestic retail electric utility subsidiaries: Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. These companies generate, transmit, distribute and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Gulf States 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 U.S. Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf 1. System Energy sells all theits power and capacity from Grand Gulf 1 at wholesale to the domestic utility companies.
Entergy Services, a corporation wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the domestic utility companies. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf 1, subject to the owner oversight of Entergy Arkansas, Entergy Gulf States,Louisiana, Entergy Louisiana, and System Energy, respectively. Entergy ServicesMississippi, and Entergy Operations provide their services to the domestic utility companies and System Energy on an "at cost" basis, pursuant to service agreements approved by the SEC under PUHCA.New Orleans.
These utility subsidiaries are each regulated by state utility commissions, and in the case of Entergy New Orleans, the City Council. System Energy is regulated by FERC as all of its transactions are at the wholesale level. The U.S. Utility continues to operate as a monopoly as efforts toward deregulation have either been delayed, abandoned, or not initiated in its service territories. The overall generation portfolio of the U.S. Utility, which is primarily made up ofrelies heavily on natural gas and nuclear generation, is consistent with Entergy's strong support for the environment.
The U.S. Utility is focused on providing highly reliable and cost effective electricity and gas service while working in an environment that provides the highest level of safety for its employees. Since 1998, the U.S. Utility has significantly improved key customer service, reliability, and safety metrics and continues to actively pursue additional improvements.
Customers
As of December 31, 2002,2004, Entergy's domestic utility companies provided retail electric and gas service to approximately 2.6 million customers in Arkansas, Louisiana, Mississippi, and Texas.Texas, as follows:
Electric Customers | Gas Customers | ||||||||
Area Served | (In Thousands) | (%) | (In Thousands) | (%) | |||||
Entergy Arkansas | Portions of Arkansas | 667 | 25% | ||||||
Entergy Gulf States | Portions of Texas and | 724 | 27% | 91 | 39% | ||||
Entergy Louisiana | Portions of Louisiana | 662 | 25% | ||||||
Entergy Mississippi | Portions of Mississippi | 420 | 16% | ||||||
Entergy New Orleans | City of New Orleans* | 189 | 7% | 145 | 61% | ||||
Total customers | 2,662 | 100% | 236 | 100% |
* | Excludes the Algiers area of the city, where Entergy Louisiana provides electric service. |
Electric Energy Sales
The electric energy sales of Entergy's domestic utility companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On August 2, 2002,July 15, Entergy reached a 20022004 peak demand of 20,41921,174 MW, compared to the 20012003 peak of 20,25720,162 MW recorded on August 2119 of that year. Selected electric energy sales data is shown in the table below:
Selected 20022004 Electric Energy Sales Data
Entergy | Entergy | Entergy | Entergy | Entergy | System | Entergy | ||||||||
(In GWh) | ||||||||||||||
Sales to retail |
|
|
|
|
|
|
| |||||||
Sales for resale: | ||||||||||||||
Affiliates | 7,437 | 1,528 | 1,129 | 305 | 1,514 | 9,212 | - | |||||||
Others | 4,911 | 3,172 | 122 | 393 | 25 | - | 8,623 | |||||||
Total | 32,083 | 39,975 | 29,434 | 13,676 | 7,594 | 9,212 | 110,849 | |||||||
Average use per |
|
|
|
|
|
|
|
(a) | Includes the effect of intercompany eliminations. |
The following table illustrates the domestic utility companies' 20022004 combined electric sales volume as a percentage of total electric sales volume, and 20022004 combined electric revenues as a percentage of total 20022004 electric revenue, each by customer class.
Customer Class % of Sales Volume % of Revenue
Residential................... 29.2 36.7Commercial................. 22.7 25.2Industrial (a)................ 36.9 27.9Wholesale................... 8.8 7.5Governmental.............. 2.4 2.7
Customer Class | % of Sales Volume | % of Revenue | ||
Residential | 29.7 | 35.2 | ||
Commercial | 23.9 | 25.3 | ||
Industrial (a) | 36.3 | 28.6 | ||
Wholesale | 7.8 | 8.3 | ||
Governmental | 2.3 | 2.6 |
(a) | Major industrial customers are in the chemical, petroleum refining, and paper industries. |
See "Selected Financial Data" for each of the domestic utility companies for the detail of their sales by customer class for 2000, 2001,2002, 2003, and 2002.
2004.
Selected 20022004 Natural Gas Sales Data
Entergy New Orleans and Entergy Gulf States provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Gulf States sold 14,596,36614,803,852 and 6,745,4006,868,935 Mcf, respectively, of natural gas to retail customers in 2002.2004. In 2002,2004, 98% of Entergy Gulf States' operating revenue was derived from the electric utility business, and only 2% from the natural gas distribution business. For Entergy New Orleans, 84%80% of operating revenue was derived from the electric utility business and 16%20% from the natural gas distribution business in 2002.2004. Following is data concerning Entergy New Orleans 2002Orleans' 2004 retail operating revenue sourcessources.
Electric Operating | Natural Gas | |||
Entergy New Orleans | Revenue | Revenue | ||
Residential | 40% | 50% | ||
Commercial | 37% | 22% | ||
Industrial | 8% | 13% | ||
Governmental/Municipal | 15% | 15% |
Retail Rate Regulation
General (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and customer data.Entergy New Orleans)
The retail regulatory philosophy has shifted in some jurisdictions from traditional, cost-of-service regulation to include performance-based rate elements. Performance-based rate plans are designed to encourage efficiencies and productivity while permitting utilities and their customers to share in the benefits. Entergy Mississippi, Entergy Louisiana, and Entergy New Orleans have implemented performance-based formula rate plans, but Entergy Louisiana's performance-based formula rate plan expired in 2001. As explained below, performance-based formula rate plans currently are under consideration for Entergy Louisiana and for the Louisiana jurisdiction of Entergy Gulf States. Following is a summary of the status of retail open access in the domestic utility companies' retail service territories.
Jurisdiction | Status of Retail Open Access | % of Entergy's | ||
Arkansas | Retail open access was repealed in February 2003. | 11.6% | ||
Texas | In July 2004, the PUCT effectively rejected Entergy Gulf States' proposal to implement retail open access in its service territory. In February 2005, bills were submitted in the Texas Legislature that specify that retail open access will not commence in Entergy Gulf States' territory until the PUCT certifies a power region. | 11.8% | ||
Louisiana | The LPSC has deferred pursuing retail open access, pending developments at the federal level and in other states. In response to a study submitted to the LPSC that was funded by a group of large industrial customers, the LPSC recently has solicited comments regarding a limited retail access program. It is uncertain what action, if any, the LPSC might take in response to the information it received. | 34.1% | ||
Mississippi | The MPSC has recommended not pursuing open access at this time. | 10.9% | ||
New Orleans | The Council has taken no action on Entergy New Orleans' proposal filed in 1997. | 4.5% |
Entergy New Orleans | Electric Operating | Natural Gas |
Residential | 41% | 54% |
Commercial | 37% | 22% |
Industrial | 6% | 9% |
Governmental/Municipal | 16% | 15% |
Each domestic utility operating subsidiary participates in retail rate proceedings on a consistent basis. The status of material retail rate proceedings is described below and in Note 2 to the domestic utility companies and System Energy financial statements.
Company | Authorized | Pending Proceedings/Events | ||
Entergy Arkansas | 11.0% | No base rate cases are pending. Transition cost recovery rider approved to collect $8.5 million effective October 2004 with recovery expected over subsequent 16 months. It is likely that a rate filing will be made in 2005 in connection with the ANO 1 steam generator and reactor vessel head replacement. | ||
Entergy Gulf States | 10.95% | Base rates are currently set at rates approved by the PUCT in June 1999. Entergy Gulf States filed a retail electric rate case with the PUCT in August 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case indicating that Entergy Gulf States is still subject to a rate freeze based on an agreement, approved by PUCT order in 2001, stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless lifted by the PUCT prior thereto. Entergy Gulf States has appealed this decision and intends to pursue other available remedies, including legislation that would clarify that it is no longer operating under a rate freeze. In February 2005, bills were filed in the Texas legislature that would clarify that Entergy Gulf States is no longer operating under a rate freeze and specify that retail open access will not commence in Entergy Gulf States' territory until the PUCT certifies a power region. | ||
Entergy Gulf States | 11.1% | In December 2003, the LPSC staff recommended a $30.6 million rate refund and a prospective rate reduction of approximately $50 million as a result of the ninth post-merger earnings analysis (2002). Hearings concluded in May 2004. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement that would resolve, among other dockets, Entergy Gulf States' ninth post-merger review, and dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, 2003, and 2004. The proposed settlement currently includes an offer to refund $76 million to Entergy Gulf States' Louisiana customers through a credit on bills rendered in March 2005, with no immediate change in the current base rates. The settlement also proposes a formula rate plan with an ROE mid-point of 10.65%. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005. | ||
Entergy Louisiana | 9.7%- | In January 2004, Entergy Louisiana filed with the LPSC an application for a $167 million base rate increase and an ROE of 11.4%. The currently authorized ROE midpoint is 10.5%. Hearings in this matter concluded in December 2004. Based on the evidence submitted at the hearing, the LPSC staff is recommending approximately a $7 million base rate increase. The LPSC staff proposed the implementation of a formula rate plan that includes a provision for the recovery of incremental capacity costs, including those related to the proposed Perryville acquisition. A decision by the LPSC is expected in mid- to late-March 2005 on these issues. | ||
Entergy Mississippi | 9.3%- | An annual formula rate plan is in place. Entergy Mississippi made its annual formula rate plan filing in March 2004 based on a 2003 test year. There was no change in rates based on an adjusted ROE midpoint of 10.77%. | ||
Entergy New Orleans | 10.25%- | The midpoint ROE of the electric and gas plans is 11.25%, with a target equity component of the capital structure of 42%. Entergy New Orleans made a formula rate plan filing in April 2004. The City Council ordered that electric and gas rates remain unchanged from levels set in 2003. Entergy New Orleans will file its formula rate plan for the year ended December 31, 2004 by May 1, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in effect based on the December 31, 2004 test year shall continue. | ||
System Energy | 10.94% | ROE approved by July 2001 FERC order. No cases pending before FERC. |
(1) | Entergy Louisiana's formula rate plan expired with the 2001 test year. Under the expired formula, if Entergy Louisiana earned outside of the bandwidth range, rates would be adjusted on a prospective basis. If earnings were above the bandwidth range, rates would be reduced by 60 percent of the amount necessary to bring earnings down to the top of the bandwidth, and if earnings were below the bandwidth range, rates would be increased by 60 percent of the corresponding shortfall. |
(2) | Under Mississippi law and Entergy Mississippi's formula rate plan, if Entergy Mississippi's earned ROE is above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's rates are reduced by 50 percent of the difference between the earned ROE and the top of the bandwidth. In such circumstance, Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the point halfway between such earned ROE and the top of the bandwidth - - Entergy Mississippi's retail rates are set at that halfway-point ROE level. (Before the comparison is made of the earned ROE to the bandwidth, the bandwidth can be adjusted for performance measures by as much as 1%. Rates are adjusted pursuant to Entergy Mississippi's formula rate plan on a prospective basis only.) In the situation where Entergy Mississippi's earned ROE is not above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the top of the range-of-no-change at the top of the bandwidth. If earnings are below the bandwidth range, rates are increased by 50 percent of the difference between the earned ROE and the bottom of the bandwidth. Under the provisions of Entergy Mississippi's formula rate plan, each annual formula rate plan filing incorporates a revised calculation of the benchmark ROE. |
(3) | If Entergy New Orleans earns outside the bandwidth range, rates will be adjusted on a prospective basis. Under the gas formula rate plan, if earnings are above the bandwidth range, rates are reduced by 100 percent of the overage, and if below, increased by 100 percent of the shortfall. In addition, if the ROE falls between 11.5% and 12.25%, rates are reduced by 60 percent of the difference (between 11.5% and 12.25%), and if the ROE falls between 10.25% and 11%, rates are increased by 40 percent of the difference (between 10.25% and 11%). Under the electric formula rate plan, rates are adjusted accordingly by 100 percent of the amount of any overage or shortfall. Entergy New Orleans may earn up to 13.25% under the electric formula rate plan provided that the increase is caused by its share of energy cost savings under the generation performance-based recovery plan discussed below. |
Fuel Recovery
Entergy Arkansas' rate schedules include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. Entergy Arkansas' 2004 filing is discussed in Note 2 to the domestic utility companies and System Energy financial statements.
Entergy Gulf States
Louisiana Jurisdiction - Formula Rate Plan
In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement with the LPSC. Included in the settlement is a proposal of a three-year formula rate plan for Entergy Gulf States' Louisiana operations that included a provision for the recovery of incremental capacity costs. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.
Fuel Recovery
Entergy Gulf States' Texas rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, not recovered in base rates. Under the current methodology, semi-annual revisions of the fixed fuel factor may be made in March and September based on the market price of natural gas. Entergy Gulf States will likely continue to use this methodology until retail open access begins in Texas. To the extent actual costs vary from the fixed fuel factor, refunds or surcharges are required or permitted. The amounts collected under the fixed fuel factor through the start of retail open access are subject to fuel reconciliation proceedings before the PUCT. At the start of retail open access for Entergy Gulf States in Texas, which is currently delayed, fuel and purchased power cost recovery will be subject to the fuel component of the price-to-beat rates approved by the PUCT. The PUCT fuel cost reviews that were resolved during the past year or are cur rently pending are discussed in Note 2 to the domestic utility companies and System Energy financial statements.
Entergy Gulf States' Louisiana electric rates include a fuel adjustment designed to recover the cost of fuel and purchased power costs. The fuel adjustment 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.
Entergy Gulf States' Louisiana gas rates include a purchased gas adjustment based on estimated gas costs for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers.
Entergy Louisiana
Formula Rate Plan
The LPSC staff has proposed the implementation of a formula rate plan for Entergy Louisiana that includes a provision for the recovery of incremental capacity costs. A decision from the LPSC is expected in mid- to late-March 2005.
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 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.
In September 2002, Entergy Louisiana settled a proceeding that concerned a contract entered into by Entergy Louisiana to purchase, through 2031, energy generated by a hydroelectric facility known as the Vidalia project. In the settlement, the LPSC approved Entergy Louisiana's proposed treatment of the regulatory impact of a tax accounting election related to that project. In general, the settlement permits Entergy Louisiana to keep a portion of the tax benefit in exchange for bearing the risk associated with sustaining the tax treatment. The LPSC settlement divided the term of the Vidalia contract into two segments: 2002-2012 and 2013-2031. During the first eight years of the 2002-2012 segment, Entergy Louisiana agreed to credit rates by flowing through its fuel adjustment calculation $11 million each year, beginning monthly in October 2002. Entergy Louisiana must credit rates in this way and by this amount even if Entergy Louisiana is unable to sustain the tax deduction. Entergy Louisiana also must credit rates by $11 million each year for an additional two years unless either the tax accounting method elected is retroactively repealed or the Internal Revenue Service denies the entire deduction related to the tax accounting method. Entergy Louisiana agreed to credit ratepayers additional amounts unless the tax accounting election is not sustained, if it is challenged. During the years 2013-2031, Entergy Louisiana and its ratepayers would share the remaining benefits of this tax accounting election. Note 8to the domestic utility companies and System Energy financial statementscontains further discussion of the obligations related to the Vidalia project.
Entergy Louisiana has reduced its indebtedness and preferred stock with a portion of the cash generated by the tax election. In accordance with the terms of the September 2002 settlement, Entergy Louisiana requested SEC approval to return up to $350 million of common equity capital to Entergy Corporation in order to maintain Entergy Louisiana's current capital structure. In December 2002, Entergy Louisiana repurchased $120 million of common stock from Entergy Corporation and paid a dividend of $122.6 million pursuant to the SEC approval. The provisions of the settlement provide that the LPSC shall not recognize or use Entergy Louisiana's use of this cash in setting any of Entergy Louisiana's rates. Therefore, to the extent Entergy Louisiana's use of the proceeds would ordinarily have reduced its rate base, no change in rate base shall be reflected for ratemaking purposes. The SEC approval for additional return of equity capital is now expired.
Entergy Mississippi
Performance-Based Formula Rate Plan
Entergy Mississippi files a performance-based formula rate plan every 12 months that compares the annual earned rate of return to, and adjusts it against, a benchmark rate of return. The benchmark is calculated under a separate formula within the formula rate plan. The formula rate plan allows for periodic small adjustments in rates, up to an amount that would produce a change in Entergy Mississippi's overall revenue of almost 2%, based on a comparison of actual earned returns to benchmark returns and upon certain performance factors. Entergy Mississippi filed a formula rate plan in March 2004 for the 2003 test year, and filings are due to continue annually thereafter. The March 2004 formula rate plan filing is discussed in Note 2 to the domestic utility companies and System Energy financial statements.
Fuel Recovery
Entergy Mississippi's rate schedules include energy cost recovery riders to recover fuel and purchased energy costs. The rider utilizes projected energy costs filed quarterly by Entergy Mississippi to develop an energy cost rate. The energy cost rate is redetermined each calendar quarter and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy cost as of the second quarter preceding the redetermination.
In January 2005, the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Entergy Mississippi's fuel over-recoveries for the third quarter of 2004 will be deferred from the first quarter 2005 energy cost recovery rider adjustment calculation. The deferred amount of $21.3 million plus carrying charges will be refunded through the energy cost recovery rider in the second and third quarters of 2005 at a rate of 45% and 55%, respectively.
Formula Rate Plans
In May 2003, the City Council approved the implementation of formula rate plans for electric and gas service that will be evaluated annually until 2005. Entergy New Orleans made a filing with the City Council in April 2004 based upon a 2003 test year, which after review, resulted in a City Council resolution approving no change in gas and electric rates. Entergy New Orleans will make a filing in accordance with the formula rate plans by May 1, 2005 based on a 2004 test year. Under the formula rate plans, the midpoint ROE of both plans is 11.25%, with a target equity component of Entergy New Orleans' capital structure of 42%. Any change in rates would be prospective, with the first billing cycle effective after September 1, 2005. Entergy New Orleans' can earn between 10.25% and 12.25% under the electric plan and between 11% and 11.5% under the gas plan, with earnings within those ranges not resulting in a change in rates. Entergy New Orleans' formula rate plan filings are disc ussed in Note 2 to the domestic utility companies and System Energy financial statements.
In May 2003, the City Council approved implementation of a generation performance-based rate calculation in the electric fuel adjustment clause under which Entergy New Orleans receives 10% of calculated fuel and purchased power cost savings in excess of $20 million, based on a defined benchmark, subject to a 13.25% return on equity limitation for electric operations as provided for in the electric formula rate plan. Entergy New Orleans bears 10% of any "negative" fuel and purchased power cost savings. In October 2004, Entergy New Orleans' annual evaluation report was submitted for the period June 2003 through May 2004. Additional savings associated with the first year generation performance-based rate calculation were $71 million of which Entergy New Orleans' share was $5.1 million.
Fuel Recovery
Entergy New Orleans' electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges. The adjustment also includes the difference between non-fuel Grand Gulf costs paid by Entergy New Orleans and the estimate of such costs, which are included in base rates, as provided in Entergy New Orleans' Grand Gulf rate settlements. Entergy New Orleans' gas rate schedules include an 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 June and November 2004, the City Council passed resolutions implementing a package of measures developed by Entergy New Orleans and the Council Advisors to protect customers from potential gas price spikes during the 2004 - 2005 winter heating season. These measures include: maintaining Entergy New Orleans' financial hedging plan for its purchase of wholesale gas, and deferral of collection of up to $6.2 million of gas costs associated with a cap on the purchased gas adjustment in November and December 2004 in the event that the average residential customer's gas bill were to exceed a threshold level. The deferrals resulting from these caps will receive accelerated recovery over a seven-month period beginning in April 2005.
In November 2004, the City Council directed Entergy New Orleans to confer with the Council Advisors regarding possible modification of the current gas cost collection mechanism in order to address concerns regarding its fluctuations particularly during the winter heating season.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 307 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are terminable upon breach of the terms of the franchise.
In Louisiana, Entergy Gulf States holds non-exclusive franchises, permits, or certificates of convenience and necessity to provide electric service in approximately 55 incorporated municipalities and the unincorporated areas of approximately 19 parishes, and to provide gas service in the City of Baton Rouge and the unincorporated areas of two parishes. In Texas, Entergy Gulf States holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 24 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 65 incorporated municipalities. Entergy Gulf States typically is granted 50-year franchises in Texas. Most of Entergy Gulf States' Louisiana franchises have a term of 60 years. Entergy Gulf States' current electric franchises will expire during 2007 - 2045 in Texas and during 2015 - 2046 in Louisiana.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 116 incorporated Louisiana municipalities. Most of these franchises have 25-year terms, although six of these municipalities have granted 60-year franchises. Entergy Louisiana also supplies electric service in approximately 353 unincorporated communities, all of which are located in Louisiana parishes in which it holds non-exclusive franchises.
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 city ordinances (except electric service in Algiers, which is provided by Entergy Louisiana). These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans' electric and gas utility properties.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
Property and Other Generation Resources
Generating Stations
The total capability of the generating stations owned and leased by the domestic utility companies and System Energy as of December 31, 2002,2004, is indicated below:
Owned and Leased Capability MW(1) | ||||||||||
Company | Total | Gas/Oil | Nuclear | Coal | Hydro | |||||
Entergy Arkansas | 4,709 | 1,613 | 1,837 | 1,189 | 70 | |||||
Entergy Gulf States | 6,485 | 4,890 | 968 | 627 | - | |||||
Entergy Louisiana | 5,363 | 4,276 | 1,087 | - | - | |||||
Entergy Mississippi | 2,898 | 2,490 | - | 408 | - | |||||
Entergy New Orleans | 915 | 915 | - | - | - | |||||
System Energy | 1,143 | - | 1,143 | - | - | |||||
Total | 21,513 | 14,184 | 5,035 | 2,224 | 70 |
(1) | "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. |
Entergy's load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections in light ofinterconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new loads, and economy. Peak load in the U.S. Utility service territory is typically around 21,000 MW, with minimum load typically around 9,000 MW. Allowing for an adequate reserve margin, Entergy has been short approximately 3,000 MW during the summer peak load period. In Septemberaddition to its net short position at summer peak, Entergy considers its generation in three categories: (1) baseload (e.g. coal and nuclear); (2) load-following (e.g. combined cycle gas-fired); and (3) peaking. The relative supply and demand for these categories of generation vary by region of the Entergy System. For example, the north end of its system has more baseload coal and nuclear generation than regional demand requires, but is short load-followin g or intermediate generation. In the south end of the Entergy system, load would be more effectively served if gas-fired intermediate resources already in place were supplemented with additional solid fuel baseload generation.
Until recently, Entergy covered its short position at summer peak almost entirely with purchases from the spot market. In the fall of 2002, Entergy Louisiana and Entergy Gulf States made an informational filing with the LPSC containingbegan a draft requestprocess of issuing requests for proposal forto procure supply-side resources. The final request for proposal was issued on November 1, 2002 by Entergy Services on behalfresources from sources other than the spot market to meet the unique regional needs of the domestic utility companies. The first request for proposal sought resources to meet both the domestic utility companies'provide summer 2003 and longer term resource needslonger-term resources through a broad range of wholesale power products, including shortshort-term (less than one year), limited-term (1 to 3 years) and long-term contractual products and possibly asset acquisitions. A detailed process which included the involvement of an independent monitor was developed to evaluate submitted bids. The following table illustrates the results of the request for proposal process for limited and short-term products. All of the contracts which were awarded and signed were with non-affiliates, with the exception of the contract covering 185 MW to 206 MW from RS Cogen.
Selected for | Contracts | Notes | ||||
Fall 2002 | 550 MW | 425 MW | Limited-term resources contracted. Entergy Services also pursued discussions with several bidders for life-of-unit purchased power agreements or the acquisition of an ownership interest in existing generating facilities. These negotiations resulted in the Perryville acquisition agreement, discussed below. | |||
Supplemental 2002 | 500 MW | 220 MW | Short-term purchase for the summer 2003. | |||
Spring 2003 | 380 MW | 380 MW | Limited-term resources contracted. | |||
Fall 2003 | 390 MW | 390 MW | Two separate resources contracted for a term of three years with deliveries beginning in the summer of 2004. |
In January 2004, Entergy Louisiana signed a definitive agreement to acquire the 718 MW Perryville power plant for $170 million. The agreement has subsequently been amended to allow the current plant owner to retain the interconnection facilities associated with the plant, resulting in a decrease in the acquisition price to $162 million. As a result of the fallamended terms, the FERC issued an order in October 2004 disclaiming jurisdiction over the acquisition. This order currently is subject to rehearing by the FERC. The plant is owned by a subsidiary of Cleco Corporation, which subsidiary submitted a bid in response to Entergy's Fall 2002 request for proposal, Entergy Services selected approximately 550 MW of short-term capacity and energy products. In January 2003, Entergy Services executed agreementsproposals for 425 MW in one- to three-year contracts as onesupply-side resources. The signing of the selected bidders failedagreement followed a voluntary Chapter 11 bankruptcy filing by the plant's owner. Entergy expects that Entergy Louisiana will own 100 percent of the Perryville plant, and that Entergy Louisiana will sell 75 percent of the output to honor its offer. Entergy Services also is pursuing discussions with several bidders for life of unit purchasedGulf States under a long-term cost-of-serv ice power agreements or the acquisition of an ownership interest in existing generating facilities. Also in January 2003, Entergy Services issued a Supplemental Request for Proposals for Short-Term Unit Capacity Purchase Agreement Products to solicit only proposals for the delivery of short-term dispatchable electric capacity and energy products beginning in the summer of 2003. As a result, Entergy Services selected approximately 500 MW of short-term capacity and energy products and expects to finalize the agreements in March 2003.
On January 31, 2003,purchase agreement. In addition, Entergy Louisiana and Entergy Gulf States executed an interim power purchase agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by December 2005) for 100 percent of the output of the Perryville power plant. In April 2004, the bankruptcy court approved Entergy Louisiana's agreement to acquire the plant. In March 2004, Entergy Gulf States and Entergy Louisiana filed with the LPSC for its approval of the acquisition and long-term cost-of-service power purchase agreement. Entergy is seeking approval from the LPSC of cost recovery for the acquisition, giving consideration to the need for the power and the prudence of Entergy Louisiana and Entergy Gulf States in engaging in the transaction. Hearings are scheduled for March 2005. Assuming regulatory approval by the LPSC, Entergy Louisiana expects the Perryville acquisition to close in mid-2005.
In addition to the purchases from non-affiliates shown above, Entergy Louisiana, Entergy New Orleans, and Entergy Arkansas made filings with their respective retail regulators seeking authorization for the companiesapproval to enter into newtransactions with affiliates as shown in the following table:
Company | Proposed Transactions | Status of Approval in | ||
Entergy Louisiana |
| The LPSC found contracts 1) and 2) to be prudent and authorized Entergy Louisiana to execute these contracts. The LPSC has not yet approved the life-of-unit PPAs for proposals 3) and 4); a bridge contract however, is currently in place for contract 3) effective through December 31, 2005. The outcome of the life-of-resources PPAs is still pending FERC approval. | ||
Entergy New Orleans |
| In May 2003, in connection with a settlement relating to Entergy New Orleans' cost-of-service study and revenue requirement, the City Council authorized Entergy New Orleans to enter into contracts for the proposed transactions. | ||
Entergy Arkansas |
| In May 2003, the APSC found the PPAs involving Entergy Arkansas in the public interest. |
Entergy also filed with the FERC the affiliate agreements described above. In May 2003, the FERC accepted the agreements for filing, subject to refund, with the contracts becoming effective on June 1, 2003. The FERC also established a hearing process to review the justness and permitting recoveryreasonableness of the additional capacity costs associated with these agreements in retail rates. These proposed purchases include potential power purchases from nuclear and coal generating resources owned by Entergy Gulf States and Entergy Arkansas, which are available for wholesale sales. In support of these filings, Entergy Louisiana and Entergy New Orleans submitted information demonstrating that their customers would benefit from these proposed purchases throughagreements. Several parties have intervened or filed protests regarding the reduction in overall retail rates resulting from the projected savings in fuel and purchased power costs, from reduced exposure to natural gas price volatility and by reducing the differential between their total production costsrequest-for-proposals process and the Entergy system's average total production costs. Entergy Louisianaagreements filed with the FERC, and Entergy New Orleans reques ted that these approvals be granted before the summer of 2003. On March 6, 2003, Entergy Arkansas requested that the APSC find that it ishearings in the public interest for Entergy Arkansas to enter into these contracts. On March 13, 2003, Entergy New Orleans and the Advisors to the City Council presented to the City Council an agreementproceeding ended in principle that, if approvedDecember 2004. An initial decision by the City Council, would grant Entergy New Orleans the authorization it requested. A procedural scheduleALJ is still pending and is scheduled for the City Council's consideration of the agreement in principle has not been established. Management cannot predict the timing or outcome of these proceedings.
July 2005.
Interconnections
Entergy's generating units are interconnected by a transmission system operating at various voltages up to 500 kV. These generating units consist primarily of steam-electric production facilities and are centrally dispatched and operated. Entergy's domestic utility companies are interconnected with many neighboring utilities. In addition, the domestic utility companies are members of the Southeastern Electric Reliability Council.Council (SERC). The primary purpose of SERC is to ensure the reliability and adequacy of the electric bulk power supply in the southeast region of the United States. SERC is a member of the North American Electric Reliability Council.
Gas Property
As of December 31, 2002,2004, Entergy New Orleans distributed and transported natural gas for distribution solely within New Orleans, Louisiana, through a total of 33 miles of gas transmission pipelines, 1,476pipeline, 1,495 miles of gas distribution mains,pipeline, and 1,0341,029 miles of gas service linepipeline from the distribution mains to the customers. As of December 31, 2002,2004, the gas properties of Entergy Gulf States, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Gulf States' financial position.
Titles
Entergy's generating stations and major transmission substations are generally located on properties owned in fee simple. Most of the transmission and distribution lines are constructed over private property or public rights-of-way pursuant to easements or appropriate franchises. The domestic utility companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are subject to the liens of mortgages securing the first mortgage bonds of such company. The Lewis Creek generating station is owned by GSG&T, Inc., a subsidiary of Entergy Gulf States, and is not subject to the lien of the Entergy Gulf States mortgage securing its first mortgage bonds. Lewis Creek is leased to and operated by Entergy Gulf States. All of the debt outstanding under the original first mortgages of Entergy Mississippi and Entergy New Orleans is retired and original first mortgages cancelled. As a result, the general and refunding mortgages of Entergy Mississippi and Entergy New Orleans constitute a first mortgage lien on substantially all of the respective physical properties and assets of these two companies.
Fuel Supply
The generation portfolio of the U.S. Utility contains a high percentage of natural gas and nuclear generation. The sources of generation and average fuel cost per kWh for the domestic utility companies and System Energy for the years 2000-20022002-2004 were:
Natural Gas | Fuel Oil | Nuclear Fuel | Coal | |||||||||||||
| % | Cents | % | Cents | % | Cents | % | Cents | ||||||||
2004 | 23 | 7.31 | 6 | 5.02 | 52 | .49 | 19 | 1.39 | ||||||||
2003 | 26 | 6.53 | 4 | 5.04 | 52 | .48 | 18 | 1.26 | ||||||||
2002 | 39 | 3.88 | - | 15.78 | 46 | .47 | 15 | 1.37 |
Natural Gas | Fuel Oil | Nuclear Fuel | Coal | |||||
% | Cents | % | Cents | % | Cents | % | Cents | |
of | Per | of | Per | of | Per | of | Per | |
Year | Gen | kWh | Gen | kWh | Gen | kWh | Gen | kWh |
2002 | 39 | 3.88 | - | 15.78 | 46 | .47 | 15 | 1.37 |
2001 | 34 | 4.62 | 8 | 4.33 | 43 | .50 | 15 | 1.58 |
2000 | 42 | 4.90 | 4 | 3.90 | 39 | .56 | 15 | 1.51 |
Actual 20022004 and projected 20032005 sources of generation for the domestic utility companies and System Energy, including proposed power purchases from affiliates under power purchase agreements in 2003,2005, are:
Natural Gas | Fuel Oil | Nuclear | Coal | |||||||||||||
2004 | 2005 | 2004 | 2005 | 2004 | 2005 | 2004 | 2005 | |||||||||
Entergy Arkansas (a) | 1% | - | - | - | 65% | 64% | 34% | 35% | ||||||||
Entergy Gulf States | 41% | 36% | 1% | - | 36% | 36% | 22% | 28% | ||||||||
Entergy Louisiana | 38% | 40% | 8% | 8% | 52% | 50% | 2% | 2% | ||||||||
Entergy Mississippi | 9% | 3% | 46% | 62% | - | - | 45% | 35% | ||||||||
Entergy New Orleans | 55% | 55% | - | - | 32% | 31% | 13% | 14% | ||||||||
System Energy | - | - | - | - | 100%(b) | 100%(b) | - | - | ||||||||
U.S. Utility (a) | 23% | 22% | 6% | 8% | 52% | 50% | 19% | 20% |
Natural Gas | Fuel Oil | Nuclear | Coal | |||||
2002 | 2003 | 2002 | 2003 | 2002 | 2003 | 2002 | 2003 | |
Entergy Arkansas (a) | 7% | - | - | - | 62% | 69% | 30% | 30% |
Entergy Gulf States | 54% | 45% | - | - | 31% | 31% | 15% | 24% |
Entergy Louisiana | 55% | 36% | - | - | 45% | 62% | - | 2% |
Entergy Mississippi | 68% | 5% | - | 32% | - | - | 32% | 63% |
Entergy New Orleans | 100% | 53% | - | - | - | 33% | - | 14% |
System Energy | - | - | - | - | 100%(b) | 100% (b) | - | - |
Total (a) | 39% | 22% | 0% | 2% | 46% | 57% | 15% | 19% |
(a) | Hydroelectric power provided less than 1% of Entergy Arkansas' generation in 2004 and is expected to provide approximately 1% of its generation in 2005. |
(b) | Capacity and energy from System Energy's interest in Grand Gulf 1 was historically allocated as follows: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements that are the subject of a pending proceeding at the FERC, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf 1 to Entergy Louisiana and Entergy New Orleans. |
Natural Gas
The domestic utility companies have long-term firm and short-term interruptible gas contracts. Long-term firm contracts for power plants comprise less than 26%15% of the domestic utility companies' total requirements but can be called upon, if necessary, to satisfy a significant percentage of the utility companies' needs. Short-term contracts and spot-market purchases satisfy additional gas requirements. As of January 1, 2005, Entergy Gulf States has a transportation service agreement withowns a gas supplierstorage facility that provides reliable and flexible natural gas service to certain generating stations by using such supplier's pipeline andstations.
Entergy Louisiana has a long-term natural gas storage facility.supply contract, which expires in 2012, in which Entergy Louisiana agreed to purchase natural gas in annual amounts equal to approximately one-third of its projected annual fuel requirements for certain generating units. Annual demand charges associated with this contract are estimated to be $7.2 million. Such charges aggregate $58 million for the years 2005 through 2012.
Many factors, including wellhead deliverability, storage and pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is tied to weather conditions as well as to the prices of other energy sources. Entergy's supplies of natural gas are expected to be adequate in 2003.2005. However, pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the domestic utility companies will use alternate fuels, such as oil, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has a long-term contract for low-sulfur Wyoming coal for Independence. This contract, which expires in 2011, provides for approximately 90% of Independence's expected coal requirements for 2003.2005. Entergy Arkansas has entered into one- to three-yearthree medium term (three-year) contracts for approximately 52% of WhiteBluff's coal supply needs and plans to enter into another for approximately 13%67% of White Bluff's coal supply needs. These contracts are staggered in term so that one is renewed every year. Entergy Arkansas has an additional 20%16% of its 20032005 coal requirement committed in a number of one- to two-year contracts.one-year contract. Additional coal requirements for both Independence and White Bluff are satisfied by spot market or over the counter purchases. Additionally, Entergy Arkansas has a long-term railroad transportation contract for the delivery of coal to both White Bluff and Independence that expires in 2011. A second carrier now delivers a portion of White Bluff's coal requirements under a long-term transportation agreement that began in 2002 and expires on December 31, 2006.
Entergy Gulf States has a long-term contract, which contains periodic price re-openers, for the supply of low-sulfur Wyoming coal for Nelson Unit 6, which should be sufficient to satisfy its requirements for that unit at current consumption rates through6. Entergy Gulf States has entered discussions with the supplier regarding the first quarter of 2003. The contract includes optionsprice re-opener. If a new price is negotiated, the agreement would extend to extend supplyApril 2007. Entergy Gulf States has executed two transportation requirements contracts with railroads to 2010 if all price re-openers are accepted. Notice has been made for a price re-opener session. If both parties cannot agree upon a price, then the contract terminates.deliver coal to Nelson Unit 6 through 2007. The operator of Big Cajun 2, Unit 3, Louisiana Generating, LLC, has advised Entergy Gulf States that it has coal supply and transportation contracts that should provide an adequate supply of coal for the operation of Big Cajun 2, Unit 3 for the foreseeable future. Additionally, Entergy Gulf States has transportation requirements contracts with railroads to deliver coal to Nelson Unit 6 through December 31, 2004. Each of the two contracts governs the movement of about half of the plant's requirements and the base contract provides flexibility for shipping up to all of the plant's requirements.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
System Fuels, a company owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, is responsible for contracts to acquire nuclear material to be used in fueling Entergy's utility nuclear units, except for River Bend. System Fuels also maintains inventories of such materials during the various stages of processing. The domestic utility companies purchase enriched uranium hexafluoride from System Fuels, but contract separately for the fabrication of their own nuclear fuel. The requirements for River Bend are met pursuant to contracts made by Entergy Gulf States.
Based upon currently planned fuel cycles, Entergy's nuclear units have contracts and inventory that provide adequate materials and services. Existing contracts for uranium concentrate, conversion of the concentrate to uranium hexafluoride, and enrichment of the uranium hexafluoride will provide a significant percentage of these materials and services over the next several years. Additional materialsUranium market supply became much tighter in 2003 and services required beyond the coverageearly 2004 than in previous years. Costs and risks of these contracts are expected to be available at a manageable costobtaining supplies have increased for the foreseeable future.
The Nuclear Waste Policy Act of 1982 provides for the disposal of spent nuclear fuel or high level waste by the DOE. Referusers. It will be necessary for Entergy to Note 9enter into additional arrangements to the domestic utility companies and System Energy financial statements for a discussion of spentacquire nuclear fuel disposal and spent fuel storage capacity.in the future. It is not possible to predict the ultimate cost or availability of such arrangements.
Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These arrangements are subject to periodic renewal. It will be necessary for these companies to enter into additional arrangements to acquire nuclear fuel in the future. It is not possible to predict the ultimate cost of such arrangements. See Note 109 to the domestic utility companies and System Energy financial statements for a discussion of nuclear fuel leases.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with three interstate and three intrastate pipelines. Entergy New Orleans' primary suppliers currently are Bridgeline Gas DistributorsAtmos Energy and Louisiana Gas Services. Entergy New Orleans has a "no-notice" service gas purchase contract with Bridgeline Gas Marketing, LLCAtmos 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 Bridgeline Gas Marketing, LLCAtmos Energy gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Entergy-Koch's Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans has firm contracts with its two intrastate suppliers and also makes interruptible spot market purchases. In recent years, natural gas deliveries to Entergy New Orleans have been subject primarily to weather-related curtailments. However, Entergy New Orlean sOrleans experienced no such curtailments in 2002.20 04.
As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy New Orleans' suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline could curtail transportation capacity only in the event of pipeline system constraints. Based on the current supply of natural gas, and absent extreme weather-related curtailments, Entergy New Orleans does not anticipate any interruptions in natural gas deliveries to its customers.
Entergy Gulf States purchases natural gas for resale under a firm contract from Enbridge Marketing (U.S.) Inc. (formerly Mid Louisiana Gas Company) entered into September 2002 for five years.
Regulationa five-year period. The contract will continue annually at the end of the Nuclear Power Industry
Entergy Operations operates ANO, River Bend, Waterford 3, and Grand Gulf 1, subject to the owner oversight of Entergy Arkansas,term unless prior notice is given by Entergy Gulf States, Entergy Louisiana, and System Energy, respectively. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy pay directly or reimburse Entergy Operations at cost for its operation of the nuclear units.States.
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974Federal Regulation
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend, Waterford 3, and Grand Gulf 1, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy has made substantial capital expenditures at these nuclear plants because of revised safety requirements of the NRC in the past, and additional expenditures could be required in the future.
Nuclear Waste Policy Act of 1982
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. Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. After twenty years of study, the DOE, in February 2002, formally recommended, and President Bush approved, Yucca Mountain, Nevada as the permanent spent fuel repository. DOE will now proceed with the licensing and, if the license is granted by the NRC, eventual construction of the repository will begin and receipt of spent fuel may begin as early as approximately 2010. Considerable 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, future expenditures will be required to increase spent fuel storage capacity at Entergy's nuclear pl ant sites. Information concerning spent fuel disposal contracts with the DOE, current on-site storage capacity, and costs of providing additional on-site storage is presented in Note 9 to the financial statements.
Low-Level Radioactive Waste Policy Act of 1980
The Low-Level Radioactive Waste Policy Act of 1980, as amended, holds each state responsible for disposal of waste originating in that state, but allows states to participate in regional compacts to fulfill their responsibilities jointly. Arkansas and Louisiana participate in the Central Interstate Low-Level Radioactive Waste Compact (Central States Compact) and Mississippi participates in the Southeast Low-Level Radioactive Waste Compact (Southeast Compact). Both the Central States Compact and the Southeast Compact waste facility development projects are on hold and further development efforts are unknown at this time. Currently the Entergy nuclear stations have disposal access at two waste disposal facilities: the Barnwell facility in South Carolina and the Envirocare facility in Utah. The Barnwell facility is licensed as a 10CFR61 facility and can accept all three classes of low level radwastes (Classes A, B, and C). With South Carolina's alliance as a member of the Atlantic Compact, disposal access for out-of-region waste generators will be limited at Barnwell. Over the next several years available out-of-region disposal capacity will continue to decrease and in 2008 out-of-region disposal will be prohibited. Currently the Envirocare facility is licensed to accept lower activity radwaste including Class A radioactive wastes. Envirocare has applied for a full service Class B and C license but has decided not to pursue that license at this time.
The Southeast Compact has filed sanctions against the host state of North Carolina and the process is currently on hold pending resolution of the sanctions action by the compact. In December 1998, the host state for the Central States Compact, Nebraska, denied the compact's license application. In December 1998, Entergy, two other utilities in the Central States Compact, and the Compact Commission filed a lawsuit against the state of Nebraska seeking damages resulting from delays and a faulty license review process. After two months of trial, United States District Court concluded that Nebraska violated its federal obligation to the United States and the States of Arkansas, Kansas, Louisiana, and Oklahoma. To be specific, Nebraska failed to act in good faith as required by an interstate compact when it considered, delayed, and then denied a license to build a low-level radioactive waste disposal facility that was to be used by the citizens of those states. As a remedy, the court ordered Nebraska to pay the Compact Commission, with interest, over $151 million that was expended during the attempt to license the facility in Nebraska. Although Entergy's cross-claims against the Commission were denied, the court's decision leaves open Entergy's claim against the Commission once the Commission receives the funds from the State of Nebraska. Until long-term disposal facilities are established, Entergy will seek continued access to existing facilities. If such access is unavailable, Entergy will store low-level waste at its nuclear plant sites.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy recover from customers through electric rates the estimated decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf 1, respectively. These amounts are deposited in trust funds that can only be used for future decommissioning costs. Entergy periodically reviews and updates estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In June 2001, Entergy Arkansas received notification from the NRC of approval for a renewed operating license authorizing operations at ANO 1 through May 2034. In October 2000, the APSC ordered Entergy Arkansas to reflect 20-year license extensions in its determination of the ANO 1 and ANO 2 decommissioning revenue requirements for rates to be effective January 1, 2001. Entergy Arkansas will not recover decommissioning costs in 2003 for ANO 1 and ANO 2 based on the extension of the ANO 1 license, the assumption that the ANO 2 license will be extended, and the fact that existing decommissioning trust funds, together with their expected future earnings, will meet the estimated decommissioning costs.
Additional information with respect to decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf 1 is found in Note 9 to the financial statements.
Energy Policy Act of 1992
The Energy Policy Act of 1992 requires all electric utilities (including Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy) that purchased uranium enrichment services from the DOE to contribute up to a total of $150 million annually over approximately 15 years (adjusted for inflation, up to a total of $2.25 billion) for decontamination and decommissioning of enrichment facilities. At December 31, 2002, four years of assessments remain. In accordance with the Energy Policy Act of 1992, contributions to decontamination and decommissioning funds are recovered through rates in the same manner as other fuel costs. The estimated annual contributions by Entergy for decontamination and decommissioning fees are discussed in Note 9 to the financial statements.
Price Anderson Act
The Price-Anderson Act limits public liability for a single nuclear incident to approximately $9.5 billion. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy have protection with respect to this liability through a combination of private insurance and an industry assessment program, as well as insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units. Insurance applicable to the nuclear programs of Entergy is discussed in Note 9 to the financial statements.
Rate Matters
State or local regulatory authorities, as described below,above, regulate the retail rates of Entergy's domestic utility companies.FERC regulates wholesale rates (including intrasystem sales pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy's sales of capacity and energy from Grand Gulf 1 to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement.
Wholesale Rate Matters
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
The domestic utility companies historically have historically engaged in the coordinated planning, construction, and operation of generation and transmission facilities pursuant to the terms of the System Agreement. Under the terms of the System Agreement, generating capacity and other power resources are jointly operated by the domestic utility companies. The System Agreement provides, among other things, that parties having generating reserves greater than their load requirements (long companies) shall receive payments from those parties having deficiencies in generating reserves (short companies). Such payments are 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 and preference stock, and a fair rate of return on common equity investment. Under the System Agreement, these charges are based on costs associated with the long companies' steam electric generati nggenerating units fueled by oil or gas. In addition, for all energy exchanged among the domestic utility companies under the System Agreement, the short companies purchasing exchange energy are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
The LPSC and the Council commenced a proceeding at FERC in April 2000 that requested revisions toLitigation involving the System Agreement whichis being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the Council alleged were necessary to accommodate the proposed introductionallocation of retail competition in Texas and Arkansas. In June 2000, the domestic utility companies filed proposed amendments tocosts as defined by the System Agreement, with FERC to facilitate the proposed implementationraise questions of retail competition in Arkansas and Texas and to provide for continued sharing of generation resources and costs amongimprudence by the domestic utility companies in Louisiana and Mississippi. These proceedings have been consolidated with a previous complaint filed with FERC by the LPSC in 1995. In that complaint, the LPSC requested, among other things, modificationtheir execution of the System Agreement, to exclude curtailable load from the allocation determination related to reserve sharing. In June 2001, in connection with these proceedings, the parties filed an offer of settlement with FERC. The offer of settlement provides fo r the following amendments to the System Agreement:
As anticipated by the offer of settlement,themselves. An unrelated case between the LPSC and Entergy Louisiana raised the Council commencedquestion of whether a new proceeding atstate regulator is preempted by federal law from reviewing and interpreting FERC in June 2001. In this proceeding, the LPSC and the Council allegerate schedules that the rough production cost equalization required by FERC underare part of the System Agreement, and the Unit Power Sales Agreement has been disrupted by changed circumstances.from subsequently enforcing that interpretation. The LPSC and the Council have requested that FERC amend theinterpreted a System Agreement or the Unit Power Sales Agreement or both to achieve full production cost equalization or to restore rough production cost equalization. Their complaint does not seek a changerate schedule in the total amount ofunrelated case, and then sought to enforce its interpretation. The Louisiana Suprem e Court affirmed the costs allocated by eitherLPSC's decision. In 2003, the System Agreement orU.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the Unit Power Sales Agreement. In addition the LPSC and the Council allege that provisions of the System Agreement relating to minimum run and must run units, the methodology of billing versus dispatch, and the use of a rolling twelve-month average of system peaks, increase costs paid by ratepayers in the LPSC and Council's jurisdictions. Several p arties have filed interventions in the proceeding, including the APSC and the MPSC. Entergy filed its response to the complaint in July 2001 denying the allegationsdecisions of the LPSC and the Council.Louisiana Supreme Court.
In February 2004, a FERC ALJ issued an Initial Decision in the LPSC-initiated proceeding at the FERC. The APSC and the MPSC also filed responses opposingInitial Decision decided some issues in favor of the relief sought by the LPSC, and decided some issues against the Council.
In their complaint,relief sought by the LPSC.Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the Council allegeFERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of pro duction cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the domestic utility companies' annualfull costs of the Vidalia project should be included in Entergy Louisiana's production costs over the period 2002 to 2007 will be over or (under) the average for the domestic utility companies by the following amounts:
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This rangepurposes of results is a function of assumptions regarding such things as future natural gas prices, the future market price of electricity, and other factors. In February 2002, the FERC set the matter for hearing and established a refund effective period consisting of the 15 months following September 13, 2001. Negotiations among the parties have not resolved the proceeding,calculating relative production costs; and the proceeding is now set for hearing commencing in June 2003. The case had been set for trial commencing in February 2003. The extensionInitial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the schedule also extendedcurrent method.
If the refund effective period by 120 days. If FERC grants the relief requested by the LPSC andin the Council,proceeding, the relief may result in a material increase in the total production costs allocatedthe FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs allocatedthe FERC allocates to companies whose costs currently are projected to exceed that average. If the average. FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility compan ies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.
An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu duri ng the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:
| Average Annual | ||
(In Millions) | (In Millions) | ||
Entergy Arkansas | $154 to $281 | $215 | |
Entergy Gulf States | ($130) to ($15) | ($63) | |
Entergy Louisiana | ($199) to ($98) | ($141) | |
Entergy Mississippi | ($16) to $8 | $1 | |
Entergy New Orleans | ($17) to ($5) | ($12) |
Management believes that any changes in the allocation of production costs resul tingresulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. Therefore,The timing of recovery of these costs in rates could be the subject of additional proceedings at the APSC and elsewhere, however, and a delay in full recovery of any increased allocation of production costs could result in additional financing requirements. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation.
In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC ALJ's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the ALJ's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; and states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate.
In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the ALJ's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations.
In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Lou isiana, as well as the named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity.
Transmission
In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs.
In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations.
Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences.
In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the petition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005.
In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion of th e proposal currently scheduled for August 2005.
FERC's Supply Margin Assessment
In November 2001, FERC issued an order that established a new generation market power screen (called Supply Margin Assessment) for purposes of evaluating a utility's request for market-based rate authority, applied that new screen to the Entergy System (among others), determined that Entergy and the others failed the screen within their respective control areas, and ordered these utilities to implement certain mitigation measures as a condition to their continued ability to buy and sell at market-based rates. Among other things, the mitigation measures would require that Entergy transact at cost-based rates when it sells in the hourly wholesale market within its control area. Entergy requested rehearing of the order, and FERC delayed the implementation of certain mitigation measures until such time as it had the opportunity to consider the rehearing request. In June 2003, the FERC proposed and ultimately adopted new market behavior rules and tariff provisions that would be applied to any market-based sale. Entergy modified its market-based rate tariffs to reflect the new provisions but requested rehearing of FERC's order.
In April 2004, the FERC issued its Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy. In its April 2004 order, the FERC established a new interim generation market power analysis that will consider two indicative market power screens: (1) the pivotal supplier screen that is designed to measure an applicant's market power based on the applicant's share of uncommitted capacity at the time of the control area market's annual peak demand; and (2) the market share screen that is designed to evaluate an applicant's market share of uncommitted capacity on a seasonal basis. An integrated utility's native load obligation will be reflected in both screens; however, the proxy for native load obligation differs between the screens. For the uncommitted pivotal supplier screen, the proxy for native load is the average of the daily native load peaks during the month in which the annual peak load day occurs; for the uncommitted market share screen the prox y for native load is the minimum peak load day for each season. In the event an applicant fails either of these screens, there will be a rebuttable presumption that market power exists. The applicant will then have the opportunity to either: (1) submit a more detailed market power analysis that reflects market prices and measures an applicant's "economic capacity" and "available economic capacity" under the "delivered price test;" or (2) propose case-specific mitigation tailored to the applicant's specific circumstances or adopt cost-based rates for sales within the applicant's control area.
In its April 2004 order, the FERC also: (1) determined that transmission market power and the need to employ an independent entity to operate and administer an applicant's OASIS site is more properly considered in other proceedings, to the extent appropriate, and would not be considered in evaluating an applicant's generation market power for purposes of granting market-based rate authority; and (2) eliminated the exemption from the generation market power analysis for sales within an RTO/ISO that had approved market monitoring. Several parties, including Entergy, filed for rehearing of the April 2004 order. Among other things, Entergy argued that the market share screen is overly conservative and overstates vertically integrated utilities' ability to exercise market power.
In July 2004, the FERC issued an order on rehearing reaffirming the use of the pivotal supplier and market share screens and clarified certain instructions for performing such analysis. With regard to the delivered price test analysis, the FERC declined to make a determination on whether an applicant's native load obligations will be reflected when evaluating an applicant's generation market power, but instead indicated that it would evaluate the arguments of both the applicant and intervenors as to which measure (one with or without native load obligations) more accurately reflects market conditions. Entergy appealed the April 2004 and July 2004 orders to the United States Court of Appeals for the District of Columbia Circuit. In February 2005, the D.C. Circuit granted the FERC's motion to dismiss Entergy's appeal on the grounds that Entergy's claims were premature. The D.C. Circuit found that Entergy's petition was premature because the D.C. Circuit was not yet in a position to evalu ate the manner in which the FERC will apply its new market power tests or whether the tests will have adverse consequences for Entergy. Thus, the D.C. Circuit did not rule on the merits of Entergy's appeal.
Entergy filed with the FERC its generation market power analysis pursuant to the two indicative screens in August 2004. Entergy's analysis indicated that it passed the pivotal supplier screen for all relevant geographical regions, but failed the market share screen within its control area. At the same time, Entergy submitted the results of the delivered price test for Entergy, which indicate that Entergy does not have market power in any wholesale market when Entergy's native load obligations are reflected.
In December 2004, the FERC issued an order pursuant to Section 206 of the Federal Power Act: (1) finding that Entergy failed the market share screen; (2) indicating that the FERC is continuing to review the delivered price test analysis submitted by Entergy; (3) establishing a refund effective date for Entergy's market-based wholesale sales within its control area; and (4) indicating that the FERC believes that it can reach a decision concerning Entergy's market-based rate authority by the second quarter of 2005.
If the FERC were to revoke Entergy's or the domestic utility companies' market-based rate authority for wholesale sales within the Entergy control area, these entities would be limited to making wholesale sales pursuant to cost-based rate schedules approved by the FERC. The wholesale sales of the domestic utility companies and their affiliates, including Entergy's non-nuclear wholesale assets business, within the Entergy control area could either be cost-justified or are of such a limited amount that management does not believe that this proceeding willthe revocation of their market-based rate authority would have a material effect on the financial conditionresults of anyEntergy. Because Entergy believes that it does not possess market power and that the FERC's tests are flawed, Entergy intends to vigorously defend its market-based rate authority.
The FERC has also initiated a rulemaking proceeding to address, among other things, whether the FERC should retain or modify its existing four-prong test for evaluating market-based rate applications (i.e., whether the applicant has generation or transmission market power, whether the applicant can erect barriers to entry, and whether there are affiliate abuse or reciprocal dealing concerns), and whether the FERC should adopt different approaches for affiliate transactions. The FERC has held a series of technical conferences to discuss these issues. Additionally, in February 2005, the FERC adopted revised reporting obligations for changes in status that apply to public utilities authorized to make wholesale sales of power at market-based rates. The FERC determined to replace the current triennial reporting requirement with more detailed guidelines concerning the types of events that will trigger a reporting obligation and the timing and format for such reports. The new rules will becom e part of all existing market-based rate tariffs during March 2005.
Interconnection Orders
The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy.
In addition, Entergy Louisiana was recently directed, effective as of March 2001, to provide transmission credits, with interest, associated with a specific generator that asserted to the FERC that it retained in its contract for interconnection a right to execute the latest form of Entergy's standard interconnection agreement in lieu of its existing contract, which thereby would apply FERC's most recent interconnection cost allocation policies to that generator. Following an ALJ's Initial Decision and an order affirming such decision by FERC, approximately $15 million in expenses and tax obligations previously paid by the generator have been ordered refunded in the form of transmission credits, to be utilized over time and applied to Entergy transmission service bills incurred after March 2001. Entergy has sought rehearing of the FERC's order.
To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators.
Available Flowgate Capacity Proceeding
On December 17, 2004, the FERC issued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission service requests under the domestic utility companies,companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although neither the timing nor the outcomeit "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the proceedings atconcerns raised by certain transmission customers and certain issues raised in a FERC canaudit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC progr am, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory.
Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy.
Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the AFC proceeding is currently scheduled to commence in August 2005.
FERC Audits
In January 2003August 2002, the domestic utility companiesFERC initiated audits and reviews of Entergy's compliance with Order Nos. 888 and 889 and Entergy's open access transmission tariff. In March 2004, a separate audit was started concerning Entergy's administration of the Generator Operating Limits ("GOL") processes. Entergy responded to numerous FERC data requests and the FERC Staff members interviewed several employees. In December 2004, the FERC issued the GOL audit report in which it identified certain input and modeling errors in the implementation of the GOL process (which process was replaced in April 2004 with the AFC process). The report recommends that Entergy implement additional quality control and assurance procedures surrounding the processes for granting short term transmission service. Separately, the FERC investigation staff has provided to Entergy its preliminary findings in a non-public draft report identifying certain areas of concern related to Entergy's compliance with provisions of its open acce ss transmission tariff. Entergy has submitted a comprehensive response and rebuttal to the specific concerns identified by the investigation staff but, at this point, believes that it has complied with the provisions of its open access transmission tariff. The draft report is not a final report and may be modified by the FERC staff based on Entergy's responses or otherwise. In addition, Entergy has the ability to appeal the final reports to the full FERC.
The FERC is currently reviewing certain wholesale sales and purchases involving EPMC that occurred during the 1998-2001 time period. EPMC was an Entergy subsidiary engaged in non-regulated wholesale marketing and trading activities prior to the formation of Entergy-Koch. Entergy is working with the FERC investigation staff to provide information regarding these transactions.
Other Customer-initiated Proceedings at FERC
In September 2004, East Texas Electric Cooperative (ETEC), filed testimonya complaint at the FERC against Entergy Arkansas relating to a contract dispute over the pricing of substitute energy at the co-owned coal unit, Independence Steam Electric Station (ISES). In October 2004 Arkansas Electric Cooperative (AECC) filed a similar complaint at FERC against Entergy Arkansas, addressing the same issue with respect to ISES and another co-owned coal unit, White Bluff Electric Station. Entergy Arkansas filed answers to these complaints in October 2004 and November 2004. FERC consolidated the cases, ordered a hearing in the consolidated proceeding, and established refund effective dates. The main issue in the case showing that overrelates to the lifeconsequences under the governing contracts when the dispatch of the System Agreementcoal units is constrained due to system operating conditions. Entergy Arkansas believes that the relative production costscontracts in dispute recognize the effects of dispatch constraints on the co-owned un its and require all of the domestic utility companies are roughly equal,co-owners, including ETEC and suggesting that no changesAECC, to bear the System Agreement such as those sought by the LPSC and the Council are appropriate. On March 13, 2003, Entergy New Orleans and the Advisors to the City Council presented to the Council an agreement in principle that, if approved by the Council, would resolve Entergy New Orleans' pending rate proceeding. The agreement in principle, if approved by the Council, would result in the Council withdrawing as a complainant in the FERC proceeding. A procedural schedule for the City Council's considerationburden of the agreementreduced output. Entergy Arkansas expects an initial decision by a FERC ALJ in principle has not been established.October 2005.
The LPSC has institutedOn February 17, 2005, ExxonMobil Chemical Company and ExxonMobil Refining & Supply Company (ExxonMobil) filed a companion ex parte System Agreement investigation to litigate several of the System Agreement issues that the LPSC is litigating before thecomplaint with FERC in the previously discussed System Agreement proceeding. This companion proceeding will require the LPSC to interpret various provisions of the System Agreement, including those relating to minimum run and must run units, the propriety of the methods used for billing and dispatch on theagainst Entergy System,Services and the use of a rolling, twelve-month average of system peaks for allocating certain costs. In addition, by this companion proceeding the LPSC is questioning whether Entergy Louisiana and Entergy Gulf States were prudent for not seeking changes to the System Agreement previously, so as to lower costs imposed upon their ratepayers and to increase costs imposed upon ratepayers of other domestic utility companies. The LPSC staff has filed testimony suggestingcomplaint alleges that the remedy forEntergy defendants have violated Entergy's open access transmission tariff, as well as its interconnection and operating agreement with ExxonMobil, by not allowing ExxonMobil to net its station power needs at its industrial complex in Baton Rouge, Louisiana. ExxonMobil also alleges that the alleged imprudenceEntergy defendants have been charging rates that are not on file with the FERC and that the Entergy defendants' monthly facilities charge is contrary to the FERC's current interconnection pricing policy. ExxonMobil states that such violations have resulted in monetary losses to it in excess of $5 million. Entergy Louisianabelieves that it has complied with the provisions of its open access transmission tariff and Entergy Gulf St ates should be a reduction in allowed rate of return on common equity of 100 basis points. The domestic utility companies have challenged the proprietyprovisions of the LPSC's litigating System Agreement issues. Nevertheless, on January 16, 2002 the LPSC affirmed a decision of its ALJ upholding the LPSC staff's right to litigate System Agreement issues at the LPSC, rather than before the FERC. In September 2002, the LPSC staff filed a motion to delay hearinginterconnection and remaining pre-hearing deadlines. After no objections from the other parties, the LPSC ALJ continued the procedural schedule until after the FERC ALJ's initial decision in the related matter, or June 13, 2003, whichever occurs first.operating agreement.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf 1 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 implementedcommenced a $65.5 million rate increase, subject to refund.proceeding at the FERC. In July 2001, the rate increase proceeding became final, with the FERC approving a prospective 10.94% return on equity, which is less than System Energy sought.equity. The FERC's decision also affected other aspects of System Energy's charges to the domestic utility 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' and Entergy Mississippi's acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by FERC. The rate increase request filed by System Energy with FERC and the Grand Gulf accelerated recovery tariffs are discussed in Note 2 to the financial statements.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy's 90% ownership and leasehold interests in Grand Gulf 1 to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered, so long as Grand Gulf 1 remains in commercial operation. 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 1 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 r ecoveredrecovered 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' cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans pending regulatory approvals that sell a portion of the output of Entergy Arkansas' retained share of Grand Gulf 1. Theto those companies. 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 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 4.6 cents per kWh for the energy related to its retained shares are discussed in Note 2portion 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 domestic utility companies and System Energy financial statements under the heading "Grand Gulf 1 Deferrals and Retained Shares."LPSC's approval.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the financing by System Energy of Grand Gulf. The Availability Agreement provided that System Energy join in the System Agreement on or before the date on which Grand Gulf 1 was placed in commercial operation and 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 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.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its first mortgage bonds and reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 109 to the financial statements under "Sale and Leaseback Transactions - Grand Gulf 1 Lease Obligations." In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if 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 allowedallow ed to repa yrepay 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 FERC for approval with respect to the terms of such sale. No such filing with 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 FERC for approval. Other aspects of the Availability Agreement are subject to the jurisdiction of the SEC, whose approval has been obtained, under PUHCA.
Since commercial operation of Grand Gulf 1 began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement. Therefore, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
Capital Funds Agreement
System Energy and Entergy Corporation have entered into the Capital Funds Agreement, whereby Entergy Corporation has agreed to supply System Energy with sufficient capital to (i) maintain System Energy'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 1 and pay in full all indebtedness for borrowed money of System Energy when due.
Entergy Corporation has entered into various supplements to the Capital Funds Agreement. System Energy has assigned its rights under such supplements as security for its first mortgage bonds and for reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 109 to the financial statements under "Sale and Leaseback Transactions - Grand Gulf 1 Lease Obligations." Each such supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of Grand Gulf may be secured by System Energy's rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as defined below). In addition, in the supplements to the Capital Funds Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital contributions directly to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). However, if there is an event of default, Entergy Corporation must make those payments directly to the holders of indebtedness benefiting from the supplemental agreements. The payments (other than the Specific Payments) must be made pro rata according to the amount of the respective obligations benefiting from the supplemental agreements.
The Capital Funds Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, upon obtaining the consent, if required, of those holders of System Energy's indebtedness then outstanding who have received the assignments of the Capital Funds Agreement.
Service Companies
Transmission (EntergyEntergy Services, a corporation wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the domestic utility companies. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy, respectively. Entergy Mississippi,Services and Entergy New Orleans)
In 2000, FERC issued an order encouraging utilities to voluntarily placeOperations provide their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs.
Entergy's domestic utility companies are participating with other transmission owners within the southeastern United States to establish an RTO, the proposed SeTrans RTO. In October 2002, FERC issued a declaratory order approving certain central aspects of the SeTrans RTO proposal, including the governance structure, the transmission pricing policy, the business model, and the selection process for the Independent System Administrator. The FERC order states that the FERC will not revisit certain findings made in the SeTrans docket if inconsistencies exist between those findings and the final rules issued in the standardized market design proceeding discussed immediately below.
Because of retail regulatory concerns regarding RTOs generally, Entergy was required to perform a cost-benefit study of the domestic utility companies' participation in an RTO. Separately, the Southeast Association of Regulatory Utility Commissions (SEARUC) requested a cost-benefit study be performed analyzing the effects on the entire southeastern United States, including the SeTrans region. Both the Entergy cost-benefit study and the SEARUC study confirm that a properly structured RTO including proper transmission pricing can provide benefits for Entergy and the area covered by SeTrans.
A number of important issues relating to the design of the transmission tariffs and the terms of the proposed SeTrans RTO remain to be finalized and approved by regulators. At this time, Entergy does not expect the proposed SeTrans RTO to become operational before the end of 2004.
In September 2001, the LPSC ordered Entergy Gulf States and Entergy Louisiana to show cause as to why these companies should not be enjoined from transferring their transmission assets to an ITC (independent transmission company) or any similar organization, asserting that FERC does not have jurisdiction to mandate an ITC or RTO. A settlement was reached with the LPSC staff and adopted by the LPSC that requires, among other things, that when Entergy files with the FERC to participate in an RTO, it will request a transfer of control of transmission assets and, as an alternative, request a transfer of ownership of those assets to an ITC.
FERC Notice of Proposed Rulemaking - Standard Market Design (Entergy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)
On July 31, 2002, FERC issued a notice of proposed rulemaking to establish a standardized transmission service and wholesale electric market design (SMD NOPR). The proposed rules would
Comments on the proposed rule were filed in mid-November 2002 and mid-January 2003. Reply comments on all issues are due in February 2003. Several technical conferences on the issues contained in the SMD NOPR were also held during November and December 2002. Some of the retail regulators in Entergy's service territory have publicly expressed opposition to the proposed rulemaking. In a recent letter sent to the Chairman of the FERC, retail regulators from Alabama, Arkansas, Florida, Georgia, Kentucky, Louisiana, North Carolina South Carolina, Tennessee, and Virginia expressed their belief that an "incremental and voluntary approach" to RTO formation and wholesale market development is necessary and appropriate for the Southeast. In the letter, the retail regulators identified certain threshold issues that FERC must commit to (including, among other things, a commitment that the FERC would not assert jurisdiction over the transmission component of bundled retail service, that native load custome rs would retain the same or equivalent rights to use the transmission system as they have today, the immediate implementation of participant funding, and RTO formation should be supported by evidence that the costs of RTO formation are outweighed by the benefits) prior to further detailed discussions between the FERC and retail regulators concerning the development of RTOs and SMD. The retail regulators requested that FERC modify the current SMD proposal to recognize these commitments. A similar letter was submitted separately by retail regulators from Mississippi. It is anticipated that the FERC will issue a white paper addressing these and other issues contained in the SMD during the spring of 2003, with the final rule issued during the latter part of the summer of 2003.
Separately, the conference report on the Fiscal Year 2003 Omnibus Appropriations bill signed into law contains language directing the Department of Energy to prepare an independent analysis of the effect of the proposed SMD rule on wholesale and retail electric prices, the safety and reliability of generation and transmission facilities, and state utility regulation. The report is to be submitted no later than April 30, 2003.
Interconnection Orders
On January 28 and 29, 2003, the FERC issued two orders in proceedings involving Interconnection Agreements between each of the domestic utility companies (except Entergy New Orleans) and certain generators interconnecting to the domestic utility companies' transmission system. In the orders, the FERC authorized the generators to abrogate certain provisions of the interconnection agreements in order to avail themselves of new FERC policies developed after the generators' execution of the agreements. Under the FERC's orders, capital costs that the generators had agreed to bear will now be shifted to Entergy's native load and other transmission customers. Other generators that previously had executed interconnection agreements agreeing to bear similar costs also may file complaints to obtain the same or similar relief. In the event that the generators that have interconnected to the Entergy transmission system are successful in obtaining such relief, it is estimated that approximately $280 million of costs will be shifted from the interconnecting generators to the domestic utility companies' other transmission customers, including the domestic utility companies' bundled-rate retail customers. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed, and the affected interconnection agreements reinstated as agreed to by the generators. The domestic utility companies had appealed previously to the Court of Appeals for the D. C. Circuit the FERC orders initially establishing the new FERC policy that was applied retroactively in the January orders. In the orders currently pending before the D.C. Circuit, the FERC had applied the new policy on a prospective basis. In an opinion issued February 18, 2003, the D.C. Circuit denied Entergy's petition for review in one proceeding, concluding that the FERC had not acted in an arbitrary and capricious manner when it changed its policy from that of directly assigning certain interconnection costs to the generator to a policy in which those costs are borne by all customers on the domestic utility companies' transmission system. A related proceeding concerning a similar change in policy for another segment of interconnection costs is still pending before the D.C. Circuit.
FERC's Market Power Screen
In November 2001, FERC issued an order that established a new generation market power screen for purposes of evaluating a utility's request for market-based rate authority, applied that new screen to the Entergy System (among others), determined that Entergy and the others failed the screen within their respective control areas, and ordered these utilities to implement certain mitigation measures as a condition to their continued ability to buy and sell at market-based rates. Among other things, the mitigation measures would require that Entergy transact at cost-based rates when it is buying or selling in the hourly wholesale market within its control area. Entergy requested rehearing of the order, and FERC has delayed the implementation of certain mitigation measures until such time as it has had the opportunity to consider the rehearing request. FERC announced it will convene a technical conference prior to issuing a rehearing order.
Generator Operating Limits proceeding
In June 2002 Entergy filed with FERC proposed Generator Operating Limit ("GOL") procedures to address local transmission constraints on the domestic utility companies' transmission system and to provide a process for generators interconnected to the transmission system to participate in short-term bulk power markets without first submitting each proposed transaction for a study. On August 2002, FERC issued an order accepting the proposed GOL procedures for filing, subject to a suspension period of five months and a final FERC order on the merits. FERC also required that prior to a final order a technical conference be held to further examine the initial GOL filing. Following the technical conference, Entergy submitted comments proposing to revise the initial GOL procedures in response to the various concerns raised during the technical conference. Certain intervenors in the proceeding filed comments opposing the proposed GOL procedures as anticompetitive and discriminatory alleging, among othe r things, that Entergy does not dispatch its system in the most economically efficient manner because it is attempting to protect its own generation from competition with the newer, more efficient independent generation on its system, and that Entergy's GOL proposal exacerbates Entergy's already existing market power by (a) fostering Entergy's ability to engage in uneconomic dispatch; (b) reducing the supply into, and liquidity of, short-term firm transmission markets; (c) forcing generators into the short-term non-firm market; and (d) impairing independent generators' ability to maximize their revenue streams. The intervenors further allege that Entergy's GOL proposal will distress independent generators, allowing Entergy to acquire such generators at "bargain prices." In its responsive documents, Entergy strongly denied these allegations and explained that the allegations found no basis in fact. In December 2002, FERC concluded that Entergy's proposal to revise its GOL procedures, in effect, su perseded the initial GOL filing and required additional detail and specification, including tariff sheets that implement the proposed revisions. FERC directed Entergy to refile the proposal described in its comments. Entergy submitted its GOL procedures for short-term firm transmission service for exports off the Entergy transmission system on January 15, 2003, which filing the FERC approved on March 13. FERC found that the proposal represented a reasonable balance between ensuring the reliability of the transmission grid and the requirement to make transmission capacity available on a non-discriminatory basis. Entergy filed GOL procedures in late-February 2003 concerning short-term firm transmission service for transactions internal to the Entergy control area. That portion of the GOL procedures is still pending before the FERC. Entergy is required to monitor the effectiveness of the GOL proposal over the summer peak period and to report the results to the FERC later in 2003.
Retail Rate Regulation
General (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)
The retail regulatory philosophy has shifted in some jurisdictions from traditional, cost-of-service regulation to include performance-based rate elements. Performance-based formula rate plans are designed to encourage efficiencies and productivity while permitting utilities and their customers to share in the benefits. Entergy Mississippi and Entergy Louisiana have implemented performance-based formula rate plans, but Entergy Louisiana's performance-based formula rate plan expired in 2001.The status of the introduction of competition in Entergy's retail service territories is summarized below.
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Retail Rate Proceedings
Each domestic utility operating subsidiary participates in retail rate proceedings on a consistent basis. The status of material retail rate proceedings are described below and in Note 2 to the domestic utility companies and System Energy financial statements.on an "at cost" basis, pursuant to service agreements approved by the SEC under PUHCA.
Earnings Ratios of Domestic Utility Companies and System Energy
The domestic utility companies' and System Energy's ratios of earnings to fixed charges and ratios of earnings to combined fixed charges and preferred dividends pursuant to Item 503 of SEC Regulation S-K are as follows:
Ratios of Earnings to Fixed Charges | ||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||
Entergy Arkansas | 3.37 | 3.17 | 2.79 | 3.29 | 3.01 | |||||
Entergy Gulf States | 3.04 | 1.51 | 2.49 | 2.36 | 2.60 | |||||
Entergy Louisiana | 3.60 | 3.93 | 3.14 | 2.76 | 3.33 | |||||
Entergy Mississippi | 3.41 | 3.06 | 2.48 | 2.14 | 2.33 | |||||
Entergy New Orleans | 3.60 | 1.73 | (b) | (c) | 2.66 | |||||
System Energy | 3.95 | 3.66 | 3.25 | 2.12 | 2.41 |
Ratios of Earnings to Combined Fixed | ||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||
Entergy Arkansas | 2.98 | 2.79 | 2.53 | 2.99 | 2.70 | |||||
Entergy Gulf States (a) | 2.90 | 1.45 | 2.40 | 2.21 | 2.39 | |||||
Entergy Louisiana | 3.16 | 3.46 | 2.86 | 2.51 | 2.93 | |||||
Entergy Mississippi | 3.07 | 2.77 | 2.27 | 1.96 | 2.09 | |||||
Entergy New Orleans | 3.31 | 1.59 | (b) | (c) | 2.43 |
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(b) | For Entergy New Orleans, earnings for the twelve months ended December 31, 2002 were not adequate to cover fixed charges and combined fixed charges and preferred dividends by $0.7 million and $3.4 million, respectively. | |
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Non-Utility Nuclear
Entergy's Non-Utility Nuclear business owns and operates five nuclear power plants and is primarily focused on selling electric power produced by those plants to wholesale customers. This business also provides operations and management services to nuclear power plants owned by other utilities in the United States. Operations and management services, including decommissioning services, are provided through Entergy's wholly-owned subsidiary, Entergy Nuclear, Inc.
Property
Generating Stations
Entergy's Non-Utility Nuclear business owns the following nuclear power plants:
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Pilgrim |
| Plymouth, MA | 688 MW | Boiling Water Reactor | 2012 | |||||
FitzPatrick | Nov. 2000 | Oswego, NY | 838 MW | Boiling Water Reactor | 2014 | |||||
Indian Point 3 | Nov. 2000 | Westchester County, NY | 994 MW | Pressurized Water Reactor | 2015 | |||||
Indian Point 2 | Sept. 2001 | Westchester County, NY | 1,028 MW | Pressurized Water Reactor | 2013 | |||||
Vermont Yankee | July 2002 | Vernon, VT | 510 MW | Boiling Water Reactor | 2012 |
Non-Utility Nuclear added 57 MW of capacity in 2004 through uprates and plans an additional 142 MW of uprates through 2006. The planned uprates include a total of 95 MW for Vermont Yankee that are currently pending approval by the NRC and the Public Service Board of Vermont.
Interconnections
The Pilgrim and Vermont Yankee plants are dispatched as a part of Independent System Operator (ISO) New England and the FitzPatrick and Indian Point plants are dispatched by the New York Independent System Operator (NYISO). The primary purpose of ISO New England is to direct the operations of the major generation and transmission facilities in the New England region and the primary purpose of NYISO is to direct the operations of the major generation and transmission facilities in New York state.
Energy and Capacity Sales
Entergy's Non-Utility Nuclear business has entered into power purchase agreements (PPAs) with creditworthy counterparties to sell the energy produced by its power plants at prices established in the PPAs. Entergy continues to pursue opportunities to extend the existing PPAs and to enter into new PPAs with other parties. Following is a summary of the amount of the Non-Utility Nuclear business' output that is currently sold forward under physical or financial contracts at fixed prices:
2005 | 2006 | 2007 | 2008 | 2009 | |||||||
Non-Utility Nuclear: | |||||||||||
Percent of planned generation sold forward: | |||||||||||
Unit-contingent | 36% | 20% | 17% | 1% | 0% | ||||||
Unit-contingent with availability guarantees | 54% | 52% | 38% | 25% | 0% | ||||||
Firm liquidated damages | 4% | 4% | 2% | 0% | 0% | ||||||
Total | 94% | 76% | 57% | 26% | 0% | ||||||
Planned generation (TWh) | 34 | 35 | 34 | 34 | 35 | ||||||
Average contracted price per MWh | $39 | $41 | $42 | $44 | N/A |
The Vermont Yankee acquisition included a 10-year PPA under which the former owners will buy the power produced by the plant, which is through the expiration in 2012 of the current operating license for the plant. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward monthly, beginning in November 2005, if power market prices drop below PPA prices. Accordingly, because the price is not fixed, the table above does not report power from that plant as sold forward after November 2005.
A sale of power on a unit contingent basis coupled with an availability guarantee provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. To date, Entergy has not incurred any payment obligation to any power purchaser pursuant to an availability guarantee. All of Entergy's outstanding availability guarantees provide for dollar limits on Entergy's maximum liability under such guarantees.
Some of the agreements to sell the power produced by Entergy's Non-Utility Nuclear power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary may be required to provide collateral based upon the difference between the current market and contracted power prices in the regions where the Non-Utility Nuclear business sells its power. The primary form of the collateral to satisfy these requirements would be an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At December 31, 2004, based on power prices at that time, Entergy had in place as collateral $545.5 million of Entergy Corporation guarantees and $47.5 million of letters of credit. In the event of a decrease in Entergy Corporation's credit rating to specified levels below investment grade, Entergy may be required to replace Entergy Corporation guarantees with cash or letters of c redit under some of the agreements.
In addition to selling the power produced by its plants, the Non-Utility Nuclear business sells installed capacity to load-serving distribution companies in order for those companies to meet requirements placed on them by the ISO in their area. Following is a summary of the amount of the Non-Utility Nuclear business' installed capacity that is currently sold forward, and the blended amount of the Non-Utility Nuclear business' planned generation output and installed capacity that is currently sold forward:
2005 | 2006 | 2007 | 2008 | 2009 | |||||||
Non-Utility Nuclear: | |||||||||||
Percent of capacity sold forward: | |||||||||||
Bundled capacity and energy contracts | 13% | 13% | 13% | 13% | 13% | ||||||
Capacity contracts | 58% | 67% | 36% | 22% | 10% | ||||||
Total | 71% | 80% | 49% | 35% | 23% | ||||||
Planned net MW in operation | 4,155 | 4,200 | 4,200 | 4,200 | 4,200 | ||||||
Average capacity contract price per kW per month | $1.2 | $1.1 | $1.1 | $1.0 | $0.9 | ||||||
Blended Capacity and Energy (based on revenues) | |||||||||||
% of planned generation and capacity sold forward | 93% | 87% | 65% | 36% | 12% | ||||||
Average contract revenue per MWh | $40 | $42 | $43 | $44 | $43 |
As of December 31, 2004, approximately 99% of Entergy's counterparties to Non-Utility Nuclear's energy and capacity contracts have investment grade credit ratings.
Fuel Supply
Nuclear Fuel
The nuclear fuel requirements for Pilgrim, FitzPatrick, Indian Point 2, Indian Point 3, and Vermont Yankee are met pursuant to contracts made by Entergy's Non-Utility Nuclear business. Entergy Nuclear Fuels Company is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for these non-utility nuclear plants.
Based upon currently planned fuel cycles, Entergy's nuclear units have contracts and inventory that provide adequate materials and services. Existing contracts for uranium concentrate, conversion of the concentrate to uranium hexafluoride, and enrichment of the uranium hexafluoride will provide a significant percentage of these materials and services over the next several years. Uranium market supply became much tighter in recent years. Costs and risks of obtaining supplies have increased for nuclear fuel users. It will be necessary for Entergy to enter into additional arrangements to acquire nuclear fuel in the future. It is not possible to predict the ultimate cost or availability of such arrangements.
Other Business Activities
Entergy Nuclear, Inc. also pursues service agreements with other nuclear power plants 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 Non-Utility Nuclear 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. currently provides decommissioning services for the Maine Yankee nuclear power plant and continues to pursue opportunities for Non-Utility Nuclear with other nuclear plant owners through operating agreements or innovative arrangements such as structured leases.
In September 2003, Entergy's Non-Utility Nuclear business agreed to provide administrative support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. The contract is for 10 years, the remaining term of the plant's operating license. Entergy will receive $13 million in 2005, and $14 million in 2006 and each of the remaining years of the contract. Entergy can also receive up to $6 million more per year beginning in 2007 if safety and regulatory goals are met. In addition, Entergy will be reimbursed for all employee-related expenses.
Entergy Nuclear, Inc. also is a party to two business arrangements that assist Entergy Nuclear, Inc. in providing operation and management services. Entergy Nuclear, Inc., in partnership with Framatome ANP, offers operating license renewal and life extension services to nuclear power plants in the United States. Entergy Nuclear Inc., through its subsidiary, TLG Services, offers decommissioning, engineering, and related services to nuclear power plant owners.
Energy Commodity Services
The Energy Commodity Services segment includes Entergy's non-nuclear wholesale assets business and Entergy-Koch, LP. Entergy's non-nuclear wholesale assets business owns power plants capable of generating about 1,500 MW of electricity for sale in the wholesale market. Entergy-Koch, LP is a limited partnership owned 50% each by Entergy and Koch Industries, Inc. through subsidiaries. Entergy-Koch engaged in two major businesses: energy commodity marketing and trading through Entergy-Koch Trading, and gas transportation and storage through Gulf South Pipeline. Entergy-Koch sold both of these businesses in the fourth quarter 2004, and Entergy-Koch is no longer an operating entity. Previously, Entergy's Energy Commodity Services business also engaged in power development activities through Entergy Wholesale Operations, but these activities were discontinued in early 2002.
Non-Nuclear Wholesale Assets Business
Property
Generating Stations
The capacity of the generating stations owned in Entergy's non-nuclear wholesale assets business as of December 31, 2004 is indicated below:
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Ritchie Unit 2, 544 MW | Helena, AR | 100% | 544 MW | Gas/Oil | ||||
Independence Unit 2, 842 MW | Newark, AR | 14% | 121 MW(2) | Coal | ||||
Warren Power, 300 MW | Vicksburg, MS | 75% | 225 MW(2) | Gas Turbine | ||||
Top of Iowa, 80 MW (3) | Worth County, IA | 50% | 40 MW | Wind | ||||
White Deer, 80 MW (3) | Amarillo, TX | 50% | 40 MW | Wind | ||||
RS Cogen, 425 MW (3) | Lake Charles, LA | 50% | 213 MW | Gas/Steam | ||||
Harrison County, 550 MW | Marshall, TX | 61% | 335 MW(2) | Gas Turbine |
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Entergy sold its interest in the Crete power plant located in Illinois in January 2004.
Energy and if below, increased by 60 percentCapacity Sales
Following is a summary of the shortfall.
2005 | 2006 | 2007 | 2008 | 2009 | |||||
Energy Commodity Services: | |||||||||
Capacity | |||||||||
Planned MW in operation | 1,578 | 1,578 | 1,578 | 1,578 | 1,578 | ||||
% of capacity sold forward | 44% | 33% | 29% | 29% | 19% | ||||
Energy | |||||||||
Planned generation (TWh) | 3 | 3 | 3 | 3 | 4 | ||||
% of planned generation sold forward | 69% | 54% | 45% | 45% | 35% | ||||
Blended Capacity and Energy (based on revenues) | |||||||||
% of planned energy and capacity sold forward | 63% | 44% | 38% | 39% | 22% | ||||
Average contract revenue per MWh | $24 | $24 | $28 | $28 | $21 |
Entergy-Koch, LP
Entergy Arkansas
Recovery of Grand Gulf 1 Costs
Under the settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22%trading contracts of its share of Grandpower marketing and trading business and $414 million cash to the venture and Koch contributed its approximately 8,000-mile Koch Gateway Pipeline (renamed Gulf 1 costsSouth Pipeline), gas storage facilities, and recoversKoch Energy Trading, which marketed and traded electricity, gas, weather derivatives, and other energy-related commodities and services. As specified in the remaining 78% of its share through rates. Underpartnership agreement, Entergy contributed an additional $72.7 million to the Unit Power Sales Agreement, Entergy Arkansas' share of Grand Gulf 1 costs is 36%. partnership in January 2004.
In the event 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' cost from the retained share.
Fuel Recovery
Entergy Arkansas' rate schedules include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior 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.
Entergy Gulf States
Texas Jurisdiction - River Bend Costs
In March 1998, the PUCT issued an order disallowing recovery of $1.4 billion of company-wide River Bend plant costs which have been held in abeyance since 1988. Entergy Gulf States appealed the PUCT's decision on this matter to a Texas District Court. A June 1999 settlement agreement addresses the treatment of abeyed plant costs, and, as a result, Entergy Gulf States removed the reserve for these costs and reduced the carrying value of the plant asset in 1999. In another settlement, Entergy Gulf States agreed not to prosecute its appeal before January 1, 2002 and agreed to cap the recovery of Entergy Gulf States' River Bend abeyed investment at $115 million net plant in service, less depreciation. The Texas District Court affirmed the PUCT decision disallowing recovery of the abeyed plant costs in April 2002, and Entergy Gulf States has appealed that ruling to the Third District Court of Appeals. The abeyed plant costs are discussed in more detail in Note 2 to the domestic utility companies and System E nergy financial statements.
Fuel Recovery
Entergy Gulf States' Texas rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, not recovered in base rates. Under current methodology, semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas. Entergy Gulf States will likely continue to use this methodology until retail open access begins in Texas. To the extent actual costs vary from the fixed fuel factor, refunds or surcharges are required or permitted. The amounts collected under the fixed fuel factor through the start of retail open access are subject to fuel reconciliation proceedings before the PUCT. At the start of retail open access for Entergy Gulf States in Texas, which is not expected before the firstfourth quarter of 2004, fuelEntergy-Koch sold its energy trading and purchased power cost recovery will be subjectpipeline businesses to third parties. The sales came after a review of strategic alternatives for enhancing the fuel componentvalue of Entergy-Koch, LP. Entergy received $862 million of cash distributions in 2004 from Entergy-Koch after the business sales, and Entergy ultimately expects to receive total net cash distributions exceeding $1 billion, comprised of the price-to-beat rates approved by the PUCT.
Entergy Gulf States' Louisiana electric rates include a fuel adjustment designed to recover the cost of fuel and purchased power costs. The fuel adjustment contains a surcharge or credit for deferred fuel expense and related carrying charges arisingafter-tax cash from the monthly reconciliationdistributions of actual fuel costs incurred with fuel cost revenues billedthe sales proceeds and the eventual liquidation of Entergy-Koch. Entergy currently expects the net cash distributions that it will receive will exceed its equity investment in Entergy-Koch, and expects to customers. record a $60 million net-of-tax gain when it receives the remaining cash distributions, which it expects will occur in 2006.
Regulation of Entergy's Business
PUHCA
The PUCT fuel cost reviewsPublic Utility Holding Company Act of 1935, as amended, regulates companies like Entergy Corporation that were resolved duringserve as holding companies to domestic operating utilities. Some of the past year ormore significant impacts of PUHCA are currently pending are discussed in Note 2that it:
Entergy continues to support the broad industry effort to pass legislation in the United States Congress to repeal PUHCA and transfer certain aspects of the oversight of public utility holding companies from the SEC to FERC. Entergy believes that PUHCA inhibits its ability to compete in the evolving electric energy marketplace and largely duplicates the oversight activities otherwise performed by FERC, other federal regulators, and state and local regulators.
Federal Power Act
The Federal Power Act regulates:
The Federal Power Act gives FERC jurisdiction over the rates charged by System Energy financial statements.
Entergy Gulf States' Louisiana gas rates include a purchased gas adjustment based on estimated gas costs for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers.
Entergy Louisiana
Recovery of Grand Gulf 1 Costs
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 Louisiana's share of capacity and energy from Grand Gulf 1, subjectprovided to certain terms and conditions. Under the Unit Power Sales Agreement, Entergy Louisiana's share of Grand Gulf 1 costs is 14%. In November 1988, Entergy Louisiana agreed to retain 18% of its share of Grand Gulf 1 costs and recover the remaining 82% of its share through rates. Non-fuel operation and maintenance costs for Grand Gulf 1 are recovered through Entergy Louisiana's base rates. Additionally, Entergy Louisiana is allowed to recover, through the fuel adjustment clause, 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to nonaffiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC's approval.
Performance-Based Formula Rate Plan
Negotiations with the LPSC staff and advisors for a statewide formula rate plan in Louisiana are ongoing.
Fuel Recovery
Entergy Louisiana's rate schedules include a fuel adjustment clause designed to recover the cost of fuel. The fuel adjustment 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.
Entergy Mississippi
Performance-Based Formula Rate Plan
Entergy Mississippi files a performance-based formula rate plan every 12 months that compares the annual earned rate of return to, and adjusts it against, a benchmark rate of return. The benchmark is calculated under a separate formula within the formula rate plan. The formula rate plan allows for periodic small adjustments in rates, up to an amount that would produce a change in Entergy Mississippi's overall revenue of almost 2%, based on a comparison of actual earned returns to benchmark returns and upon certain performance factors. The formula rate plan filing for the 2001 test year is discussed in Note 2 to the domestic utility companies and System Energy financial statements. In accordance with the MPSC's December 2002 rate order, there will be no formula rate plan filing in 2003 for the 2002 test year. The next formula rate plan will be submitted in March 2004 for the 2003 test year, and filings are due to continue annually thereafter.
Fuel Recovery
Entergy Mississippi's rate schedules include energy cost recovery riders to recover fuel and purchased energy costs. The rider is utilizing projected energy costs filed quarterly by Entergy Mississippi to develop an energy cost rate. The energy cost rate is redetermined each calendar quarter and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy cost as of the second quarter preceding the redetermination.
Entergy New Orleans
Recovery of Grand Gulf 1 Costs
Under Entergy New Orleans' various rate settlements with the Council in 1986, 1988, and 1991, Entergy New Orleans agreed to absorb and not recover from ratepayers a total of $96.2 million of its Grand Gulf 1 costs. Entergy New Orleans was permitted to implement annual rate increases in decreasing amounts each year through 1995, and to defer certain costs and related carrying charges for recovery on a schedule extending from 1991 through 2001.
Fuel Recovery
Entergy New Orleans' electric rate schedules include a fuel adjustment clause designed to recover the cost of fuel, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers. The adjustment also includes the difference between non-fuel Grand Gulf 1 costs paid by Entergy New Orleans and the estimate of such costs, which are included in base rates, as provided in Entergy New Orleans' Grand Gulf 1 rate settlements. Entergy New Orleans' gas rate schedules include an 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, in addition to carrying charges. The Council is currently studying Entergy New Orleans' fuel adjustment methodologies, with the intention of considering means of mitigating the effect on ratepayers of sudden increases in fuel costs. The resolution commencing the study not es that the Council does not intend to deny Entergy New Orleans full recovery of its prudently incurred fuel and purchased power costs.
State Regulation (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)Orleans and over some of the rates charged by Entergy Arkansas and Entergy Gulf States. FERC also regulates the rates charged for intrasystem sales pursuant to the System Agreement.
GeneralEntergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.
State Regulation
Entergy Arkansas is subject to regulation by the APSC, which includes the authority to:
Entergy Gulf States may be subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texaswith appellate jurisdiction over such matters residing in the PUCT. Whether such municipal jurisdiction currently exists is the subject of a declaratory judgment proceeding initiated at the PUCT by certain Cities served by Entergy Gulf States in December 2004. Entergy Gulf States' Texas business is also subject to regulation by the PUCT as to:
Entergy Gulf States' Louisiana electric and gas business and Entergy Louisiana are subject to regulation by the LPSC as to:
Entergy Louisiana is also subject to the jurisdiction of the Council with respect to such matters within Algiers in Orleans Parish.
Entergy Mississippi is subject to regulation by the MPSC as to the following:
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 Council as to the following:
Regulation of the Nuclear Power Industry
FranchisesAtomic 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, holds exclusive franchises to provide electric service in approximately 306 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are terminable upon breach of the terms of the franchise.
In Louisiana, Entergy Gulf States, holds non-exclusive franchises, permits,Entergy Louisiana, and System Energy, as owners of all or certificatesportions of convenienceANO, River Bend, Waterford 3, and necessityGrand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy has made substantial capital expenditures at these nuclear plants because of revised safety requirements of the NRC in the past, and additional expenditures could be required in the future. Entergy's Non-Utility Nuclear business is subject to the NRC's jurisdiction as the owner and operator of Pilgrim, Indian Po int Energy Center, FitzPatrick, and Vermont Yankee. Substantial capital expenditures at these nuclear plants because of revised safety requirements of the NRC could be required in the future.
Nuclear Waste Policy Act of 1982
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 provide for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE will furnish disposal service 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 Entergy company that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2004 of $156.3 million for the one-time fee. Entergy's Non-Utility Nuclear business has accepted assignment of the Pilgrim, FitzPatrick, Indian Point 3, Indian Point 2, and Vermont Yankee 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 U.S. Utility plants.
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE will now proceed with the licensing and, if the license is granted by the NRC, eventual construction of the repository will begin and receipt of spent fuel may begin sometime after 2010. Considerable 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, future expenditures will be required to increase spent fuel storage capacity at Entergy's nuclear plant sites.
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. These subsidiaries in November 2003 began litigation to recover the damages caused by the DOE's delay in performance. Management cannot predict the timing or amount of any potential recovery.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are responsible for their own spent fuel storage. Current on-site spent fuel storage capacity at Grand Gulf 1, River Bend, and Waterford is estimated to be sufficient until approximately 2007,2006, and 2012, respectively; dry cask storage facilities are planned to be placed into service at these units in 2007, 2005, and 2011, respectively. An ANO storage facility using dry casks began operation in 1996 and has been expanded since and will be further expanded as needed. The spent fuel storage facility at Pilgrim is licensed to provide electric serviceenough storage capacity until approximately 2012. The first dry spent fuel storage casks were loaded at Fitzpatrick in 2002, and further casks will be loaded there as needed. Indian Point and Vermont Yankee currently have sufficient spent fuel storage capacity until approximately 55 incorporated municipalities2006 and 2007, respectively; dry cask storage facilities are planned to begin operation at both sites in 2006. Implementation of dry cask storage at Vermont Yankee is currently the unincorporated areassubject of approximately 19 parishes,pending legislative and to provide gas serviceregulatory proceedings in approximately one incorporated municipality and the unincorporated areas of two parishes. In Texas,Vermont.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Gulf States, holds a certificateEntergy Louisiana, and System Energy recover from customers through electric rates the estimated decommissioning costs for ANO, the portion of convenienceRiver Bend subject to retail rate regulation, Waterford 3, and necessityGrand Gulf, respectively. These amounts are deposited in trust funds that can only be used for future decommissioning costs. Entergy periodically reviews and updates estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In June 2001, Entergy Arkansas received notification from the PUCTNRC of approval for a renewed operating license authorizing operations at ANO 1 through May 2034. In October 2003, a request was filed with the NRC to provide electric serviceextend the operating license of ANO 2 for an additional 20 years. The APSC ordered Entergy Arkansas to areas within approximately 24 countiesuse a 20-year life extension assumption for ANO 1 and 2, which resulted in eastern Texas,the cessation of the collection of funds to decommission ANO 1 and holds non-exclusive franchises2 beginning in 2001. Entergy Arkansas' projections show that with the assumption of 20 years of extended operational life for both units, the current fund balance with earnings over the extended life will be sufficient to provide electric servicedecommission both units. Every five years, Entergy Arkansas is required by the APSC to update the estimated costs to decommission ANO. In March 2003, Entergy Arkansas filed with the APSC its third five-year estimate of ANO decommissioning costs. The updated estimate indicated the current cost to decommission the two ANO units would be $936 million compared to $813 million in approximately 65 incorporated municipalities.the 1997 estimate. In September 2003, the APSC approved a stipulation between the APSC Staff and Entergy Arkansas resolving issues in the decommissioning cost estimate proceeding. Entergy Arkansas and the APSC Staff agreed to exclude, at this time, certain spent fuel management costs because of uncertainty associated with the responsibility of the DOE for all or a portion of those costs as a result of Entergy Arkansas' contract with the DOE to start taking spent fuel from ANO beginning in 1998. Entergy Arkansas reserves the right to seek a decision from the APSC on this issue prior to the next required decommissioning cost filing should significant changes in relevant facts and circumstances warrant.
In December 2002, the LPSC approved a settlement between Entergy Gulf States typicallyand the LPSC staff. The settlement included, among other things, the approval to cease collection of funds to decommission River Bend based on an assumed license extension for River Bend.
As part of the Pilgrim, Indian Point 1 and 2, and Vermont Yankee purchases, Boston Edison, Consolidated Edison, and VYNPC, respectively, transferred decommissioning trust funds, along with the liability to decommission the plants, to Entergy. Entergy believes that the decommissioning trust funds will be adequate to cover future decommissioning costs for these plants without any additional deposits to the trusts.
For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liability. NYPA and Entergy executed decommissioning agreements, which specify their decommissioning obligations. NYPA has the right to require Entergy to assume the decommissioning liability provided that it assigns the corresponding decommissioning trust, up to a specified level, to Entergy. If the decommissioning liability is granted 50-year franchisesretained by NYPA, Entergy will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in Texasthe decommissioning trusts. Entergy believes that the amounts available to it under either scenario are sufficient to cover the future decommissioning costs without any additional contributions to the trusts. In conjunction with the Pilgrim acquisition, Entergy received Pilgrim's decommissioning trust fund. Entergy believes that Pilgrim's decommissioning fund will be adequate to cover future decommissioning costs for the plant without any additional deposits to the trust. As part of the Indian Point 1 and 60-year franchises2 purchase, Consolidated Edison transferred the decommissioning trust fund and the liability to decommission Indian Point 1 and 2 to Entergy. Entergy also funded an additional $25 million to the decommissioning trust fund and believes that the trust will be adequate to cover future decommissioning costs for Indian Point 1 and 2 without any additional deposits to the trust.
Additional information with respect to decommissioning costs for ANO, River Bend, Waterford 3, Grand Gulf, Pilgrim, Indian Point 1, Indian Point 2, Indian Point 3, and FitzPatrick is found in Louisiana.Note 8 to the financial statements.
Energy Policy Act of 1992
The Energy Policy Act of 1992 requires all electric utilities (including Entergy Arkansas, Entergy Gulf States' current electric franchises will expire during 2007 - 2045 in Texas and during 2015 - 2046 in Louisiana.
States, Entergy Louisiana, holds non-exclusive franchisesand System Energy) that purchased uranium enrichment services from the DOE to provide electric servicecontribute up to a total of $150 million annually over approximately 15 years (adjusted for inflation, up to a total of $2.25 billion) for decontamination and decommissioning of enrichment facilities. At December 31, 2004, two years of assessments remain. In accordance with the Energy Policy Act of 1992, contributions to decontamination and decommissioning funds are recovered through rates in the same manner as other fuel costs. The estimated annual contributions by Entergy for decontamination and decommissioning fees are discussed in Note 8 to the financial statements. Entergy will oppose any attempts to extend the assessments past this date, but cannot state with certainty that an extension will not be made.
Price-Anderson Act
The Price-Anderson Act limits public liability for a single nuclear incident to approximately 116 incorporated Louisiana municipalities. Most of these franchises have 25-year terms, although six of these municipalities have granted 60-year franchises.$100.6 million per reactor (with currently 104 nuclear industry reactors participating). Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, also supplies electric service in approximately 353 unincorporated communities, all of which are located in Louisiana parishes in which it holds non-exclusive franchises.
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 city ordinances (except electric service in Algiers, which is provided by Entergy Louisiana). These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans' electric and gas utility properties. A resolution to study the advantages for ratepayers that might result from an acquisition of these properties was filed in a committee of the Council in January 2001. The committee has deferred consideration of and has taken no further action regarding that resolution. The full Council must approve the resolution to commence such a study before it can become effective.
The business of System Energy, and Entergy's Non-Utility Nuclear business have protection with respect to this liability through a combination of private insurance and an industry assessment program, as well as insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units. Insurance applicable to the nuclear programs of Entergy is limiteddiscussed in Note 8 to wholesale power sales. It has no distribution franchises.
the financial statements.
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 its affected companies are in substantial compliance with environmental regulations currently applicable to their facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Clean Air Act and Subsequent Amendments of 1990
The Clean Air Act and its subsequent Amendments of 1990 (the Clean Air Act) established the following fourseveral programs that currently or in the future may affect Entergy's fossil-fueled generation:
generation facilities:
New Source Review
Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that is not classified as routine repair, maintenance, or replacement. Units that undergo a non-routine modification must obtain a permit modification and may be required to install additional air pollution control technologies. Entergy has an established process for identifying modifications requiring additional permitting approval and has followed the 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, EPA has begun an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine and that have failed to obtain a permit modification. Entergy to date has not been included in any of these enforcement actions. Nevertheless, various courts and EPA have been inconsistent in their judgmen ts regarding what modifications are considered routine. In 2003, EPA promulgated a rule to attempt to clarify this issue, but the rule has been challenged in the United States Court of Appeals for the District of Columbia Circuit, and its effectiveness has been stayed by the court. In June 2004, EPA granted a request to reconsider certain aspects of the rule.
Acid Rain Program
The Clean Air Act provides SO2allowances 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. UtilitiesPlant owners are required to possess allowances for SO2 emissions from affected generating units. AllVirtually all Entergy fossil-fueled generating units are subject to SO2 allowance requirements. Entergy is a net buyer ofcould be required to purchase additional allowances when it generates power using fuel oil. Fuel oil usage is determined by economic dispatch and influenced by the price of natural gas, incremental emission allowance costs, and the availability and cost of purchased power.
Ozone Non-attainment
Controls were recently implemented at certain Entergy Gulf States and Entergy Louisiana each operate fossil-fueled generating units to achieve NOx reductions due toin geographic areas that are not in attainment of the ozonecurrently-enforced national ambient air quality standards for ozone. Texas non-attainment areas that impact Entergy are the Houston-Galveston and the Beaumont-Port Arthur areas. In Louisiana, Entergy is affected by the non-attainment status of areas servedthe Baton Rouge area. Areas in non-attainment are classified as "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. Texas and around Beaumont and Houston, Texas. To date, the cost of additional control equipment necessary to maintain this compliance is not material. In April and December 2000, Texas authorities adopted future ozone control strategiesLouisiana submitted plans for the BeaumontBeaumont-Port Arthur and HoustonBaton Rouge areas respectively, andthat included an extension of the regulatory deadline to gain attainment. The EPA initially approved these strategies. In December 2002,plans and the Houston area control strategy was revised. The strategy fordeadline extensions, but through litigation and a decision of the Beaumont area included an ozone level attainment date extension based on the transport of ozone precursor emissions from the Houston area. In December 2002, the U.S.United Stat es Court of Appeals for the Fifth Circuit invalidatedin December 2002, the attainment date extension,approval of the state plans has been withdrawn as violating provisions and deadlines required by the Clean Air Act.
The EPA has now reclassified the Beaumont-Port Arthur area from "moderate" to "serious" and has reclassified the Baton Rouge area from "serious" to "severe". These actions will require that Texas and Louisiana adopt plans to restrict the emission of certain air pollutants and to date no replacement strategy has been adopted. Even beforemake progress toward eventual attainment of national standards. Texas adopted and forwarded to the EPA for approval revisions to the state implementation plan in December 2004. Based on this recent invalidation, the strategies adopted by the State of Texas will causesubmittal, Entergy Gulf States to incur additional c osts for NOx controls. Installation of equipment is well along and will be complete in 2005. Prior to the recent invalidation of the Beaumont area attainment date extension, Entergy estimated compliance costs to be $11 to $26 million in the Beaumont area and approximately $15 million in the Houston area. The Beaumont compliance costs will have to be reevaluated when the State of Texas adopts a replacement strategy. As part of legislation passed in Texas in June 1999 to restructure the electric power industry in the state, certain generating units of Entergy Gulf States will be required to obtain operating permits and meet new, lower emission limits for NOx. Entergy believes the control strategies in the ozone non-attainment regulations include emission limits that are more restrictive than those related to utility restructuring. Thus, Entergy Gulf States is expected to incur costs through 2003 to meet the standards in the restructuring legislation within its overall project of mee ting the non-attainment regulations.
The State of Louisiana has developed a new emission control strategy to address continued ozone non-attainment status of areas in and around Baton Rouge, Louisiana. Implementation of the strategy has been challenged in separate court actions by an environmental organization and by an unaffiliated electric generating company. More specifically, in August 2002, the LDEQ issued a rule for control of NOx as part of the State Implementation Plan (SIP) to bring this area into attainment with the National Ambient Air Quality standards for ozone by 2005. The rule is expected to lead to installation of new NOxcontrol equipment at Entergy Gulf States generating units. The latest analyses indicate compliance costs at these units may be as much as $12 million in new capital spending from 2003 into early 2005. Cost estimates will be refined as engineering studies progress. Entergy Gulf States willnot be required at the Beaumont-Port Arthur area facilities. The Louisiana plan revisions were due in June 2004; however, due to obtain revised operating permits fromlegal and regulatory disputes over requirements unrelated to Entergy's interests, the LDEQstate has chosen to delay the submittal. The final content and meeteffect on Entergy of these developing plans is unknown, but Entergy continues to monitor events in these areas.
In April 2004, EPA issued a final rule, effective June 2005, stating that areas designated as non-attainment under a new lower emission limit s for NOx.
In September 2002, the EPA approved revisions8-hour ozone standard shall have one year to adjust to the SIP that address NOx control. In October 2002, the EPA then approved the entire ozone attainment demonstration SIP fornew requirements. For Louisiana, the Baton Rouge area. In conjunctionarea would be classified as a "marginal" (rather than "severe") non-attainment area under the new standard with this approval, the EPA extended the ozonean attainment date to November 15, 2005, while retaining the area's current classification as a serious ozone non-attainment area. In November 2002, the Louisiana Environmental Action Network (LEAN) filed a Petition for Judicial Review of the EPA's approval of the Baton Rouge SIP with the U.S. 5th Circuit Court of Appeals challenging several aspects including the attainment date extension and the withdrawal of non-attainment determination and reclassification. In December 2002, the U.S. 5th Circuit Court of Appeals invalidated an ozone attainment date extension approved by the EPA forJune 2007. For Texas, the Beaumont/Port Arthur area. It is not certain at this time what impact this ruling or the Petition for Judicial Review filings will have uponarea would be designated as a "marginal" (rather than "serious") non-attainment area under the new Baton Rouge emission control strategy at Entergy Gulf States.standard with an attainment date of June 2007 and the Houston-Galveston area would be designated as "moderate" non-attainment under the new standard with an attainment date of June 2010.
Hazardous Air Pollutants
In December 2000, the EPA made a determination that coal and oil-fired steam electric generating units should be regulated under the section of the Clean Air Act relating to emissions of hazardous air pollutants ("HAPs")(HAPs). The principal HAPs of concern are mercury from coal and nickel from oil. The EPA is in the process of developing thehas proposed regulations for these sources and hasinitially set a deadline of December 2004 for finalizing the rules. Entergy owns units that would be subject to these regulations. The EPA has since postponed finalization of mercury and nickel HAPs regulations until the second quarter of 2005.
The regulations may require coal and oil-fired units to reduce mercury and nickel emissions through various methods, including installation of controls, switching fuels or fuel suppliers, reducedreducing utilization of units, or some combination of these methods. The earliest expected compliance date for this rule would be 20082007, and Entergy could begin to incur costs of compliance as early as 2006 with the work taking up to three years to complete. These costs should be offset by advances in control technology or through the implementation of proposed cap and trade provisions which are not final at this time.
Interstate Air Transport
In January 2004, the EPA proposed the Interstate Air Quality Rule, renamed the Clean Air Interstate Rule (CAIR), which intends to reduce SO2 and NOx emissions from plants in order to improve air quality in the northeastern United States. The EPA has postponed issuing a final rule until the second quarter of 2005. The rule has the potential to require significant pollution control capital and/or operating costs (including any potential impacts to the value of SO2 allowances). Entergy's capital investment and annual operation and maintenance allowance purchase costs will depend on the economic assessment of NOx and SO2 allowance markets, cost of control technologies, and unit usage as well as other uncertainties described below.
The capital financial impact could be extended for an additional year.offset by proposed emission markets which would allow operation and maintenance purchases or use of allocated credits; however, the allocation of the emission allowances and the set up of the market will determine the ultimate cost to Entergy. Entergy is concerned that the allocation may be unfairly skewed towards states with relatively higher emissions. Entergy will continue to study the proposed rule's impact to its generation fleet and will work to ensure that all states are treated fairly in the allocation of emission credits.
In May 2004, the EPA re-proposed the Best Retrofit Control Technology (BART) regulations which could potentially result in a requirement to install SO2 pollution control technology on certain of Entergy's coal and oil generation units. The impact of this proposed rule is unclear, but could result in significant increased capital and operating costs on certain units.
Future Legislative and Regulatory Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives relating to the reduction of emissions that are under consideration at the federal, state, and international level. Because of the nature of Entergy's business, the adoption of each of these could effectaffect its operations. These initiatives include:
Entergy continues to monitor these actions in order to analyze their potential operational and cost implications. In anticipation of the potential imposition of CO2emission limits on the electric industry in the future, Entergy has initiated actions designed to reduce its exposure to potential new governmental requirements related to CO2 emissions. These actions include establishment of a formal program to stabilize power plant CO2 emissions at year 2000 levels through 2005 and support for national legislation that would increase planning certainty for electric utilities while addressing emissions in a responsible and flexible manner. By virtue of its proportionally large investment in low or non-emitting gas-fired and nuclear generation technologies, Entergy's overall CO2 emission "intensity," or rate of CO2 emitted per kilowatt-hour of electricity generated, is already among the lowest in the industry. Total carbon dio xideTo tal CO2 emissions representing the company's ownership share of power plants in the United States were approximately 53.24 million tons in 2000, 49.58 million tons in 2001, and 44.20 million tons in 2002.
2002, 36.78 million tons in 2003, and 38.28 million tons in 2004.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act or CWA) 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 CWA requires anyone who wants to dischargeall discharges of pollutants to first obtain an NPDES permit, or else that discharge willwaters of the United States to be considered illegal. permitted.
316(b) Cooling Water Intake Structures
The EPA recently proposed draftfinalized new regulations forin July 2004 governing the intake of water at large existing power plants including certain electric generating stations employing once-throughthat employ cooling technology (the draft Rule).water intake structures. The draft Rulerule seeks to reduce perceived impacts on aquatic resources by requiring covered facilities to take steps to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic impacts. WhileEntergy, other industry members and industry groups, environmental groups, and a coalition of northeastern and mid-Atlantic states have challenged various aspects of the rule. This challenge currently is lodged in the United States Court of Appeals for the Second Circuit in New York City after a motion to transfer from the Ninth Circuit in San Francisco was granted in December 2004.
Entergy's non-utility nuclear generation business is currently in various stages of the data evaluation and discharge permitting process for its generation facilities. Indian Point is involved in an administrative permitting process with the New York environmental authority for renewal of the Indian Point 2 and 3 discharge permits. In November 2003, the New York State Department of Environmental Conservation (NYDEC) issued a draft permit indicating that closed cycle cooling would be considered the "best technology available" for minimizing perceived adverse environmental impacts attributable to the intake and discharge of cooling water at Indian Point 2 and 3. The draft permit would require Entergy to take certain steps to assess the feasibility of retrofitting the site to install cooling towers before re-licensing Indian Point 2 and 3, whose current licenses with the NRC expire in 2013 and 2015. The draft permit could also require, upon its becoming effective, the facilities to take a n annual 42 unit-day outage and provide a payment into a NYDEC account until the start of cooling tower construction. Entergy is participating in the administrative process in order to have the draft Rule is the subject of extensive comment and also is expected to be challenged (which may result in changes t o itpermit modified prior to final promulgation),issuance and opposes any requirement to install cooling towers or to begin annual outages at Indian Point 2 and 3. Accordingly, Entergy currentlyalso has begunfiled a separate action in New York state court seeking a determination that the state cooling water intake structure regulation underpinning the NYDEC's draft permit for Indian Point 2 and 3 was improperly promulgated and is thus void. The New York trial court dismissed Entergy's claim, and Entergy has appealed to the New York Court of Appeals. Pilgrim received approval from EPA allowing the full 3 1/2-year schedule for compliance demonstration as is outlined in the new rule and will continuealso pursue appropriate supplementation of the existing record regarding perceived impacts, options and costs. Entergy's other Non-Utility Nuclear gener ation facilities are in the process of reviewing data, considering implementation options, providing information required by the current rule to evaluateEPA and the draft Rule, includingaffected states, and requesting the 3 1/2-year submission schedule allowed by considering options for complying with the draft Rule if promulgated in substantially its current form. Those options considered may include operational controls, the installation of equipment to address perceived aquatic impacts, and other mitigation measures, or combinations of these alternatives.
rule, where necessary.
Oil Pollution Prevention Regulation
The EPA published a revised Oil Pollution Prevention regulationrule in July 2002. The regulationrule affects Entergy's operation of its approximately 3,500 transmission and distribution electrical equipment installations that are potentially subject to the rule. While the published rule provides a great deal of flexibility to the regulated community insofar as allowable strategies, it also providesprovided the EPA with a great deal of discretion in evaluation of a facility's compliance with the rule. TheIn September 2004, EPA Oil Program Headquarters staffsolicited comments on alternative management strategies for oil-filled electrical equipment that were proposed by the Utility Solid Waste Activities Group and Entergy. Entergy is currently in the processfinal stages of trainingrevising existing Integrated Response Plans and Spill Prevention, Control and Countermeasures Plans to meet the EPA Regions onrequirements of the rule and its enforcement. Entergy is currently working directly with the EPA Oil Program Headquarters staff to have Entergy's electrical equipment oil pollution prevention strategy formally recognized as an industry standard.
does not expect significant compliance costs.
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 and, indirectly, the states, to mandate clean-up, or reimbursement of clean-up costs, by owners or operators of sites from which hazardous substances may be or have been released. Parties that generated or 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. The domestic utility companies have sent waste materials to various disposal sites over the years. In addition, environmental laws now regulate certain of the companies' operating procedures and maintenance practices which historically were not subject to regulation. Some of Entergy's disposal sites used by Entergy have been the subject of governmental action under CERCLA, resulting in site clean-up activities. The domestic utility companies have participatedparti cipated to various degrees in accordance with their respective potential lia bilitiesliabilities in such site clean-ups and have developed experience with clean-up costs. The affected companies have established reserves for such environmental clean-up and restoration activities. Details of material CERCLA liabilities are discussed for each operating company in the "Other Environmental Matters" section below.
Other Environmental Matters
Entergy Arkansas
Entergy Arkansas is currently involved in litigation relating to contamination at a site near Rison, Arkansas, which has been placed on the state Superfund list. The site was operated by Utilities Services, Inc. Neither Entergy Arkansas nor any other Entergy-affiliated company ever owned or operated the site. Entergy Arkansas had contracted with Utilities Services, Inc., to perform transformer and bushing repairs which involved filtering oil at various transformer sites. Hazardous substances found in the soil and in containers and drums at the site included polychlorinated biphenyls (PCBs) and pentachlorophenol (a wood preservative). The litigation is currently pending before the Arkansas Supreme Court on an appeal from the decision of the trial court to dismiss the complaint that had been filed against Entergy Arkansas and other defendants seeking declaratory and injunctive relief holding the defendants liable for having dispensed hazardous substances at the site and requiring remediation. In the light of the trial court's decision, Entergy Arkansas will not be liable for remediation of the site unless the trial court's order is overturned on appeal or it is adjudicated to be liable.
Entergy Arkansas spent approximately $380,000 in its efforts to stabilize the site and has a claim against the State Trust Fund for reimbursement. The amount of clean-up costs associated with the site cannot be accurately determined until a site characterization has been performed, but it is estimated that such costs will be at least $5 million.
During November 2002, Entergy Arkansas received notice from EPA Region IV that it is considered to be a PRP for the Industrial Pollution Control Site located in Jackson, Mississippi. The business operated a waste oil and water recycling facility from 1991 until 1997. Industrial Pollution Control, Inc. filed for Chapter 11 bankruptcy in 1997. In 1999, EPA began a removal response action and currently believes that no further clean up is needed. Entergy Arkansas is in the initial stages of addressing its liability in this site, but believes, based on information provided by EPA, that its share could be as much as $450,000.
Entergy Gulf States
Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Gulf States and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Gulf States' premises (see "Litigation" below).
Entergy Gulf States is currently involved in a remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, was apparently routed to a portion of the property for disposal. The same area has also been used as a landfill. In 1999, Entergy Gulf States signed a second Administrative Consent Order with the EPA to perform removal action at the site. In 2002, approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. AIn 2003, a cap was constructed over the remedial area to prevent the migration of contamination to the surface. Entergy Gulf States anticipates commencement of a ten-year groundwater monitoring program will beginstudy upon issuance of a negotiated order by the EPA, which is expected to issue the order in 2003.early 2 005. Entergy Gulf States believes that its ultimate responsibility for this site will not materially exceed its existing clean-up provision of $11.9$1.5 million.
In 1994, Entergy Gulf States performed a site assessment in conjunction with a construction project at the Louisiana Station Generating Plant (Louisiana Station). In 1995, a further assessment confirmed subsurface soil and groundwater impact to three areas on the plant site. After further review,validation, a notification was made to the LDEQ.LDEQ and a phased process was executed to remediate each area of concern. The final phase of groundwater clean upclean-up and monitoring at Louisiana Station is expected to continue through 2005. The remediation cost incurred through December 31, 20022004 for this site was $6.4$6.7 million. Future costs are not expected to exceed the existing provision of $1.1$0.8 million.
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' premises (see "Litigation" below).
The Southern Transformer Shop located in New Orleans served both Entergy Louisiana and Entergy New Orleans. This transformer shop is now closed and environmental assessments are being performedsoil and communicationsgroundwater assessment activities have resumed since the demolition of the onsite buildings and structures was completed in early 2004. Entergy has entered into the Voluntary Remediation Program with EPAthe LDEQ and LDEQ are underway to determine what remediation may be necessary. Based on preliminary findings, an expected clean-up costsubmitted a Site Investigation Workplan. A liability of $750,000approximately $350,000 has been reservedestablished for this project.environmental assessment and remediation costs with estimated completion by the end of 2005.
During 1993, the LDEQ issued new rules for solid waste regulation, including regulation of wastewater impoundments. Entergy Louisiana and Entergy New Orleans have determined that certain of their power plant wastewater impoundments were affected by these regulations and chose to remediate and repair or close them. Completion of this work is pending LDEQ approval. LDEQ has issued notices of deficiencies for certain of these sites. As a result, recorded liabilities in the amounts of $5.8 million for Entergy Louisiana and $0.5 million for Entergy New Orleans existed at December 31, 20022004 for wastewater remediation and repairs and closures. Management of Entergy Louisiana and Entergy New Orleans believes these reserves are adequate based on current estimates.
Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana
The Texas Commission on Environmental Quality (Commission) notified Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana in September through November 2003 that the Commission 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 Gulf States and Entergy Louisiana sent transformers to this facility during the 1980s. There has been no indication that Entergy Arkansas ever used this facility. Entergy Gulf States, Entergy Louisiana, and Entergy Arkansas have responded to an information request from the Commission and will continue to cooperate in this investigation. It is likely that Entergy Gulf States and Entergy Louisiana will be required to contribute to the remediation of contaminated gr oundwater at the site, but the contributions likely will be less than those of other SESCO customers that continued to use the site long after 1990, and the list of PRPs who likely will share in the cost is long. Based on current information, the estimate of Entergy's portion of the liability is $0.6 million.
Entergy New Orleans
In March 2004, agents of the United States Fish and Wildlife Service conducted an inspection of Entergy New Orleans' Michoud power plant and found a number of dead brown pelicans near the facility's water intake structure and fish-return trough. Brown pelicans are an endangered species in Louisiana. The United States Attorney's Office for the Eastern District of Louisiana (Attorney's Office) issued a grand jury subpoena to an Entergy New Orleans employee in May 2004 to give evidence regarding the cause of death of the pelicans. The Attorney's Office then agreed to meet with Entergy New Orleans rather than requiring the employee to testify. As a result of that meeting, Entergy New Orleans conducted an internal investigation of the matter and submitted a report to the Attorney's Office in August 2004. Entergy New Orleans also constructed an engineered walkway and cover over the intake structure and feeding trough to eliminate pelican access to the area. Entergy New Orleans continues neg otiations with the Attorney's Office regarding final resolution of this matter.
Litigation
Certain states in which Entergy operates in particular Louisiana, Mississippi, and Texas, have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment in these states poses a significant business risk.
Ratepayer Lawsuits (Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and Entergy New Orleans)
Vidalia Project Sub-Docket
Marathon Oil Company and Louisiana Energy Users Group, intervenors in another proceeding that has since been settled, requested that the LPSC review the prudence of a contract entered into by Entergy Louisiana to purchase energy generated by a hydroelectric facility known as the Vidalia project through the year 2031. Note 9 to the domestic utility companies and System Energy financial statements contains further discussion of the obligations related to the Vidalia project. By orders entered by the LPSC in 1985 and 1990, the LPSC approved Entergy Louisiana's entry into the Vidalia contract and Entergy Louisiana's right to recover from its customers, through the fuel adjustment clause, the costs of power purchased thereunder. Additionally, the wholesale electric rates under the Vidalia power purchase contract were filed at FERC. In December 1999, the LPSC instituted a review of the following issues relating to the Vidalia project: (i) the LPSC's jurisdiction over the Vidalia project; (ii) Entergy Louisiana' s management of the Vidalia contract, including opportunities to restructure or otherwise reform the contract; (iii) the appropriateness of Entergy Louisiana's recovery of 100% of the Vidalia contract costs from ratepayers; (iv) the appropriateness of the fuel adjustment clause as the method for recovering all or part of the Vidalia contract costs; (v) the appropriate regulatory treatment of the Vidalia contract in the event the LPSC approves implementation of retail competition; and (vi) Entergy Louisiana's communication of pertinent information to the LPSC regarding the Vidalia project and contract.
In September 2002, the LPSC approved a settlement of the proceeding and concluded the Vidalia project subdocket. The settlement is based on Entergy Louisiana sharing with Entergy Louisiana customers a portion of the benefits of a tax deduction that became available when Entergy Louisiana elected to mark the Vidalia contract to market for tax accounting purposes. The tax benefit sharing is described in more detail in Entergy's"MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources" under the heading "Entergy Louisiana Tax Accounting Election." Three issues are not addressed by the settlement, but there is no proceeding pending before the LPSC at this time to consider them. Those issues are: (i) the LPSC's jurisdiction over the Vidalia project; (ii) the appropriateness of Entergy Louisiana's recovery of 100% of the Vidalia contract costs from customers; and (iii) the appropriate regulatory treatment of the Vidalia contract in the event the LPSC a pproves implementation of retail competition.
Entergy New Orleans Fuel Clause Lawsuit
In April 1999, a group of ratepayers filed a complaint against Entergy New Orleans, Entergy Corporation, Entergy Services, and Entergy Power in state court in Orleans Parish purportedly on behalf of all Entergy New Orleans ratepayers. The plaintiffs seek treble damages for alleged injuries arising from the defendants' alleged violations of Louisiana's antitrust laws in connection with certain costs passed on to ratepayers in Entergy New Orleans' fuel adjustment filings with the City Council. In particular, plaintiffs allege that Entergy New Orleans improperly included certain costs in the calculation of fuel charges and that Entergy New Orleans imprudently purchased high-cost fuel from other Entergy affiliates. Plaintiffs allege that Entergy New Orleans and the other defendant Entergy companies conspired to make these purchases to the detriment of Entergy New Orleans' ratepayers and to the benefit of Entergy's shareholders, in violation of Louisiana's antitrust laws. Plaintiffs also seekse ek to recover inter estinterest and attorneys' fees. Entergy filed exceptions to the plaintiffs' allegations, asserting, among other things, that jurisdiction over these issues rests with the City Council and FERC. In March 2004, the plaintiffs supplemented and amended their petition. If necessary, at the appropriate time, Entergy will also raise its defenses to the antitrust claims. At present, theThe suit in state court ishas been stayed by stipulation of the parties.parties pending a decision by the City Council in the proceeding discussed in the next paragraph.
Plaintiffs also filed this complaint with the City Council in order to initiate a review by the City Council of the plaintiffs' allegations and to force restitution to ratepayers of all costs they allege were improperly and imprudently included in the fuel adjustment filings. Testimony was filed on behalf of the plaintiffs in this proceeding in April 2000 and has been supplemented. The testimony, as supplemented, asserts,asserting, among other things, that Entergy New Orleans and other defendants have engaged in fuel procurement and power purchasing practices and included costs in Entergy New Orleans' fuel adjustment that could have resulted in Entergy New Orleans customers being overcharged by more than $100 million over a period of years. In June 2001, the City Council's advisors filed testimony on these issues in which they allege that Entergy New Orleans ratepayers may have been overcharged by more than $32 million, the vast majority of which is reflected in the plaintiffs' claim. However, it is not clear precisely wh at periods and damages are being alleged in the proceeding. Entergy intends to defend this matter vigorously, both in court and before the City Council. Hearings were held in February and March 2002. The parties have submitted post-hearing briefs and the matter has been submitted toIn February 2004, the City Council forapproved a decision. In October 2002,resolution that resulted in a refund to customers of $11.3 million, including interest, during the plaintiffs filed a motion to re-openmonths of June through September 2004. The resolution concludes, among other things, that the evidentiary record does not support an allegation tha t Entergy New Orleans' actions or inactions, either alone or in concert with Entergy or any of its affiliates, constituted a misrepresentation or a suppression of the alternative, a motion for a new trial seekingtruth made in order to re-open the recordobtain an unjust advantage of Entergy New Orleans, or to accept certain testimony filed bycause loss, inconvenience or harm to its ratepayers. The plaintiffs have appealed the City Council advisorsresolution to the state court in a separate proceeding atOrleans Parish. Oral argument on the FERC. The ultimate outcome of the lawsuit and the City Council proceeding cannot be predicted at this time.
plaintiffs' appeal was conducted in February 2005.
Entergy New Orleans Rate of Return Lawsuit
In April 1998, a group of residential and business ratepayers filed a complaint against Entergy New Orleans in state court in Orleans Parish purportedly on behalf of all ratepayers in New Orleans. The plaintiffs allege that Entergy New Orleans overcharged ratepayers by at least $300 million since 1975 in violation of limits on Entergy New Orleans' rate of return that the plaintiffs allege were established by ordinances passed by the Council in 1922. The plaintiffs seek, among other things, (i) a declaratory judgment that such franchise ordinances have been violated; and (ii) a remand to the Council for the establishment of the amount of overcharges plus interest. Entergy New Orleans believes the lawsuit is without merit. Entergy New Orleans has charged only those rates authorized by the Council in accordance with applicable law. In May 2000, a court of appeal granted Entergy New Orleans' exception to jurisdiction in the case and dismissed the proceeding. The Louisiana Supreme CourtCou rt denied the plaintiff 'splaintiff's request for a writ of certiorari. The plaintiffs then commenced a similar proceeding before the Council. The plaintiffs and the advisors for the Council each filed their first round of testimony in January 2002. In their testimony, the plaintiffs allege that Entergy New Orleans earned in excess of the legally authorized rate of return during the period 1979 to 2000 and that Entergy New Orleans should be required to refund between $240 million and $825 million to its ratepayers. In the testimony submitted by the Council advisors, the advisors allege that Entergy New Orleans has not earned in excess of its authorized rate of return for the period at issue and that no refund is therefore warranted. A hearing scheduled in June 2002 was canceledcanceled.
In December 2003, the Council Advisors filed a motion in the Council proceedings to bifurcate the hearing in this matter, such that the effect of the provision of the 1922 Ordinance in setting lawful rates would be considered first. Only if it is determined that this provision establishes a limitation, would the remaining issues be reached. The motion to bifurcate was granted by the City Council in April 2004, and a hearing on the first part of the bifurcated proceeding has been continued without a proposed trial date.is currently scheduled to begin in June 2005.
Entergy Gulf States Merger SavingsTexas Power Price Lawsuit
In February 2002, various plaintiffs, who claim to beAugust 2003, a lawsuit was filed in the district court of Chambers County, Texas by Texas residents on behalf of a purported class apparently of the Texas retail customers of Entergy Gulf States in Texaswho were billed and further claimpaid for electric power from January 1, 1994 to be class representatives for all other similarly situated customers, filed a lawsuit againstthe present. The named defendants are Entergy Corporation, Entergy Services, Entergy Power, Entergy Power Marketing Corp., Arkansas Electric Cooperative Corporation and Entergy Arkansas. Entergy Gulf States and Entergy Corporation inis not a named defendant, but is alleged to be a co-conspirator. The court has granted the district courtrequest of Jefferson County, Texas. The petition alleges that Entergy Corporation and Entergy Gulf States violatedto intervene in the 1993 agreement enteredlawsuit 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 partiesthe defendants while rejecting and/or reselling to off-system utilities, less expensive power offered and/or purchased from off-system suppliers and/or generated by the Entergy system. In particular, plaintiffs allege that the defendants manipulated and continue to manipulate the dispatch of generation so that power is purchased from affiliated expensive resources instead of buying cheaper off-system power.
Plaintiffs estimate 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. In September 2003, the Entergy defendants removed the lawsuit to the Entergy-Gulf States Utilities merger docketfederal court in Texas by failing to pass 100% of Texas retail non-fuel merger-related savings to Entergy Gulf States' ratepayersGalveston, and in Texas beginning on January 1, 2002. The petition alleges that the non-fuel merger-related savings accrue atOctober 2003, filed a rate of about $2 million per month. The petition seeks damages, exemplary damages, and attorney's fees and costs, in addition to certificationpleading seeking dismissal of the plaintiffs' claims. In October 2003, the plaintiffs filed a motion to remand the case as a class action. Theto state court. In January 2004, the federal court determined that it did not have jurisdiction over the subject matter of the lawsuit, and remanded the case to the state district court has denied Entergy Gulf States' and Entergy Corporation's motions to transfer venue and to dismiss or abatein Chambers County. In November 2004, the state district court dismissed the case based on the basisa lack of th e PUCT's jurisdiction over this matter. In September 2002, Entergy Gulf States and Entergy Corporation sought mandamus relief at the Ninth District Court of Appeals which was denied. Afterjurisdiction. The plaintiffs have initiated appellate proceedings in the Court of Appeals denied rehearing, in January 2003, Entergy Corporation and Entergy Gulf States filed a petition for mandamus relief at the Texas Supreme Court. Proceedings have been stayed in the district court pending the decision in the mandamus application. Management cannot predict the outcome of this litigation at this time.
Appeals.
Entergy Louisiana Formula Ratemaking Plan Lawsuit
In May 1998, a group of ratepayers filed a complaint against Entergy Louisiana and the LPSC in state court in East Baton Rouge Parish purportedly on behalf of all Entergy Louisiana ratepayers. The plaintiffs allege that the formula ratemaking plan authorized by the LPSC has allowed Entergy Louisiana to earn amounts in excess of a fair return. The plaintiffs seek, among other things, (i) a declaratory judgment that the formula ratemaking plan is an improper ratemaking practice; and (ii) a refund of the amounts allegedly charged in excess of proper ratemaking practices. Entergy Louisiana believes the lawsuit is without merit and plans to vigorously defend itself. This case has not been active, and abandonment issues are being evaluated. At this time, management cannot determine the amount of damages being sought.
Street Lighting Lawsuit (Entergy New Orleans)
In February 2002, the City of New Orleans (City) filed a petition against Entergy New Orleans in state court in Orleans Parish, seeking declaratory relief, injunctive relief, an unspecified amount of monetary damages, and attorney and consulting fees and costs. The City's petition alleged that Entergy New Orleans had breached its obligations to the City related to the provision of street lighting maintenance services. After mediation, the City dismissed its lawsuit with prejudice on October 28, 2002, and any amounts that may be owed by Entergy New Orleans will be determined by an independent third party audit. Management believes that Entergy New Orleans does not owe the City any net amount under the street lighting contract, and will vigorously assert its rights in the audit.
Murphy Oil Lawsuit (Entergy Corporation and Entergy Louisiana)
Residents located near the Murphy Oil Refinery in Meraux, Louisiana filed several lawsuits in state court in St. Bernard Parish, Louisiana against Murphy Oil, Entergy Louisiana, and others for injuries they allegedly suffered as a result of an explosion at the refinery in June 1995. The lawsuits were consolidated and a class of plaintiffs was certified. Plaintiffs alleged, among other things, that an electrical fault at an Entergy Louisiana substation contributed to causing the explosion. Murphy Oil filed a cross-claim against Entergy Louisiana based on the same allegation, in which Murphy Oil seeks recovery of any damages it has paid to the plaintiffs. Claiborne P. Deming, who became a director of Entergy Corporation in 2002, is the President and Chief Executive Officer of Murphy Oil.
Murphy Oil and other defendants settled with the plaintiffs for $8.8 million, but Entergy Louisiana did not participate in the settlement. After trial for the remaining parties in the proceeding, the judge issued a decision finding Entergy Louisiana believes the claims40% responsible and awarding monetary damages, which total approximately $11 million with interest against it are without merit and is vigorously defending itself.Entergy Louisiana. Entergy Louisiana alsoappealed the judgment to the Court of Appeals. Entergy Louisiana has insurance in place for claims of this type. A trial date for the remaining parties in the proceeding has been set for September 2003.
type, and management does not expect a material adverse financial effect from this decision.
Fiber Optic Cable Litigation (Entergy Corporation, Entergy Gulf States, and Entergy Louisiana and Entergy Mississippi)
In 1998, a group of property owners filed a class action suit against Entergy Corporation, Entergy Gulf States, Entergy Services and ETHCEntergy Technology Holding Company in state court in Jefferson County, Texas purportedly on behalf of all property owners in each of the states throughout the Entergy service area who have conveyed easements to the defendants. The lawsuit alleged that Entergy installed fiber optic cable across their property without obtaining appropriate easements. The plaintiffs sought actual damages for the use of the land and a share of the profits made through use of the fiber optic cables and punitive damages. The state court petition was voluntarily dismissed, and the plaintiffs commenced a class action suit with the same claims in the United States District Court in Beaumont, Texas. Both sides have filed motions for summary judgment, which were heard by the court in late 2001. TheIn 2003, the district judge foundruled that although four typesas a matter of law, all of the Texas easements can be usedpe rmit Entergy to utilize the fiber for internal communications, two types cannot be usedtheir own communications. Further, the court ruled that approximately two-thirds of the Texas easements allow Entergy to use the fiber for thir d-partyexternal or third party communications. Entergy believes that any damages suffered by the remaining one-third plaintiff landowners are negligible and that there is no basis for the claim seeking a share of profits. In April 2004, the trial court entered an order denying the plaintiffs' request that this case be certified as a class. The plaintiffs have appealed this ruling to the United States Court of Appeals for the Fifth Circuit. At this time, management cannot determine the specific amount of damages being sought.
Several property owners have filed a class action suit against Entergy Louisiana, Entergy Services, ETHC, and Entergy Technology Company in state court in St. James Parish, Louisiana purportedly on behalf of all property owners in Louisiana who have conveyed easements to the defendants. The lawsuit alleges that Entergy installed fiber optic cable across their property without obtaining appropriate easements. The plaintiffs seek actual damages for the use of the land and a share of the profits made through use of the fiber optic cables and punitive damages. Entergy removed the case to federal court in New Orleans; however, the District Court remanded the case back to state court. While Entergy appealed this ruling, recently the United States Court of Appeals for the Fifth Circuit denied this appeal. In December 2003, the trial court held a hearing to determine if a class should be certified. On February 18, 2004, the trial court entered an order certifying this matter as a c lass. Entergy has appealed this ruling to the Louisiana Fifth Circuit Court of Appeals, and oral arguments have been held. At this time, management cannot determine the specific amount of damages being sought.
In January 2002, a class action lawsuit asserting similar allegations to those alleged in the lawsuitSeveral property owners have filed in Texas was commencedseparate lawsuits against Entergy Corporation, Entergy Mississippi, Entergy Services, ETHC, and ETC in state court in Ascension Parish, Louisiana, against Entergy Louisiana, Entergy Services, ETHC, and Entergy Technology Company, purportedly on behalf of all similarly situated property ownersvarious counties in Louisiana. Summary judgment was granted in Entergy's favor in January 2003 and the lawsuit has been dismissed.
In June 2002,a class action lawsuit was filed by two defendants in the United States District Court of the Northern District of Mississippi against Entergy Mississippi, purportedly on behalf of others similarly situated, alleging that Entergy Mississippi installed fiber optic cable across their propertyproperties without obtaining the appropriate easement.easements. The plaintiffs seek declaratory reliefactual damages for the use of the land, a share of the profits made through use of the fiber optic cables, and at least $20 million in punitive damages in one case, and an unspecified amount of punitive damages including punitive damages. Entergy Mississippi filed a motion to dismiss in September 2002, contending that it has no fiber optic cables attached to its facilities and has not authorized any party to place fiber optic facilities on or under its right of way on the property in question. Entergy Mississippi intends to vigorously defend the lawsuit. At this time, management cannot determine the specific amount of damages being sought.other cases.
Asbestos and Hazardous Waste Suits (Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)
Numerous lawsuits have been filed in federal and state courts in Texas, Louisiana, and LouisianaMississippi primarily by contractor employees in the 1950-1980 timeframe against Entergy Gulf States, Entergy Louisiana, and Entergy New Orleans, and Entergy Mississippi as premises owners of power plants, for damages caused by alleged exposure to asbestos or other hazardous material. Many other defendants are named in these lawsuits as well. Since 1992, these companies have resolved over three thousand claims for nominal amounts that in the aggregate total less that $13 million, including defense costs. Some of this loss has been offset by reimbursement from insurers. PresentlyCurrently, there are over three thousand claims pending and reservesapproximately 480 lawsuits involving approximately 10,000 claims. Reserves have been established that should be adequate to cover any exposure. Additionally, negotiations continue with insurers to recover more reimbursement, while new coverage is being secured to minimize anticipated future potential exposures. Management believes that loss exposure has been and will continue to be handled success fullysuccessfully so that the ultimate resolution of these matters will not be material, in the aggregate, to itsthe companies' financial position or results of operation.
Employment Litigation (Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
Entergy Corporation and the domestic utility companies are defendants in numerous lawsuits that have been filed by former employees alleging that they were wrongfully terminated and/or discriminated against on the basis of age, race, sex, and/or sex.other protected characteristics. Entergy Corporation and the domestic utility companies are vigorously defending these suits and deny any liability to the plaintiffs. However, no assurance can be given as to the outcome of these cases, and at this time management cannot estimate the total amount of damages sought.
Included in the employment litigation are two cases filed in state court in Claiborne County, Mississippi in December 2002. The two cases were filed by former employees of Entergy Operations who were based at Grand Gulf. Entergy Operations and Entergy employees are named as defendants. The cases make employment-related claims, and seek in total $53 million in alleged actual damages and $168 million in punitive damages. Entergy Operations will vigorously defend these suits and denies any liabilitysubsequently removed both proceedings to the plaintiffs. However, no assurance can be given as tofederal district in Jackson, Mississippi. Entergy cannot predict the ultimate outcome of these cases.this proceeding.
Research Spending
Research
The domestic utility companies are membersEntergy is a member of the Electric Power Research Institute (EPRI). EPRI conducts a broad range of research in major technical fields related to the electric utility industry. Entergy participates in various EPRI projects based on Entergy's needs and available resources. The domestic utility companies contributed $1.6 million in 2004, $1.5 million in 2003, and $2.1 million in 2002 $4 million in 2001, and $4.5 million in 2000 to EPRI.
Earnings Ratios of Domestic Utility Companies and System Energy
The domestic utility companies' and System Energy's ratios of earnings to fixed charges and ratios of earnings to combined fixed charges and preferred dividends pursuant to Item 503 of SEC Regulation S-K are as follows:
Ratios of Earnings to Fixed Charges
Years Ended December 31,
2002 | 2001 | 2000 | 1999 | 1998 | |
Entergy Arkansas | 2.79 | 3.29 | 3.01 | 2.08 | 2.63 |
Entergy Gulf States | 2.49 | 2.36 | 2.60 | 2.18 | 1.40 |
Entergy Louisiana | 3.14 | 2.76 | 3.33 | 3.48 | 3.18 |
Entergy Mississippi | 2.48 | 2.14 | 2.33 | 2.44 | 3.12 |
Entergy New Orleans | (b) | (c) | 2.66 | 3.00 | 2.65 |
System Energy | 3.25 | 2.12 | 2.41 | 1.90 | 2.52 |
Ratios of Earnings to Combined Fixed
Charges and Preferred Dividends
Years Ended December 31,
2002 | 2001 | 2000 | 1999 | 1998 | |
Entergy Arkansas | 2.53 | 2.99 | 2.70 | 1.80 | 2.28 |
Entergy Gulf States (a) | 2.40 | 2.21 | 2.39 | 1.86 | 1.20 |
Entergy Louisiana | 2.86 | 2.51 | 2.93 | 3.09 | 2.75 |
Entergy Mississippi | 2.27 | 1.96 | 2.09 | 2.18 | 2.80 |
Entergy New Orleans | (b) | (c) | 2.43 | 2.74 | 2.41 |
U.S. UTILITY FINANCIAL INFORMATION For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING INFORMATION Operating revenues $6,773,509 $7,432,920 $7,401,598 Operating expenses $5,434,694 $6,050,534 $5,893,631 Other income $ 47,603 $ 69,157 $ 61,119 Interest and other charges $ 465,703 $ 576,705 $ 515,156 Income taxes $ 313,752 $ 300,284 $ 435,667 Net income $ 606,963 $ 574,554 $ 618,263 CASH FLOW INFORMATION Net cash flow provided by operating activities $2,341,161 $ 1,647,969 $ 1,705,370 Net cash flow used in investing activities $ (1,020,087) $(1,243,715) $(1,501,142) Net cash flow provided by (used in) financing activities $ (688,201) $ (303,520) $ 12,702 December 31, 2002 2001 (In Thousands) FINANCIAL POSITION INFORMATION Current assets $ 2,517,001 $ 2,076,437 Other property and investments $ 1,083,221 $ 1,098,555 Property, plant and equipment - net $15,124,077 $15,159,858 Deferred debits and other assets $ 2,354,066 $ 1,974,846 Current liabilities $ 2,479,783 $ 2,136,778 Deferred credits and other liabilities $ 7,658,359 $ 6,285,871 Long-term debt $ 5,542,438 $ 6,007,199 Shareholders' equity $ 5,397,785 $ 5,879,848
Non-Utility Nuclear
Entergy's Non-Utility Nuclear business ownscontributed $3.2 million in 2004 and operates five nuclear power plants$3 million in both 2003 and is primarily focused on selling electric power produced by those plants2002 to wholesale customers. This business also provides operations and management services to nuclear power plants owned by other utilities in the United States. Operations and management services, including decommissioning services, are provided through Entergy's wholly-owned subsidiary, Entergy Nuclear, Inc.
Property
EPRI.
Generating StationsEmployees
Employees are an integral part of Entergy's Non-Utility Nuclear business owns the following nuclear power plants:commitment to serving its customers. As of December 31, 2004, Entergy employed 14,425 people.
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Entergy Arkansas | 1,494 | |
Entergy Gulf States | 1,641 | |
Entergy Louisiana | 943 | |
Entergy Mississippi | 793 | |
Entergy New Orleans | 403 | |
System Energy | - | |
Entergy Operations | 2,735 | |
Entergy Services | 2,704 | |
Entergy Nuclear Operations | 3,245 | |
Other subsidiaries | 277 | |
Total Full-time | 14,235 | |
Part-time | 190 | |
Total Entergy | 14,425 |
Approximately 4,900 employees are represented by the International Brotherhood of Electrical Workers Union, the Utility Workers Union of America, and the International Brotherhood of Teamsters Union.
ENTERGY ARKANSAS, INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
2004 Compared to 2003
Net income increased $16.2 million due to lower other operation and maintenance expenses, a lower effective income tax rate for 2004 compared to 2003, and lower interest charges. The increase was partially offset by lower net revenue.
2003 Compared to 2002
Net income decreased $9.6 million due to lower net revenue, higher depreciation and amortization expenses, and a higher effective income tax rate for 2003 compared to 2002. The decrease was substantially offset by lower other operation and maintenance expenses, higher other income, and lower interest charges.
Net Revenue
2004 Compared to 2003
Net revenue, which is Entergy Arkansas' measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2004 to 2003.
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Interconnections
The Pilgrim and Vermont Yankee plants are dispatched as a part of Independent System Operator (ISO) New England and the James A. FitzPatrick and Indian Point Energy Center plants are dispatched by the New York Independent System Operator (NYISO). The primary purpose of ISO New England is to direct the operations of the major generation and transmission facilities in the New England region and the primary purpose of NYISO is to direct the operations of the major generation and transmission facilities in New York state.
Power Purchase Agreements
Entergy's Non-Utility Nuclear business has entered into unit-contingent power purchase agreements (PPAs), as noted below, with creditworthy counterparties to sell the power produced by its power plants at prices established in the PPAs. Following is a summary of the amount of the Non-Utility Nuclear business' output that is currently sold forward under physical or financial contracts at fixed prices:
2003 | 2004 | 2005 | 2006 | 2007 | ||||||
Non-Utility Nuclear: | ||||||||||
% of planned generation sold forward | 100% | 92% | 25% | 11% | 9% | |||||
Planned generation (GWh) | 33,317 | 33,361 | 34,006 | 34,613 | 34,300 | |||||
Average price per MWh | $37.06 | $38.36 | $35.94 | $31.97 | $31.42 |
Power not sold under PPAs is subject to price fluctuations in the market. Entergy may be required to provide credit support in the form of guarantees in order to secure PPAs.
Fuel Supply
Nuclear Fuel
The requirements for Pilgrim, FitzPatrick, Indian Point 2, Indian Point 3, and Vermont Yankee are pursuant to contracts made by Entergy's Non-Utility Nuclear business. Entergy Nuclear Fuels Company is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for these non-utility nuclear plants.
Other
Research
Entergy's Non-Utility Nuclear business is a member of the Electric Power Research Institute (EPRI). EPRI conducts a broad range of research in major technical fields related to the electric utility industry. Entergy participates in various EPRI projects based on Entergy's needs and available resources. The Non-Utility Nuclear business contributed $3 million in 2002, $0.8 million in 2001, and $0.5 million in 2000 to EPRI.
Services
Entergy Nuclear, Inc. also provides services to other nuclear power plants owners who seek the advantages of Entergy's scale and expertise but do not necessarily want to sell their assets. Services 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. currently provides decommissioning services for the Maine Yankee nuclear power plant and continues to pursue opportunities with other nuclear plant owners through operating agreements or innovative arrangements such as structured leases.
Entergy Nuclear, Inc. also is a party to two business arrangements that assist Entergy Nuclear, Inc. in providing operation and management services. Entergy Nuclear, Inc., in partnership with Framatome ANP, offers operating license renewal and life extension services to nuclear power plants in the United States. Entergy Nuclear Inc., through its subsidiary TLG Services, offers decommissioning, engineering, and related services to nuclear power plant owners.
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's Non-Utility Nuclear business is subject to the NRC's jurisdiction as the owner and operator of Pilgrim, Indian Point Energy Center, FitzPatrick, and Vermont Yankee. Substantial capital expenditures at these nuclear plants because of revised safety requirements of the NRC could be required in the future.
Nuclear Waste Policy Act of 1982
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. Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. After twenty years of study, the DOE, in February 2002, formally recommended, and President Bush approved, Yucca Mountain, Nevada as the permanent spent fuel repository. DOE will now proceed with the licensing and, if the license is granted by the NRC, eventual construction of the repository will begin and receipt of spent fuel may begin as early as approximately 2010. Considerable 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, future expenditures will be required to increase spent fuel storage capacity at Entergy's nuclear pl ant sites. Information concerning spent fuel disposal contracts with the DOE, current on-site storage capacity, and costs of providing additional on-site storage is presented in Note 9 to the consolidated financial statements.
Low-Level Radioactive Waste Policy Act of 1980
The Low-Level Radioactive Waste Policy Act of 1980, as amended, holds each state responsible for disposal of waste originating in that state, but allows states to participate in regional compacts to fulfill their responsibilities jointly. Neither Massachusetts, where Pilgrim is located, nor New York, where Indian Point Energy Center and FitzPatrick are located, participates in any regional compact and efforts to fulfill their responsibilities have been minimal. The state of Vermont, where Vermont Yankee is located, participates in a compact with Maine and Texas. The efforts to develop a disposal facility in the host state of Texas have been minimal during the last several years. Currently the Entergy nuclear stations have disposal access at two waste disposal facilities: the Barnwell facility in South Carolina and the Envirocare facility in Utah. The Barnwell facility is licensed as a 10CFR61 facility and can accept all three classes of low level radwastes (Classes A, B, and C). With South Carolina's a lliance as a member of the Atlantic Compact, disposal access for out-of-region waste generators will be limited at Barnwell. Over the next several years available out-of-region disposal capacity will continue to decrease and in 2008 out-of-region disposal will be prohibited. Currently the Envirocare facility is licensed to accept lower activity radwaste including Class A radioactive wastes. Envirocare has applied for a full service Class B and C license but has decided not to pursue that license at this time.
Nuclear Plant Decommissioning
As part of the Pilgrim, Indian Point 1 and 2, and Vermont Yankee purchases, Boston Edison, Consolidated Edison, and VYNPC, respectively, transferred decommissioning trust funds, along with the liability to decommission the plants, to Entergy. Entergy believes that the decommissioning trust funds will be adequate to cover future decommissioning costs for these plants without any additional deposits to the trusts.
For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liability. NYPA and Entergy executed decommissioning agreements, which specify their decommissioning obligations. NYPA has the right to require Entergy to assume the decommissioning liability provided that it assigns the corresponding decommissioning trust, up to a specified level, to Entergy. If the decommissioning liability is retained by NYPA, Entergy will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. Entergy believes that the amounts available to it under either scenario are sufficient to cover the future decommissioning costs without any additional contributions to the trusts. In conjunction with the Pilgrim acquisition, Entergy received Pilgrim's decommissioning trust fund. Entergy believes that Pilgrim's decommissioning fund will be adequate to cover future decommissioning costs for the plant without any additional deposits to the trust. Subject to decommissioning service agreements between Entergy and NYPA, NYPA retains the decommissioning liability and trusts relating to Indian Point 3 and FitzPatrick up to a specified amount. Entergy believes that the amounts that will be available from the trusts will be sufficient to cover the future decommissioning costs of Indian Point 3 and FitzPatrick without any additional contributions to the trusts. As part of the Indian Point 1 and 2 purchase, Consolidated Edison transferred the decommissioning trust fund and the liability to decommission Indian Point 1 and 2 to Entergy. Entergy also funded an additional $25 million to the decommissioning trust fund and believes that the trust will be adequate to cover future decommissioning costs for Indian Point 1 and 2 without any additional deposits to the trust. Additional information with respect to decommissioning costs for ANO, River Bend, Waterford 3, Grand Gulf 1, Pilgrim, Indian Point 1, Indian Point 2, Indian Point 3, and FitzPatrick is found in Note 9 to the financial statements.
Price Anderson Act
The Price-Anderson Act limits public liability for a single nuclear incident to approximately $9.5 billion. Entergy's Non-Utility Nuclear business has protection with respect to this liability through a combination of private insurance and an industry assessment program, as well as insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units. Insurance applicable to the nuclear programs of Entergy is discussed in Note 9 to the consolidated financial statements.
Nuclear Matters
Groups of concerned citizens and local public officials have raised concerns about safety issues associated with Entergy's Indian Point power plants located in New York. They argue that Indian Point's security measures and emergency plans do not provide reasonable assurance to protect the public health and safety. The NRC has legal jurisdiction over these matters. In a decision that became final on December 13, 2002, the NRC denied a petition filed by Riverkeeper, Inc. asking the NRC to order Entergy to suspend operations, revoke the operating license or adopt other measures, including a temporary shutdown of Indian Point 2 and Indian Point 3. The NRC noted that after September 11, 2001, it ordered enhanced security measures at all nuclear facilities and found that as a result of the collective measures taken since September 11, 2001, the security at Indian Point provides adequate protection of public health and safety. The NRC further found that the existing emergency response plans are flexible enough to respond to a wide variety of adverse conditions, including a terrorist attack, and that the current spent fuel storage system adequately protects the public health and safety. Riverkeeper has petitioned the United States Court of Appeals for the Second Circuit for review of this final action of the NRC. In order to prevail, Riverkeeper must show that the NRC has violated the Atomic Energy Act, abused its discretion, and has completely abdicated its statutory duty regarding this matter. Entergy believes that the action of the NRC was based upon a thorough and thoughtful review of the law and the facts and that the NRC decision will be affirmed by the court.
In addition, certain concerns are being raised regarding the adequacy of the emergency response plans for Indian Point. These matters initially must be reviewed by the Federal Emergency Management Agency ("FEMA"). Jurisdiction as to the overall adequacy of emergency planning and preparedness for Indian Point lies with the NRC. Entergy believes that the emergency response plans for Indian Point are in compliance with NRC requirements and thus adequately protect public health and safety.
A January 2003 consultant's draft report prepared for the State of New York to review emergency preparedness around Indian Point concluded generically that federal emergency planning regulations and guidelines were not adequate to cope with new threats of terrorism. This conclusion was based in part on the view that radiation releases, including those caused by terrorist events, could be faster and larger than those for which the emergency plans were designed. As a result, even if emergency planning for Indian Point were to comply fully with all federal regulations and guidelines, this criticism in the report would stand. There were other plant-specific criticisms in the report. For these reasons, the report concluded that emergency planning for Indian Point is not adequate at this time. In March 2003, a final report was issued which reached similar conclusions. The NRC in reacting to the draft report observed that current emergency plans are already designed to cope with significant radiation releases regardless of cause and stated that it was reviewing the draft report's findings to determine if the emergency plans require modification.
A February 2003, report issued by FEMA Region II evaluated a September 2002 exercise and related activities for the ten-mile emergency planning zone around Indian Point. The report identified no deficiencies with respect to the exercise. The report did conclude that in the absence of corrected and updated state and county plans, FEMA could not provide "reasonable assurance" that appropriate measures can be taken in the event of a radiological emergency. If the state provided this information and a schedule of corrective actions by May 2, 2003, the report stated that FEMA would reevaluate this decision. If corrective actions are not taken, FEMA Region II indicated that (a) it would notify FEMA headquarters that assurance cannot be provided regarding the adequacy of the plans to protect the health and safety of the public and (b) FEMA headquarters would notify the NRC and Governor of New York of the same. The notice from FEMA to the NRC would begin corrective action periods. If corrective action were not taken by the end of these periods, the NRC must determine whether there is reasonable assurance regarding the adequacy of plans to protect the health and safety of the public. If the NRC determines that there is not such assurance, it has the authority to order the Indian Point plants to shut down.
Entergy is interacting with New York state and county officials, FEMA, NRC and other federal agencies to make additional improvements to the emergency response plans that may be warranted and to further assure them as to the adequacy of the plans. Entergy will vigorously oppose all attempts to shut down the Indian Point plants.
The Westchester County Executive announced his proposal to acquire Indian Point by purchase or condemnation and has announced an intention to commission a feasibility study regarding municipalization of Indian Point. At this time, considering the financial and legal impediments that the County would face in implementing this proposal, it is improbable that the County could condemn or municipalize Indian Point.
Environmental Regulation
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act or CWA) 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 CWA requires anyone who wants to discharge pollutants to first obtain an NPDES permit, or else that discharge will be considered illegal. Entergy's Non-Utility Nuclear business is currently in negotiations with EPA for renewal of the Pilgrim NPDES permit, and is in negotiations with the New York environmental authority for renewal of the Indian Point discharge permit issued by New York. It is possible that the environmental authorities will require operating or physical modifications to the plants before renewing the permits. The EPA recently proposed draft regulations for existing power plants, including certain electric generating stations employing once-through cooling technology (the draft Rule). The draft Rule seeks to reduce perceived impacts on aquatic resources by requiring covered facilities to take steps to implement technology or other measures to me et EPA-targeted reductions in water use and corresponding perceived aquatic impacts. While the draft Rule is the subject of extensive comment and also is expected to be challenged (which may result in changes to it prior to final promulgation), Entergy currently has begun and will continue to evaluate the draft Rule, including by considering options for complying with the draft Rule if promulgated in substantially its current form. Those options considered may include operational controls, the installation of equipment to address perceived aquatic impacts, and other mitigation measures, or combinations of these alternatives.
NON-UTILITY NUCLEAR FINANCIAL INFORMATION For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING INFORMATION Operating revenues $ 1,200,238 $ 789,244 $ 298,147 Operating expenses $ 837,429 $ 551,113 $ 211,700 Other income $ 63,672 $ 50,916 $ 27,416 Interest and other charges $ 93,250 $ 81,114 $ 33,213 Income taxes $ 132,726 $ 80,053 $ 31,492 Net income $ 200,505 $ 127,880 $ 49,158 CASH FLOW INFORMATION Net cash flow provided by operating activities $ 281,589 $ 263,476 $ 92,286 Net cash flow used in investing activities $ (438,664) $(1,061,850) $ (65,547) Net cash flow provided by financing activities $ 176,162 $ 292,872 $ 599,827 December 31, 2002 2001 (In Thousands) FINANCIAL POSITION INFORMATION Current assets $ 706,056 $ 475,631 Other property and investments $ 1,437,896 $ 1,164,186 Property, plant and equipment - net $ 1,613,369 $ 1,349,982 Deferred debits and other assets $ 724,987 $ 459,357 Current liabilities $ 947,731 $ 555,797 Deferred credits and other liabilities $ 1,557,144 $ 1,234,750 Long-term debt $ 618,323 $ 688,796 Shareholders' equity $ 1,359,110 $ 969,813
Energy Commodity Services
Entergy's Energy Commodity Services business is focused almost exclusively on providing energy commodity marketing and trading and gas transportation and storage services through Entergy-Koch, L.P. Entergy's non-nuclear wholesale asset business generates electricity to be sold in the wholesale market. Previously, Entergy's Energy Commodity Services business also engaged in power development activities through Entergy Wholesale Operations, but these activities were discontinued in early 2002. Entergy recorded net charges of $428.5 million ($238.3 million net of tax) to operating expenses because of the decision to discontinue additional EWO greenfield power plant development and to reflect asset impairments resulting from the deteriorating economics of wholesale power markets in principally the United States and the United Kingdom. EWO sold its Damhead Creek power plant in the UK and its interests in Latin American projects during 2002.
Entergy-Koch, LP
Entergy-Koch is a venture between subsidiaries of Entergy and Koch Industries, Inc. Entergy-Koch launched on February 1, 2001, and is a 50-50 limited partnership with about 700 employees and $1 billion in assets. Entergy contributed most of the assets and trading contracts of its power marketing and trading business and $414 million cash to the venture and Koch contributed its 8,025-mile Koch Gateway Pipeline (renamed Gulf South Pipeline), gas storage facilities, and Koch Energy Trading, which marketed and traded electricity, gas, weather derivatives, and other energy-related commodities and services.
Entergy-Koch is engaged in two major businesses: energy commodity trading which includes power, gas, weather derivatives, emissions, and cross-commodities through Entergy-Koch Trading; and gas transportation and storage through the Gulf South Pipeline. Each of these businesses contributes from 40-60% of Entergy-Koch's earnings. Entergy-Koch has attained the following credit ratings: an "A" rating from Standard and Poor's and an "A3" rating from Moody's Investors Service.
Entergy-Koch Trading
Entergy-Koch Trading buys and sells natural gas, power, and other energy-related services and commodities, such as weather derivatives, in the United States, the United Kingdom, Western Europe, and Canada. It provides energy management services using knowledge systems that promote fundamental and quantitative understanding of market risk. Entergy-Koch Trading uses advanced analytics and knowledge of the marketplace, natural gas pipelines, power transmission infrastructure, transportation management, gas storage, and weather.
Gulf South Pipeline
Gulf South Pipeline owns and operates an interstate natural gas pipeline system in the Gulf Coast region and provides critical links to many major markets nationwide. Gulf South Pipeline gathers natural gas from the Gulf South region and transports it to local distribution companies, industrial facilities, power generators, utility companies, other pipelines, and natural gas marketing companies. The Gulf South Pipeline's existing system comprises 8,025 miles of pipeline (6,875 transmission, 1,150 gathering) with connections to more than 100 pipelines including Texas Eastern, Transco and Florida Gas Transmission. The pipeline system covers parts of Texas, Louisiana, Mississippi, Alabama, and Florida and connects to the Henry Hub, located in Vermilion Parish, Louisiana.
Gulf South's operational flexibility is enhanced by its Bistineau and Jackson storage facilities with total working storage capacity of 68.5 Bcf. Additionally, Gulf South Pipeline is developing a natural gas salt dome storage facility - Magnolia Gas Storage located near Napoleanville, Louisiana. This new facility, expected to be in service by early 2004, complements the existing storage at Bistineau and Jackson, and offers multiple pipeline interconnects providing increased reliability for customers and opportunities for Gulf South to improve gas flows across its system. The facility will have an initial working capacity of approximately 4.1 Bcf and will be expanded to 6.5 Bcf in 2007.
Entergy-Koch, LP Agreement Details
Although the ownership interests of Entergy and Koch Industries are equal, the capital accounts are different. As described above, each contributed different assets to the partnership with those contributed by Koch valued at more than those contributed by Entergy. Through the end of 2003, substantially all of the partnership profits are allocated to Entergy to allow the capital accounts to equalize. The capital accounts are expected to be equal in 2004 as a result of this disproportionate sharing of income. In all years, losses and distributions from operations are allocated equally to the capital accounts based on ownership interest.
In the partnership agreement, Entergy agreed to contribute $72.7 million to the partnership in January 2004. Koch also will receive a distribution of $72.7 million in 2004. In addition, at that time, Entergy-Koch's assets will be revalued for capital account purposes. If the value of the assets exceeds their carrying value for capital account purposes, then that difference will be allocated to the capital accounts. Entergy expects that after this revaluation the capital accounts of Entergy and Koch Industries will be approximately equal and that future profit allocations other than for weather trading and international trading will be equal. If the capital accounts differ significantly, however, then profits may be allocated disproportionately to one partner or the other until the capital accounts are approximately equal.
The partnership agreement provides that losses are allocated between the capital accounts of the partners based on ownership interest. Distributions from operations are shared based on ownership interest and distributions in the event of liquidation are shared based on capital accounts, as revalued at the time of the liquidation. Prior to 2004, a partner may transfer its partnership interest only with the consent of the other partner. Beginning in 2004, a partner may transfer its interest to a third party, only if it has first offered to sell its interest to the other partner at the approximate sales price and the other partner has not accepted the offer. Certain buy/sell rights are triggered (a) at the option of the non-defaulting partner, upon a change of control of, or material breach of the agreement by, either partner or (b) at the option of either partner, at any time beginning in 2004. Under the buy/sell rights, the initiating partner offers to sell all its partnership interest at a specified pri ce and other terms or to buy all of the other partner's partnership interest at the same price and same other terms.
Non-Nuclear Wholesale Asset Business
Property
Generating Stations
The capacity of the generating stations owned in Entergy's non-nuclear wholesale asset business as of December 31, 2002 is indicated below:
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(1) "Owned Capacity" refersDeferred fuel cost revisions includes the difference between the estimated deferred fuel expense and the actual calculation of recoverable fuel expense, which occurs on an annual basis. Deferred fuel cost revisions decreased net revenue due to a revised estimate of fuel costs filed for recovery at Entergy Arkansas in the nameplate rating on the generating unit.
(2)March 2004 energy cost recovery rider, which reduced net revenue by $11.5 million. The owned MW capacity is the portionremainder of the plant capacity owned by Entergy. For a complete listing of Entergy's joint-owned generating stations, refer to "Jointly-Owned Generating Stations" in Note 1 to the Entergy Corporation and Subsidiaries financial statements.
Entergy's non-nuclear wholesale asset businessvariance is currently constructing a 550 MW combined-cycle gas turbine power plant in Harrison County, Texas. Entergy will own approximately 385 MW once construction is completed and operation has begun (currently projected to be June 2003), with Northeast Texas Electric Cooperative, Inc. owning the remainder.
Following is a summary of the amount of Energy Commodity Services' output that is currently sold forward under physical or financial contracts at fixed prices:
2003 | 2004 | 2005 | 2006 | 2007 | |||||
Energy Commodity Services: | |||||||||
% of planned generation sold forward | 38% | 18% | 22% | 19% | 21% | ||||
Planned generation (GWh) | 3,124 | 3,249 | 3,820 | 3,494 | 3,618 | ||||
Contracted spark spread per MWh | $11.70 | $10.63 | $10.62 | $9.69 | $9.68 |
Litigation
Power Generation Mexico, Inc. Lawsuit
In May 2001, Power Generation Mexico, Inc. (PGI) filed suit against Entergy Power Development Corporation (EPDC), Entergy Power Netherlands Company, B.V., and Entergy Corporation in the San Francisco Superior Court. In December 2001, PGI filed a First Amended Complaint. PGI asserts that EPDC agreed to develop several power projects and to receive certain fees and equity interest for its efforts, and that EPDC failed to fulfill its obligations and deliberately frustrated development of the projects, all to PGI's detriment. PGI seeks general compensatory, consequential, incidental, and punitive damages in excess of $10 million. Entergy has filed motions that, if successful, will limit the number of defendants and claims, as well as the type of damages that could be recovered. Entergy is vigorously defending this suit and denies any liability to the plaintiff. However, no assurance can be given as to the ultimate outcome of this suit.
ENERGY COMMODITY SERVICES FINANCIAL INFORMATION For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING INFORMATION Operating revenues $ 294,670 $ 1,370,485 $ 2,353,792 Operating expenses $ 769,834 $ 1,323,371 $ 2,377,316 Other income $ 249,678 $ 208,271 $ 99,396 Interest and other charges $ 61,632 $ 74,953 $ (3,725) Income taxes $ (141,288) $ 74,493 $ 24,689 Net income $ (145,830) $ 105,939 $ 54,908 CASH FLOW INFORMATION Net cash flow provided by (used in) operating activities $ (3,714) $ (127,938) $ 64,292 Net cash flow provided by (used in) investing activities $ (760) $ 138,351 $ (547,024) Net cash flow provided by (used in) financing activities $ (66,151) $ (148,501) $ 538,948 December 31, 2002 2001 (In Thousands) FINANCIAL POSITION INFORMATION Current assets $ 504,836 $ 442,667 Other property and investments $ 1,175,842 $ 982,628 Property, plant and equipment - net $ 429,677 $ 749,661 Deferred debits and other assets $ 57,117 $ 202,777 Current liabilities $ 348,200 $ 225,865 Deferred credits and other liabilities $ 11,782 $ 257,264 Long-term debt $ 79,029 $ 671,668 Shareholders' equity $ 1,728,461 $ 1,222,936
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Operating Income
2002 Compared to 2001
Operating income decreased by $77.5 million primarily due to the following:
Gross operating revenues, fuel and purchased power expenses, by $62.7and other regulatory credits
Gross operating revenues increased primarily due to:
Other operation and maintenance expenses increased in 2002gross wholesale revenue primarily due to:
Fuel and purchased power expenses increased primarily due to increased recovery of deferred fuel and purchased power costs primarily due to an increase in April 2004 in the energy cost recovery rider and the true-ups to the 2003 and 2002 energy cost recovery rider filings.
Other regulatory credits decreased primarily due to the over-recovery of Grand Gulf costs due to an increase in the Grand Gulf rider effective January 2004.
2003 Compared to 2002
Net revenue, which is Entergy Arkansas' measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2003 to 2002.
(In Millions) | ||
2002 net revenue | $1,095.9 | |
March 2002 settlement agreement | (154.0) | |
Volume/weather | (7.7) | |
Asset retirement obligation | 30.1 | |
Net wholesale revenue | 16.6 | |
Deferred fuel cost revisions | 10.2 | |
Other | 7.6 | |
2003 net revenue | $998.7 |
The March 2002 settlement agreement resolved a request for recovery of ice storm costs incurred in December 2000 with an offset of those costs for funds contributed to pay for future stranded costs. A 1997 settlement provided for the collection of earnings in excess of an 11% return on equity in a transition cost account (TCA) to offset stranded costs if retail open access were implemented.
In mid- and late December 2000, two separate ice storms left 226,000 and 212,500 Entergy Arkansas customers, respectively, without electric power in its service area. Entergy Arkansas filed a proposal to recover costs plus carrying charges associated with power restoration caused by the ice storms. Entergy Arkansas' final storm damage cost determination reflected costs of approximately $195 million. The APSC approved a settlement agreement submitted in March 2002 by Entergy Arkansas, the APSC staff, and the Arkansas Attorney General. In the March 2002 settlement, the parties agreed that $153 million of the ice storm costs would be classified as incremental ice storm expenses that can be offset against the TCA on a rate class basis, and any excess of ice storm costs over the amount available in the TCA would be deferred and amortized over 30 years, although such excess costs were not allowed to be included as a separate component of rate base. The a llocated ice storm expenses exceeded the available TCA funds by $15.8 million which was recorded as a regulatory asset in June 2002. In accordance with the settlement agreement and following the APSC's approval of the 2001 earnings review related to the TCA, Entergy Arkansas filed to return $18.1 million of the TCA to certain large general service class customers that paid more into the TCA than their allocation of storm costs. The APSC approved the return of funds to the large general service customer class in the form of refund checks in August 2002. As part of the implementation of the March 2002 settlement agreement provisions, the TCA procedure ceased with the 2001 earnings evaluation.
Of the remaining ice storm costs, $32.2 million was addressed through established ratemaking procedures, including $22.2 million classified as capital additions, while $3.8 million of the ice storm costs was not recovered through rates.
The effect on net income of the March 2002 settlement agreement and 2001 earnings review allowingwas a $2.2 million increase in 2003, because the decrease in net revenue was offset by the decrease in operation and maintenance expenses discussed below.
The volume/weather variance is the result of less favorable sales volume primarily due to the effect of colder winter weather in December 2002.
The asset retirement obligation variance was due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," adopted in January 2003. See "Critical Accounting Estimates" for more details on SFAS 143. The increase was offset by an increase in decommissioning expense and has no effect on net income.
The net wholesale revenue variance was primarily due to an increase in sales volume to Entergy New Orleans pursuant to a purchased power agreement and also due to higher wholesale prices and volume.
Deferred fuel cost revisions includes the difference between the estimated deferred fuel expense and the actual calculation of recoverable fuel expense, which occurs on an annual basis. In 2002, the deferred fuel expense estimate was larger than the actual recoverable fuel expense, which decreased net revenue. In 2003, the actual recoverable fuel expense was larger than the deferred fuel expense estimate, which increased net revenue.
Gross operating revenues, fuel and purchased power expenses, and other regulatory credits
Gross operating revenues increased primarily due to an increase of $95.7 million in gross wholesale revenue due to the same factors discussed above that increased net wholesale revenue and also due to increased sales to affiliates in addition to the Entergy New Orleans sales mentioned above. The increase was partially offset by a decrease of $74.4 million in fuel cost recovery revenues due to a decrease in the annual recovery rider in October 2002.
Fuel and purchased power expenses decreased primarily due to the displacement of higher-priced natural gas generation by lower-priced purchased power and coal generation.
Other regulatory credits decreased primarily due to the March 2002 settlement agreement and 2001 earnings review mentioned above, which increased other regulatory credits in 2002 to offset $159.9 million in other operation and maintenance expenses related to the December 2000 ice storms. The decrease was partially offset by the asset retirement obligation mentioned above, which increased regulatory credits in 2003 to offset the increase in decommissioning expense.
Other Income Statement Variances
2004 Compared to 2003
Other operation and maintenance expenses decreased primarily due to voluntary severance accruals of $31.8 million in 2003. The decrease was partially offset by the following:
Interest charges decreased primarily due to the refinancing of First Mortgage Bonds in mid-2003.
2003 Compared to 2002
Other operation and maintenance expenses decreased primarily due to expenses in 2002 of $159.9 million due to the March 2002 settlement agreement and 2001 earnings review which allowed Entergy Arkansas to recover a large majority of 2000 and 2001 ice storm repair expenses through the previously-collected transition cost account amounts (offset(which was offset by a corresponding decrease in other regulatory credits as discussed above);
decrease. The increase in other operation and maintenance expensesdecrease was partially offset by a $16the following:
Decommissioning expense increased due to turbine refurbishing costs expensedthe implementation of SFAS 143, "Accounting for Asset Retirement Obligations." The increase in 2001 at a plant after its lease expired.decommissioning expense was offset by increases in other regulatory credits and interest and dividend income and has no effect on net income.
The March 2002 settlement agreement is discussed further in Note 2 to the domestic utility companiesDepreciation and System Energy financial statements.
2001 Compared to 2000
Operating incomeamortization expenses increased by $69.7 million primarily due to the following:
Thean increase in operatingplant in service.
Other income was partially offset by:
increased primarily due to:
Other operation and maintenance expenses decreased in 2001 primarily due to:
The decrease in other operation and maintenance expenses was partially offset by a $16 million increase due to the payment of turbine refurbishing costs discussed above.
The December 2000 ice storms are discussed in more detail in Note 2 to the domestic utility companies and System Energy financial statements.
Other Impacts on Earnings
2002 Compared to 2001
Other income decreased in 2002 primarily due to a decrease in interest income of $7.1 million recorded on the deferred fuel balance due to the balance shifting from an asset to a liability in 2002.
Interest charges decreased in 2002 primarily due to:
2001 Compared to 2000
Other income decreased in 2001 primarily due to a decrease in the allowance for equity funds used during construction due to a loweran increase in construction work in progress balance during 2001 compared to the same period in 2000. The construction balance was lower because the ANO 2 replacement steam generators were placed in service in late 2000.
Interest charges increased in 2001decreased primarily due to:
Other Income Statement Variances
2002 Compared to 2001
Fuel cost recovery revenue decreased in 2002 due to decreases in the annual recovery rider in April and again in October (refer to Note 2 to the domestic utility companies and System Energy financial statements for further discussion). Corresponding to the decrease in fuel cost recovery revenue, fuel and purchased power expenses also decreased.
2001 Compared to 2000
Fuel cost recovery revenue increased in 2001 due to increases in the annual recovery rider in April 2000 and April 2001. Fuel and purchased power expenses increased (excluding the aforementioned System Energy refund) consistent with the increase in fuel cost recovery revenue.
Other regulatory credits decreased in 2001 primarily due to:
Income Taxes
The effective income tax rates for 2004, 2003, and 2002 2001, and 2000 were 34.5%38.5%, 37.3%45.5%, and 42.3%34.5%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate. The lower effective income tax rate in 2004 compared to 2003 was primarily due to book and tax differences related to utility plant items and flow-through items. Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2002, 2001,2004, 2003, and 20002002 were as follows:
2002 | 2001 | 2000 | ||||
(In Thousands) | ||||||
Cash and cash equivalents at beginning of period | $ 103,466 | $ 7,838 | $ 6,862 | |||
Cash flow provided by (used in): | ||||||
Operating activities | 357,421 | 413,178 | 421,560 | |||
Investing activities | (249,438) | (326,602) | (467,454) | |||
Financing activities | (115,936) | 9,052 | 46,870 | |||
Net increase (decrease) in cash and cash equivalents | (7,953) | 95,628 | 976 | |||
Cash and cash equivalents at end of period | $ 95,513 | $ 103,466 | $ 7,838 |
2004 | 2003 | 2002 | |||||
(In Thousands) | |||||||
Cash and cash equivalents at beginning of period | $8,834 | $95,513 | $103,466 | ||||
Cash flow provided by (used in): | |||||||
Operating activities | 446,298 | 437,520 | 357,421 | ||||
Investing activities | (269,385) | (337,509) | (249,438) | ||||
Financing activities | (96,003) | (186,690) | (115,936) | ||||
Net increase (decrease) in cash and cash equivalents | 80,910 | (86,679) | (7,953) | ||||
Cash and cash equivalents at end of period | $89,744 | $8,834 | $95,513 |
Operating Activities
Cash flow from operations decreasedincreased $8.8 million in 20022004 compared to 20012003 primarily due to income tax benefits received in 2004, and increased recovery of deferred fuel costs. This increase was substantially offset by money pool activity.
In 2003, the domestic utility companies and System Energy filed, with the IRS, a decreasechange in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $1.171 billion deduction for Entergy Arkansas on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004, Entergy Arkansas realized $173 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. As of December 31, 2004, Entergy Arkansas has a net operating loss (NOL) carryforward for tax purposes of $766.9 million, principally resulting from the change in tax accounting method related to cost of goods sold. If the tax accounting method change is sustained, Entergy Arkansas expects to utilize the NOL carryforward through 2006.
Cash flow from operations increased $80.1 million in 2003 compared to 2002 primarily due to income as explained above.taxes paid of $2.2 million in 2003 compared to income taxes paid of $83.9 million in 2002, and money pool activity. This increase was partially offset by decreased recovery of deferred fuel costs in 2003.
Entergy Arkansas' receivablereceivables from or (payables) to(payables to) the money pool were as follows as of December 31 for each of the following years:
2004 | 2003 | 2002 | 2001 | |||
(In Thousands) | ||||||
$23,561 | ($69,153) | $4,279 | $23,794 |
2002 | 2001 | 2000 | 1999 | ||||
(In Thousands) | |||||||
$4,279 | $23,794 | ($30,719) | ($40,622) |
Money pool activity increasedused $92.7 million of Entergy Arkansas' operating cash flows byflow in 2004, provided $73.4 million in 2003, and provided $19.5 million in 2002. In 2001, money pool activity decreased Entergy Arkansas' operating cash flows by $54.5 million. Money pool activity decreased Entergy Arkansas' operating cash flows by $9.9 million in 2000. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.
Investing Activities
The decrease of $68.1 million in net cash used in investing activities in 2002 was primarily due2004 compared to the maturity of $38.4 million of other temporary investments.
The decrease in net cash used in investing activities in 20012003 was primarily due to a decrease in construction expenditures of $88.6 million and the recovery of $93.8 million of other regulatory investments (deferred fuel costs). Construction expenditures decreased primarily due to ANO Unit 2 steam generator replacement costs being incurredresulting from less transmission upgrade work requested by merchant generators in 2000. The decrease was partially offset by other temporary investments of $38.4 million made2004 combined with lower spending on customer support projects in 2001.
Financing Activities2004.
Entergy Arkansas used cash in financing activities in 2002 compared to providing a small amount of cash in 2001 primarily due to anThe increase of $43.4$88.1 million in common stock dividends paid to Entergy Corporation. Entergy Arkansas had a net issuance of $18.4 million of long-term debt in 2002 compared to a net issuance of $97.4 million in 2001 that also contributed to the decrease in net cash provided.
The decreaseused in net cash provided by financinginvesting activities in 20012003 compared to 2002 was primarily due to an increase in construction expenditures of $37.9$57.4 million and the maturity of $38.4 million of other temporary investments in the first quarter of 2002. Construction expenditures increased in 2003 primarily due to the following:
Financing Activities
The decrease of $90.7 million in net cash used in financing activities in 2004 compared to 2003 was primarily due to the net redemption of $2.4 million of long-term debt in 2004 compared to $109.3 million in 2003, partially offset by the payment of $16.2 million more in common stock dividends paidduring the same period.
The increase of $70.8 million in net cash used in financing activities in 2003 compared to Entergy Corporation.2002 was primarily due to the net redemption of $109.3 million of long-term debt in 2003 compared to the net issuance of $18.4 million in 2002, partially offset by the payment of $56.3 million less in common stock dividends during the same period.
See Note 75 to the domestic utility companies and System Energy financial statements for details on long-term debt.
Uses of Capital
Entergy Arkansas requires capital resources for:
Following are the amounts of Entergy Arkansas' planned construction and other capital investments, existing debt and lease obligations, and other purchase obligations:
|
| 2005 |
| 2006-2007 |
| 2008-2009 |
| after 2009 |
| Total |
|
| (In Millions) | ||||||||
Planned construction and |
|
|
|
|
|
|
|
|
|
|
capital investment (1) |
| $321 |
| $455 |
| N/A |
| N/A |
| $776 |
Long-term debt |
| $147 |
| $- |
| $1 |
| $1,191 |
| $1,339 |
Capital lease payments |
| $10 |
| $9 |
| $2 |
| $2 |
| $23 |
Operating leases |
| $24 |
| $38 |
| $23 |
| $54 |
| $139 |
Purchase obligations (2) |
| $433 |
| $832 |
| $827 |
| $2,840 |
| $4,932 |
Nuclear fuel lease obligations (3) |
| $42 |
| $52 |
| N/A |
| N/A |
| $94 |
2003 | 2004 | 2005 | 2006-2007 | after 2007 | |||||
(In Millions) | |||||||||
Planned construction and | |||||||||
capital investment | $283 | $286 | $315 | N/A | N/A | ||||
Long-term debt maturities | $255 | $- | $262 | $100 | $763 | ||||
Capital and operating lease payments | $28 | $28 | $25 | $31 | $58 | ||||
Unconditional fuel and purchased | |||||||||
power obligations | $380 | $382 | $383 | $775 | $3,631 | ||||
Nuclear fuel lease obligations (1) | $53 | $35 | N/A | N/A | N/A |
(1) | Includes approximately $175 to $180 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. |
(2) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Arkansas almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the domestic utility companies and System Energy financial statements. |
(3) |
|
In addition to acquire additional fuel,these contractual obligations, Entergy Arkansas expects to pay interest,contribute $20.6 million to its pension plans and $16.1 million to pay maturing debt. If such additional financing cannot be arranged, however, the lesseeother postretirement plans in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations.
2005.
On July 25, 2002, the Board authorized Entergy Arkansas and Entergy Operations to replace the ANO 1 steam generatorgenerators and reactor vessel closure head. Entergy management estimates the cost of the fabrication and replacement to be approximately $235 million, of which approximately $135$96 million willhas been incurred through 2004. $115 million is expected to be incurred through 2004.in 2005, with the remainder of the costs expected in 2006. Management expects that the replacement will occur during a planned refueling outage in 2005. Entergy Arkansas filed with the APSC in January 2003 a request for a declaratory order by the APSC that the investment in the replacement is in the public interestinterest. The APSC issued the requested order in May 2003. This order is analogous to the order received in 1998 prior to the replacement of the ANO 2 steam generator for ANO 2. Receipt of an order relating to the replacement at ANO 1 would provide additional support for the inclusion of these costs in a future general rate case, however, management cannot predict the outcome of either the request for a declaratory order or a general rate proceeding.generators. See "Nuclear Matters"''Nuclear Matters'' below for further discussion of the replacement of the ANO 1 st eamsteam generators and reactor vessel closure head.
In addition to the steam generatorgenerators and reactor vessel closure head replacement, the planned capital investment estimate for Entergy Arkansas also reflects capital required to support existing business and customer growth. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, market volatility, economic trends, environmental compliance, and the ability to access capital. Management provides more information on construction expenditures and long-term debt and preferred stock maturities in Notes 5 6, 7, and 96 to the domestic utility companies and System Energy financial statements.
As a wholly-owned subsidiary, Entergy Arkansas pays dividends its earnings to Entergy Corporation from its earnings at a percentage determined monthly. Entergy Arkansas is restricted byArkansas' long-term debt indentures inrestrict 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, 2002,2004, Entergy Arkansas had restricted retained earnings unavailable for distribution to Entergy Corporation of $296.1$394.9 million.
Sources of Capital
Entergy Arkansas' sources to meet its capital requirements include:
In 2002, Entergy Arkansas issued $200 million of long-term debt andfirst mortgage bonds in 2004 as follows:
Issue Date | Description | Maturity | Amount | |||
(In Thousands) | ||||||
October 2004 | 6.38% Series | November 2034 | $60,000 |
The proceeds were used the net proceeds to redeem outstanding debt of $85 million in 2002 and $100 million in 2003. The 2003 redemption occurred at maturity. junior subordinated debentures as follows:
Retirement Date |
|
|
| |||
(In Thousands) | ||||||
November 2004 | 8.50% Series | September 2045 | $61,856 |
Entergy Arkansas is expected to continue refinancingmay refinance or redeeming higher-costredeem 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 corporate charters, bond indentures, and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Short-term borrowings by Entergy Arkansas, including borrowings under the money pool, are limited to an amount authorized by the SEC, which is $235 million. Under theits SEC order authorizing the short-term borrowing limits,Order and without further authorization, Entergy Arkansas cannot incur newadditional short-term indebtedness if itsunless (a) it and Entergy Corporation maintain a common equity would comprise less thanratio of at least 30% and (b) with the exception of its capital.money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy Arkansas, has a 364-day credit facility available with an expiration dateas well as all outstanding securities of May 2003 in the amount of $63 million, of which none was drawn at December 31, 2002.Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Arkansas' short-term borrowing limits.
Significant Factors and Known Trends
Utility Restructuring
Major changes are occurring in the wholesale and retail electric utility business, including in the electric transmission business. In April 1999, the Arkansas legislature enacted Act 1556, the Arkansas Electric Consumer Choice Act, providing for competition in the electric utility industry through retail open access. In December 2001, the APSC recommended to the Arkansas General Assembly that legislation be enacted during the 2003 legislative session to either repeal Act 1556 or further delay retail open access until at least 2010. In February 2003, the Arkansas legislature voted to repeal Act 1556 and the repeal was signed into law by the governor.
At FERC, the pace of restructuring at the wholesale level has begun but has been delayed. It is too early to predict the ultimate effects of changes in U.S. energy markets. Restructuring issues are complex and are continually affected by events at the national, regional, state, and local levels. However, these changes may result, in the long-term,long term, in fundamental changes in the way traditional integrated utilities and holding company systems, like the Entergy system, conduct their business. Some of these changes may be positive for Entergy, while others may not be.
not.
System Agreement Proceedings
The System Agreement provides fordomestic utility companies historically have engaged in the integratedcoordinated planning, construction, and operation of Entergy's electric generationgenerating and transmission assets throughoutfacilities under the retail service territoriesterms of an agreement called the System Agreement that has been approved by the FERC. Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies. Under the termscompanies in their execution of the System Agreement, generating capacity and other power resources are jointly operated by the domestic utility companies. Theseek support for local regulatory authority over System Agreement provides, among other things,issues. Regarding the proceeding at the LPSC, Entergy believes that parties having generating reserves greater than their load requirements (long companies) shall receive paymentsstate and local regulators are preempted by federal law from those parties having deficiencies in generating reserves (short companies). Such payments are at amounts sufficient to cover certain of the long companies' costs for intermediatereviewing and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred and preference stock, and a fair rate of return on common equity investment. Under thedeciding System Agreement these charges are based on costs associated with the long companies' steam electric generating units fueled by oil or gas. In addition,issues for all energy exchanged among the domestic utility companies under the System Agreement, the short companies are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
The LPSC and the Council commenced a proceeding at FERC in June 2001. In this proceeding,themselves. An unrelated case between the LPSC and Entergy Louisiana raised the Council allegequestion of whether a state regulator is preempted by federal law from reviewing and interpreting F ERC rate schedules that the rough production cost equalization required by FERC underare part of the System Agreement, and the Unit Power Sales Agreement has been disrupted by changed circumstances.from subsequently enforcing that interpretation. The LPSC and the Council have requested that FERC amend theinterpreted a System Agreement or the Unit Power Sales Agreement or both to achieve full production cost equalization or to restore rough production cost equalization. Their complaint does not seek a changerate schedule in the total amount ofunrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed the costs allocated by eitherLPSC's decision. In 2003, the System Agreement orU.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the Unit Power Sales Agreement. In addition, the LPSC and the Council allege that provisions of the System Agreement relating to minimum run and must run units, the methodology of billing versus dispatch, and the use of a rolling twelve-month average of system peaks, increase costs paid by ratepayers in the LPSC and Council's jurisdictions. Several parties have filed interventions in the proceed ing, including the APSC and the MPSC. Entergy filed its response to the complaint in July 2001 denying the allegationsdecisions of the LPSC and the Council.Louisiana Supreme Court.
In February 2004, a FERC ALJ issued an Initial Decision in the LPSC-initiated proceeding at the FERC. The APSC and the MPSC also filed responses opposingInitial Decision decided some issues in favor of the relief sought by the LPSC, and decided some issues against the Council.
In their complaint,relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the Council allegeFERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Arkansas' annualLouisiana's production costs over the period 2002 to 2007 will be $130 million to $278 million under the average for the domestic utility companies. This rangepurposes of results is a function of assumptions regarding such things as future natural gas prices, the future market price of electricity, and other factors. In February 2002, the FERC set the matter for hearing and established a refund effective period consisting of the 15 months following September 13, 2001. Negotiations among the parties have not resolved the proceeding,calculating relative production costs; and the proceeding is now set for hearing commencing in June 2003. The case had been set for trial commencing in February 2003. The extensionInitial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the schedule also extendedcurrent method.
If the refund effective period by 120 days. If FERC grants the relief requested by the LPSC andin the Council,proceeding, the relief may result in a material increase in the total production costs allocatedthe FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs allocatedthe FERC allocates to companies whose costs currently are projected to exceed that average. If the average. FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility compan ies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.
An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu duri ng the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:
| Average Annual | ||
(In Millions) | (In Millions) | ||
Entergy Arkansas | $154 to $281 | $215 | |
Entergy Gulf States | ($130) to ($15) | ($63) | |
Entergy Louisiana | ($199) to ($98) | ($141) | |
Entergy Mississippi | ($16) to $8 | $1 | |
Entergy New Orleans | ($17) to ($5) | ($12) |
Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. Therefore, managementThe timing of recovery of these costs in rates could be the subject of additional proceedings at the APSC and elsewhere, however, and a delay in full recovery of any increased allocation of production costs could result in additional financing requirements. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy Arkansas does not believe that this proceedingthe ultimate resolution of these proceedings will have a material effect on theits financial condition or results of operation.
In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC ALJ's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas although neitheror the timing norAPSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the ALJ's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; an d states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate.
In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the ALJ's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations.
In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Louisiana, as well as t he named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity.
Transmission
In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs.
In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations.
Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences.
In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the proceedingspetition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005.
In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion o f the proposal currently scheduled for August 2005.
Interconnection Orders
The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC canin which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos, including $42 million for Entergy Arkansas. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy. To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to ha ve these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators.
Available Flowgate Capacity Proceeding
On December 17, 2004, the FERC issued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised in a FERC audit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC program, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory.
Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy.
Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time.
A hearing in the AFC proceeding is currently scheduled to commence in August 2005.
Market and Credit Risks
Entergy Arkansas has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.
Interest Rate and Equity Price Risk - Decommissioning Trust Funds
Entergy Arkansas' nuclear decommissioning trust funds are exposed to fluctuations in equity prices and interest rates. The NRC requires Entergy Arkansas to maintain trusts to fund the costs of decommissioning ANO 1 and ANO 2. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the ANO trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 912 to the domestic utility companies and System Energy financial statements.
State and Local Rate Regulatory Risks
The rates that Entergy Arkansas charges for its services are an important item influencing Entergy Arkansas' financial position, results of operations, and liquidity. Entergy Arkansas is closely regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the APSC, is primarily responsible for approval of the rates charged to customers. In addition to rate proceedings, Entergy Arkansas' fuel costs recovered from customers are also subject to regulatory scrutiny.
Entergy Arkansas' retail rate matters and proceedings, including fuel cost recovery-related issues, are discussed more thoroughly in Refer to Note 2 to the domestic utility companies and System Energy financial statements.
statements for fuel recovery and retail rate proceedings.
Nuclear Matters
Entergy Arkansas owns and operates, through an affiliate, the ANO 1 and 2.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, 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 August 2001, the NRC issued a bulletin requesting all pressurized water reactor owners and operators to report on the structural integrity of their reactor vessel head penetration nozzles to justify continued operations past December 31, 2001. These types of reactors are susceptible to water stress corrosion cracking of the reactor vessel head nozzles. ANO 1 and ANO 2 are pressurized water reactors. In March 2001, an inspection of ANO 1 revealed one leaking control rod drive mechanism nozzle, which was subsequently repaired. During a planned refueling outage that began in October 2002, visual inspection of the reactor vessel head at ANO 1 revealed one nozzle leak. Further ultrasonic testing showed the presence of seven additional minor indications that could potentially develop into leaks. Entergy Arkansas made repairs during the outage. Entergy Arkansas has received favorable responses from th e NRC for continued operations of ANO 1 and 2.
Inspections of the ANO 1 steam generators during planned outages also have revealed cracks in certain steam generator tubes, which have been repaired or plugged. The current number of cracks is below the limit authorized by the NRC to allow the unit to remain in operation and has not affected ANO 1's output to date. Using current projections of steam generator tube plugging, the current best estimate is that replacement of the ANO Unit 1 steam generators will be required by 2013. Entergy Operations currently does not expect ANO Unit 1 to have to conduct mid-cycle outages for steam generator inspection before 2005. ANO 2's steam generator was replaced during a refueling outage in the second half of 2000.
In December 2001, Entergy issued a Requestrequest for Proposal ("RFP")proposal to provide replacement steam generators"generators for ANO 1. Two companies submitted bids in response to the RFP. Entergy subsequently entered a contract with one of the companies for delivery of the replacement generators in August 2005 in time for installation during athe scheduled refueling outage beginningoutage. Both the new steam generators and the reactor vessel head will be installed in Septemberthe fall of 2005. The other companyTo date, there has been no primary side stress corrosion cracking identified in the ANO 2 reactor vessel head. Inspections of the ANO 2 reactor vessel head will continue during planned refueling outages.
Entergy Arkansas filed with the APSC in January 2003 a suit in federal district court in Virginia seekingrequest for a temporary and permanent injunction against winning bidder claimingdeclaratory order that the winning bidder was using the other company's proprietary informationinvestment in the design and fabrication ofreplacement is in the replacement generators.public interest. The preliminary injunction hearing was conductedAPSC issued the requested order in October 2002 andMay 2003. This order is analogous to the court granted the temporary injunction, subject to adequate bond being posted, on February 13, 2003.
The two companies have agreed to jointly move the district court to modify its order granting the preliminary injunction to provide that the injunction is stayed and shall not take effect until 30 days following a decision of the Fourth Circuit Court of Appeals affirming the injunction, assuming such an affirmance is granted. The parties also agreed to request expedited handling of the appeal by the court of appeals. Should the other company prevail on this appeal and no settlement is reached between the two companiesreceived in 1998 prior to the issuancereplacement of the temporary injunction, the installation of theANO 2 steam generators at ANO 1 may be delayed until a 2007 scheduled refueling outage.
generators.
Environmental Risks
Entergy Arkansas' 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.
Critical Accounting Estimates
The preparation of Entergy Arkansas' 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 accounting estimates because they are based on assumptions and measurements that involve an unusuala high degree of uncertainty, and there is the potential that differentfor future changes in the assumptions and measurements could produce estimates that are significantly different than those recorded inwould have a material effect on the presentation of Entergy Arkansas' financial statements.
position or results of operations.
Nuclear Decommissioning Costs
Regulations require thatEntergy Arkansas to decommission the ANO 1 and ANO 2 be decommissionednuclear power plants after the facilities are taken out of service, and funds aremoney is collected and deposited in trust funds during the facilities' operating lives in order to provide for this obligation. Entergy Arkansas conducts periodic decommissioning cost studies (typically updated every five years) to estimate the costs that will be incurred to decommission the facilities. See Note 9 to the domestic utility companies and System Energy financial statements for details regarding Entergy Arkansas' most recent study and the obligations recorded by Entergy Arkansas related to decommissioning. The following key assumptions have a significant effect on these estimates:
Through 2001, Entergy Arkansas collected the projected costs of decommissioning ANO 1 and ANO 2 through rates charged to customers. TheNow, based on assumptions approved by the APSC, orderedincluding an assumed license extension for ANO 2 (ANO 1's license has already been extended), which significantly extends the earnings period, and the sufficiency of previously collected funds, Entergy Arkansas to cease collection ofis not collecting additional funds to decommission ANO 1 and ANO 2 effective with the calendar year 2001, and approved the continued cessation of collection of funds during 2003.in its current rates. The APSC based its decision on the approval of Entergy's application with the NRC to extend the license of ANO 1 by 20 years, anticipated approval of a 20 year license extension for ANO 2, and the conclusion that the funds previously collected will be sufficient to decommission the units. This decisionassumptions will be reviewed annually and reflected in Entergy Arkansas' filing of its annual determination of the nuclear decommissioning rate rider. The amounts that were collected through rates, which were based upon decommissioning cost studies, were deposited in decommissioning trus t funds. Decommissioning costs have no impact on Entergy Arkansas' earnings, as earnings on trust funds are offset by recording increases to the decommissioning obligation.
The obligations recorded by Entergy Arkansas for decommissioning are classified as a component of accumulated depreciation. The amounts recorded for these obligations are comprised of past collections from customers and earnings on the trust funds. The classification and recording of these obligations will change with the implementation of SFAS 143.
SFAS 143
Entergy Arkansas implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy Arkansas' asset retirement obligations, and the measurement and recording of Entergy Arkansas' decommissioning obligations outlined above will changechanged significantly with the implementation of SFAS 143. The most significant differences in the measurement of these obligations are outlined below:
The net effect of implementing this standard for Entergy Arkansas will bewas recorded as a regulatory asset, or liability, with no resulting impact on Entergy Arkansas' net income. AssetsEntergy Arkansas recorded this regulatory asset because its existing rate mechanism is based on the original or historical cost standard that allows Entergy Arkansas to recover all ultimate costs of decommissioning existing assets from current and future customers. Upon implementation, assets and liabilities are expected to increaseincreased by approximately $500$532 million in 2003 as a result of recording the asset retirement obligation at its fair value as determined under SFAS 143, increasing total utility plant by $106 million, reducing accumulated depreciation by $252 million, and recording the related regulatory asset of $174 million.
In the first quarter of 2004, Entergy Arkansas recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for ANO 1 and liability.2 as a result of revised decommissioning costs and changes in assumptions regarding the timing of when the decommissioning of the plants will begin. The revised estimate resulted in a $107.7 million reduction in its decommissioning liability, along with a $19.5 million reduction in utility plant and an $88.2 million reduction in the related regulatory asset.
Unbilled Revenue
As discussed in Note 1 to the domestic utility companies and System Energy financial statements, Entergy Arkansas records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month'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 including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regarding price such as the fuel cost recovery mechanism.
Pension and Other Postretirement Benefits
Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 1110 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and poorworse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt.debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 7.5% in 2000 and 2001 to 6.75% in 2002.2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rates fromrate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to a range of 8%10% increase in health care costs in 2005 gradually decreasing to 5%each successive year, until it reaches a 4.5% annual increase in 2001 to a range of 10% gradually decreasing to 4.5%health care costs in 2002.2011 and beyond.
In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities, and 35%4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities and 49% fixed income securities. Based on recent market trends, Entergy decreasedreduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 9% in 2000 and 2001 to 8.75% for 2002.2002 and 2003 to 8.5% in 2004. The trend of reduced inflation caused Entergy to reduce its assumed rate of increase in future compensation levels from 4.6% in 2000 and 2001used to calculate benefit obligations was 3.25% in 2002.2002, 2003, and 2004.
Cost Sensitivity
The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (in(dollars in thousands):
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| $907 |
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The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (in(dollars in thousands):
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Health care cost trend | 0.25% |
| $557 |
| $3,633 | |
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| $342 |
| $4,623 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
In accordance with SFAS No. 87, "Employers' Accounting for Pensions," 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 cost 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, Entergy smoothesaccounts for the impact of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87.
Costs and Funding
Total pension cost for Entergy Arkansas in 20022004 was $2.1$16.5 million. Taking into account asset performance and the changes made in the actuarial assumptions, Entergy Arkansas does not anticipate 2003anticipates 2005 pension cost to be materially different from 2002.increase to $21.8 million due to decrease in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. Entergy Arkansas was not required to make contributionscontributed $5.3 million to its pension plan in 2004, and anticipates making $20.6 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, and does not anticipate fundingpartially offset by the Pension Funding Equity Act relief passed in 2003.April 2004.
Due to negative pension plan asset returns over the past several years, Entergy Arkansas' accumulated benefit obligation at December 31, 2004, 2003, and 2002 exceeded plan assets. As a result, Entergy Arkansas was required to recognize an additional minimum liability of $29.6 million as prescribed by SFAS 87.87 at December 31, 2004, 2003, and 2002. At December 31, 2004, Entergy Arkansas recorded anincreased its additional minimum liability to $81.2 million from $54.9 million at December 31, 2003. Entergy Arkansas decreased its intangible asset for the $10.6 million of unrecognized prior service cost andto $10.3 million at December 31, 2004 from $13.3 million at December 31, 2003. Entergy Arkansas also increased the remaining $19regulatory asset to $70.8 million was recorded as a regulatory asset.at December 31, 2004 from $41.6 million at December 31, 2003. Net income for 2004, 2003, and 2002 was not impacted.
Total postretirement health care and life insurance benefit costs for Entergy Arkansas in 20022004 were $16.1 million. Because$12.8 million, including $5 million in savings due to the estimated effect of a numberfuture Medicare Part D subsidies. Entergy Arkansas expects 2005 postretirement health care and life insurance benefit costs to approximate $13.7 million, including $5.8 million in savings due to the estimated effect of factors, includingfuture Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the increaseddecrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate Entergy Arkansas expects 2003 costsused to approximate $20.4 million.calculate benefit obligations.
REPORT OF INDEPENDENT AUDITORS' REPORT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Entergy Arkansas, Inc.:
We have audited the accompanying balance sheets of Entergy Arkansas, Inc. as of December 31, 20022004 and 2001,2003, and the related statements of income, retained earnings, and cash flows (pages 151165 through 156170 and applicable items in pages 250284 through 303)348) for each of the three years in the period ended December 31, 2002.2004. 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 auditing standards generally accepted inof the United States of America.Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Arkansas, Inc. as of December 31, 20022004 and 2001,2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20022004 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 5 and Note 8 to the notes to respective financial statements, in 2003 Entergy Arkansas, Inc. adopted the provisions of Statement of Financial Accounting Standards Board Interpretation No. 46,Consolidation of Variable Interest Entities,and Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control - - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 8, 2005
February 21, 2003
ENTERGY ARKANSAS, INC. INCOME STATEMENTS For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING REVENUES Domestic electric $1,561,110 $1,776,776 $1,762,635 ---------- ---------- ---------- OPERATING EXPENSES Operation and Maintenance: Fuel, fuel-related expenses, and gas purchased for resale 294,244 397,080 258,294 Purchased power 355,211 397,885 560,793 Nuclear refueling outage expenses 24,387 28,695 25,884 Other operation and maintenance 543,677 364,409 427,409 Decommissioning - 13 3,845 Taxes other than income taxes 38,127 35,186 39,662 Depreciation and amortization 187,525 174,539 169,806 Other regulatory credits - net (184,270) (721) (33,078) ---------- ---------- ---------- TOTAL 1,258,901 1,397,086 1,452,615 ---------- ---------- ---------- OPERATING INCOME 302,209 379,690 310,020 ---------- ---------- ---------- OTHER INCOME Allowance for equity funds used during construction 7,324 6,115 15,020 Interest and dividend income 2,467 8,983 8,784 Miscellaneous - net (6,442) (5,109) (4,453) ---------- ---------- ---------- TOTAL 3,349 9,989 19,351 ---------- ---------- ---------- INTEREST AND OTHER CHARGES Interest on long-term debt 84,823 90,260 88,140 Other interest - net 13,287 14,163 8,360 Distributions on preferred securities of subsidiary 5,100 5,100 5,100 Allowance for borrowed funds used during construction (4,699) (3,962) (9,788) ---------- ---------- ---------- TOTAL 98,511 105,561 91,812 ---------- ---------- ---------- INCOME BEFORE INCOME TAXES 207,047 284,118 237,559 Income taxes 71,404 105,933 100,512 ---------- ---------- ---------- NET INCOME 135,643 178,185 137,047 Preferred dividend requirements and other 7,776 7,744 7,776 ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $127,867 $170,441 $129,271 ========== ========== ========== See Notes to Respective Financial Statements.
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ENTERGY ARKANSAS, INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING ACTIVITIES Net income $135,643 $178,185 $137,047 Noncash items included in net income: Other regulatory credits - net (184,270) (721) (33,078) Depreciation, amortization, and decommissioning 187,525 174,552 173,651 Deferred income taxes and investment tax credits 54,955 6,389 39,776 Allowance for equity funds used during construction (7,324) (6,115) (15,020) Changes in working capital: Receivables 50,898 (16,073) (47,647) Fuel inventory (6,509) 5,437 (6,512) Accounts payable 39,077 (206,185) 141,172 Taxes accrued (88,019) 64,018 1,731 Interest accrued (2,772) 2,920 5,246 Deferred fuel costs 59,849 89,184 35,993 Other working capital accounts (15,491) 23,283 17,162 Provision for estimated losses and reserves (9,952) (978) (895) Changes in other regulatory assets 182,244 (39,924) (85,452) Changes in other deferred credits 10,423 43,157 13,253 Other (48,856) 96,049 45,133 --------- --------- --------- Net cash flow provided by operating activities 357,421 413,178 421,560 --------- --------- --------- INVESTING ACTIVITIES Construction expenditures (277,189) (280,755) (369,370) Allowance for equity funds used during construction 7,324 6,115 15,020 Nuclear fuel purchases (68,127) (19,103) (44,722) Proceeds from sale/leaseback of nuclear fuel 68,127 19,103 44,722 Decommissioning trust contributions and realized change in trust assets (17,970) (10,105) (15,761) Changes in other temporary investments - net 38,397 (38,397) - Other regulatory investments - (3,460) (97,343) --------- --------- --------- Net cash flow used in investing activities (249,438) (326,602) (467,454) --------- --------- --------- FINANCING ACTIVITIES Proceeds from the issuance of long-term debt 188,407 97,384 99,381 Retirement of long-term debt (170,000) - (220) Changes in short-term borrowings (667) - - Dividends paid: Common stock (125,900) (82,500) (44,600) Preferred stock (7,776) (5,832) (7,691) --------- --------- --------- Net cash flow provided by (used in) financing activities (115,936) 9,052 46,870 --------- --------- --------- Net increase (decrease) in cash and cash equivalents (7,953) 95,628 976 Cash and cash equivalents at beginning of period 103,466 7,838 6,862 --------- --------- --------- Cash and cash equivalents at end of period $95,513 $103,466 $7,838 ========= ========= ========= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $100,965 $101,330 $91,291 Income taxes $83,911 $31,939 $60,291 Noncash investing and financing activities: Change in unrealized depreciation of decommissioning trust assets ($34,453) ($14,843) ($3,920) Proceeds from long-term debt issued for the purpose of refunding prior long-term debt - $47,000 - Long-term debt refunded with proceeds from long-term debt issued in prior period ($47,000) - - See Notes to Respective Financial Statements.
ENTERGY ARKANSAS, INC. BALANCE SHEETS ASSETS December 31, 2002 2001 (In Thousands) CURRENT ASSETS Cash and cash equivalents: Cash $28,174 $18,331 Temporary cash investments - at cost, which approximates market 67,339 85,135 ---------- ---------- Total cash and cash equivalents 95,513 103,466 ---------- ---------- Other temporary investments - 38,397 Accounts receivable: Customer 67,674 80,719 Allowance for doubtful accounts (8,031) (5,837) Associated companies 32,352 65,102 Other 16,619 25,059 Accrued unbilled revenues 67,838 62,307 ---------- ---------- Total accounts receivable 176,452 227,350 ---------- ---------- Deferred fuel costs - 17,246 Accumulated deferred income taxes 5,061 22,698 Fuel inventory - at average cost 10,881 4,372 Materials and supplies - at average cost 78,533 75,499 Deferred nuclear refueling outage costs 25,858 14,508 Prepayments and other 8,335 53,386 ---------- ---------- TOTAL 400,633 556,922 ---------- ---------- OTHER PROPERTY AND INVESTMENTS Investment in affiliates - at equity 11,215 11,217 Decommissioning trust funds 334,631 351,114 Non-utility property - at cost (less accumulated depreciation) 1,460 1,465 Other 2,976 2,976 ---------- ---------- TOTAL 350,282 366,772 ---------- ---------- UTILITY PLANT Electric 5,644,477 5,399,294 Property under capital lease 30,354 35,604 Construction work in progress 132,792 157,994 Nuclear fuel under capital lease 88,101 65,556 Nuclear fuel 10,543 8,156 ---------- ---------- TOTAL UTILITY PLANT 5,906,267 5,666,604 Less - accumulated depreciation and amortization 2,722,342 2,615,013 ---------- ---------- UTILITY PLANT - NET 3,183,925 3,051,591 ---------- ---------- DEFERRED DEBITS AND OTHER ASSETS Regulatory assets: SFAS 109 regulatory asset - net 111,748 164,146 Unamortized loss on reacquired debt 39,792 40,817 Other regulatory assets 130,689 260,535 Other 39,899 10,797 ---------- ---------- TOTAL 322,128 476,295 ---------- ---------- TOTAL ASSETS $4,256,968 $4,451,580 ========== ========== See Notes to Respective Financial Statements.
ENTERGY ARKANSAS, INC. BALANCE SHEETS LIABILITIES AND SHAREHOLDERS' EQUITY December 31, 2002 2001 (In Thousands) CURRENT LIABILITIES Currently maturing long-term debt $255,000 $85,000 Notes payable - 667 Accounts payable: Associated companies 37,833 32,868 Other 121,148 87,036 Customer deposits 35,886 32,589 Taxes accrued 16,262 104,281 Interest accrued 27,772 30,544 Deferred fuel costs 42,603 - Obligations under capital leases 58,745 51,973 System Energy refund 3,764 53,732 Other 17,734 17,221 ---------- ---------- TOTAL 616,747 495,911 ---------- ---------- DEFERRED CREDITS AND OTHER LIABILITIES Accumulated deferred income taxes and taxes accrued 821,829 809,742 Accumulated deferred investment tax credits 78,231 83,239 Obligations under capital leases 59,711 49,187 Transition to competition - 152,414 Accumulated provisions 31,463 41,415 Other 117,847 107,424 ---------- ---------- TOTAL 1,109,081 1,243,421 ---------- ---------- Long-term debt 1,125,000 1,308,075 Company-obligated mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated deferrable debentures 60,000 60,000 SHAREHOLDERS' EQUITY Preferred stock without sinking fund 116,350 116,350 Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 2002 and 2001 470 470 Paid-in capital 591,127 591,127 Retained earnings 638,193 636,226 ---------- ---------- TOTAL 1,346,140 1,344,173 ---------- ---------- Commitments and Contingencies TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $4,256,968 $4,451,580 ========== ========== See Notes to Respective Financial Statements.
ENTERGY ARKANSAS, INC. STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 2002 2001 2000 (In Thousands) Retained Earnings, January 1 $636,226 $548,285 $463,614 Add: Net income 135,643 178,185 137,047 Deduct: Dividends declared: Preferred stock 7,776 7,744 7,776 Common stock 125,900 82,500 44,600 -------- -------- -------- Total 133,676 90,244 52,376 -------- -------- -------- Retained Earnings, December 31 $638,193 $636,226 $548,285 ======== ======== ======== See Notes to Respective Financial Statements.
ENTERGY ARKANSAS, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
2002 | 2001 | 2000 | 1999 | 1998 | |
(In Thousands) | |||||
Operating revenues | $ 1,561,110 | $ 1,776,776 | $ 1,762,635 | $ 1,541,894 | $ 1,608,698 |
Net income | $ 135,643 | $ 178,185 | $ 137,047 | $ 69,313 | $ 110,951 |
Total assets | $ 4,256,968 | $ 4,451,580 | $ 4,228,211 | $ 3,917,111 | $ 4,006,651 |
Long-term obligations (1) | $ 1,244,711 | $ 1,417,262 | $ 1,401,062 | $ 1,265,846 | $ 1,335,248 |
ENTERGY ARKANSAS, INC. | ||||||
INCOME STATEMENTS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
OPERATING REVENUES | ||||||
Domestic electric | $1,653,145 | $1,589,670 | $1,561,110 | |||
OPERATING EXPENSES | ||||||
Operation and Maintenance: | ||||||
Fuel, fuel-related expenses, and | ||||||
gas purchased for resale | 210,394 | 153,866 | 294,244 | |||
Purchased power | 484,849 | 476,447 | 355,211 | |||
Nuclear refueling outage expenses | 24,568 | 23,638 | 24,387 | |||
Other operation and maintenance | 384,424 | 402,108 | 543,677 | |||
Decommissioning | 32,902 | 35,887 | - - | |||
Taxes other than income taxes | 35,848 | 37,385 | 38,127 | |||
Depreciation and amortization | 206,926 | 202,497 | 187,525 | |||
Other regulatory credits - net | (20,501) | (39,347) | (184,270) | |||
TOTAL | 1,359,410 | 1,292,481 | 1,258,901 | |||
OPERATING INCOME | 293,735 | 297,189 | 302,209 | |||
OTHER INCOME | ||||||
Allowance for equity funds used during construction | 11,737 | 12,153 | 7,324 | |||
Interest and dividend income | 10,298 | 9,790 | 2,467 | |||
Miscellaneous - net | (6,354) | (4,332) | (6,442) | |||
TOTAL | 15,681 | 17,611 | 3,349 | |||
INTEREST AND OTHER CHARGES | ||||||
Interest on long-term debt | 79,521 | 87,666 | 89,923 | |||
Other interest - net | 4,909 | 3,555 | 13,287 | |||
Allowance for borrowed funds used during construction | (6,288) | (7,726) | (4,699) | |||
TOTAL | 78,142 | 83,495 | 98,511 | |||
INCOME BEFORE INCOME TAXES | 231,274 | 231,305 | 207,047 | |||
Income taxes | 89,064 | 105,296 | 71,404 | |||
NET INCOME | 142,210 | 126,009 | 135,643 | |||
Preferred dividend requirements and other | 7,776 | 7,776 | 7,776 | |||
EARNINGS APPLICABLE TO | ||||||
COMMON STOCK | $134,434 | $118,233 | $127,867 | |||
See Notes to Respective Financial Statements. | ||||||
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ENTERGY ARKANSAS, INC. | ||||||
STATEMENTS OF CASH FLOWS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
OPERATING ACTIVITIES | ||||||
Net income | $142,210 | $126,009 | $135,643 | |||
Adjustments to reconcile net income to net cash flow provided by operating activities: | ||||||
Reserve for regulatory adjustments | 3,099 | 1,739 | - - | |||
Other regulatory credits - net | (20,501) | (39,347) | (184,270) | |||
Depreciation, amortization, and decommissioning | 239,828 | 238,384 | 187,525 | |||
Deferred income taxes and investment tax credits | 65,847 | 48,357 | 54,955 | |||
Changes in working capital: | ||||||
Receivables | (86,564) | (29,616) | 50,898 | |||
Fuel inventory | 2,424 | 4,159 | (6,509) | |||
Accounts payable | (40,871) | 40,615 | 39,077 | |||
Taxes accrued | 137,767 | 48,791 | (69,812) | |||
Interest accrued | (48) | (6,348) | (2,772) | |||
Deferred fuel costs | 6,880 | (46,333) | 59,849 | |||
Other working capital accounts | 4,753 | (79,331) | (33,698) | |||
Provision for estimated losses and reserves | (5,172) | 8,686 | (9,952) | |||
Changes in other regulatory assets | 37,668 | (54,745) | 182,244 | |||
Other | (41,022) | 176,500 | (45,757) | |||
Net cash flow provided by operating activities | 446,298 | 437,520 | 357,421 | |||
INVESTING ACTIVITIES | ||||||
Construction expenditures | (270,427) | (334,556) | (277,189) | |||
Allowance for equity funds used during construction | 11,737 | 12,153 | 7,324 | |||
Nuclear fuel purchases | (8,101) | (60,685) | (68,127) | |||
Proceeds from sale/leaseback of nuclear fuel | 8,101 | 60,685 | 68,127 | |||
Decommissioning trust contributions and realized | ||||||
change in trust assets | (8,860) | (8,279) | (17,970) | |||
Changes in other investments - net | 1,856 | - - | 38,397 | |||
Other regulatory investments | (3,691) | (6,827) | - - | |||
Net cash flow used in investing activities | (269,385) | (337,509) | (249,438) | |||
FINANCING ACTIVITIES | ||||||
Proceeds from the issuance of long-term debt | 59,429 | 361,726 | 188,407 | |||
Retirement of long-term debt | (61,856) | (471,040) | (170,000) | |||
Changes in short-term borrowings | - - | - - | (667) | |||
Dividends paid: | ||||||
Common stock | (85,800) | (69,600) | (125,900) | |||
Preferred stock | (7,776) | (7,776) | (7,776) | |||
Net cash flow used in financing activities | (96,003) | (186,690) | (115,936) | |||
Net increase (decrease) in cash and cash equivalents | 80,910 | (86,679) | (7,953) | |||
Cash and cash equivalents at beginning of period | 8,834 | 95,513 | 103,466 | |||
Cash and cash equivalents at end of period | $89,744 | $8,834 | $95,513 | |||
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||
Cash paid/(received) during the period for: | ||||||
Interest - net of amount capitalized | $78,144 | $91,142 | $100,965 | |||
Income taxes | ($103,476) | $2,177 | $83,911 | |||
Noncash investing and financing activities: | ||||||
Long-term debt refunded with proceeds from | ||||||
long-term debt issued in prior periods | - - | - - | ($47,000) | |||
See Notes to Respective Financial Statements. |
ENTERGY ARKANSAS, INC. | ||||
BALANCE SHEETS | ||||
ASSETS | ||||
December 31, | ||||
2004 | 2003 | |||
(In Thousands) | ||||
CURRENT ASSETS | ||||
Cash and cash equivalents: | ||||
Cash | $7,133 | $8,834 | ||
Temporary cash investments - at cost, | ||||
which approximates market | 82,611 | - - | ||
Total cash and cash equivalents | 89,744 | 8,834 | ||
Accounts receivable: | ||||
Customer | 87,131 | 69,036 | ||
Allowance for doubtful accounts | (11,039) | (9,020) | ||
Associated companies | 72,472 | 50,390 | ||
Other | 72,425 | 30,930 | ||
Accrued unbilled revenues | 71,643 | 64,732 | ||
Total accounts receivable | 292,632 | 206,068 | ||
Deferred fuel costs | 7,368 | 10,557 | ||
Accumulated deferred income taxes | 27,306 | 18,362 | ||
Fuel inventory - at average cost | 4,298 | 6,722 | ||
Materials and supplies - at average cost | 85,076 | 80,506 | ||
Deferred nuclear refueling outage costs | 16,485 | 19,793 | ||
Prepayments and other | 6,154 | 23,938 | ||
TOTAL | 529,063 | 374,780 | ||
OTHER PROPERTY AND INVESTMENTS | ||||
Investment in affiliates - at equity | 11,208 | 11,212 | ||
Decommissioning trust funds | 383,784 | 360,485 | ||
Non-utility property - at cost (less accumulated depreciation) | 1,453 | 1,456 | ||
Other | 2,976 | 4,832 | ||
TOTAL | 399,421 | 377,985 | ||
UTILITY PLANT | ||||
Electric | 6,124,359 | 5,948,090 | ||
Property under capital lease | 17,500 | 24,047 | ||
Construction work in progress | 226,172 | 238,807 | ||
Nuclear fuel under capital lease | 93,855 | 102,691 | ||
Nuclear fuel | 12,201 | 7,466 | ||
TOTAL UTILITY PLANT | 6,474,087 | 6,321,101 | ||
Less - accumulated depreciation and amortization | 2,753,525 | 2,627,441 | ||
UTILITY PLANT - NET | 3,720,562 | 3,693,660 | ||
DEFERRED DEBITS AND OTHER ASSETS | ||||
Regulatory assets: | ||||
SFAS 109 regulatory asset - net | 101,658 | 128,311 | ||
Other regulatory assets | 400,174 | 437,544 | ||
Other | 42,514 | 45,798 | ||
TOTAL | 544,346 | 611,653 | ||
TOTAL ASSETS | $5,193,392 | $5,058,078 | ||
See Notes to Respective Financial Statements. | ||||
ENTERGY ARKANSAS, INC. | ||||
BALANCE SHEETS | ||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||
December 31, | ||||
2004 | 2003 | |||
(In Thousands) | ||||
CURRENT LIABILITIES | ||||
Currently maturing long-term debt | $147,000 | $ - | ||
Accounts payable: | ||||
Associated companies | 68,829 | 106,958 | ||
Other | 89,896 | 92,638 | ||
Customer deposits | 41,639 | 37,693 | ||
Taxes accrued | 35,874 | - - | ||
Interest accrued | 21,376 | 21,424 | ||
Obligations under capital leases | 49,816 | 59,089 | ||
Other | 19,648 | 16,924 | ||
TOTAL | 474,078 | 334,726 | ||
NON-CURRENT LIABILITIES | ||||
Accumulated deferred income taxes and taxes accrued | 1,121,623 | 996,455 | ||
Accumulated deferred investment tax credits | 68,452 | 73,280 | ||
Obligations under capital leases | 61,538 | 67,648 | ||
Other regulatory liabilities | 67,362 | 52,923 | ||
Decommissioning | 492,745 | 567,546 | ||
Accumulated provisions | 34,977 | 40,149 | ||
Long-term debt | 1,191,763 | 1,338,378 | ||
Other | 237,447 | 192,200 | ||
TOTAL | 3,275,907 | 3,328,579 | ||
Commitments and Contingencies | ||||
SHAREHOLDERS' EQUITY | ||||
Preferred stock without sinking fund | 116,350 | 116,350 | ||
Common stock, $0.01 par value, authorized 325,000,000 | ||||
shares; issued and outstanding 46,980,196 shares in 2004 | ||||
and 2003 | 470 | 470 | ||
Paid-in capital | 591,127 | 591,127 | ||
Retained earnings | 735,460 | 686,826 | ||
TOTAL | 1,443,407 | 1,394,773 | ||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $5,193,392 | $5,058,078 | ||
See Notes to Respective Financial Statements. |
ENTERGY ARKANSAS, INC. | |||||
STATEMENTS OF RETAINED EARNINGS | |||||
For the Years Ended December 31, | |||||
2004 | 2003 | 2002 | |||
(In Thousands) | |||||
Retained Earnings, January 1 | $686,826 | $638,193 | $636,226 | ||
Add: | |||||
Net income | 142,210 | 126,009 | 135,643 | ||
Deduct: | |||||
Dividends declared: | |||||
Preferred stock | 7,776 | 7,776 | 7,776 | ||
Common stock | 85,800 | 69,600 | 125,900 | ||
Total | 93,576 | 77,376 | 133,676 | ||
Retained Earnings, December 31 | $735,460 | $686,826 | $638,193 | ||
See Notes to Respective Financial Statements. | |||||
ENTERGY ARKANSAS, INC. | ||||||||||
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | ||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||
(In Thousands) | ||||||||||
Operating revenues | $1,653,145 | $1,589,670 | $1,561,110 | $1,776,776 | $1,762,635 | |||||
Net Income | $142,210 | $126,009 | $135,643 | $178,185 | $137,047 | |||||
Total assets | $5,193,392 | $5,058,078 | $4,569,511 | $4,451,580 | $4,228,211 | |||||
Long-term obligations (1) | $1,253,301 | $1,406,026 | $1,246,567 | $1,417,262 | $1,401,062 | |||||
(1) Included long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. | ||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||
(Dollars In Millions) | ||||||||||
Electric Operating Revenues: | ||||||||||
Residential | $539 | $526 | $556 | $586 | $561 | |||||
Commercial | 305 | 291 | 304 | 330 | 307 | |||||
Industrial | 318 | 305 | 330 | 371 | 353 | |||||
Governmental | 16 | 15 | 15 | 16 | 15 | |||||
Total retail | 1,178 | 1,137 | 1,205 | 1,303 | 1,236 | |||||
Sales for resale: | ||||||||||
Associated companies | 250 | 234 | 165 | 240 | 246 | |||||
Non-associated companies | 186 | 188 | 164 | 201 | 235 | |||||
Other | 39 | 31 | 27 | 33 | 46 | |||||
Total | $1,653 | $1,590 | $1,561 | $1,777 | $1,763 | |||||
Billed Electric Energy Sales (GWh): | ||||||||||
Residential | 7,028 | 7,057 | 7,050 | 6,918 | 6,791 | |||||
Commercial | 5,428 | 5,328 | 5,221 | 5,162 | 5,063 | |||||
Industrial | 7,004 | 6,999 | 7,074 | 7,052 | 7,240 | |||||
Governmental | 275 | 266 | 255 | 245 | 239 | |||||
Total retail | 19,735 | 19,650 | 19,600 | 19,377 | 19,333 | |||||
Sales for resale: | ||||||||||
Associated companies | 7,437 | 7,036 | 6,811 | 7,217 | 6,513 | |||||
Non-associated companies | 4,911 | 5,399 | 5,069 | 4,909 | 5,537 | |||||
Total | 32,083 | 32,085 | 31,480 | 31,503 | 31,383 | |||||
ENTERGY GULF STATES, INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
OperatingNet Income
20022004 Compared to 20012003
OperatingNet income decreased $45.5increased $149.7 million primarily due to the following:
The increase was partially offset by a higher effective income tax rate.
2003 Compared to 2002
Entergy Gulf States experienced a significant decline in net income in 2003 compared to 2002 primarily due to the following:
The decrease was partially offset by a lower effective income tax rate.
Net Revenue
2004 Compared to 2003
Net revenue, which is Entergy Gulf States' measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2004 to 2003.
(In Millions) | ||
2003 net revenue | $1,110.1 | |
Volume/weather | 26.7 | |
Net wholesale revenue | 13.0 | |
Summer capacity charges | 5.5 | |
Price applied to unbilled sales | 4.8 | |
Fuel recovery revenues | (14.2) | |
Other | 3.9 | |
2004 net revenue | $1,149.8 |
The volume/weather variance resulted primarily from an increase of 1,179 GWh in electricity usage in the industrial sector. Billed usage also increased a total of 291 GWh in the residential, commercial, and governmental sectors.
The increase in net wholesale revenue is primarily due to an increase in sales volume to municipal and co-op customers.
Summer capacity charges variance is due to the amortization in 2003 of deferred capacity charges for the summer of 2001 compared to the absence of the amortization in 2004. The amortization of these capacity charges began in June 2002 and ended in May 2003.
The price applied to unbilled sales variance resulted primarily from an increase in the fuel price applied to unbilled sales.
Fuel recovery revenues represent an under-recovery of fuel charges that are recovered in base rates.
Gross operating revenues, fuel and purchased power expenses, and other regulatory credits
Gross operating revenues increased primarily due to an increase of $187.8 million in fuel cost recovery revenues as a result of higher fuel rates in both the Louisiana and Texas jurisdictions. The increases in volume/weather and wholesale revenue, discussed above, also contributed to the increase.
Fuel and purchased power expenses increased primarily due to:
Other regulatory credits increased primarily due to the amortization in 2003 of deferred capacity charges for the summer of 2001 compared to the absence of amortization in 2004. The amortization of these charges began in June 2002 and ended in May 2003.
2003 Compared to 2002
Net revenue, which is Entergy Gulf States' measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2003 to 2002.
(In Millions) | ||
2002 net revenue | $1,130.7 | |
Volume/weather | 17.8 | |
Fuel write-offs in 2002 | 15.3 | |
Net wholesale revenue | 10.2 | |
Base rate decreases | (23.3) | |
NISCO gain recognized in 2002 | (15.2) | |
Rate refund provisions | (11.3) | |
Other | (14.1) | |
2003 net revenue | $1,110.1 |
The volume/weather variance was due to higher electric sales volume in the service territory. Billed usage increased a total of 517 GWh in the residential and commercial sectors. The increase was partially offset by a decrease in industrial usage of 470 GWh due to the loss of two large industrial customers to cogeneration. The customers accounted for approximately 1% of Entergy Gulf States' net revenue in 2002.
In 2002, deferred fuel costs of $8.9 million related to a Texas fuel reconciliation case were written off and $6.5 million in expense resulted from an adjustment in the deregulated asset plan percentage as the result of a power uprate at River Bend.
The increase in net wholesale revenue was primarily due to an increase in sales volume to municipal and co-op customers and also to affiliated systems related to Entergy's generation resource planning.
The base rate decreases were effective June 2002 and January 2003, both in the Louisiana jurisdiction. The January 2003 base rate decrease of $22.1 million had a minimal impact on net income due to a corresponding reduction in nuclear depreciation and decommissioning expenses associated with the change in accounting to reflect an assumed extension of River Bend's useful life.
In 2002, a gain recognition of $15.2 million was recognized for the Louisiana portion of the 1988 Nelson Units 1 and 2 sale;
Rate refund provisions caused a decrease in net wholesale revenue of $38.6 milliondue to additional provisions recorded in 2003 compared to 2002 for potential rate actions and refunds.
Gross operating revenues and fuel and purchased power expenses
Gross operating revenues increased primarily due to an increase of $440.2 million in fuel cost recovery revenues as a decreaseresult of higher fuel rates in sales volume;
Fuel and purchased power expenses increased other operation and maintenance expenses of $15.6 million, which are explained below; and
Other Income Statement Variances
2004 Compared to 2003
Other operation and maintenance expenses decreased primarily due to:
The decrease was partially offset by the following:
Miscellaneous income - net increased $145.6 million primarily due to:
The decrease in operating income was partially offset by:
Interest on long-term debt decreased $23.2 million primarily due to the financing and weather of $36.5 million.debt restructuring program implemented in 2003, which resulted in extended maturities and lower interest rates in Entergy Gulf States' debt portfolio.
2003 Compared to 2002
Other operation and maintenance expenses increased primarily due to:to voluntary severance accruals of $22.5 million in 2003.
The increase in other operation and maintenance expenses was partially offset by decreased unbundling and transition to competition costs of $7.2 million.
2001 Compared to 2000
Operating income decreased $16.1 million primarily due to the following drivers:
The decreasedecommissioning expense was partially offset by increasedincreases in other regulatory credits and interest and dividend income and has no effect on net wholesale revenues of $34.1 million primarily due to increased sales volume to municipalincome.
Depreciation and co-op customers.
Other Impacts on Earnings
2002 Compared to 2001
Other incomeamortization expenses decreased $5.9 million primarily due to decreased interest incomerates associated with the assumed life extension of $11.4 million recorded on the deferred fuel balanceRiver Bend, partially offset by higher depreciation due to partial recoveryan increase in plant in service. The decrease in depreciation related to the assumed license extension of the balance, somewhatRiver Bend has a minimal impact on net income because it was offset by the settlement of liability insurance coverage for $5.6 million.
January 2003 base rate decrease discussed in "Net Revenue" above.
Interest charges decreased $30.0 million primarily due to:
2001 Compared to 2000
Other income increased $6.7 milliondecreased primarily due to increased interest income recordedthe abeyed River Bend plant cost accrual discussed above.
Interest expense on the deferred fuel balance due to significantly higher natural gas prices in 2001.
Interest chargeslong-term debt increased $13.1 million primarily due to:
Income Taxes
The effective income tax rates for 2004, 2003, and 2002 2001, and 2000 were 27.5%36.0%, 31.4%21.3%, and 36.5%27.5%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0%35% to the effective income tax rate.
Other Income Statement Variances
2002 Compared Tax reserves not expected to 2001
Operating revenues decreased $464.7 million primarily due to decreased fuel cost recovery revenues whichreverse within the next year are offset by decreased fuel and purchased power expenses of $467.2 million due to lower prices.
Decreased usage in the industrial sector in 2002 was due to contractual modifications that reclassified sales associated with certain customers from retail to wholesale. Under the terms of the former contract with these customers, Entergy Gulf States was also required to purchase the electricity produced by the customers' generating units. As a result of the cessation of the purchased power obligation, the reclassification of these sales did not have a material impact on Entergy Gulf States' earnings.
Other regulatory credits decreased $18.9 million primarily due to the:
The decrease was somewhat offset by the income recognition of $15.2 million of the Louisiana portion of the unamortized deferred gainreflected as non-current taxes accrued on the 1988 sale of Nelson Units 1 and 2. The deferred gain was recognized in income because the LPSC no longer requires that amortization of the gain reduce Entergy Gulf States' recoverable fuel.
2001 Compared to 2000
Operating revenues increased $137.3 million primarily due to:
Fuel and purchased power expenses related to electric sales increased by $177.6 million primarily as a result of the over-recovery of fuel and purchased power costs. The over-recovery is due to the collection of higher fuel and purchased power costs through the fuel adjustment clause in the Louisiana jurisdiction and due to increases in the fixed fuel factor and a fuel recovery surcharge in the Texas jurisdiction.
Other regulatory credits increased $18.5 million primarily due to:
The increase was partially offset by the recording of a regulatory asset of $3.2 million in 2000 related to low-level radiation waste expenses and the amortization of the Louisiana capacity charges of $2.0 million.
balance sheet.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2002, 2001,2004, 2003, and 20002002 were as follows:
2002 | 2001 | 2000 | ||||
(In Thousands) | ||||||
Cash and cash equivalents at beginning of period | $123,728 | $ 68,279 | $ 32,312 | |||
Cash flow provided by (used in): | ||||||
Operating activities | 500,654 | 338,486 | 403,880 | |||
Investing activities | (351,456) | (363,416) | (410,027) | |||
Financing activities | 45,478 | 80,379 | 42,114 | |||
Net increase in cash and cash equivalents | 194,676 | 55,449 | 35,967 | |||
Cash and cash equivalents at end of period | $318,404 | $123,728 | $ 68,279 |
2004 | 2003 | 2002 | |||||
(In Thousands) | |||||||
Cash and cash equivalents at beginning of period | $206,030 | $318,404 | $123,728 | ||||
Cash flow provided by (used in): | |||||||
Operating activities | 649,458 | 425,963 | 500,654 | ||||
Investing activities | (389,344) | (446,639) | (351,456) | ||||
Financing activities | (459,170) | (91,698) | 45,478 | ||||
Net increase (decrease) in cash and cash equivalents | (199,056) | (112,374) | 194,676 | ||||
Cash and cash equivalents at end of period | $6,974 | $206,030 | $318,404 |
Operating Activities
Cash flow from operations increased $223.5 million in 20022004 compared to 20012003 primarily due to an increase in payables due to the timing of fuelmoney pool activity. Decreased vendor payments, partially offset by the decreased collectionincreased recovery of deferred fuel costs, and lower interest payments also contributed to the increase.
In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in 2002 duetax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to collectionsthe production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in 2001a $674 million deduction for Entergy Gulf States on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004 Entergy Gulf States realized $69 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. As of high balances.December 31, 2004, Entergy Gulf States has a net operating loss (NOL) carryforward for tax purposes of $447.5 million, principally resulting from the change in tax accounting method related to cost of goods sold. If the tax accounting method change is sustained, Entergy Gulf States expects to utilize the NOL carryforward through 2006.
Cash flow from operations decreased $74.7 million in 20012003 compared to 20002002 primarily due to amoney pool activity, higher working capital needs, and increased vendor payments in 2003 relating to storm expense accruals in late-2002. The decrease in payables due to increased payments to fuel suppliers in 2001,was partially offset by the increased collection of deferred fuel.lower income tax payments.
Entergy Gulf States' receivables from or (payables) to(payables to) the money pool were as follows as of December 31 for each of the following years:
2002 | 2001 | 2000 | 1999 | ||||
(In Thousands) | |||||||
$18,131 | $27,665 | $23,437 | ($36,104) |
2004 |
| 2003 |
| 2002 |
| 2001 |
(In Thousands) | ||||||
|
|
|
|
|
|
|
($59,720) |
| $69,354 |
| $18,131 |
| $27,665 |
Money pool activity increasedprovided $129.1 million of Entergy Gulf States' operating cash flows byin 2004, used $51.2 million in 2003, and provided $9.5 million in 2002, decreased operating cash flow by $4.2 million in 2001, and decreased operating cash flow by $59.5 million in 2000.2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.
Investing Activities
Net cash used in investing activities decreased slightly$57.3 million in 20022004 compared to 2001 because of2003 primarily due to the maturity in 20022004 of the$23.6 million of other temporary investments that had been made in 2001. The2003, which provided cash in 2004. Also contributing to the decrease was a $27.2 million decrease in net cash used was almost entirely offset by increasesunder-recovered fuel and purchased power expenses in other regulatory investments, whichTexas that have been deferred and are deferred fuel costs expected to be collected over a period greater than twelve month,months. See Note 1 to the domestic utility companies and capital expenditures. Capital expenditures increased primarily due to increased spending on environmental projects.System Energy financial statements for further discussion of the accounting for fuel costs.
The decrease in netNet cash used in investing activities increased $95.2 million in 20012003 compared to 2000 was2002 primarily due to increasesan increase of $23.6 million in other temporary investments in 2003 compared to the maturity of $44.6 million of other temporary investments that provided cash in 2002. The increase was also due to an increase of $37.7 million in under-recovered fuel and capital expenditures,purchased power expenses in Texas that have been deferred and are expected to be collected over a period greater than twelve months. See Note 1 to the domestic utility companies and System Energy financial statements for further discussion of the accounting for fuel costs.
Financing Activities
Net cash used in financing activities increased $367.5 million in 2004 compared to 2003 primarily due to the net reduction of $357 million of long-term debt in 2004 compared to $15.4 million in 2003 as well as an increase of $26.2 million in common stock dividends paid.
Entergy Gulf States used $91.7 million of cash in financing activities in 2003 compared to providing $45.5 million of cash in 2002 primarily due to the net reduction of $15.4 million of long-term debt in 2003 compared to the net issuance of $143.4 million of long-term debt in 2002. The increase in cash used in financing activities was partially offset by a decrease in other regulatory investments due to collection of deferred fuel costs. Capital expenditures increased primarily due to additional transmission line work, transition to competition projects, and increased spending on customer information systems projects.
Financing Activities
The decrease in net cash provided by financing activities in 2002 was primarily due to a decrease of $30.3$23.1 million in net issuances of long-term debt.common stock dividends paid.
The increase in net cash provided by financing activities in 2001 was primarily due to the redemption of $150 million of preference stock in 2000, partially offset by the decrease of $124.9 million in net issuances of long-term debt in 2001.
See Note 75 to the domestic utility companies and System Energy financial statements for details on long-term debt.
Uses of Capital
Entergy Gulf States requires capital resources for:
Following are the amounts of Entergy Gulf States' planned construction and other capital investments, existing debt and lease obligations, and other purchase obligations:
| 2005 |
| 2006-2007 |
| 2008-2009 |
| after 2009 |
| Total |
| (In Millions) | ||||||||
Planned construction and |
|
|
|
|
|
|
|
|
|
capital investment (1) | $275 |
| $505 |
| N/A |
| N/A |
| $780 |
Long-term debt | $98 |
| - |
| $550 |
| $1,341 |
| $1,989 |
Operating leases | $27 |
| $41 |
| $19 |
| $115 |
| $202 |
Purchase obligations (2) | $164 |
| $78 |
| $6 |
| $21 |
| $269 |
Other long-term liabilities | $3 |
| $7 |
| $7 |
| - |
| $17 |
Nuclear fuel lease obligations (3) | $33 |
| $38 |
| N/A |
| N/A |
| $71 |
(1) | Includes approximately $210 to $220 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. |
(2) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Gulf States it primarily includes unconditional fuel and purchased power obligations. |
(3) | It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations. |
2003 | 2004 | 2005 | 2006-2007 | after 2007 | |||||
(In Millions) | |||||||||
Planned construction and | |||||||||
capital investment | $236 | $226 | $230 | N/A | N/A | ||||
Long-term debt maturities | $293 | $654 | $98 | $200 | $1,007 | ||||
Capital and operating lease payments (1) | $29 | $28 | $17 | $24 | $14 | ||||
Unconditional fuel and purchased | |||||||||
power obligations (2) | $28 | $24 | $2 | $4 | $25 | ||||
Nuclear fuel lease obligations (1)(3) | $29 | $12 | N/A | N/A | N/A |
2005.
The planned capital investment estimate for Entergy Gulf States reflects capital required to support existing business and customer growth. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, business restructuring, and the ability to access capital. Management provides more information on construction expenditures and long-term debt and preferred stock maturities in Notes 5 6, 7, and 96 to the domestic utility companies and System Energy financial statements.
In addition to the purchase obligations presented in the table above, Entergy Gulf States expects to have an obligation to purchase power from the Perryville power plant. In January 2004, Entergy Louisiana signed a definitive agreement to acquire the 718 MW Perryville power plant for $170 million. The agreement has subsequently been amended to allow the current plant owner to retain the interconnection facilities associated with the plant, resulting in a decrease in the acquisition price to $162 million. As a result of the amended terms, the FERC issued an order in October 2004 disclaiming jurisdiction over the acquisition. This order currently is subject to rehearing by the FERC. The plant is owned by a subsidiary of Cleco Corporation, which subsidiary submitted a bid in response to Entergy's Fall 2002 request for proposals for supply-side resources. The signing of the agreement followed a voluntary Chapter 11 bankruptcy filing by the plant's owner. Entergy expects that Entergy Louisiana will own 100 percent of the Perryville plant, and that Entergy Louisiana will sell 75 percent of the output to Entergy Gulf States under a long-term cost-of-service power purchase agreement. In addition, Entergy Louisiana and Entergy Gulf States executed an interim power purchase agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by December 2005) for 100 percent of the output of the Perryville power plant. In April 2004, the bankruptcy court approved Entergy Louisiana's agreement to acquire the plant. In March 2004, Entergy Gulf States and Entergy Louisiana filed with the LPSC for its approval of the acquisition and long-term cost-of-service power purchase agreement. Entergy is seeking approval from the LPSC of cost recovery for the acquisition, giving consideration to the need for the power and the prudence of Entergy Louisiana and Entergy Gulf States in engaging in the transaction. Hearings are scheduled for March 2005. Assuming regulato ry approval by the LPSC, Entergy Louisiana expects the Perryville acquisition to close in mid-2005.
As a wholly-owned subsidiary, Entergy Gulf States pays dividends its earnings to Entergy Corporation from its earnings at a percentage determined monthly. Entergy Gulf States is restricted by long-term debt indentures in the payment of cash dividends or other distributions on its common and preferred stock. Currently, all of Entergy Gulf States' retained earnings are available for distribution.
Sources of Capital
Entergy Gulf States' sources to meet its capital requirements include:
In 2002,The following table lists First Mortgage Bonds issued by Entergy Gulf States issued $340 million of long-term debt. in 2004:
Issue Date | Description | Maturity | Amount | |||
(In Thousands) | ||||||
October 2004 | 4.875% Series | November 2011 | $200,000 | |||
November 2004 | Libor + 0.4% Series | December 2009 | 225,000 | |||
November 2004 | 5.6% Series | December 2014 | 50,000 | |||
$475,000 |
The net proceeds were used to redeem or repurchase prior to maturity, or to repay at maturity, $339 million of Entergy Gulf States' outstanding debt with 2003 maturities.following table lists First Mortgage Bonds retired by Entergy Gulf States is expected to continue refinancingin 2004:
Retirement Date | Description | Maturity | Amount | |||
(In Thousands) | ||||||
April 2004 | 8.25% Series | April 2004 | $292,000 | |||
December 2004 | Libor + 0.9% Series | June 2007 | 275,000 | |||
December 2004 | 5.2% Series | December 2007 | 200,000 | |||
$767,000 |
Entergy Gulf States may refinance or redeeming higher-costredeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
In addition, in September 2004, Entergy Gulf States purchased its $62 million 5.65% Series tax-exempt bonds from the holders, pursuant to a mandatory tender provision, and has not remarketed the bonds at this time.
All debt and common and preferred stock issuances by Entergy Gulf States require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in its corporate charter, bond indentures, and other agreements. Entergy Gulf States has sufficient capacity under these tests to meet its foreseeable capital needs.
Short-term borrowingsBorrowings and securities issuances by Entergy Gulf States are limited to amounts authorized by the SEC. The current short-term borrowing limitation, including borrowings under the money pool, are limited to an amount authorized by the SEC,is $340 million. Under theits SEC order authorizing the short-term borrowing limits,Orders and without further SEC authorization, Entergy Gulf States cannot incur new short-termadditional indebtedness if itsor issue other securities unless (a) it and Entergy Corporation maintain a common equity would comprise less thanratio of at least 30% and (b) with the exception of its capital. In addition, this order restrictsmoney pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy Gulf States from publicly issuing new long-term debt unless(other than its senior secured debt will bepreferred stock), as well as all outstanding securities of Entergy Corporation, that are rated, asare rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Gulf States' short-term borrowing limits.
Significant Factors and Known Trends
Transition to Retail Competition
Texas
included:
After considering the proposal, in an April 2003 order the PUCT is expec tedset forth a sequence of proceedings and activities designed to consider this proposal on March 21, 2003.
This proposal takes into account that other regulatory approvals, including that of the LPSCinitiate an interim solution. These proceedings and the SEC, are necessary prioractivities included initiating a proceeding to January 1, 2004.
With retail opencertify an independent organization to administer market protocols and ensure nondiscriminatory access generation and a new retail electric provider operation are competitive businesses, butto transmission and distribution operations continue to be regulated. The new retail electric providers are the primary point of contact with customers. The provisions of the retail open access law in Texas:
systems.
On August 3, 2001,In July 2004 the PUCT staff filed a petition requesting thatdenied Entergy's application to certify Entergy's transmission organization as an independent organization under Texas law. In its order, the PUCT determine whetheralso ordered: the market is readycessation of efforts to develop an interim solution for retail open access in the portion of Texas within the Southeastern Electric Reliability Council (SERC), which includes Entergy Gulf States' service territory. Several parties, including Entergy Gulf States and the PUCT staff, agreed to a non-unanimous settlement that was approved by the PUCT after a hearing in October 2001. In December 2001, the PUCT issued a written order approving the settlement. The settlement agreement contains several points, including:
In February 2005, bills were submitted in the Texas Legislature that would clarify that Entergy Gulf States through December 31, 2001 if a rate proceeding is initiated for Entergy Gulf States during the delay period. The settlement agreement provides forno longer subject to a rate freeze during the delay period. Entergy cannot predict whether a new rate proceeding for Entergy Gulf States will be initiated during the delay period or what the outcome of such proceeding might be;
Louisiana
In November 2001, the LPSC decided not to develop market protocols to support retail open access;
In February 2002, certain cities in Texas (cities) served by Entergy Gulf States filed a petition in district court in Travis County, Texas seeking judicial review of the order issued by the PUCT. The cities' petition alleges that the PUCT's order is unlawful becauseinformation it violates statutory and constitutional provisions. Entergy will defend vigorously its position that the cities' claims are without merit. Management cannot predict the outcome of this litigation at this time.received.
BusinessJurisdictional Separation Plan
Pursuit of Entergy Gulf States' business separation plan mandated by Texas law in connection with retail open access in the Texas service territory has been complicated by the existence of retail operations in Louisiana subject to the jurisdiction of the LPSC. During the course of Entergy Gulf States' retail open access proceedings with the PUCT, the LPSC has been holding independent proceedings concerning the proposed separation of Entergy Gulf States' business. Unlike the plan filed with the PUCT in 2000 (and amended through 2001), discussed below, to separate Entergy Gulf States' Texas generation, transmission, distribution, and retail electric functions into separate companies, the investigation recently initiated in the LPSC proceedings is evaluating a jurisdictional split of Entergy Gulf States into a Louisiana company and a Texas company. In a status conference held in September 2004 before an ALJ, the LPSC staff asserted that uncertainty with respect to retail open access in Texas should not control whether or when the LPSC should require the jurisdictional separation of Entergy Gulf States and recommended that an investigation concerning the proposed jurisdictional separation proceed. Entergy Gulf States submitted a preliminary methodology developed by Entergy for the jurisdictional separation of Entergy Gulf States if the regulators should determine that a jurisdictional separation is in the public interest. Although it contains many components that are similar to those set forth in the business separation plan filed with the PUCT, the preliminary methodology filed with the LPSC provides for the separation of Entergy Gulf States into a Louisiana vertically integrated utility company and a Texas vertically integrated utility company; rather than the separation of Entergy Gulf States' Texas generation, transmission, distribution, and retail electric functions into separate companies as is envisioned in the plan filed with the PUCT. A procedural schedule was established in the status conference that sets discovery through February 2005, testimony through the first half of June 2005, and a hearing beginning later in June 2005. Approvals of the FERC, the SEC, the PUCT, and the NRC may also be required for certain matters before any implementation of the jurisdictional separation of Entergy Gulf States.
Business Separation Plan under the Texas Retail Open Access Law
Entergy Gulf States' business separation plan for Texas retail open access developed pursuant to the Texas restructuring law provides for the separation of its generation, transmission, distribution, and retail electric functions.functions into separate companies. It has been amended during the course of various PUCT and LPSC proceedings and is subject to further change and regulatory proceedings. Entergy Gulf States filed the business separation plan with the PUCT in January 2000 and amended that plan in June and November 2000 and January 2001. In July 2000, the PUCT approved the amended business separation plan in an interim order. In December 2001, the PUCT abated the proceeding and indicated it will consider a final order in a timely manner consistent with a settlement agreement delaying retail open access. The outcome of the LPSC proceedings as described below.below, which have resulted in amendments to the plan beyond what was approved by the PUCT, have been and will continue to be reported to the PUCT and the Office of Public Utility Counsel and may require additional PUCT action before the business separation plan could become final.
The LPSC opened a docket to identify the changes in corporate structure and operations of Entergy Gulf States, and their potential impact on Louisiana retail ratepayers, resulting from restructuring in Texas. In those proceedings, Entergy Gulf States and the LPSC staff reached a settlement on certain Texas business separation plan issues, and after a May 2001 hearing, the LPSC issued an interim order in July 2001 approving the settlement. In July 2001, Entergy Gulf States and the LPSC Staff completed an additional settlement on business separation plan issues relating to the separation of Texas distribution and transmission. A hearing on the distribution and transmission settlement was held and the LPSC approved the settlement in September 2001. Issues related to the separation of generation are still unresolved.
The amended plan currentlyapproved by the LPSC in September 2001 provides that Entergy Gulf States will be separated into the following principal companies:companies if retail open access were to commence in Texas:
Pursuant to the LPSC-approved plan, Entergy Gulf States-Louisiana will:would:
Entergy Gulf States' assets and liabilities (other than its long-term debt and liabilities) will be allocated among these companies generally based upon categorizing them by function. Entergy Gulf States will allocate assets and liabilities not associated with a single function based upon specified factors. In an April 2001 filing with the LPSC discussing its separation methodology, Entergy Gulf States included a balance sheet separated by jurisdiction and function. The balance sheet was based on September 30, 1999 balances. In this balance sheet, Entergy Gulf States allocated approximately 27% of the net utility plant balance to Texas generation, approximately 12% to Texas distribution, approximately 6% to Texas transmission, approximately 7% to Louisiana transmission, and less than 1% to Texas retail. Applying these percentages to Entergy Gulf States' December 31, 2002 net utility plant book value of $4.4 billion, for illustrative purposes only, results in net book values of approximately $1.2 billio n for Texas generation, approximately $520 million for Texas distribution, approximately $260 million for Texas transmission, approximately $300 million for Louisiana transmission, approximately $20 million for Texas retail, and approximately $2.1 billion for the remainder of Entergy Gulf States-Louisiana. The actual allocations could materially differ from these figures because of a number of factors, including changes to the plan and the allocation methodology. In addition, the actual allocations will be based on allocation factors and account balances as of a different date.
The business separation plan provides that Entergy Gulf States-Louisiana will retain liability for all of its long-term debt and liabilities and that the property transferred to the Texas companies will be released from the lien of Entergy Gulf States' mortgage on the basis of property additions. Pursuant to separate agreements, the Texas distribution company and the intermediate transmission company will each assume a portion of Entergy Gulf States' long-term debt and liabilities, which assumptions will not act to release Entergy Gulf States-Louisiana's liability. The Texas distribution company and the intermediate transmission company will undertake to pay the outstanding assumed long-term debt and liabilities within 1 year and 3 years, respectively, of the assumption. Entergy must provide a contingent indemnity with respect to the intermediate transmission company's assumed portion of Entergy Gulf States' long-term debt and liabilities in the event that the obligations under the debt assumption agreeme nt have not been extinguished within one year of the assumption. The Texas generation company will be required to pay an allocated portion of the outstanding principal amount of Entergy Gulf States' long-term debt and liabilities each time that Texas generating assets are transferred to it, and the transfers must be completed within 3 years of the commencement of retail open access.
After the transfer of the Texas distribution and transmission assets contemplated by the current business separation plan, the distribution and transmission businesses conducted by the Texas distribution company and the intermediate transmission company, respectively, will continue to be regulated as to rates by the PUCT and the FERC, respectively. Accordingly, management believes that the Texas distribution company and the intermediate transmission company will be able to fund the payment of the assumed debt within the required period from a combination of cash flow from operations and third party financing.
Entergy Gulf States filed the business separation plan with the PUCT in January 2000 and amended that plan in June and November 2000 and January 2001. In July 2000, the PUCT approved the amended business separation plan in an interim order. In January 2001, the PUCT consolidated remaining action on the business separation plan into the unbundled cost of service proceeding discussed below. In December 2001, the PUCT abated the proceeding and indicated it will consider a final order in a timely manner consistent with the settlement agreement delaying retail open access. The outcome of the LPSC proceedings described below, which have resulted in amendments to the plan beyond what was approved by the PUCT, have been and will continue to be reported to the PUCT and the Office of Public Utility Counsel and may require additional PUCT action before the business separation plan is final.
The LPSC opened a docket to identify the changes in corporate structure and operations of Entergy Gulf States, and their potential impact on Louisiana retail ratepayers, resulting from restructuring in Texas and Arkansas. In those proceedings, Entergy Gulf States and the LPSC staff reached a settlement on certain Texas business separation plan issues described above, and after a May 2001 hearing, the LPSC issued an interim order in July 2001 approving the settlement. In July 2001, Entergy Gulf States and the LPSC staff completed an additional settlement on business separation plan issues relating to the separation of Texas distribution and transmission. A hearing on the distribution and transmission settlement has been held and the LPSC approved the settlement in September 2001. With respect to issues related to the separation of generation, the LPSC had scheduled a hearing in November 2001 to address settled issues. In light of the delay in the commencement of retail open access, the procedural schedul e in the LPSC docket has been suspended to assess the impact of the PUCT approval of the settlement agreement delaying retail open access.
Generation-related Issues
Regarding the generation-related issues referred to in the preceding paragraph, Entergy Gulf States has not yet reached agreement with the LPSC staff on certain matters related to the separation of the Texas generating assets. Entergy Gulf States has proposed that Texas generating assets be a jurisdictional portion (approximately 45 - 50%) of each generating plant and that Entergy Gulf States-Louisiana continue to operate the plants. Entergy Gulf States has also suggested that certain generating assets be allocated by specific plant such that the Texas generating assets have approximately the Texas jurisdictional portion of the capacity and value of all of Entergy Gulf States' generating assets.
Until the Texas generating assets are transferred to the Texas generation company, which, as currently proposed, will occur within three years from the commencement of retail open access in Texas, Entergy Gulf States-Louisiana expects to sell most of the Texas jurisdictional capacity and energy from these assets to the Texas generation company under a power sale agreement. The power sale agreement is expected to require the Texas generation company to pay all costs, including a reasonable return on equity, for the capacity and energy of the Texas generating assets. The Texas generation company is expected to sell most of this capacity and energy to Entergy's affiliated Texas retail electric providers at a negotiated rate and sell any remainder to the market. Entergy's affiliated Texas retail electric providers will use the capacity and energy to provide retail electric service to retail customers in Texas, including Entergy's price-to-beat obligation, which requires it to sell electricity to residential and small commercial customers in the service territory of the Texas distribution company at a rate equal to the existing base rates plus a fuel component.
Up to 20% of capacity and energy from the Texas generating assets must be sold to third parties under PUCT rules, or to Entergy's domestic utility companies that elect to purchase it, as described below:
Beginning on the date retail open access begins, the market power measures in the Texas restructuring law will prohibit the Texas generation company and its affiliates from owning and controlling more than 20% of the installed generation capacity located in, or capable of delivering electricity to, a power region. The implications of this limit are uncertain. It is possible that the Texas generation company (or its affiliates) could be required to auction additional capacity entitlements, divest some of the Texas generating assets, or seek other means of mitigation if it is found to have ownership and control in excess of this limit.
Other PUCT Restructuring-related Proceedings
In March 2001, Entergy Gulf States filed with the PUCT a non-unanimous settlement agreement in the unbundled cost proceeding that establishes the Texas distribution company's revenue requirement. The settlement agreement is between Entergy Gulf States, the PUCT staff, and other parties. Pursuant to a generic order by the PUCT, the Texas distribution company's allowed return on equity will be 11.25%. The capital structure prescribed by the PUCT is 60% debt and 40% equity. A rider to recover nuclear decommissioning costs will be implemented. Also in the settlement agreement, the parties agreed that Entergy Gulf States' Texas-jurisdictional stranded costs and benefits are $0, and no charge to recover stranded costs or credit to refund excess mitigation will be implemented. Entergy Gulf States agreed in the settlement to refund any excess earnings resulting from the restructuring law's annual report process for 2000 and 2001, which management does not expect to have a material financial effect. After a hea ring in April 2001, the PUCT voted to approve a rate order consistent with the terms of the settlement. A written interim order was signed in May 2001. In December 2001, the PUCT abated the proceeding and indicated its intent to defer a final ruling on this proceeding until a date closer to the commencement of retail open access.
The settlement that has delayed the commencement of retail open access requires a new power region certification proceeding for Entergy Gulf States' service territory in Texas. If Entergy Gulf States' power region in Texas is not certified by the PUCT before retail open access is introduced, Entergy's affiliated Texas retail electric provider could be required to maintain rates at the price-to-beat levels for residential and small commercial customers in Entergy Gulf States' service territory beyond January 1, 2007. Entergy's affiliated Texas retail electric provider could also be required to offer rates to industrial and large commercial customers in Entergy Gulf States' service territory that are no higher than the rates that, on a bundled basis, were in effect on January 1, 1999, subject to fuel factor adjustments. Entergy's affiliated Texas retail electric provider might also face requests for restrictions on its ability to compete for retail customers in parts of its power region in Texas outside of its current service area.
In July 2001, Entergy Gulf States filed an application for approval of the fuel factor portion of Entergy's affiliated Texas retail electric provider's price-to-beat rates, and the gas prices included in that filing were updated in October 2001. After the gas price update, Entergy Gulf States recommended that the PUCT approve an average fuel factor of approximately $29/MWh adjusted, if necessary, to maintain an adequate competitive margin. After hearing, an ALJ recommended in November 2002 a lower fuel factor than Entergy Gulf States requested. The PUCT has not taken final action on the ALJ's recommendation. In June 2001, Entergy Gulf States filed tariffs for the non-fuel component of the price-to-beat rates. The tariffs are based on Entergy Gulf States' current base rates. In September 2001, Entergy Gulf States entered into a unanimous settlement regarding the non-fuel component of price-to-beat rates. In February 2002, the PUCT voted to approve the settlement.
State and Local Rate Regulatory Risks
The rates that Entergy Gulf States charges for its services are an important item influencing its financial position, results of operations, and liquidity. Entergy Gulf States is closely regulated and the rates charged to its customers are determined in regulatory proceedings, except for a portion of its operations. Governmental agencies, the LPSC and the PUCT, are primarily responsible for approval of the rates charged to customers.
In December 2002, the LPSC approved a settlement between Entergy Gulf States and the LPSC staff pursuant to which Entergy Gulf States agreed to make a base rate refund of $16.3 million, including interest, and to implement a $22.1 million prospective base rate reduction effective January 2003. The settlement discharged any potential liability relating to remaining issues that arose in Entergy Gulf States' fourth, fifth, sixth, seventh, and eighth earnings reviews. Entergy Gulf States made the refund in February 2003. In addition to resolving and discharging all liability associated with the fourth through eighth earnings reviews, the settlement provides that Entergy Gulf States shall be authorized to continue to reflect in rates a ROE of 11.1% until a different ROE is authorized by a final resolution disposing of all issues in the proceeding that was commenced with Entergy Gulf States' May 2002 filing.
In May 2002, Entergy Gulf States filed its ninth and last required post-merger analysis with the LPSC. The filing included an earnings review filing for the 2001 test year that resulted in a rate decrease of $11.5 million, which was implemented effective June 2002. The filing also contained a prospective revenue requirement study based on the 2001 test year that showed that a prospective rate increase of approximately $21.7 million would be appropriate. Both components of the filing are subject to review by the LPSC and may result in changes in rates other than those sought in the filing. A procedural schedule has been adopted and hearings are scheduled for October 2003.
In addition to rate proceedings, Entergy Gulf States' fuel costs recovered from customers are subject to regulatory scrutiny. In January 2003, the LPSC opened a docket to investigate the fuel adjustment clause practices of Entergy Gulf States and its affiliates. The investigation will include a review of the reasonableness of charges flowed by Entergy Gulf States through its fuel adjustment clause in Louisiana for the period subsequent to 1994. No assurance can be given as to the timing or outcome of this proceeding.
Entergy Gulf States' retail rate matters and proceedings, including fuel cost recovery-related issues, are discussed in Note 2 to the domestic utility companies and System Energy financial statements.
System Agreement Proceedings
The System Agreement provides fordomestic utility companies historically have engaged in the integratedcoordinated planning, construction, and operation of Entergy's electric generationgenerating and transmission assets throughoutfacilities under the retail service territoriesterms of an agreement called the System Agreement that has been approved by the FERC. Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies. Under the termscompanies in their execution of the System Agreement, generating capacity and other power resources are jointly operated by the domestic utility companies. Theseek support for local regulatory authority over System Agreement provides, among other things, that parties having generating reserves greater than their load requirements (long companies) shall receive payments from those parties having deficienciesissues.
In February 2004, a FERC ALJ issued an Initial Decision in generating reserves (short companies). Such payments are 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 and preference stock, and a fair rate of return on common equity investment. Under the System Agreement, these charges are based on costs associated with the long companies' steam electric generating units fueled by oil or gas. In addition, for all energy exchanged among the domestic utility companies under the System Agreement, the short companies are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
The LPSC and the Council commenced aLPSC-initiated proceeding at FERCthe FERC. The Initial Decision decided some issues in June 2001. In this proceeding, the LPSC and the Council allege that the rough production cost equalization required by FERC under the System Agreement and the Unit Power Sales Agreement has been disrupted by changed circumstances. The LPSC and the Council have requested that FERC amend the System Agreement or the Unit Power Sales Agreement or both to achieve full production cost equalization or to restore rough production cost equalization. Their complaint does not seek a change in the total amountfavor of the costs allocated by either the System Agreement or the Unit Power Sales Agreement. In addition, the LPSC and the Council allege that provisions of the System Agreement relating to minimum run and must run units, the methodology of billing versus dispatch, and the use of a rolling twelve-month average of system peaks, increase costs paid by ratepayers in the LPSC and Council's jurisdictions. Several parties have filed interventions in the proceed ing, including the APSC and the MPSC. Entergy filed its response to the complaint in July 2001 denying the allegations of the LPSC and the Council. The APSC and the MPSC also filed responses opposing the relief sought by the LPSC, and decided some issues against the Council.
In their complaint,relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the Council allegeFERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Gulf States' Louisiana annualLouisiana's production costs over the period 2002 to 2007 will be $11 million to $87 million over the average for the domestic utility companies. This rangepurposes of results is a function of assumptions regarding such things as future natural gas prices, the future market price of electricity, and other factors. In February 2002, the FERC set the matter for hearing and established a refund effective period consisting of the 15 months following September 13, 2001. Negotiations among the parties have not resolved the proceeding,calculating relative production costs; and the proceeding is now set for hearing commencing in June 2003. The case had been set for trial commencing in February 2003. The extensionInitial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the schedule also extendedcurrent method.
If the refund effective period by 120 days. If FERC grants the relief requested by the LPSC andin the Council,proceeding, the relief may resu ltresult in a material increase in the total production costs allocatedthe FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs allocatedthe FERC allocates to companies whose costs currently are projected to exceed that average. If the average. FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility compan ies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.
An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu duri ng the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:
| Average Annual | ||
(In Millions) | (In Millions) | ||
Entergy Arkansas | $154 to $281 | $215 | |
Entergy Gulf States | ($130) to ($15) | ($63) | |
Entergy Louisiana | ($199) to ($98) | ($141) | |
Entergy Mississippi | ($16) to $8 | $1 | |
Entergy New Orleans | ($17) to ($5) | ($12) |
Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. Therefore, managementAlthough the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy Gulf States does not believe that this proceedingthe ultimate resolution of these proceedings will have a material effect on theits financial condition or results of Entergy Gulf States, although neitheroperation.
In February 2004, the timing norAPSC issued an "Order of Investigation," in which it discusses the outcomenegative effect that implementation of the proceedingsFERC ALJ's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the ALJ's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; an d states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate.
In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the ALJ's Initial Decision in the System Agreement proceeding at the FERC, can be predicted atthat the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations.
In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this time.requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Louisiana, as well as t he named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity.
The LPSC has instituted a companion ex parteex-parte System Agreement investigation to litigate several of the System Agreement issues that the LPSC is litigating before the FERC in the previously discussed System Agreement proceeding. This companion proceeding will require the LPSC to interpret various provisions of the System Agreement, including those relating to minimum runminimum-run and must runmust-run units, the propriety of the methods used for billing and dispatch on the Entergy System, and the use of a rolling, twelve-month average of system peaks for allocating certain costs. In addition, by this companion proceeding the LPSC is questioning whether Entergy Louisiana and Entergy Gulf States were prudent for not seeking changes to the System Agreement previously, so as to lower costs imposed upon their ratepayers and to increase costs imposed upon ratepayers of other domestic utility companies. The LPSC staff has filed testimony suggesting that the remedy for the alleged imprudence of Entergy Louisiana and Entergy Gulf States should be a reduction in allowed rate of return on common equity of 100 basis points. The domestic uti lityutility companies have challenged the propriety of the LPSC's litigating System Agreement issues. Nevertheless, inon January 16, 2002 the LPSC affirmed a decision of its ALJ upholding the LPSC staff's right to litigate System Agreement issues at the LPSC, rather than before the FERC. The procedural schedule is suspended at this time and an evidentiary hearing is not scheduled. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting FERC rate schedules that are part of the System Agreement, and from subsequently enforcing that interpretation. The LPSC interpreted a System Agreement rate schedule in the unrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed. In 2003, the U.S. Supreme Court ruled in Entergy Louisiana's favor and reve rsed the decisions of the LPSC and the Louisiana Supreme Court.
Transmission
In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs.
In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations.
Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences.
In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the petition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005.
In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion o f the proposal currently scheduled for August 2005.
Interconnection Orders
The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos, including $28 million for Entergy Gulf States. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy. To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators.
Available Flowgate Capacity Proceeding
On December 17, 2004, the FERC issued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised in a FERC audit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC program, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory.
Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy.
Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the AFC proceeding is currently scheduled to commence in August 2005.
State and Local Rate Regulatory Risks
The rates that Entergy Gulf States charges for its services are an important item influencing its financial position, results of operations, and liquidity. Entergy Gulf States is closely regulated and the rates charged to its customers are determined in regulatory proceedings, except for a portion of its operations. Governmental agencies, the LPSC and the PUCT, are primarily responsible for approval of the rates charged to customers.
Entergy Gulf States is operating in Texas under the terms of a December 2001 settlement agreement approved by the PUCT. The settlement provided for a base rate freeze that has remained in effect during the delay in the implementation of retail open access in Entergy Gulf States' Texas service territory. In view of the PUCT order in July 2004 to further delay retail open access in the Texas service territory, Entergy Gulf States filed a retail electric rate case and fuel reconciliation proceeding with the PUCT in August 2004 seeking the following:
In addition, Entergy Gulf States' fuel reconciliation filing made in conjunction with the base rate case sought to reconcile approximately $288 million in fuel and purchased power costs incurred during the period September 2003 through March 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case and fuel reconciliation proceeding indicating that Entergy Gulf States is still subject to a rate freeze based on an agreement, approved by PUCT order in 2001, stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless the rate freeze is lifted by the PUCT prior thereto. Entergy Gulf States believes the PUCT has misinterpreted the settlement and has appealed the PUCT order to the Travis County District Court and intends to pursue other available remedies.
Dismissal of Entergy Gulf States' rate case does not preclude it from seeking recovery of the transition to competition costs when the rate freeze is no longer in effect. Similarly, the dismissal of the rate case does not preclude Entergy Gulf States from seeking the reconciliation of fuel and purchased power costs of $288 million for the period September 2003 through March 2004 when, at the appropriate time, similar costs are reconciled in the future. As discussed above, in February 2005, bills were submitted in the Texas Legislature that would clarify that Entergy Gulf States is no longer subject to a rate freeze and specify that retail open access will not commence in Entergy Gulf States' Texas service territory until the PUCT certifies a power region.
In September 2002,2004, the LPSC consolidated various dockets that were the subject of settlement discussions between the LPSC staff and Entergy Gulf States and Entergy Louisiana. The LPSC directed its staff to continue the settlement discussions and submit any proposed settlement to the LPSC for its consideration. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a motionproposed settlement that currently includes an offer to Delay Hearingrefund $76 million to Entergy Gulf States' Louisiana customers, with no immediate change in current base rates. If the LPSC approves the proposed settlement, Entergy Gulf States will be regulated under a three-year formula rate plan that, among other provisions, establishes a ROE mid-point of 10.65% and Remaining Pre-Hearing deadlines. After no objectionspermits Entergy Gulf States to recover incremental capacity costs without filing a traditional base rate proceeding. The settlement resolves all issues in, and will result in the dismissal of, Entergy Gulf States' four th, fifth, sixth, seventh, and eighth annual earnings reviews, Entergy Gulf States' ninth post-merger earnings review and revenue requirement analysis, a fuel review for Entergy Gulf States, dockets established to consider issues concerning power purchases for both Entergy Gulf States and Entergy Louisiana for the summers of 2001, 2002, 2003, and 2004, and a docket concerning retail issues arising under the Entergy System Agreement. The settlement does not include the System Agreement case pending at FERC. The LPSC has solicited comments on the proposed settlement from the other parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC ALJ continuedfor consideration on March 23, 2005. Refer to Note 2 to the procedural schedule until afterdomestic utility and System Entergy financial statements for details of the FERC ALJ's initial decisionproceedings included in the related matter, or June 13, 2003, whichever occurs first.proposed settlement.
In July 2004, Entergy Gulf States filed with the LPSC an application for a change in its gas base rates and charges seeking an increase of $9.1 million. Entergy Gulf States also is seeking approval of certain proposed rate design, rate schedule, and policy changes. Discovery is underway, and a decision is expected during the third quarter of 2005.
In addition to rate proceedings, Entergy Gulf States' fuel costs recovered from customers are subject to regulatory scrutiny. Entergy Gulf States' retail rate matters and proceedings, including fuel cost recovery-related issues, are discussed in Note 2 to the domestic utility companies and System Energy financial statements.
Industrial, Commercial, and Wholesale Customers
Entergy Gulf States' large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Gulf States' industrial customer base. Entergy Gulf States responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that provide service at rates lower than would otherwise be charged.match specific customer needs and load profiles. Despite these actions, Entergy Gulf States lost twoexpects to lose one large industrial customerscustomer to cogeneration in 2002. The customers accounted2005. Current sales to that customer account for approximately 1%$12 million of itsEntergy Gulf States' net revenue in 2001. In addition to working with its current customers,annually. Entergy Gulf States also continuallyactively participates in economic development, customer retention, and reclamation activities that canto increase industrial and commercial energy demand, from both new and existing customers. Entergy Gulf States does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and newEntergy Gulf States' marketing efforts in retaining industrial customers.
Market and Credit Risks
Entergy Gulf States has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.
Interest Rate and Equity Price Risk - Decommissioning Trust Funds
Entergy Gulf States' nuclear decommissioning trust funds expose it to fluctuations in equity prices and interest rates. The NRC requires Entergy Gulf States to maintain trusts to fund the costs of decommissioning River Bend. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the River Bend trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Note 9Notes 1, 8, and 12 to the domestic utility companies and System Energy financial statements.
Foreign Currency Exchange Rate Risk
Entergy Gulf States entered into foreign currency forward contracts to hedge the Euro-denominated payments due under certain purchase contracts. As of December 31, 2002, the total notional amount of the foreign currency forward contracts is 33.7 million Euro and the forward currency rates range from .8742 to .8802. The maturities of these forward contracts depend on the purchase contract payment dates and range in time from January 2003 to July 2004. The mark-to-market valuation of the forward contracts at December 31, 2002 was a net asset of $5.5 million. The counterparty bank obligated on 16.5 million Euro of the notional amount of these agreements is rated by Standard & Poor's Rating Services at A+ on their senior debt obligations as of December 31, 2002. The counterparty bank obligated on 17.2 million Euro of the notional amount of these agreements is rated by Standard & Poor's Rating Services at AA on its senior debt obligations as of December 31, 2002.
Nuclear Matters
Entergy Gulf States owns and operates, through an affiliate, the River Bend.Bend nuclear power plant. Entergy Gulf States 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, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of River Bend, Entergy Gulf States may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
Environmental Risks
Entergy Gulf States' facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Gulf States 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.
Litigation Risks
The states of Louisiana and Texas in which Entergy Gulf States operates 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 Gulf States uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment in these states poses a significant business risk.
Critical Accounting Estimates
The preparation of Entergy Gulf States' 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 accounting estimates because they are based on assumptions and measurements that involve an unusuala high degree of uncertainty, and there is the potential that differentfor future changes in the assumptions and measurements could produce estimates that are significantly different than those recorded inwould have a material effect on the presentation of Entergy Gulf States' financial statements.
position or results of operations.
Nuclear Decommissioning Costs
Regulations require thatEntergy Gulf States to decommission the River Bend be decommissionednuclear power plant after the facility is taken out of service, and funds aremoney is collected and deposited in trust funds during the facility's operating life in order to provide for this obligation. Entergy Gulf States conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facility. See Note 9 to the domestic utility companies and System Energy financial statements for details regarding Entergy Gulf States' most recent study and the obligations recorded by Entergy Gulf States related to decommissioning. The following key assumptions have a significant effect on these estimates:
Entergy Gulf States collects the projected costs of decommissioning River Bend through rates charged to customers for the portion of the plant subject to cost-based ratemaking. The amounts collected through rates, which are based upon decommissioning cost studies, are deposited in decommissioning trust funds. In December 2002, decommissioning collections from customers for the Louisiana-regulated portion of River Bend waswere suspended as a result of the settlement with the LPSC of Entergy Gulf States' fourth through eighth earnings reviews. Decommissioning costs have no impact on Entergy Gulf States' earnings, as accrued costs are offset by earnings on trust funds and collections from customers. If decommissioning cost study estimates wereare changed and approved by regulators, collections from customers would also change.
Approximately half of River Bend is not subject to cost-based ratemaking. When Entergy Gulf States purchasedacquired the 30% share of River Bend formerly owned by Cajun, Entergy Gulf States obtained decommissioning trust funds of $132 million, which have since grown to $158 million. Entergy Gulf States believes that these funds will be sufficient to cover the costs of decommissioning this portion of River Bend, and no further collections or deposits are being made for these costs. Additionally, under the Deregulated Asset Plan in the Louisiana jurisdiction of Entergy Gulf States, a portion of River Bend (approximately 16% of its total capacity) is excluded from rate base, and no amounts have been or are being collected from customers for decommissioning for this portion of the plant.
The obligations recorded by Entergy Gulf States for decommissioning are classified either as a component of accumulated depreciation (the regulated portion of River Bend) or as a deferred credit (the nonregulated portion of River Bend) in the line item entitled "Decommissioning." The amounts recorded for these obligations are comprised of collections from customers and earnings on the trust funds. The classification and recording of these obligations will change with the implementation of SFAS 143.
SFAS 143
Entergy Gulf States implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy Gulf States' asset retirement obligations, and the measurement and recording of Entergy Gulf States' decommissioning obligations outlined above will changechanged significantly with the implementation of SFAS 143. The most significant differences in the measurement of these obligations are outlined below:
The net effect of implementing this standardSFAS 143 for the portion of River Bend subject to cost-based ratemaking will bewas recorded as a regulatory asset, or liability, with no resulting impact on Entergy Gulf States' net income. TheEntergy Gulf States recorded this regulatory asset because its existing rate mechanism is based on the original or historical cost standard that allows Entergy Gulf States to recover all ultimate costs of decommissioning existing assets from current and future customers. Upon implementation of SFAS 143 is expected to result in increases in2003, assets and liabilities in 2003 of approximately $165 million and $190 million, respectively,increased as a result of recordingincreasing the asset retirement obligation atby $129 million to its fair value as determined under SFAS 143, reducing accumulated depreciation by $63 million, and recording the related regulatory asset. Earnings are expectedasset of $32 million. The net effect of implementing SFAS 143 for the portion of River Bend not subject to cost-based ratemaking resulted in an earnings decrease by $25of $21 million net-of-tax as a result of a one-time cumulative effect of accounting change.
In the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected an expected life extension for the plant. The revised estimate resulted in a $166.4 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $49.6 million reduction in non-utility property, a $40.1 million reduction in the related regulatory asset, and a regulatory liability of $17.7 million. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million.
Application of SFAS 71
The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation," has a significant and pervasive impact on accounting and reporting for Entergy Gulf States.
Entergy Gulf States' financial statements primarily reflect assets and costs based on existing cost-based ratemaking regulation in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Under traditional ratemaking practice, Entergy Gulf States is granted a geographic franchise to sell electricity. In return, Entergy Gulf States must make investments and incur obligations to serve customers. Prudently incurred costs are recovered from customers along with a return on investment. Regulators may require Entergy Gulf States to defer collecting from customers some operating costs until a future date. These deferred costs are recorded as regulatory assets in the financial statements. In order to continue applying SFAS 71 to its financial statements, Entergy Gulf States' rates must be set on a cost-of-service basis by an authorized body and the rates must be charged to and collected from customers.
AsIf the generation portion of thea utility industrycompany moves toward competition, it is likelypossible that generation rates will no longer be set on a cost-of-service basis. WhenIf that occurs, the generation portion of the business could be required to discontinue application of SFAS 71. The result of discontinuing application of SFAS 71 would be the removal of regulatory assets and liabilities from the balance sheet, and could include the recording of asset impairments. This result is because some of the costs or commitments incurred under a regulated pricing system might be impaired or not recovered in a competitive market. These costs are referred to as stranded costs.
Unbilled Revenue
Retail open access legislationAs discussed in Note 1 to the domestic utility companies and System Energy financial statements, Entergy Gulf States 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 place in Texas, but the implementation of retail open accessthat month, including fuel price in Entergy Gulf States' territory is likely delayed untilLouisiana jurisdiction. Therefore, revenue recognized may be affected by the estimated price and usage at least the first quarterbeginning and end of 2004. Several proceedings necessaryeach period and fuel price fluctuations, in addition to implement retail open access are still pending, including proceedings to implement Entergy Gulf States' business separation plan, and to form an RTO or pursue retail open accesschanges in the absence of an RTO in Entergy Gulf States' Texas service area. In addition, the LPSC has not approved for the Louisiana jurisdictional operations the transfer of generation assets to, or a power purchase agreement with, Entergy's Texas generation company. Therefore, neither the necessary regulatory actions nor the opportunity for a reasonable determinationcertain components of the effectcalculation including changes to estimates such as line loss, which affects the estimate of deregulation has occurred that are prerequisites for Entergy Gulf States to discontinueunbilled customer usage, and assumptions regarding price such as the application of regulatory accounting principles to its Texas generation operation. For further information on Gulf States' retail open access law, see "Transition to Retail Competition" below.
fuel cost recovery mechanism.
Pension and Other Postretirement Benefits
Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 1110 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and poorworse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt.debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 7.5% in 2000 and 2001 to 6.75% in 2002.2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rates fromrate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to a range of 8%10% increase in health care costs in 2005 gradually decreasing to 5%each successive year, until it reaches a 4.5% annual increase in 2001 to a range of 10% gradually decreasing to 4.5%health care costs in 2002.2011 and beyond.
In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities, and 35%4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities and 49% fixed income securities. Based on recent market trends, Entergy decreasedreduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 9% in 2000 and 2001 to 8.75% for 2002. The trend of reduced inflation caused Entergy2002 and 2003 to reduce its8.5% in 2004. The assumed rate of increase in future compensation levels from 4.6% in 2000 and 2001used to calculate benefit obligations was 3.25% in 2002.
2002, 2003, and 2004.
Cost Sensitivity
The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (in(dollars in thousands):
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The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (in(dollars in thousands):
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| $847 |
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Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
In accordance with SFAS No. 87, "Employers' Accounting for Pensions," 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 cost 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, Entergy smoothesaccounts for the impact of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87.
Costs and Funding
Total pension incomecost for Entergy Gulf States in 20022004 was $6.8$0.4 million. Taking into account asset performance and the changes made in the actuarial assumptions, Entergy Gulf States does not anticipate 2003anticipates 2005 pension incomecost to be materially different from 2002.increase to $7.3 million due to decrease in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. Entergy Gulf States was not required to make contributionscontributed $17 thousand to its pension plan in 2004, and anticipates making $18.9 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, partially offset by the Pension Funding Equity Act relief passed in April 2004.
At December 31, 2003 and does not anticipate funding in 2003.
Due to negative pension plan asset returns over the past several years,2004, Entergy Gulf States' accumulated benefit obligation at December 31, 2002 exceededwas less than plan assets. As a result, Entergy Gulf Statesassets, therefore there was no additional minimum pension liability required to recognize an additional minimum liability of $7.1 million as prescribed by SFAS 87. Entergy Gulf States recorded an intangible asset for the $7.1 million of unrecognized prior service cost.be recognized. Net income for 2004, 2003, and 2002 was not impacted.
Totalpostretirement health care and life insurance benefit costsfor Entergy Gulf States in 2004 were $17.6 million, including $4.4 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Gulf States expects 2005 postretirement health care and life insurance benefit costs for Entergy Gulf Statesto be approximately $19.6 million, including $5.1 million in 2002 were $15.9 million. Becausesavings due to the estimated effect of a number of factors, includingfuture Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the increaseddecrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate Entergy Gulf States expects 2003 costsused to approximate $19.1 million.calculate benefit obligations.
REPORT OF INDEPENDENT AUDITORS' REPORT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Entergy Gulf States, Inc.:
We have audited the accompanying balance sheets of Entergy Gulf States, Inc. as of December 31, 20022004 and 2001,2003, and the related statements of income, retained earnings and comprehensive income, and cash flows (pages 176194 through 180198 and applicable items in pages 250284 through 303)348) for each of the three years in the period ended December 31, 2002.2004. 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 auditing standards generally accepted inof the United States of America.Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Gulf States, Inc. as of December 31, 20022004 and 2001,2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20022004 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 5 and Note 8 to the notes to respective financial statements, in 2003 Entergy Gulf States, Inc. adopted the provisions of Statement of Financial Accounting Standards Board Interpretation No. 46,Consolidation of Variable Interest Entities,and Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control - - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 2003
March 8, 2005
ENTERGY GULF STATES, INC. | ||||||
INCOME STATEMENTS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
OPERATING REVENUES | ||||||
Domestic electric | $2,821,296 | $2,579,916 | $2,141,873 | |||
Natural gas | 61,088 | 59,821 | 42,006 | |||
TOTAL | 2,882,384 | 2,639,737 | 2,183,879 | |||
OPERATING EXPENSES | ||||||
Operation and Maintenance: | ||||||
Fuel, fuel-related expenses, and | ||||||
gas purchased for resale | 772,914 | 693,612 | 692,901 | |||
Purchased power | 969,779 | 838,498 | 368,140 | |||
Nuclear refueling outage expenses | 15,969 | 14,045 | 12,190 | |||
Other operation and maintenance | 445,413 | 457,428 | 438,259 | |||
Decommissioning | 13,645 | 14,268 | 3,980 | |||
Taxes other than income taxes | 118,081 | 117,009 | 120,295 | |||
Depreciation and amortization | 197,234 | 199,583 | 204,202 | |||
Other regulatory credits - net | (10,070) | (2,476) | (7,818) | |||
TOTAL | 2,522,965 | 2,331,967 | 1,832,149 | |||
OPERATING INCOME | 359,419 | 307,770 | 351,730 | |||
OTHER INCOME (DEDUCTIONS) | ||||||
Allowance for equity funds used during construction | 13,027 | 15,855 | 11,010 | |||
Interest and dividend income | 15,753 | 17,902 | 8,866 | |||
Miscellaneous - net | 36,180 | (109,389) | 3,560 | |||
TOTAL | 64,960 | (75,632) | 23,436 | |||
INTEREST AND OTHER CHARGES | ||||||
Interest on long-term debt | 125,356 | 148,516 | 139,343 | |||
Other interest - net | 8,242 | 8,827 | 5,497 | |||
Allowance for borrowed funds used during construction | (9,771) | (13,349) | (9,749) | |||
TOTAL | 123,827 | 143,994 | 135,091 | |||
INCOME BEFORE INCOME TAXES AND | ||||||
CUMULATIVE EFFECT OF ACCOUNTING CHANGE | 300,552 | 88,144 | 240,075 | |||
Income taxes | 108,288 | 24,249 | 65,997 | |||
INCOME BEFORE CUMULATIVE EFFECT | ||||||
OF ACCOUNTING CHANGE | 192,264 | 63,895 | 174,078 | |||
CUMULATIVE EFFECT OF ACCOUNTING | ||||||
CHANGE (net of income taxes of $12,713) | - - | (21,333) | - - | |||
NET INCOME | 192,264 | 42,562 | 174,078 | |||
Preferred dividend requirements and other | 4,472 | 4,701 | 4,888 | |||
EARNINGS APPLICABLE TO | ||||||
COMMON STOCK | $187,792 | $37,861 | $169,190 | |||
See Notes to Respective Financial Statements. | ||||||
ENTERGY GULF STATES, INC. | ||||||
STATEMENTS OF CASH FLOWS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
OPERATING ACTIVITIES | ||||||
Net income | $192,264 | $42,562 | $174,078 | |||
Adjustments to reconcile net income to net cash flow provided by operating activities: | ||||||
Reserve for regulatory adjustments | 24,112 | 12,605 | 11,147 | |||
Other regulatory credits - net | (10,070) | (2,476) | (7,818) | |||
Depreciation, amortization, and decommissioning | 210,879 | 213,851 | 208,182 | |||
Deferred income taxes and investment tax credits | 57,908 | 24,574 | (11,576) | |||
Cumulative effect of accounting change | - | 21,333 | - | |||
Changes in working capital: | ||||||
Receivables | 14,774 | (96,409) | 18,155 | |||
Fuel inventory | 1,205 | (1,469) | 4,617 | |||
Accounts payable | 59,846 | (17,013) | 83,428 | |||
Taxes accrued | 99,955 | 12,618 | (24,740) | |||
Interest accrued | (3,834) | (1,900) | (4,544) | |||
Deferred fuel costs | 78,200 | 59,165 | 65,556 | |||
Other working capital accounts | 7,426 | 11,874 | (19,551) | |||
Provision for estimated losses and reserves | (13,844) | 115,878 | 1,478 | |||
Changes in other regulatory assets | (10,060) | 3,983 | (51,490) | |||
Other | (59,303) | 26,787 | 53,732 | |||
Net cash flow provided by operating activities | 649,458 | 425,963 | 500,654 | |||
INVESTING ACTIVITIES | ||||||
Construction expenditures | (357,720) | (348,507) | (355,334) | |||
Allowance for equity funds used during construction | 13,027 | 15,855 | 11,010 | |||
Nuclear fuel purchases | (45,085) | (39,959) | (21,820) | |||
Proceeds from sale/leaseback of nuclear fuel | 38,800 | 38,029 | 21,923 | |||
Decommissioning trust contributions and realized | ||||||
change in trust assets | (12,070) | (11,428) | (12,488) | |||
Changes in other temporary investments - net | 23,579 | (23,579) | 44,643 | |||
Other regulatory investments | (49,875) | (77,050) | (39,390) | |||
Net cash flow used in investing activities | (389,344) | (446,639) | (351,456) | |||
FINANCING ACTIVITIES | ||||||
Proceeds from the issuance of long-term debt | 472,039 | 1,032,682 | 337,481 | |||
Retirement of long-term debt | (829,000) | (1,048,129) | (194,057) | |||
Redemption of preferred stock | (3,450) | (3,450) | (1,858) | |||
Dividends paid: | ||||||
Common stock | (94,300) | (68,100) | (91,200) | |||
Preferred stock | (4,459) | (4,701) | (4,888) | |||
Net cash flow provided by (used in) financing activities | (459,170) | (91,698) | 45,478 | |||
Net increase (decrease) in cash and cash equivalents | (199,056) | (112,374) | 194,676 | |||
Cash and cash equivalents at beginning of period | 206,030 | 318,404 | 123,728 | |||
Cash and cash equivalents at end of period | $6,974 | $206,030 | $318,404 | |||
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||
Cash paid/(received) during the period for: | ||||||
Interest - net of amount capitalized | $130,491 | $152,655 | $143,961 | |||
Income taxes | ($28,169) | ($30,987) | $98,734 | |||
See Notes to Respective Financial Statements. |
ENTERGY GULF STATES, INC. INCOME STATEMENTS For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING REVENUES Domestic electric $2,141,873 $2,590,836 $2,470,884 Natural gas 42,006 57,724 40,356 ---------- ---------- ---------- TOTAL 2,183,879 2,648,560 2,511,240 ---------- ---------- ---------- OPERATING EXPENSES Operation and Maintenance: Fuel, fuel-related expenses, and gas purchased for resale 692,901 1,061,037 895,361 Purchased power 368,140 467,196 455,300 Nuclear refueling outage expenses 12,190 11,159 16,663 Other operation and maintenance 438,259 422,667 423,031 Decommissioning 3,980 6,247 6,273 Taxes other than income taxes 120,295 118,670 120,428 Depreciation and amortization 204,202 191,120 189,149 Other regulatory credits - net (7,818) (26,728) (8,254) ---------- ---------- ---------- TOTAL 1,832,149 2,251,368 2,097,951 ---------- ---------- ---------- OPERATING INCOME 351,730 397,192 413,289 ---------- ---------- ---------- OTHER INCOME Allowance for equity funds used during construction 11,010 9,248 7,617 Gain on sale of assets 3,409 2,454 2,327 Interest and dividend income 8,866 24,818 16,428 Miscellaneous - net 151 (7,148) (3,692) ---------- ---------- ---------- TOTAL 23,436 29,372 22,680 ---------- ---------- ---------- INTEREST AND OTHER CHARGES Interest on long-term debt 131,906 153,393 143,053 Other interest - net 5,497 13,537 8,458 Distributions on preferred securities of subsidiary 7,437 7,438 7,438 Allowance for borrowed funds used during construction (9,749) (9,286) (6,926) ---------- ---------- ---------- TOTAL 135,091 165,082 152,023 ---------- ---------- ---------- INCOME BEFORE INCOME TAXES 240,075 261,482 283,946 Income taxes 65,997 82,038 103,603 ---------- ---------- ---------- NET INCOME 174,078 179,444 180,343 Preferred dividend requirements and other 4,888 5,025 9,998 ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $169,190 $174,419 $170,345 ========== ========== ========== See Notes to Respective Financial Statements.
ENTERGY GULF STATES, INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING ACTIVITIES Net income $174,078 $179,444 $180,343 Noncash items included in net income: Reserve for regulatory adjustments 11,147 (27,374) (49,571) Other regulatory credits - net (7,818) (26,728) (8,254) Depreciation, amortization, and decommissioning 208,182 197,367 195,422 Deferred income taxes and investment tax credits (11,576) 4,320 54,279 Allowance for equity funds used during construction (11,010) (9,248) (7,617) Gain on sale of assets (3,409) (2,454) (2,327) Changes in working capital: Receivables 18,155 59,132 (131,643) Fuel inventory 4,617 (16,753) 1,013 Accounts payable 83,428 (151,090) 130,435 Taxes accrued (54,690) (41,764) 30,570 Interest accrued (4,544) (125) 14,969 Deferred fuel costs 65,556 161,396 (26,291) Other working capital accounts (19,551) 6,183 20,896 Provision for estimated losses and reserves 1,478 (3,593) (1,991) Changes in other regulatory assets (51,490) (54,613) (47,777) Other 98,101 64,386 51,424 ---------- --------- --------- Net cash flow provided by operating activities 500,654 338,486 403,880 ---------- --------- --------- INVESTING ACTIVITIES Construction expenditures (355,334) (317,776) (277,635) Allowance for equity funds used during construction 11,010 9,248 7,617 Nuclear fuel purchases (21,820) (14,148) (34,735) Proceeds from sale/leaseback of nuclear fuel 21,923 15,222 34,154 Decommissioning trust contributions and realized change in trust assets (12,488) (11,319) (12,051) Changes in other temporary investments - net 44,643 (44,643) - Other regulatory investments (39,390) - (127,377) ---------- --------- --------- Net cash flow used in investing activities (351,456) (363,416) (410,027) ---------- --------- --------- FINANCING ACTIVITIES Proceeds from the issuance of long-term debt 337,481 298,554 298,819 Retirement of long-term debt (194,057) (124,829) (185) Redemption of preferred stock (1,858) (4,573) (157,658) Dividends paid: Common stock (91,200) (83,700) (88,000) Preferred stock (4,888) (5,073) (10,862) ---------- --------- --------- Net cash flow provided by financing activities 45,478 80,379 42,114 ---------- --------- --------- Net increase in cash and cash equivalents 194,676 55,449 35,967 Cash and cash equivalents at beginning of period 123,728 68,279 32,312 ---------- --------- --------- Cash and cash equivalents at end of period $318,404 $123,728 $68,279 ========== ========= ========= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $143,961 $169,067 $136,154 Income taxes $98,734 $107,726 $23,259 Noncash investing and financing activities: Change in unrealized depreciation of decommissioning trust assets ($17,135) ($9,492) ($3,172) See Notes to Respective Financial Statements.
ENTERGY GULF STATES, INC. BALANCE SHEETS ASSETS December 31, 2002 2001 (In Thousands) CURRENT ASSETS Cash and cash equivalents: Cash $25,591 $19,503 Temporary cash investments - at cost, which approximates market 292,813 104,225 ---------- ---------- Total cash and cash equivalents 318,404 123,728 ---------- ---------- Other temporary investments - 44,643 Accounts receivable: Customer 81,879 81,136 Allowance for doubtful accounts (5,893) (3,696) Associated companies 21,356 34,032 Other 40,156 54,814 Accrued unbilled revenues 95,377 84,744 ---------- ---------- Total accounts receivable 232,875 251,030 ---------- ---------- Deferred fuel costs 100,564 126,730 Accumulated deferred income taxes 1,681 - Fuel inventory - at average cost 49,394 54,011 Materials and supplies - at average cost 99,190 95,674 Prepayments and other 47,206 22,373 ---------- ---------- TOTAL 849,314 718,189 ---------- ---------- OTHER PROPERTY AND INVESTMENTS Decommissioning trust funds 240,735 245,382 Non-utility property - at cost (less accumulated depreciation) 192,975 194,830 Other 18,108 15,970 ---------- ---------- TOTAL 451,818 456,182 ---------- ---------- UTILITY PLANT Electric 7,895,009 7,694,226 Property under capital lease 19,795 28,087 Natural gas 60,810 59,100 Construction work in progress 306,209 221,730 Nuclear fuel under capital lease 41,447 67,688 ---------- ---------- TOTAL UTILITY PLANT 8,323,270 8,070,831 Less - accumulated depreciation and amortization 3,885,559 3,750,770 ---------- ---------- UTILITY PLANT - NET 4,437,711 4,320,061 ---------- ---------- DEFERRED DEBITS AND OTHER ASSETS Regulatory assets: SFAS 109 regulatory asset - net 452,887 426,623 Unamortized loss on reacquired debt 31,186 34,321 Other regulatory assets 226,555 201,329 Long-term receivables 23,192 26,576 Other 35,194 26,460 ---------- ---------- TOTAL 769,014 715,309 ---------- ---------- TOTAL ASSETS $6,507,857 $6,209,741 ========== ========== See Notes to Respective Financial Statements.
ENTERGY GULF STATES, INC. BALANCE SHEETS LIABILITIES AND SHAREHOLDERS' EQUITY December 31, 2002 2001 (In Thousands) CURRENT LIABILITIES Currently maturing long-term debt $293,000 $147,921 Accounts payable: Associated companies 51,383 38,728 Other 205,796 135,023 Customer deposits 48,061 45,876 Taxes accrued 35,914 90,604 Accumulated deferred income taxes - 21,412 Nuclear refueling outage costs 14,244 2,080 Interest accrued 38,870 43,414 Obligations under capital leases 36,157 36,668 Other 15,441 20,995 ---------- ---------- TOTAL 738,866 582,721 ---------- ---------- DEFERRED CREDITS AND OTHER LIABILITIES Accumulated deferred income taxes and taxes accrued 1,310,028 1,227,084 Accumulated deferred investment tax credits 156,401 163,766 Obligations under capital leases 25,085 60,163 Other regulatory liabilities 5,557 - Decommissioning 148,728 144,926 Transition to competition 79,098 79,098 Regulatory reserves 44,738 33,591 Accumulated provisions 65,289 63,811 Other 93,396 93,719 ---------- ---------- TOTAL 1,928,320 1,866,158 ---------- ---------- Long-term debt 1,959,288 1,958,897 Preferred stock with sinking fund 24,327 26,185 Company-obligated mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated deferrable debentures 85,000 85,000 SHAREHOLDERS' EQUITY Preferred stock without sinking fund 47,327 47,327 Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 100 shares in 2002 and 2001 114,055 114,055 Paid-in capital 1,157,459 1,157,459 Retained earnings 449,929 371,939 Accumulated other comprehensive income 3,286 - ---------- ---------- TOTAL 1,772,056 1,690,780 ---------- ---------- Commitments and Contingencies TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $6,507,857 $6,209,741 ========== ========== See Notes to Respective Financial Statements.
ENTERGY GULF STATES, INC. STATEMENTS OF RETAINED EARNINGS AND COMPREHENSIVE INCOME For the Years Ended December 31, 2002 2001 2000 (In Thousands) RETAINED EARNINGS Retained Earnings - Beginning of period $371,939 $285,128 $202,783 Add - Earnings applicable to common stock $169,190 169,190 174,419 $174,419 170,345 $170,345 Deduct: Dividends declared on common stock 91,200 83,700 88,000 Capital stock and other expenses - 3,908 --------- -------- -------- Total 91,200 87,608 88,000 --------- -------- -------- Retained Earnings - End of period $449,929 $371,939 $285,128 ========= ======== ======== ACCUMULATED OTHER COMPREHENSIVE INCOME (Net of Taxes): Balance at beginning of period: Accumulated derivative instrument fair value changes $ - $ - $ - Net derivative instrument fair value changes arising during the period 3,286 3,286 - - - - --------- -------- -------- -------- -------- -------- Balance at end of period: Accumulated derivative instrument fair value changes $3,286 $ - $ - ========= --------- ======== -------- ======== -------- Comprehensive Income $172,476 $174,419 $170,345 ========= ======== ======== See Notes to Respective Financial Statements.
ENTERGY GULF STATES, INC. | ||||||
BALANCE SHEETS | ||||||
ASSETS | ||||||
December 31, | ||||||
2004 | 2003 | |||||
(In Thousands) | ||||||
CURRENT ASSETS | ||||||
Cash and cash equivalents: | ||||||
Cash | $5,627 | $20,754 | ||||
Temporary cash investments - at cost, | ||||||
which approximates market | 1,347 | 185,276 | ||||
Total cash and cash equivalents | 6,974 | 206,030 | ||||
Other temporary investments | - - | 23,579 | ||||
Accounts receivable: | ||||||
Customer | 124,801 | 115,729 | ||||
Allowance for doubtful accounts | (2,687) | (4,856) | ||||
Associated companies | 13,980 | 76,726 | ||||
Other | 40,697 | 27,243 | ||||
Accrued unbilled revenues | 137,719 | 114,442 | ||||
Total accounts receivable | 314,510 | 329,284 | ||||
Deferred fuel costs | 90,124 | 118,449 | ||||
Accumulated deferred income taxes | 14,339 | 6,116 | ||||
Fuel inventory - at average cost | 49,658 | 50,863 | ||||
Materials and supplies - at average cost | 101,922 | 99,357 | ||||
Prepayments and other | 20,556 | 51,236 | ||||
TOTAL | 598,083 | 884,914 | ||||
OTHER PROPERTY AND INVESTMENTS | ||||||
Decommissioning trust funds | 290,952 | 267,917 | ||||
Non-utility property - at cost (less accumulated depreciation) | 94,052 | 139,911 | ||||
Other | 22,012 | 21,852 | ||||
TOTAL | 407,016 | 429,680 | ||||
UTILITY PLANT | ||||||
Electric | 8,418,119 | 8,208,394 | ||||
Property under capital lease | - - | 11,009 | ||||
Natural gas | 78,627 | 69,180 | ||||
Construction work in progress | 331,703 | 325,888 | ||||
Nuclear fuel under capital lease | 71,279 | 63,684 | ||||
TOTAL UTILITY PLANT | 8,899,728 | 8,678,155 | ||||
Less - accumulated depreciation and amortization | 4,047,182 | 3,953,275 | ||||
UTILITY PLANT - NET | 4,852,546 | 4,724,880 | ||||
DEFERRED DEBITS AND OTHER ASSETS | ||||||
Regulatory assets: | ||||||
SFAS 109 regulatory asset - net | 444,799 | 442,062 | ||||
Other regulatory assets | 285,017 | 320,363 | ||||
Long-term receivables | 23,228 | 19,375 | ||||
Other | 44,713 | 33,588 | ||||
TOTAL | 797,757 | 815,388 | ||||
TOTAL ASSETS | $6,655,402 | $6,854,862 | ||||
See Notes to Respective Financial Statements. | ||||||
ENTERGY GULF STATES, INC. | ||||||
BALANCE SHEETS | ||||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||
December 31, | ||||||
2004 | 2003 | |||||
(In Thousands) | ||||||
CURRENT LIABILITIES | ||||||
Currently maturing long-term debt | $98,000 | $354,000 | ||||
Accounts payable: | ||||||
Associated companies | 153,069 | 84,394 | ||||
Other | 147,337 | 156,166 | ||||
Customer deposits | 53,229 | 47,044 | ||||
Taxes accrued | 22,882 | - - | ||||
Nuclear refueling outage costs | - - | 8,238 | ||||
Interest accrued | 32,742 | 36,576 | ||||
Obligations under capital leases | 33,518 | 34,075 | ||||
Other | 19,912 | 14,755 | ||||
TOTAL | 560,689 | 735,248 | ||||
NON-CURRENT LIABILITIES | ||||||
Accumulated deferred income taxes and taxes accrued | 1,533,804 | 1,422,776 | ||||
Accumulated deferred investment tax credits | 138,616 | 144,323 | ||||
Obligations under capital leases | 37,711 | 40,618 | ||||
Other regulatory liabilities | 34,009 | 13,885 | ||||
Decommissioning and retirement cost liabilities | 152,095 | 298,785 | ||||
Transition to competition | 79,098 | 79,098 | ||||
Regulatory reserves | 81,455 | 57,343 | ||||
Accumulated provisions | 66,875 | 75,868 | ||||
Long-term debt | 1,891,478 | 1,989,613 | ||||
Preferred stock with sinking fund | 17,400 | 20,852 | ||||
Other | 229,408 | 233,985 | ||||
TOTAL | 4,261,949 | 4,377,146 | ||||
Commitments and Contingencies | ||||||
SHAREHOLDERS' EQUITY | ||||||
Preferred stock without sinking fund | 47,327 | 47,327 | ||||
Common stock, no par value, authorized 200,000,000 | ||||||
shares; issued and outstanding 100 shares in 2004 and 2003 | 114,055 | 114,055 | ||||
Paid-in capital | 1,157,486 | 1,157,484 | ||||
Retained earnings | 513,182 | 419,690 | ||||
Accumulated other comprehensive income | 714 | 3,912 | ||||
TOTAL | 1,832,764 | 1,742,468 | ||||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $6,655,402 | $6,854,862 | ||||
See Notes to Respective Financial Statements. |
ENTERGY GULF STATES, INC. | ||||||||||||||
STATEMENTS OF RETAINED EARNINGS AND COMPREHENSIVE INCOME | ||||||||||||||
For the Years Ended December 31, | ||||||||||||||
2004 | 2003 | 2002 | ||||||||||||
(In Thousands) | ||||||||||||||
RETAINED EARNINGS | ||||||||||||||
Retained Earnings - Beginning of period | $419,690 | $449,929 | $371,939 | |||||||||||
Add - Net Income | 192,264 | $192,264 | 42,562 | $42,562 | 174,078 | $174,078 | ||||||||
Deduct: | ||||||||||||||
Dividends declared on common stock | 94,300 | 68,100 | 91,200 | |||||||||||
Preferred dividend requirements and other | 4,472 | 4,472 | 4,701 | 4,701 | 4,888 | 4,888 | ||||||||
Total | 98,772 | 72,801 | 96,088 | |||||||||||
Retained Earnings - End of period | $513,182 | $419,690 | $449,929 | |||||||||||
ACCUMULATED OTHER COMPREHENSIVE | ||||||||||||||
INCOME (Net of Taxes): | ||||||||||||||
Balance at beginning of period: | ||||||||||||||
Accumulated derivative instrument fair value changes | $3,912 | $3,286 | $ - | |||||||||||
Net derivative instrument fair value changes | ||||||||||||||
arising during the period | (3,198) | (3,198) | 626 | 626 | 3,286 | 3,286 | ||||||||
Balance at end of period: | ||||||||||||||
Accumulated derivative instrument fair value changes | $714 | $3,912 | $3,286 | |||||||||||
Comprehensive Income | $184,594 | $38,487 | $172,476 | |||||||||||
See Notes to Respective Financial Statements. | ||||||||||||||
ENTERGY GULF STATES, INC. | ||||||||||
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | ||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||
(In Thousands) | ||||||||||
Operating revenues | $2,882,384 | $2,639,737 | $2,183,879 | $2,648,560 | $2,511,240 | |||||
Net Income | $192,264 | $45,262 | $174,078 | $179,444 | $180,343 | |||||
Total assets | $6,655,402 | $6,854,862 | $6,599,533 | $6,209,741 | $6,134,017 | |||||
Long-term obligations (1) | $1,946,589 | $2,051,083 | $2,096,329 | $2,130,245 | $1,978,149 | |||||
(1) Included long-term debt (excluding currently maturing debt), preferred stock with sinking fund, and noncurrent capital lease obligations. | ||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||
(Dollars In Millions) | ||||||||||
Electric Operating Revenues: | ||||||||||
Residential | $881 | $829 | $700 | $788 | $717 | |||||
Commercial | 672 | 614 | 502 | 587 | 505 | |||||
Industrial | 976 | 853 | 695 | 946 | 871 | |||||
Governmental | 37 | 39 | 34 | 38 | 33 | |||||
Total retail | 2,566 | 2,335 | 1,931 | 2,359 | 2,126 | |||||
Sales for resale: | ||||||||||
Associated companies | 52 | 42 | 28 | 73 | 94 | |||||
Non-associated companies | 160 | 150 | 139 | 146 | 113 | |||||
Other | 43 | 53 | 44 | 13 | 138 | |||||
Total | $2,821 | $2,580 | $2,142 | $2,591 | $2,471 | |||||
Billed Electric Energy Sales (GWh): | ||||||||||
Residential | 9,803 | 9,739 | 9,502 | 9,059 | 9,405 | |||||
Commercial | 8,444 | 8,174 | 7,894 | 7,668 | 7,660 | |||||
Industrial | 16,596 | 15,417 | 15,887 | 16,658 | 17,960 | |||||
Governmental | 432 | 475 | 477 | 452 | 450 | |||||
Total retail | 35,275 | 33,805 | 33,760 | 33,837 | 35,475 | |||||
Sales for resale: | ||||||||||
Associated companies | 1,528 | 1,185 | 708 | 1,087 | 1,381 | |||||
Non-associated companies | 3,172 | 3,358 | 4,391 | 3,305 | 3,248 | |||||
Total | 39,975 | 38,348 | 38,859 | 38,229 | 40,104 | |||||
ENTERGY GULF STATES, INC. AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
2002 | 2001 | 2000 | 1999 | 1998 | |
(In Thousands) | |||||
Operating revenues | $ 2,183,879 | $ 2,648,560 | $ 2,511,240 | $ 2,127,208 | $ 1,853,809 |
Net income | $ 174,078 | $ 179,444 | $ 180,343 | $ 125,000 | $ 46,393 |
Total assets | $ 6,507,857 | $ 6,209,741 | $ 6,134,017 | $ 5,733,022 | $ 6,293,744 |
Long-term obligations (1) | $ 2,093,700 | $ 2,130,245 | $ 1,978,149 | $ 1,966,269 | $ 1,993,811 |
(1) Includes long-term debt (excluding currently maturing debt), preferred stock with sinking fund, preferred securities of subsidiary trust, and noncurrent capital lease obligations.
(1) 1998 includes the effects of an Entergy Gulf States reserve for rate refund.
ENTERGYLOUISIANA, INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
OperatingNet Income
20022004 Compared to 20012003
OperatingNet income decreased $8.0$18.7 million primarily due to:to lower net revenue, partially offset by lower other operation and maintenance expenses.
2003 Compared to 2002
Net Revenue
2004 Compared to 2003
Net revenue, which is explained below;
(In Millions) | ||
2003 net revenue | $973.7 | |
Price applied to unbilled sales | (31.9) | |
Deferred fuel cost revisions | (29.4) | |
Rate refund provisions | (12.2) | |
Volume/weather | 17.0 | |
Summer capacity charges | 11.8 | |
Other | 2.3 | |
2004 net revenue | $931.3 |
The price applied to the unbilled sales variance is due to a decrease in the fuel price included in unbilled sales in 2004 caused primarily by the effect of nuclear plant outages in 2003 on average fuel costs.
The deferred fuel cost revisions variance resulted from a revised unbilled sales pricing estimate made in the first quarter of 2003 to more closely align the fuel component of that pricing with expected recoverable fuel costs.
Rate refund provisions caused a decrease in net revenue due to additional provisions recorded in 2004 compared to 2003 for potential rate actions and refunds.
The volume/weather variance is due to a total increase of 620 GWh in weather-adjusted usage in all sectors, partially offset by the effect of milder weather on billed sales in the residential and commercial sectors.
The summer capacity charges variance is due to the amortization in 2003 of deferred capacity charges for the summerssummer of 2001 compared to the absence of the amortization in 2004. The amortization of these capacity charges began in August 2002 and 2000ended in July 2003.
Gross operating revenues, fuel and purchased power expenses, and other regulatory credits
Gross operating revenues increased primarily due to:
The increase in plant in service combined with revisions made to the useful lives of certain intangible plant assets to more appropriately reflect their actual lives, which lowered expense in 2001 in accordance with regulatory treatment.
Almost entirely offsetting the decrease werewas partially offset by the following:
Fuel and purchased power expenses increased primarily due to:
Other regulatory credits increased primarily due to:
2003 Compared to 2002
Net revenue, which is Entergy Louisiana's measure of $45.0gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2003 to 2002.
(In Millions) | ||
2002 net revenue | $922.9 | |
Deferred fuel cost revisions | 59.1 | |
Asset retirement obligation | 8.2 | |
Volume | (16.2) | |
Vidalia settlement | (9.2) | |
Other | 8.9 | |
2003 net revenue | $973.7 |
The deferred fuel cost revisions variance resulted from a revised unbilled sales pricing estimate made in December 2002 and a further revision made in the first quarter of 2003 to more closely align the fuel component of that pricing with expected recoverable fuel costs.
The asset retirement obligation variance was due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," adopted in January 2003. See "Critical Accounting Estimates" for more details on SFAS 143. The increase was offset by decommissioning expense and had no effect on net income.
The volume variance was due to a decrease in electricity usage in the service territory. Billed usage decreased 1,868 GWh in the industrial sector including the loss of a large industrial customer to cogeneration.
See "Liquidity and Capital Resources" below for more details regarding the September 2002 settlement related to the Vidalia contract.
Gross operating revenues, fuel and purchased power expenses, and other regulatory charges (credits)
Gross operating revenues increased primarily due to:
Fuel and purchased power expenses increased primarily due to an increase in the market prices of natural gas and purchased power.
Other regulatory credits increased primarily due to:
Other Income Statement Variances
2004 Compared to 2003
Other operation and maintenance expenses decreased primarily due to voluntary severance program accruals of $19.7 million in 2003, partially offset by an increase of $9.1 million in customer service support costs.
2003 Compared to 2002
Other operation and maintenance expenses increased primarily due to:
Decommissioning expenses increased $10.1 million primarily due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," adopted in January 2003. See "Critical Accounting Estimates" for more details on SFAS 143. The increase in decommissioning expense was offset by regulatory credits and interest and dividend income and had no effect on net income.
Taxes other than income taxes increased primarily due to the franchise tax adjustments of $10.8 million recorded in 2002 as a result of a favorable court decision which would allowthat allowed Entergy Louisiana to receive a refund for certain franchise taxes previously expensed and paid under protest.
Other operationDepreciation and maintenanceamortization expenses increased $41.3 million primarily due to:to an increase in plant in service.
2001 Compared to 2000
Operating income decreased $47.7 million primarily due to:
The decrease was partially offset by the following:
Other operation and maintenance expenses decreased $19.3 million primarily due to:
Other Impacts on Earnings
Other income and interest charges increased earnings by $18.6 million primarily due to:
2001 Compared to 2000
Other income and interest charges decreased earnings by $8.8 million primarily due to:
Other Income Statement Variances
2002, Compared to 2001
Operating revenues decreased $86.6 million primarily due to a decrease in fuel recovery revenues due to lower fuel rates, partially offset by an increase in price applied to unbilled sales and an increase in electricity usage in the service territory. Billed usage increased 1,042 GWh primarily in the residential and industrial sectors.
Fuel and purchased power expenses decreased $155.7 million primarily due to:
The decrease was partially offset by the reductionissuance of purchased power expenses$150 million of First Mortgage Bonds in 2001 as a result of the FERC-ordered refund from System Energy.
Other regulatory charges increased $42.0 million primarily due to the deferral in 2001 of capacity charges included in purchased power costs for the summers of 2000 and 2001 and the amortization of these capacity charges inMarch 2002. The amortization of the summer 2000 capacity charges ended in July 2002. The amortization of the capacity charges for the summer of 2001 began in August 2002 and will occur through July 2003. Refer to Note 2 to the domestic utility companies and System Energy financial statements for further discussion of deferred capacity charges.
2001 Compared to 2000Income Taxes
Operating revenues decreased $160.5 million primarily due to a decrease in price applied to unbilled and decreased electricity usage in the service territory. Billed usage decreased 1,156 GWh primarily in the industrial and residential sectors.
Fuel and purchased power expenses decreased $67.1 million primarily due to the reduction of purchased power expenses as a result of the FERC-ordered refund from System Energy.
Other regulatory credits increased $25.7 million due to the deferral of capacity charges included in purchased power costs for the summers of 2000 and 2001, partially offset by the amortization of the 2000 capacity charges.
Income taxes
The effective income tax rates for 2004, 2003, and 2002 2001,were 38.4%, 40.0%, and 2000 were 36.9%, 39.4%, and 40.9%.respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate. Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2002, 2001,2004, 2003, and 20002002 were as follows:
2002 | 2001 | 2000 | ||||
(In Thousands) | ||||||
Cash and cash equivalents at beginning of period |
$ 42,408
$ 43,959
$ 7,734
Cash flow provided by (used in):
Operating activities
1,035,777
430,515
270,423
Investing activities
(212,333)
(218,331)
(211,020)
Financing activities
(554,052)
(213,735)
(23,178)
Net increase (decrease) in cash and cash equivalents
269,392
(1,551)
36,225
Cash and cash equivalents at end of period
$ 311,800
$ 42,408
$ 43,959
2004 | 2003 | 2002 | |||||
(In Thousands) | |||||||
Cash and cash equivalents at beginning of period | $8,787 | $311,800 | $42,408 | ||||
Cash flow provided by (used in): | |||||||
Operating activities | 424,718 | 413,939 | 1,035,777 | ||||
Investing activities | (243,231) | (268,372) | (212,333) | ||||
Financing activities | (44,225) | (448,580) | (554,052) | ||||
Net increase (decrease) in cash and cash equivalents | 137,262 | (303,013) | 269,392 | ||||
Cash and cash equivalents at end of period | $146,049 | $8,787 | $311,800 |
Operating Activities
Cash flow from operations increased $605.3$10.8 million in 20022004 primarily due to the increased collection of deferred fuel costs and the receipt of an income tax payment through Entergy's inter-company tax allocation process. The increase was almost entirely offset by money pool activity.
In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $505 million deduction for Entergy Louisiana on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004 Entergy Louisiana realized $100 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. As of December 31, 2004, Entergy Louisiana has a net operating loss (NOL) carryforward for tax purposes of $195.7 million, principally resulting from the change in tax accounting method related to cost of goods sold. If the tax accounting method change is sustained, Entergy Louisiana expects to utilize the NOL carryforward through 2005.
Cash flow from operations decreased $621.8 million in 2003 as a result of Entergy Louisiana changing its method of accounting for tax purposes in 2001 related to theits wholesale electric power contracts, includingthe contract to purchase power from the Vidalia project (the contract is discussed in Note 98 to the domestic utility companies and System Energy financial statements). The new tax accounting method provided a cumulative cash flow benefit of approximately $867$790 million in 2002,through 2004, which is expected to reverse in the years 20032005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power.
In a September 2002 settlement of an LPSC proceeding that concerned the Vidalia contract,approved by the LPSC, approved Entergy Louisiana's proposed treatment of the regulatory impact of the tax accounting election. In general, the settlement permits Entergy Louisiana towill keep a portion of the tax benefit in exchange for bearingcrediting customer rates. The credit will be $11 million annually through at least 2010. See Part I, Item 1 for additional details concerning the risk associated with sustaining the tax treatment. The LPSC settlement divided the term of the Vidalia contract into two segments: 2002-12 and 2013-31. During the first eight years of the 2002-12 segment, settl ement.
Entergy Louisiana agreed to credit rates by flowing throughreduced its fuel adjustment calculation $11 million each year, beginning monthly in October 2002. Entergy Louisiana must credit rates in this way and by this amount even if Entergy Louisiana is unable to sustain the tax deduction. Entergy Louisiana also must credit rates by $11 million each year for an additional two years unless either the tax accounting method elected is retroactively repealed or the Internal Revenue Service denies th e entire deduction related to the tax accounting method. Entergy Louisiana agreed to credit ratepayers additional amounts unless the tax accounting election is not sustained, if it is challenged. During the years 2013-2031, Entergy Louisiana and its ratepayers would share the remaining benefits of this tax accounting election.
Management expects to reduce Entergy Louisiana's indebtedness and preferred stock with a portion of the cash.cash from the tax benefit. In accordance with the terms of the settlement, Entergy Louisiana requested SEC approval to return up to $350 million of common equity capital to Entergy Corporation in order to maintain Entergy Louisiana's current capital structure. In December 2002, Entergy Louisiana repurchased $120 million of common stock from Entergy Corporation and, at the time of settlement, paid a dividend of $122.6 million pursuant to the SEC approval.
Cash flow from operations increased $160.1 million The provisions of the settlement provide that the LPSC shall not recognize or use Entergy Louisiana's use of this cash in 2001 compared to 2000 primarily duesetting any of Entergy Louisiana's rates. Therefore, to the FERC-ordered refund from System Energy.extent Entergy Louisiana's use of the proceeds would ordinarily have reduced its rate base, no change in rate base shall be reflected for ratemaking purposes. The amount Entergy Louisiana was required to pass on to customers was significantly lower than the refund amount because Entergy Louisiana had not passed through to customers allSEC approval for additional return of System Energy's rate increase in effect since 1995. The increase was also due to recovery of deferred fuel costs in 2001.equity capital is now expired.
Entergy Louisiana's receivables from or (payables) to(payables to) the money pool were as follows as of December 31 for each of the following years:
2002 | 2001 | 2000 | 1999 | ||||
(In Thousands) | |||||||
$18,854 | $3,812 | $22,907 | ($91,467) |
2004 |
| 2003 |
| 2002 |
| 2001 |
(In Thousands) | ||||||
|
|
|
|
|
|
|
$40,549 |
| ($41,317) |
| $18,854 |
| $3,812 |
Money pool activity decreasedused $81.9 million of Entergy Louisiana's operating cash flows byflow in 2004, provided $60.2 million in 2003, and used $15.0 million in 2002, increased operating cash flow by $19.1 million in 2001, and decreased operating cash flow by $114.4 million in 2000.2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.
Investing Activities
The decrease of $25.1 million in net cash used by investing activities in 2004 was primarily due to decreased spending on customer service projects, partially offset by increases in spending on transmission projects and fossil plant projects.
The increase of $56.0 million in net cash used by investing activities in 2003 was primarily due to increased spending on customer service, transmission, and nuclear projects.
Financing Activities
The increasedecrease of $340.3$404.4 million in net cash used by financing activities in 20022004 was primarily due to:
The decrease of $134.5 million; and
The increase of $190.6$105.5 million in net cash used by financing activities in 20012003 was primarily due to:
The decrease in net issuancecash used in 2003 was partially offset by the following:
See Note 75 to the domestic utility companies and System Energy financial statements for details of long-term debt.
Uses of Capital
Entergy Louisiana requires capital resources for:
Following are the amounts of Entergy Louisiana's planned construction and other capital investments, existing debt and lease obligations, and other purchase obligations:
| 2005 |
| 2006-2007 |
| 2008-2009 |
| After 2009 |
| Total |
| (In Millions) | ||||||||
Planned construction and |
|
|
|
|
|
|
|
|
|
capital investment (1) | $455 |
| $472 |
| N/A |
| N/A |
| $927 |
Long-term debt | $55 |
| $- |
| $7 |
| $924 |
| $986 |
Operating leases | $10 |
| $11 |
| $6 |
| $2 |
| $29 |
Purchase obligations (2) | $639 |
| $1,120 |
| $980 |
| $4,691 |
| $7,430 |
Nuclear fuel lease obligations (3) | $23 |
| $9 |
| N/A |
| N/A |
| $32 |
2003 | 2004 | 2005 | 2006-2007 | after 2007 | |||||
(In Millions) | |||||||||
Planned construction and | |||||||||
capital investment | $197 | $184 | $195 | N/A | N/A | ||||
Long-term debt maturities | $296 | $15 | $55 | $- | $760 | ||||
Capital and operating lease payments | $13 | $12 | $7 | $5 | $1 | ||||
Unconditional fuel and purchased | |||||||||
power obligations | $162 | $168 | $172 | $356 | $3,354 | ||||
Nuclear fuel lease obligations (1) | $34 | $17 | N/A | N/A | N/A |
(1) | Includes approximately $130 to $160 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. |
(2) | 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 domestic utility companies and System Energy financial statements. |
(3) |
|
In addition to acquire additional fuel,these contractual obligations, Entergy Louisiana expects to pay interest,contribute $2.6 million to its pension plans and $8.5 million to pay maturing debt. If such additional financing cannot be arranged, however, the lesseeother postretirement plans in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations.
2005.
The planned capital investment estimate for Entergy Louisiana reflects capital required to support existing business and customer growth. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, business restructuring, and the ability to access capital. Management provides more information on construction expenditures and long-term debt and preferred stock maturities in Notes 5 6, 7, and 96 to the domestic utility companies and System Energy financial statements.
In January 2004, Entergy Louisiana signed a definitive agreement to acquire the 718 MW Perryville power plant for $170 million. The agreement has subsequently been amended to allow the current plant owner to retain the interconnection facilities associated with the plant, resulting in a decrease in the acquisition price to $162 million. As a result of the amended terms, the FERC issued an order in October 2004 disclaiming jurisdiction over the acquisition. This order currently is subject to rehearing by the FERC. The plant is owned by a subsidiary of Cleco Corporation, which subsidiary submitted a bid in response to Entergy's Fall 2002 request for proposals for supply-side resources. The signing of the agreement followed a voluntary Chapter 11 bankruptcy filing by the plant's owner. Entergy expects that Entergy Louisiana will own 100 percent of the Perryville plant, and that Entergy Louisiana will sell 75 percent of the output to Entergy Gulf States under a long-term cost-of-serv ice power purchase agreement. In addition, Entergy Louisiana and Entergy Gulf States executed an interim power purchase agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by December 2005) for 100 percent of the output of the Perryville power plant. In April 2004, the bankruptcy court approved Entergy Louisiana's agreement to acquire the plant. In March 2004, Entergy Gulf States and Entergy Louisiana filed with the LPSC for its approval of the acquisition and long-term cost-of-service power purchase agreement. Entergy is seeking approval from the LPSC of cost recovery for the acquisition, giving consideration to the need for the power and the prudence of Entergy Louisiana and Entergy Gulf States in engaging in the transaction. Hearings are scheduled for March 2005. Assuming regulatory approval by the LPSC, Entergy Louisiana expects the Perryville acquisition to close in mid-2005.
As a wholly-owned subsidiary, Entergy Louisiana dividends its earnings to Entergy Corporation at a percentage determined monthly. Currently,In addition, all of Entergy Louisiana's retained earnings are currently available for distribution.
Sources of Capital
Entergy Louisiana's sources to meet its capital requirements include:
In 2002, Entergy Louisiana issued $150$285 million of first mortgage bonds in 2004 as follows:
Issue Date | Description | Maturity | Amount | |||
(In Thousands) | ||||||
March 2004 | 5.50% Series | April 2019 | $100,000 | |||
October 2004 | 6.40% Series | October 2034 | 70,000 | |||
October 2004 | 5.09% Series | November 2014 | 115,000 | |||
$285,000 |
Entergy Louisiana retired $187.2 million of long-term debt and used a portion of the proceeds to redeem $115 million of outstanding debt. The remaining net proceeds were used to reduce short-term indebtedness incurred for working capital and other purposes. in 2004 as follows:
Retirement Date | Description | Maturity | Amount | |||
(In Thousands) | ||||||
November 2004 | 6.50% Series | March 2008 | $115,000 | |||
November 2004 | 9.00% Series | September 2045 | 72,165 | |||
$187,165 |
Entergy Louisiana is expected to continue refinancingmay refinance or redeeming higher-costredeem 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 Louisiana require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.
Short-termIn July 2004, Entergy Louisiana renewed its 364-day credit facility and Entergy New Orleans entered into a separate credit facility with the same lender. Both facilities will expire in April 2005. Entergy Louisiana can borrow up to $15 million and Entergy New Orleans can borrow up to $14 million under their respective credit facilities, but at no time can the total amount borrowed under these facilities by the two companies combined exceed $15 million. As of December 31, 2004, no borrowings were outstanding under these facilities. Borrowings and securities issuances by Entergy Louisiana are limited to amounts authorized by the SEC. The current short-term borrowing limitation, including borrowings under the money pool, are limited to an amount authorized by the SEC,is $225 million. Under theits SEC order authorizing the short-term borrowing limits,Orders and without further SEC authorization, Entergy Louisiana cannot incur new short-termadditional indebtedness if itsor issue other securities unless (a) it and Entergy Corporation maintain a common equity would comprise less thanratio of at least 30% and (b) with the except ion of its capital. In addition,money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy Louisiana, is restricted from publicly issuing new long-term debt unless its senior secured debt will beas well as all outstanding securities of Entergy Corporation, that are rated, asare rated investment grade. Entergy Louisiana has a 364-day credit facility available expiring May 2003 in the amount of $15 million of which none was drawn at December 31, 2002. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Louisiana's short-term borrowing limits.
Significant Factors and Known Trends
Utility Restructuring
Major changes are occurring in the wholesale and retail electric utility business, including in the electric transmission business. In a July 2001 report to the LPSC, the LPSC staff concluded that retail competition is not in the public interest at this time for any customer class. Nevertheless, the LPSC staff recommended that retail open access be made available for certain large industrial customers as early as January 2003. An eligible customer choosing to go to competition would be required to provide its utility with a minimum of six months notice prior to the date of retail open access. The LPSC staff report also recommended that all customers who do not currently co- or self-generate, or have co- or self-generation under construction as of a date to be specified by the LPSC, remain liable for their share of stranded costs. During its October 2001 meeting, the LPSC adopted dates by which a total of 800 MW of co- or self-generation could be developed in Louisiana without being affected by stranded costs. During its November 2001, meeting, the LPSC decided not to adopt a plan formove forward with retail open access for any customers at this time, buttime. The LPSC instead directed its staff to havehold collaborative group meetings concerning open access from time to time, and to have the LPSC staff monitor developments in neighboring states and to report to the LPSC regarding the progress of retail access developments in those states. In September 2004, in response to a study funded by certain industrial customers that evaluated a limited industrial-only retail choice program, the LPSC asked the LPSC staff to solicit comments and obtain information from utilities, customers, and other interested parties concerning the potential costs and benefits of a limited choice program, the impact of such a program on other customers, as well as issues such as stranded costs and transmission service. Comments from interested parties were filed with the LPSC on January 14, 2005. The LPSC has not established a procedural framework for c onsideration of the comments. At this time, it is not certain what further action, if any, the LPSC might take in response to the information it received.
At FERC, the pace of restructuring at the wholesale level has begun but has been delayed. It is too early to predict the ultimate effects of changes in U.S.United States energy markets. Restructuring issues are complex and are continually affected by events at the national, regional, state, and local levels. However, these changes may result, in the long-term, in fundamental changes in the way traditional integrated utilities and holding company systems, like the Entergy system, conduct their business. Some of these changes may be positive for Entergy, while others may not be.
not.
State Rate Regulation
The rates that Entergy Louisiana charges for its services are an important item influencing its financial position, results of operations, and liquidity. Entergy Louisiana is closely 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.
In July 2002,January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC approvedin support of a proposed settlement with the LPSC that resolved all remainingwould resolve, among other dockets, dockets established to consider issues concerning power purchases for both Entergy Gulf States and Entergy Louisiana for the summers of 2001, 2002, 2003, and 2004. The proposed settlement currently includes an offer to refund $14 million to Entergy Louisiana's customers. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the 2000proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.
In January 2004, Entergy Louisiana made a rate filing with the LPSC requesting a base rate increase of approximately $167 million. In that filing, Entergy Louisiana noted that approximately $73 million of the base rate increase was attributable to the acquisition of a generating station and 2001certain power purchase agreements that, based on current natural gas prices, would produce fuel and purchased power savings for customers that substantially mitigate the impact of the requested base rate increase. The filing also requested an allowed ROE of 11.4%. Entergy Louisiana's previously authorized ROE mid-point currently in effect is 10.5%. Hearings concluded in December 2004. Based on evidence submitted at the hearing, the LPSC staff is recommending approximately a $7 million base rate increase. The LPSC staff proposed the implementation of a formula rate plan proceedings in which Entergy Louisiana agreed tothat includes a $5 million rate reduction effective August 2001. The prospective rate reduction was implemented beginning in August 2002 and the refundprovision for the retroactive period occurred in September 2002.
Performance based formularecovery of incremental capacity costs, including those related to the proposed Perryville acquisition, without filing a traditional base rate plan filings expired in 2001 for Entergy Louisiana. Performance based formula rate plan filings are designed to reward increased efficiency and productivity, with utility shareholders and customers sharing in the benefits. Negotiations withproceeding. A decision by the LPSC staff and advisors for a statewide formula rate planis expected in Louisiana are ongoing.mid- to late-March 2005 on these issues.
In addition to rate proceedings, Entergy Louisiana's fuel costs recovered from customers are subject to regulatory scrutiny. This regulatory risk represents Entergy Louisiana's largest potential exposure to price changes in the commodity markets.
Entergy Louisiana's retail rate matters and proceedings, including fuel cost recovery- relatedrecovery-related issues, are discussed in Note 2 to the domestic utility companies and System Energy financial statements.
System Agreement Proceedings
The System Agreement provides fordomestic utility companies historically have engaged in the integratedcoordinated planning, construction, and operation of Entergy's electric generationgenerating and transmission assets throughoutfacilities under the retail service territoriesterms of an agreement called the System Agreement that has been approved by the FERC. Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies. Under the termscompanies in their execution of the System Agreement, generating capacity and other power resources are jointly operated by the domestic utility companies. Theseek support for local regulatory authority over System Agreement provides, among other things, that parties having generating reserves greater than their load requirements (long companies) shall receive payments from those parties having deficienciesissues.
In February 2004, a FERC ALJ issued an Initial Decision in generating reserves (short companies). Such payments are 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 and preference stock, and a fair rate of return on common equity investment. Under the System Agreement, these charges are based on costs associated with the long companies' steam electric generating units fueled by oil or gas. In addition, for all energy exchanged among the domestic utility companies under the System Agreement, the short companies are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
The LPSC and the Council commenced aLPSC-initiated proceeding at FERCthe FERC. The Initial Decision decided some issues in June 2001. In this proceeding, the LPSC and the Council allege that the rough production cost equalization required by FERC under the System Agreement and the Unit Power Sales Agreement has been disrupted by changed circumstances. The LPSC and the Council have requested that FERC amend the System Agreement or the Unit Power Sales Agreement or both to achieve full production cost equalization or to restore rough production cost equalization. Their complaint does not seek a change in the total amountfavor of the costs allocated by either the System Agreement or the Unit Power Sales Agreement. In addition, the LPSC and the Council allege that provisions of the System Agreement relating to minimum run and must run units, the methodology of billing versus dispatch, and the use of a rolling twelve-month average of system peaks, increase costs paid by ratepayers in the LPSC and Council's jurisdictions. Several parties have filed interventions in the proceed ing, including the APSC and the MPSC. Entergy filed its response to the complaint in July 2001 denying the allegations of the LPSC and the Council. The APSC and the MPSC also filed responses opposing the relief sought by the LPSC, and decided some issues against the Council.
In their complaint,relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the Council allegeFERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's annual production costs over the period 2002 to 2007 will be $132 million to $139 million over the average for the domestic utility companies. This rangepurposes of results is a function of assumptions regarding such things as future natural gas prices, the future market price of electricity, and other factors. In February 2002, the FERC set the matter for hearing and established a refund effective period consisting of the 15 months following September 13, 2001. Negotiations among the parties have not resolved the proceeding,calculating relative production costs; and the proceeding is now set for hearing commencing in June 2003. The case had been set for trial commencing in February 2003;Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the extension ofcurrent method.
If the schedule also extended the refund effective period by 120 days. If FERC grants the relief requested by the LPSC andin the Council,proceeding, the relief may result in a material increase in the total production costs allocatedthe FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs allocatedthe FERC allocates to companies whose costs currently are projected to exceed that average. If the average. FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility compan ies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.
An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu duri ng the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:
| Average Annual | ||
(In Millions) | (In Millions) | ||
Entergy Arkansas | $154 to $281 | $215 | |
Entergy Gulf States | ($130) to ($15) | ($63) | |
Entergy Louisiana | ($199) to ($98) | ($141) | |
Entergy Mississippi | ($16) to $8 | $1 | |
Entergy New Orleans | ($17) to ($5) | ($12) |
Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. Therefore, managementAlthough the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy Louisiana does not believe that this proceedingthe ultimate resolution of these proceedings will have a material effect on theits financial condition or results of operation.
In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC ALJ's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the ALJ's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; an d states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate.
In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the ALJ's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations.
In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana although neitherto notify the timing norCity Council and obtain prior approval for any action that would materially modify, amend, or terminate the outcomeSystem Agreement for one or more of the proceedings at FERC can be predicted atdomestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this time.requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Louisiana, as well as t he named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity.
The LPSC has instituted a companion ex parteex-parte System Agreement investigation to litigate several of the System Agreement issues that the LPSC is litigating before the FERC in the previously discussed System Agreement proceeding. This companion proceeding will require the LPSC to interpret various provisions of the System Agreement, including those relating to minimum runminimum-run and must runmust-run units, the propriety of the methods used for billing and dispatch on the Entergy System, and the use of a rolling, twelve-month average of system peaks for allocating certain costs. In addition, by this companion proceeding the LPSC is questioning whether Entergy Louisiana and Entergy Gulf States were prudent for not seeking changes to the System Agreement previously, so as to lower costs imposed upon their ratepayers and to increase costs imposed upon ratepayers of other domestic utility companies. The LPSC staff has filed testimony suggesting that the remedy for the alleged imprudence of Entergy Louisiana and Entergy Gulf States should be a reduction in allowed rate of return on common equity of 100 basis points. The domestic utility companies have challenged the propriety of the LPSC's litigating System Agreement issues. Nevertheless, inon January 16, 2002 the LPSC affirmed a decision of its ALJ upholding the LPSC staff's right to litigate System Agreement issues at the LPSC, rather than before the FERC. In September 2002,The procedural schedule is suspended at this time and an evidentiary hearing is not scheduled. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting FERC rate schedules that are part of the System Agreement, and from subsequently enforcing that interpretation. The LPSC interpreted a System Agreement rate schedule in the unrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed. In 2003, the U.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the decisions of the LPSC and the Louisiana Supreme Court.
Transmission
In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs.
In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations.
Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences.
In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the petition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005.
In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a motionpetition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion o f the proposal currently scheduled for August 2005.
Interconnection Orders
The domestic utility companies (except Entergy New Orleans) are currently defendants to delayseveral complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos, including $3 million for Entergy Louisiana. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy.
In addition, Entergy Louisiana was recently directed, effective as of March 2001, to provide transmission credits, with interest, associated with a specific generator that asserted to the FERC that it retained in its contract for interconnection a right to execute the latest form of Entergy's standard interconnection agreement in lieu of its existing contract, which thereby would apply FERC's most recent interconnection cost allocation policies to that generator. Following an ALJ's Initial Decision and an order affirming such decision by FERC, approximately $15 million in expenses and tax obligations previously paid by the generator have been ordered refunded in the form of transmission credits, to be utilized over time and applied to Entergy transmission service bills incurred after March 2001. Entergy Louisiana has sought rehearing of the FERC's order.
To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators.
Available Flowgate Capacity Proceeding
On December 17, 2004, the FERC issued an order initiating a hearing and remaining pre-hearing deadlines. After no objections frominvestigation concerning the other parties,justness and reasonableness of the LPSC ALJ continuedAvailable Flowgate Capacity (AFC) methodology, the procedural schedule until aftermethodology used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC ALJ's initial decisionindicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised in a FERC audit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC program, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory.
Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy.
Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the related matter, or June 13, 2003, whichever occurs first.
AFC proceeding is currently scheduled to commence in August 2005.
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 contracts to provide competitive rates that provide service at rates lower than would otherwise be charged.match specific customer needs and load profiles. Despite these actions, Entergy Louisiana lost a large industrial customer to cogeneration in late in 2002. The customer accounted for approximately 2% of its net revenue in 2001. In addition to working with its current customers, Entergy Louisiana also continuallyactively participates in economic development, customer retention, and reclamation activities that canto increase industrial and commercial energy demand, from both currentexisting and new customers.
Entergy Louisiana does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Louisiana's market ing efforts in retaining industrial customers.
Market and Credit Risks
Entergy Louisiana has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.
Interest Rate and Equity Price Risk - Decommissioning Trust Funds
Entergy Louisiana's nuclear decommissioning trust funds expose it to fluctuations in equity prices and interest rates. The NRC requires Entergy Louisiana to maintain trusts to fund the costs of decommissioning Waterford 3. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the Waterford 3 trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 912 to the domestic utility companies and System Energy financial statements.
Nuclear Matters
Entergy Louisiana owns and operates, through an affiliate, the Waterford 3.3 nuclear power plant. Entergy Louisiana is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
In August 2001, the NRC issued a bulletin requesting all pressurized water reactor owners and operators to report on the structural integrity of their reactor vessel head penetration nozzles to justify continued operations past December 31, 2001. These types of reactors are susceptible to stress corrosion cracking of the reactor vessel head nozzles. Waterford is a pressurized water reactor. To date, there has been no primary side stress corrosion cracking identified in the Waterford reactor vessel head. Inspections of the Waterford reactor vessel head will continue during planned refueling outages.
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.
Litigation Risks
The state of Louisiana has proven to be an unusually litigious environment. Judges and juries in Louisiana have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy Louisiana uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment poses a significant business risk.
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 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 accounting estimates because they are based on assumptions and measurements that involve an unusuala high degree of uncertainty, and there is the potential that differentfor future changes in the assumptions and measurements could produce estimates that are significantly different than those recorded inwould have a material effect on the presentation of Entergy Louisiana's financial statements.
position or results of operations.
Nuclear Decommissioning Costs
Regulations require thatEntergy Louisiana to decommission the Waterford 3 be decommissionednuclear power plant after the facility is taken out of service, and funds aremoney is collected and deposited in trust funds during the facility's operating life in order to provide for this obligation. Entergy Louisiana conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facility. See Note 9 to the domestic utility companies and System Energy financial statements for details regarding Entergy Louisiana's most recent study and the obligations recorded by Entergy Louisiana related to decommissioning. The following key assumptions have a significant effect on these estimates:
Entergy Louisiana collects substantially all of the projected costs of decommissioning Waterford 3 through rates charged to customers. The amounts collected through rates, which are based upon decommissioning cost studies, are deposited in decommissioning trust funds. These collections plus earnings on the trust fund investments are estimated to be sufficient to fund the future decommissioning costs. Accordingly, decommissioning costs have no impact on Entergy Louisiana's earnings, as accrued costs are offset by earnings on trust funds and collections from customers. If decommissioning cost study estimates wereare changed and approved by regulators, collections from customers would also change.
The obligations recorded by Entergy Louisiana for decommissioning are classified as a component of accumulated depreciation. The amounts recorded for these obligations are comprised of collections from customers and earnings on the trust funds. The classification and recording of these obligations will change with the implementation of SFAS 143.
SFAS 143
Entergy Louisiana implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy Louisiana's asset retirement obligations, and the measurement and recording of Entergy Louisiana's decommissioning obligations outlined above will changechanged significantly with the implementation of SFAS 143. The most significant differences in the measurement of these obligations are outlined below:
The net effect of implementing this standardSFAS 143 for Entergy Louisiana will bewas recorded as a regulatory asset, or liability, with no resulting impact on Entergy Louisiana's net income. AssetsEntergy Louisiana recorded this regulatory asset because its existing rate mechanism is based on the original or historical cost standard that allows Entergy Louisiana to recover all ultimate costs of decommissioning existing assets from current and future customers. Upon implementation of SFAS 143 in 2003, assets and liabilities are expected to increaseincreased by approximately $300$305 million in 2003 as a result of recording the asset retirement obligation at its fair value of $305 million as determined under SFAS 143, increasing total utility plant by $99 million, reducing accumulated depreciation by $82 million, and recording the related regulatory asset of $124 million.
Unbilled Revenue
As discussed in Note 1 to the domestic utility companies and liability.
System Energy financial statements, Entergy Louisiana records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month, including fuel price. 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 including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regarding price such as the fuel cost recovery mechanism.
Pension and Other Postretirement Benefits
Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 1110 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and poorworse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt.debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 7.5% in 2000 and 2001 to 6.75% in 2002.2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rates fromrate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to a range of 8%10% increase in health care costs in 2005 gradually decreasing to 5%each successive year, until it reaches a 4.5% annual increase in 2001 to a range of 10% gradually decreasing to 4.5%health care costs in 2002.2011 and beyond.
In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities, and 35%4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities and 49% fixed income securities. Based on recent market trends, Entergy decreasedreduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 9% in 2000 and 2001 to 8.75% for 2002.2002 and 2003 to 8.5% in 2004. The trend of reduced inflation caused Entergy to reduce its assumed rate of increase in future compensation levels from 4.6% in 2000 and 2001used to calculate benefit obligations was 3.25% in 2002.
2002, 2003, and 2004.
Cost Sensitivity
The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (in(dollars in thousands):
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| $523 |
| $3,018 |
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The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (in(dollars in thousands):
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| $416 |
| $2,407 |
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| $234 |
| $3,033 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
In accordance with SFAS No. 87, "Employers' Accounting for Pensions," 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 cost 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, Entergy smoothesaccounts for the impact of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87.
Costs and Funding
Total pension incomecost for Entergy Louisiana in 20022004 was $3.9$3.3 million. Taking into account asset performanceEntergy Louisiana anticipates 2005 pension cost to increase to $6.8 million due to decrease in the discount rate (from 6.25% to 6.00%) and the changes made in the actuarial assumptions,expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. Entergy Louisiana does not anticipate 2003 pension income to be materially different from 2002. Entergy Louisiana was not required to make contributionscontributed $3.9 million to its pension plan in 20022004 and does not anticipateanticipates making $2.6 million in contributions in 2005. The decrease in pension funding requirements is due to the Pension Funding Equity Act relief passed in 2003.April 2004, partially offset by declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002.
Due to negative pension plan asset returns over the past several years, Entergy Louisiana's accumulated benefit obligation at December 31, 2004, and 2002 exceeded plan assets. As a result, Entergy Louisiana was required to recognize an additional minimum liability of $44.2 million as prescribed by SFAS 87.87 in those years. At December 31, 2003, Entergy Louisiana's accumulated benefit obligation was less than plan assets, therefore there was no additional minimum pension liability required to be recognized. At December 31, 2004, Entergy Louisiana recorded an additional pension minimum liability of $38.9 million; an offsetting intangible asset for the $5.4of $4.8 million, of unrecognized prior service cost and the remaining $38.8 million was recorded as a regulatory asset.asset of $34.1 million. Net income for 2004, 2003, and 2002 was not impacted.impacted by the additional minimum pension liability.
Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 20022004 were $12.6 million. Because$12.3 million, including $2.8 million in savings due to the estimated effect of a numberfuture Medicare Part D subsidies. Entergy Louisiana expects 2005 postretirement health care and life insurance benefit costs to approximate $12.7 million, including $3.2 million in savings due to the estimated effect of factors, includingfuture Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the increaseddecrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate Entergy Louisiana expects 2003 costsused to approximate $15.4 million.calculate benefit obligations.
REPORT OF INDEPENDENT AUDITORS' REPORT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Entergy Louisiana, Inc.:
We have audited the accompanying balance sheets of Entergy Louisiana, Inc. as of December 31, 20022004 and 2001,2003, and the related statements of income, retained earnings, and cash flows (pages 195219 through 200224 and applicable items in pages 250284 through 303)348) for each of the three years in the period ended December 31, 2002.2004. 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 auditing standards generally accepted inof the United States of America.Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Louisiana, Inc. as of December 31, 20022004 and 2001,2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20022004 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 5 and Note 8 to the notes to respective financial statements, in 2003 Entergy Louisiana, Inc. adopted the provisions of Statement of Financial Accounting Standards Board Interpretation No. 46,Consolidation of Variable Interest Entities,and Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control - - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 2003
March 8, 2005
ENTERGY LOUISIANA, INC. | ||||||
INCOME STATEMENTS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
OPERATING REVENUES | ||||||
Domestic electric | $2,226,986 | $2,165,570 | $1,815,352 | |||
OPERATING EXPENSES | ||||||
Operation and Maintenance: | ||||||
Fuel, fuel-related expenses, and | ||||||
gas purchased for resale | 671,549 | 525,645 | 436,568 | |||
Purchased power | 667,893 | 668,337 | 438,627 | |||
Nuclear refueling outage expenses | 13,633 | 11,130 | 11,502 | |||
Other operation and maintenance | 367,824 | 376,770 | 340,803 | |||
Decommissioning | 21,958 | 20,569 | 10,422 | |||
Taxes other than income taxes | 68,999 | 70,084 | 60,698 | |||
Depreciation and amortization | 197,380 | 192,972 | 182,871 | |||
Other regulatory charges (credits) - net | (43,765) | (2,160) | 17,219 | |||
TOTAL | 1,965,471 | 1,863,347 | 1,498,710 | |||
OPERATING INCOME | 261,515 | 302,223 | 316,642 | |||
OTHER INCOME | ||||||
Allowance for equity funds used during construction | 7,494 | 6,900 | 5,195 | |||
Interest and dividend income | 8,209 | 8,820 | 7,668 | |||
Miscellaneous - net | (929) | (3,100) | (3,244) | |||
TOTAL | 14,774 | 12,620 | 9,619 | |||
INTEREST AND OTHER CHARGES | ||||||
Interest on long-term debt | 70,210 | 73,227 | 98,242 | |||
Other interest - net | 3,931 | 3,529 | 2,425 | |||
Allowance for borrowed funds used during construction | (4,822) | (5,475) | (3,880) | |||
TOTAL | 69,319 | 71,281 | 96,787 | |||
INCOME BEFORE INCOME TAXES | 206,970 | 243,562 | 229,474 | |||
Income taxes | 79,475 | 97,408 | 84,765 | |||
NET INCOME | 127,495 | 146,154 | 144,709 | |||
Preferred dividend requirements and other | 6,714 | 6,714 | 6,714 | |||
EARNINGS APPLICABLE TO | ||||||
COMMON STOCK | $120,781 | $139,440 | $137,995 | |||
See Notes to Respective Financial Statements. | ||||||
ENTERGY LOUISIANA, INC. | ||||||
STATEMENTS OF CASH FLOWS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
OPERATING ACTIVITIES | ||||||
Net income | $127,495 | $146,154 | $144,709 | |||
Adjustments to reconcile net income to net cash flow provided by | ||||||
Reserve for regulatory adjustments | 14,076 | 1,858 | - | |||
Other regulatory charges (credits) - net | (43,765) | (2,160) | 17,219 | |||
Depreciation, amortization, and decommissioning | 219,338 | 213,541 | 193,293 | |||
Deferred income taxes and investment tax credits | 75,078 | 859,157 | 39,849 | |||
Changes in working capital: | ||||||
Receivables | (36,185) | (4,418) | (68,936) | |||
Accounts payable | (36,862) | 49,028 | 7,370 | |||
Taxes accrued | 89,079 | (804,805) | 779,590 | |||
Interest accrued | (1,791) | (10,324) | (3,971) | |||
Deferred fuel costs | 21,955 | (56,211) | (41,891) | |||
Other working capital accounts | 20,693 | 10,395 | (118,718) | |||
Provision for estimated losses and reserves | 6,119 | 12,194 | 5,818 | |||
Changes in other regulatory assets | (14,456) | 59,169 | (23,879) | |||
Other | (16,056) | (59,639) | 105,324 | |||
Net cash flow provided by operating activities | 424,718 | 413,939 | 1,035,777 | |||
INVESTING ACTIVITIES | ||||||
Construction expenditures | (240,283) | (257,754) | (209,826) | |||
Allowance for equity funds used during construction | 7,494 | 6,900 | 5,195 | |||
Nuclear fuel purchases | - | (41,525) | (50,473) | |||
Proceeds from the sale/leaseback of nuclear fuel | - | 41,525 | 50,473 | |||
Decommissioning trust contributions and realized | ||||||
change in trust assets | (12,615) | (17,506) | (13,854) | |||
Changes in other investments - net | 2,173 | (12) | 6,152 | |||
Net cash flow used in investing activities | (243,231) | (268,372) | (212,333) | |||
FINANCING ACTIVITIES | ||||||
Proceeds from the issuance of long-term debt | 282,745 | - | 144,679 | |||
Retirement of long-term debt | (203,756) | (296,366) | (300,617) | |||
Repurchase of common stock | - | - | (120,000) | |||
Dividends paid: | ||||||
Common stock | (116,500) | (145,500) | (271,400) | |||
Preferred stock | (6,714) | (6,714) | (6,714) | |||
Net cash flow used in financing activities | (44,225) | (448,580) | (554,052) | |||
Net increase (decrease) in cash and cash equivalents | 137,262 | (303,013) | 269,392 | |||
Cash and cash equivalents at beginning of period | 8,787 | 311,800 | 42,408 | |||
Cash and cash equivalents at end of period | $146,049 | $8,787 | $311,800 | |||
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||
Cash paid/(received) during the period for: | ||||||
Interest - net of amount capitalized | $73,170 | $84,089 | $99,998 | |||
Income taxes | ($70,650) | $35,128 | ($781,540) | |||
See Notes to Respective Financial Statements. |
ENTERGY LOUISIANA, INC.INCOME STATEMENTS For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING REVENUES Domestic electric $1,815,352 $1,901,913 $2,062,437 ---------- ---------- ---------- OPERATING EXPENSES Operation and Maintenance: Fuel, fuel-related expenses, and gas purchased for resale 436,568 620,415 560,329 Purchased power 438,627 410,435 537,589 Nuclear refueling outage expenses 11,502 12,624 13,542 Other operation and maintenance 340,803 299,532 318,841 Decommissioning 10,422 10,422 10,422 Taxes other than income taxes 60,698 77,376 77,190 Depreciation and amortization 182,871 171,217 171,204 Other regulatory charges (credits) - net 17,219 (24,738) 960 ---------- ---------- ---------- TOTAL 1,498,710 1,577,283 1,690,077 ---------- ---------- ---------- OPERATING INCOME 316,642 324,630 372,360 ---------- ---------- ---------- OTHER INCOME Allowance for equity funds used during construction 5,195 4,531 4,328 Gain on sale of assets - 152 - Interest and dividend income 7,668 6,234 10,100 Miscellaneous - net (3,244) (4,056) (3,496) ---------- ---------- ---------- TOTAL 9,619 6,861 10,932 ---------- ---------- ---------- INTEREST AND OTHER CHARGES Interest on long-term debt 91,942 97,887 98,655 Other interest - net 2,425 11,889 6,788 Distributions on preferred securities of subsidiary 6,300 6,300 6,300 Allowance for borrowed funds used during construction (3,880) (3,422) (3,775) ---------- ---------- ---------- TOTAL 96,787 112,654 107,968 ---------- ---------- ---------- INCOME BEFORE INCOME TAXES 229,474 218,837 275,324 Income taxes 84,765 86,287 112,645 ---------- ---------- ---------- NET INCOME 144,709 132,550 162,679 Preferred dividend requirements and other 6,714 7,495 9,514 ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $137,995 $125,055 $153,165 ========== ========== ========== See Notes to Respective Financial Statements.
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ENTERGY LOUISIANA, INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING ACTIVITIES Net income $144,709 $132,550 $162,679 Noncash items included in net income: Reserve for regulatory adjustments - (11,456) 11,456 Other regulatory charges (credits) - net 17,219 (24,738) 960 Depreciation, amortization, and decommissioning 193,293 181,639 181,626 Deferred income taxes and investment tax credits 39,849 (27,382) 16,350 Allowance for equity funds used during construction (5,195) (4,531) (4,328) Gain on sale of assets - (152) - Changes in working capital: Receivables (68,936) 131,313 (97,154) Accounts payable 7,370 (50,121) (11,848) Taxes accrued 779,590 (2,897) (2,555) Interest accrued (3,971) (1,012) 15,300 Deferred fuel costs (41,891) 151,544 (81,890) Other working capital accounts (118,718) (71,119) 38,064 Provision for estimated losses and reserves 5,818 4,321 6,114 Changes in other regulatory assets (23,879) 2,569 25,400 Other 110,519 19,987 10,249 --------- -------- -------- Net cash flow provided by operating activities 1,035,777 430,515 270,423 --------- -------- -------- INVESTING ACTIVITIES Construction expenditures (209,826) (203,059) (203,049) Allowance for equity funds used during construction 5,195 4,531 4,328 Nuclear fuel purchases (50,473) - (38,270) Proceeds from sale/leaseback of nuclear fuel 50,473 - 38,270 Decommissioning trust contributions and realized change in trust assets (13,854) (13,651) (12,299) Changes in other temporary investments - net 6,152 (6,152) - --------- -------- -------- Net cash flow used in investing activities (212,333) (218,331) (211,020) --------- -------- -------- FINANCING ACTIVITIES Proceeds from the issuance of long-term debt 144,679 - 148,736 Retirement of long-term debt (300,617) (35,088) (100,000) Redemption of preferred stock - (35,000) - Repurchase of common stock (120,000) - - Dividends paid: Common stock (271,400) (134,600) (62,400) Preferred stock (6,714) (9,047) (9,514) --------- -------- -------- Net cash flow used in financing activities (554,052) (213,735) (23,178) --------- -------- -------- Net increase (decrease) in cash and cash equivalents 269,392 (1,551) 36,225 Cash and cash equivalents at beginning of period 42,408 43,959 7,734 --------- -------- -------- Cash and cash equivalents at end of period $311,800 $42,408 $43,959 ========= ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid/(received) during the period for: Interest - net of amount capitalized $99,998 $110,971 $89,627 Income taxes ($781,540) $111,507 $105,354 Noncash investing and financing activities: Change in unrealized depreciation of decommissioning trust assets ($8,463) ($4,251) ($2,979) See Notes to Respective Financial Statements.
ENTERGY LOUISIANA, INC. BALANCE SHEETS ASSETS December 31, 2002 2001 (In Thousands) CURRENT ASSETS Cash and cash equivalents: Cash $15,130 $28,768 Temporary cash investments - at cost, which approximates market 296,670 13,640 ---------- ---------- Total cash and cash equivalents 311,800 42,408 ---------- ---------- Other temporary investments - 6,152 Accounts receivable: Customer 95,009 48,640 Allowance for doubtful accounts (4,090) (2,909) Associated companies 30,722 9,090 Other 17,949 49,103 Accrued unbilled revenues 104,470 71,200 ---------- ---------- Total accounts receivable 244,060 175,124 ---------- ---------- Accumulated deferred income taxes 4,400 42,566 Materials and supplies - at average cost 78,327 77,523 Deferred nuclear refueling outage costs 10,017 4,096 Prepayments and other 117,720 9,008 ---------- ---------- TOTAL 766,324 356,877 ---------- ---------- OTHER PROPERTY AND INVESTMENTS Investment in affiliates - at equity 14,230 14,230 Decommissioning trust funds 125,054 119,663 Non-utility property - at cost (less accumulated depreciation) 21,489 21,671 ---------- ---------- TOTAL 160,773 155,564 ---------- ---------- UTILITY PLANT Electric 5,557,776 5,456,093 Property under capital lease 241,071 239,395 Construction work in progress 147,122 110,792 Nuclear fuel under capital lease 50,893 70,316 ---------- ---------- TOTAL UTILITY PLANT 5,996,862 5,876,596 Less - accumulated depreciation and amortization 2,651,336 2,538,964 ---------- ---------- UTILITY PLANT - NET 3,345,526 3,337,632 ---------- ---------- DEFERRED DEBITS AND OTHER ASSETS Regulatory assets: SFAS 109 regulatory asset - net 157,642 179,368 Unamortized loss on reacquired debt 25,846 28,341 Other regulatory assets 119,359 73,754 Long-term receivables 1,511 1,515 Other 26,007 16,650 ---------- ---------- TOTAL 330,365 299,628 ---------- ---------- TOTAL ASSETS $4,602,988 $4,149,701 ========== ========== See Notes to Respective Financial Statements.
ENTERGY LOUISIANA, INC. BALANCE SHEETS LIABILITIES AND SHAREHOLDERS' EQUITY December 31, 2002 2001 (In Thousands) CURRENT LIABILITIES Currently maturing long-term debt $296,366 $185,627 Accounts payable: Associated companies 54,622 73,208 Other 119,416 93,460 Customer deposits 63,255 61,359 Taxes accrued - 20,410 Interest accrued 30,553 34,524 Deferred fuel costs 25,602 67,493 Obligations under capital leases 33,927 34,171 Other 8,941 14,119 ---------- ---------- TOTAL 632,682 584,371 ---------- ---------- DEFERRED CREDITS AND OTHER LIABILITIES Accumulated deferred income taxes and taxes accrued 1,695,570 776,610 Accumulated deferred investment tax credits 106,539 111,942 Obligations under capital leases 16,966 36,144 Other regulatory liabilities 6,601 - Accumulated provisions 74,340 68,522 Other 95,504 82,780 ---------- ---------- TOTAL 1,995,520 1,075,998 ---------- ---------- Long-term debt 830,188 1,091,329 Company-obligated mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated deferrable debentures 70,000 70,000 SHAREHOLDERS' EQUITY Preferred stock without sinking fund 100,500 100,500 Common stock, no par value, authorized 250,000,000 shares; issued 165,173,180 shares in 2002 and 2001 1,088,900 1,088,900 Capital stock expense and other (1,718) (1,718) Retained earnings 6,916 140,321 Less - treasury stock, at cost (18,202,573 shares in 2002) 120,000 - ---------- ---------- TOTAL 1,074,598 1,328,003 ---------- ---------- Commitments and Contingencies TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $4,602,988 $4,149,701 ========== ========== See Notes to Respective Financial Statements.
ENTERGY LOUISIANA, INC. STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 2002 2001 2000 (In Thousands) Retained Earnings, January 1 $140,321 $150,319 $59,554 Add: Net income 144,709 132,550 162,679 Deduct: Dividends declared: Preferred stock 6,714 7,495 9,514 Common stock 271,400 134,600 62,400 Capital stock expenses - 453 - -------- -------- -------- Total 278,114 142,548 71,914 -------- -------- -------- Retained Earnings, December 31 $6,916 $140,321 $150,319 ======== ======== ======== See Notes to Respective Financial Statements.
ENTERGY LOUISIANA, INC. | ||||
BALANCE SHEETS | ||||
ASSETS | ||||
December 31, | ||||
2004 | 2003 | |||
(In Thousands) | ||||
CURRENT ASSETS | ||||
Cash and cash equivalents: | ||||
Cash | $3,875 | $8,787 | ||
Temporary cash investments - at cost, | ||||
which approximates market | 142,174 | - | ||
Total cash and cash equivalents | 146,049 | 8,787 | ||
Accounts receivable: | ||||
Customer | 88,154 | 93,393 | ||
Allowance for doubtful accounts | (3,135) | (4,487) | ||
Associated companies | 43,121 | 9,074 | ||
Other | 13,070 | 12,334 | ||
Accrued unbilled revenues | 143,453 | 138,164 | ||
Total accounts receivable | 284,663 | 248,478 | ||
Deferred fuel costs | 8,654 | 30,609 | ||
Accumulated deferred income taxes | 12,712 | - | ||
Materials and supplies - at average cost | 77,665 | 74,349 | ||
Deferred nuclear refueling outage costs | 5,605 | 19,226 | ||
Prepayments and other | 6,861 | 67,623 | ||
TOTAL | 542,209 | 449,072 | ||
OTHER PROPERTY AND INVESTMENTS | ||||
Investment in affiliates - at equity | 14,230 | 14,230 | ||
Decommissioning trust funds | 172,083 | 151,996 | ||
Non-utility property - at cost (less accumulated depreciation) | 21,176 | 21,307 | ||
Other | 4 | 2,177 | ||
TOTAL | 207,493 | 189,710 | ||
UTILITY PLANT | ||||
Electric | 5,985,889 | 5,836,914 | ||
Property under capital lease | 250,964 | 250,102 | ||
Construction work in progress | 188,848 | 172,405 | ||
Nuclear fuel under capital lease | 31,655 | 65,066 | ||
TOTAL UTILITY PLANT | 6,457,356 | 6,324,487 | ||
Less - accumulated depreciation and amortization | 2,799,936 | 2,686,778 | ||
UTILITY PLANT - NET | 3,657,420 | 3,637,709 | ||
DEFERRED DEBITS AND OTHER ASSETS | ||||
Regulatory assets: | ||||
SFAS 109 regulatory asset - net | 132,686 | 156,111 | ||
Other regulatory assets | 302,456 | 217,689 | ||
Long-term receivables | 10,736 | 1,511 | ||
Other | 25,994 | 22,737 | ||
TOTAL | 471,872 | 398,048 | ||
TOTAL ASSETS | $4,878,994 | $4,674,539 | ||
See Notes to Respective Financial Statements. | ||||
ENTERGY LOUISIANA, INC. | ||||
BALANCE SHEETS | ||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||
December 31, | ||||
2004 | 2003 | |||
(In Thousands) | ||||
CURRENT LIABILITIES | ||||
Currently maturing long-term debt | $55,000 | $14,809 | ||
Accounts payable: | ||||
Associated companies | 57,681 | 101,191 | ||
Other | 128,523 | 121,875 | ||
Customer deposits | 66,963 | 61,215 | ||
Accumulated deferred income taxes | - | 566 | ||
Taxes accrued | 7,268 | - | ||
Interest accrued | 18,438 | 20,229 | ||
Obligations under capital leases | 22,753 | 35,506 | ||
Other | 10,428 | 5,110 | ||
TOTAL | 367,054 | 360,501 | ||
NON-CURRENT LIABILITIES | ||||
Accumulated deferred income taxes and taxes accrued | 1,805,410 | 1,728,156 | ||
Accumulated deferred investment tax credits | 96,130 | 101,258 | ||
Obligations under capital leases | 8,903 | 29,560 | ||
Other regulatory liabilities | 51,260 | 39,026 | ||
Decommissioning liabilities | 347,255 | 325,298 | ||
Accumulated provisions | 92,653 | 86,534 | ||
Long-term debt | 930,695 | 887,687 | ||
Other | 106,815 | 47,981 | ||
TOTAL | 3,439,121 | 3,245,500 | ||
Commitments and Contingencies | ||||
SHAREHOLDERS' EQUITY | ||||
Preferred stock without sinking fund | 100,500 | 100,500 | ||
Common stock, no par value, authorized 250,000,000 | ||||
shares; issued 165,173,180 shares in 2004 and 2003 | 1,088,900 | 1,088,900 | ||
Capital stock expense and other | (1,718) | (1,718) | ||
Retained earnings | 5,137 | 856 | ||
Less - treasury stock, at cost (18,202,573 shares in 2004 and 2003) | 120,000 | 120,000 | ||
TOTAL | 1,072,819 | 1,068,538 | ||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $4,878,994 | $4,674,539 | ||
See Notes to Respective Financial Statements. | ||||
ENTERGY LOUISIANA, INC. | ||||||
STATEMENTS OF RETAINED EARNINGS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
Retained Earnings, January 1 | $856 | $6,916 | $140,321 | |||
Add: | ||||||
Net income | 127,495 | 146,154 | 144,709 | |||
Deduct: | ||||||
Dividends declared: | ||||||
Preferred stock | 6,714 | 6,714 | 6,714 | |||
Common stock | 116,500 | 145,500 | 271,400 | |||
Total | 123,214 | 152,214 | 278,114 | |||
Retained Earnings, December 31 | $5,137 | $856 | $6,916 | |||
See Notes to Respective Financial Statements. |
ENTERGY LOUISIANA, INC.
ENTERGY LOUISIANA, INC. | ||||||||||||||||||||||||||||||||||||||||||||||
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | ||||||||||||||||||||||||||||||||||||||||||||||
2004
| 2002 | 2001 | 2000 | |||||||||||||||||||||||||||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||||||||||||||||||||||||
Operating revenues | $2,226,986 | $2,165,570 | $1,815,352 | $1,901,913 | $2,062,437 | |||||||||||||||||||||||||||||||||||||||||
Net Income | $127,495 | $146,154 | $144,709 | $132,550 | $162,679 | |||||||||||||||||||||||||||||||||||||||||
Total assets | $4,878,994 | $4,674,539 | $4,753,704 | $4,149,701 | $4,289,409 | |||||||||||||||||||||||||||||||||||||||||
Long-term obligations (1) | $939,598 | $917,247 | $919,319 | $1,197,473 | $1,411,345 | |||||||||||||||||||||||||||||||||||||||||
(1) Included long-term debt (excluding currently maturing debt), preferred stock with sinking fund | ||||||||||||||||||||||||||||||||||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||||||||||||||||||||||||||||||||||||||
(Dollars In Millions) | ||||||||||||||||||||||||||||||||||||||||||||||
Electric Operating Revenues: | ||||||||||||||||||||||||||||||||||||||||||||||
Residential | $739 | $638 | $658 | $717 | ||||||||||||||||||||||||||||||||||||||||||
Commercial | 501 | 473 | 403 | 429 | 441 | |||||||||||||||||||||||||||||||||||||||||
Industrial | 779 | 723 | 637 | 760 | 767 | |||||||||||||||||||||||||||||||||||||||||
Governmental | 38 | 41 | 36 | 39 | 39 | |||||||||||||||||||||||||||||||||||||||||
Total retail |
|
| 1,714 | 1,886 | 1,964 | |||||||||||||||||||||||||||||||||||||||||
Sales for resale: | ||||||||||||||||||||||||||||||||||||||||||||||
|
| 102 | 8 | 25 | 21 | |||||||||||||||||||||||||||||||||||||||||
Non-associated companies | 13 | 12 | 11 | 23 | 40 | |||||||||||||||||||||||||||||||||||||||||
Other | 30 | 76 | 82 | (32) | 38 | |||||||||||||||||||||||||||||||||||||||||
Total | $2,227 | $2,166 | $1,815 | $1,902 | $2,063 | |||||||||||||||||||||||||||||||||||||||||
Billed Electric Energy Sales (GWh): | ||||||||||||||||||||||||||||||||||||||||||||||
Residential | 8,842 | 8,795 | 8,780 | 8,255 | 8,648 | |||||||||||||||||||||||||||||||||||||||||
Commercial | 5,762 | 5,622 | 5,538 | 5,369 | 5,367 | |||||||||||||||||||||||||||||||||||||||||
Industrial | 13,140 | 12,870 | 14,738 | 14,402 | 15,184 | |||||||||||||||||||||||||||||||||||||||||
Governmental | 439 | 491 | 510 | 498 | 481 | |||||||||||||||||||||||||||||||||||||||||
Total retail | 28,183 | 27,778 | 29,566 | 28,524 | 29,680 | |||||||||||||||||||||||||||||||||||||||||
Sales for resale: | ||||||||||||||||||||||||||||||||||||||||||||||
Associated companies | 1,129 | 1,344 | 146 | 381 | 228 | |||||||||||||||||||||||||||||||||||||||||
Non-associated companies | 122 | 132 | 139 | 334 | 554 | |||||||||||||||||||||||||||||||||||||||||
Total | 29,434 | 29,254 | 29,851 | 29,239 | 30,462 | |||||||||||||||||||||||||||||||||||||||||
ENTERGY MISSISSIPPI, INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
2004 Compared to 2003
Net income increased $6.4 million primarily due to higher net revenue, partially offset by higher other operation and maintenance expenses and higher taxes other than income taxes.
2003 Compared to 2002
Net income increased $14.7 million primarily due to higher net revenue, partially offset by higher other operation and maintenance expenses and depreciation and amortization expenses, and lower interest income.
Net Revenue
2004 Compared to 2003
Net revenue, which is Entergy Mississippi's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2004 to 2003.
(In Millions) | ||
2003 net revenue | $426.6 | |
Volume/weather | 6.4 | |
Net wholesale revenue | 5.0 | |
Other | 5.5 | |
2004 net revenue | $443.5 |
The volume/weather variance resulted from an increase of 247 GWh in weather-adjusted usage, partially offset by the effect of milder weather on billed sales.
The net wholesale revenue variance resulted from an increase in energy available for resale sales, partially offset by a decrease in the average price of energy supplied for affiliated sales.
Gross operating revenues, fuel and purchased power expenses, and other regulatory charges (credits)
Gross operating revenues increased primarily due to an increase of $174.0 million in fuel cost recovery revenues due to higher fuel rates and an increase of $26.3 million in gross wholesale revenue. The increase was partially offset by a decrease of $37.6 million in Grand Gulf revenue as a result of the cessation of the Grand Gulf Accelerated Tariff in July 2003.
Fuel and purchased power expenses increased primarily due to the over-recovery of fuel and purchased power costs as a result of higher fuel rates. Entergy Mississippi's fuel rates include an energy cost recovery rider to recover projected energy costs. Actual fuel and purchased power costs were lower than those projected in the computation of the energy cost factors for the third quarter of 2004 which contributed to the over-recovery of fuel and purchased power costs. The MPSC has allowed Entergy Mississippi to refund these over-recoveries in the second and third quarters of 2005. The energy cost recovery rider is discussed in more detail in Note 2 to the domestic and System Energy financial statements.
Other regulatory charges (credits) have no material effect on net income due to recovery and/or refund of such expenses. Other regulatory credits increased primarily due to the under-recovery through the Grand Gulf rider of Grand Gulf capacity charges.
2003 Compared to 2002
Net revenue, which is Entergy Mississippi's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2003 to 2002.
(In Millions) | ||
2002 net revenue | $380.2 | |
Base rates | 48.3 | |
Other | (1.9) | |
2003 net revenue | $426.6 |
The increase in base rates was effective January 2003 as approved by the MPSC.
Gross operating revenue, fuel and purchased power expenses, and other regulatory charges (credits)
Gross operating revenues increased primarily due to an increase in base rates effective January 2003 and an increase of $29.7 million in fuel cost recovery revenues due to quarterly changes in the fuel factor resulting from the increases in market prices of natural gas and purchased power. This increase was partially offset by a decrease of $35.9 million in gross wholesale revenue as a result of decreased generation and purchases that resulted in less energy available for resale sales.
Fuel and fuel-related expenses decreased primarily due to the decreased recovery of fuel and purchased power costs and decreased generation, partially offset by an increase in the market price of purchased power.
Other regulatory charges increased primarily due to over-recovery of capacity charges related to the Grand Gulf rate rider and the cessation of the Grand Gulf Accelerated Recovery Tariff that was suspended in July 2003.
Other Income Statement Variances
2004 Compared to 2003
Other operation and maintenance expenses increased primarily due to:
The increase was partially offset by the absence of the voluntary severance program accruals of $7.1 million that occurred in 2003.
Taxes other than income taxes increased primarily due to a higher assessment of ad valorem and franchise taxes compared to the same period in 2003.
2003 Compared to 2002
Other operation and maintenance expenses increased primarily due to:
The increases were partially offset by a decrease of $4.0 million in plant maintenance expense due to outage costs at a fossil plant in 2002.
Depreciation and amortization expense increased due to an increase in plant in service.
Interest and dividend income decreased as result of carrying charges associated with under-recovery of fuel and purchased power costs during 2002.
Income Taxes
The effective income tax rates for 2004, 2003, and 2002 were 33.5%, 33.9%, and 25.4%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate. Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows:
2004 | 2003 | 2002 | |||||
(In Thousands) | |||||||
Cash and cash equivalents at beginning of period | $63,838 | $147,721 | $54,048 | ||||
Cash flow provided by (used in): | |||||||
Operating activities | 258,179 | 253,288 | 156,868 | ||||
Investing activities | (151,505) | (264,495) | (135,122) | ||||
Financing activities | (90,116) | (72,676) | 71,927 | ||||
Net increase (decrease) in cash and cash equivalents | 16,558 | (83,883) | 93,673 | ||||
Cash and cash equivalents at end of period | $80,396 | $63,838 | $147,721 |
Operating Activities
Cash flow from operations increased by $4.9 million in 2004 primarily due to money pool activity and an increase in recovery of deferred fuel and purchased power costs, partially offset by an $12 million income tax payment in 2004 compared to a $78 million income tax refund in 2003 and an increase in the account receivable balance as a result of the timing of customer collections.
Cash flow from operations increased by $96.4 million in 2003 primarily due to a $78 million income tax refund and increased net income, partially offset by money pool activity.
Entergy Mississippi's receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years:
2004 |
| 2003 |
| 2002 |
| 2001 |
(In Thousands) | ||||||
|
|
|
|
|
|
|
$21,584 |
| $22,076 |
| $8,702 |
| $11,505 |
Money pool activity provided $0.5 million of Entergy Mississippi's operating cash flows in 2004, used $13.4 million of its operating cash flows in 2003, and provided $2.8 million of its operating cash flows in 2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.
Investing Activities
Net cash used in investing activities decreased $113.0 million in 2004 primarily due to:
Net cash used in investing activities increased $129.4 in 2003 primarily due to cash used for other regulatory investments of $72.6 million as a result of under-recovered fuel and purchased power costs and other temporary cash investments of $18.6 million that provided cash in 2002 upon maturity.
In May 2003, Entergy Mississippi filed and the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Under the MPSC's order, Entergy Mississippi deferred until 2004 the collection of fuel under-recoveries for the first and second quarters of 2003 that would have been collected in the third and fourth quarters of 2003, respectively. The deferred amount of $77.6 million plus carrying charges was collected over a twelve-month period that began in January 2004.
Financing Activities
Net cash used in financing activities increased $17.4 million in 2004 primarily due to an increase of $15.1 million in dividends paid.
Net cash used in financing activities increased $144.6 million in 2003 primarily due to a decrease in net issuances of long-term debt.
See Note 5 to the domestic utility companies and System Energy financial statements for details on long-term debt.
Uses of Capital
Entergy Mississippi requires capital resources for:
Following are the amounts of Entergy Mississippi's planned construction and other capital investments, and existing debt obligations:
| 2005 |
| 2006-2007 |
| 2008-2009 |
| After 2009 |
| Total |
| (In Millions) | ||||||||
Planned construction and |
|
|
|
|
|
|
|
|
|
capital investment (1) | $147 |
| $381 |
| N/A |
| N/A |
| $528 |
Long-term debt | - |
| - |
| $100 |
| $595 |
| $695 |
Operating leases | $7 |
| $10 |
| $6 |
| $11 |
| $34 |
Purchase obligations (2) | $190 |
| $361 |
| $336 |
| $2,059 |
| $2,946 |
(1) | Includes approximately $120 to
|
(2) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to
|
In addition to these contractual obligations, Entergy Mississippi expects to contribute $3.4 million to its pension plans and $4.2 million to other postretirement plans in 2005.
The planned capital investment estimate for Entergy Mississippi reflects capital required to support existing business, customer growth, and the anticipated acquisition of additional generation supply resources. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, 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 domestic utility companies and System Energy financial statements.
As a wholly-owned subsidiary, Entergy Mississippi dividends its earnings to Entergy Corporation at a percentage determined monthly. Entergy Mississippi's long-term debt indentures 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, 2004, Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $68.5 million.
Sources of Capital
Entergy Mississippi's sources to meet its capital requirements include:
The following table lists First Mortgage Bonds issued by Entergy Mississippi in 2004:
Issue Date | Description | Maturity | Amount | ||||||||||||||||||||||||||
(In Thousands) | |||||||||||||||||||||||||||||
April 2004 | 6.25% Series |
| $ | ||||||||||||||||||||||||||
April 2004 |
| May 2011 |
| ||||||||||||||||||||||||||
$180,000 |
The following table lists First Mortgage Bonds retired by Entergy Mississippi in 2004:
Retirement Date | Description | Maturity | Amount | |||||
(In Thousands) | ||||||||
May 2004 | 6.20% Series | May 2004 | $75,000 | |||||
| 6.45% Series | April 2008 | 80,000 | |||||
| 7.70% Series | July 2023 | 60,000 | |||||
$215,000 |
In September 2004, Entergy Mississippi arranged the issuance of $16 million of Mississippi Business Finance Corporation 4.60% Series Pollution Control Revenue Refunding Bonds (Entergy Mississippi, Inc. Project) Series 2004 due April 2022. The proceeds from this issuance were used to redeem prior to maturity, $7.9 million of 7.0% Series Washington County Bonds due April 2022 and $8.1 million of 7.0% Series Warren County, Mississippi Bonds due April 2022.
Entergy Mississippi may refinance or redeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred stock issuances by Entergy Mississippi require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy Mississippi has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Mississippi has a 364-day credit facility available expiring May 2005 in the amount of $25 million of which none was drawn at December 31, 2004. Borrowings and securities issuances by Entergy Mississippi are limited to amounts authorized by the SEC. The current short-term borrowing limitation, including borrowings under the money pool, is $160 million. Under its SEC Orders and without further SEC authorization, Entergy Mississippi cannot incur additional indebtedness or issue other securities unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy Mississippi, as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Mississippi's short-term borrowing l imits.
Significant Factors and Known Trends
Utility Restructuring
The MPSC has recommended not pursuing open access at this time. At FERC, the pace of restructuring at the wholesale level has begun but has been delayed. It is too early to predict the ultimate effects of changes in U.S. energy markets. Restructuring issues are complex and are continually affected by events at the national, regional, state, and local levels. However, these changes may result, in the long-term, in fundamental changes in the way traditional integrated utilities and holding company systems, like the Entergy system, conduct their business. Some of these changes may be positive for Entergy, while others may not be.
State and Local Rate Regulation
The rates that Entergy Mississippi charges for electricity significantly influence its financial position, results of operations, and liquidity. Entergy Mississippi is closely 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.
As discussed in Note 2 to the domestic utility companies and System Energy financial statements, Entergy Mississippi made its annual formula rate plan filing with the MPSC in March 2004 based on a 2003 test year. In April 2004, the MPSC approved a joint stipulation entered into between the Mississippi Public Utilities Staff and Entergy Mississippi that provides for no change in rates based on an adjusted return on common equity mid-point of 10.77%, establishing an allowed annual regulatory earnings range of 9.3% to 12.2%.
In December 2002, the MPSC issued a final order approving a joint stipulation entered into by Entergy Mississippi and the Mississippi Public Utilities Staff in October 2002. The final order resulted in a $48.2 million rate increase effective January 2003.
Entergy Mississippi's fuel costs recovered from customers are subject to regulatory scrutiny. Entergy Mississippi's retail rate matters and proceedings, including fuel cost recovery-related issues are discussed more thoroughly in Note 2 to the domestic utility companies and System Energy financial statements.
System Agreement Proceedings
The domestic utility companies historically have engaged in the coordinated planning, construction, and operation of generating and transmission facilities under the terms of an agreement called the System Agreement that has been approved by the FERC. Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies in their execution of the System Agreement, and seek support for local regulatory authority over System Agreement issues. Regarding the proceeding at the LPSC, Entergy believes that state and local regulators are preempted by federal law from reviewing and deciding System Agreement issues for themselves. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting F ERC rate schedules that are part of the System Agreement, and from subsequently enforcing that interpretation. The LPSC interpreted a System Agreement rate schedule in the unrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed the LPSC's decision. In 2003, the U.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the decisions of the LPSC and the Louisiana Supreme Court.
In February 2004, a FERC ALJ issued an Initial Decision in the LPSC-initiated proceeding at the FERC. The Initial Decision decided some issues in favor of the relief sought by the LPSC, and decided some issues against the relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method.
If the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average. If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility compan ies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.
An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu duri ng the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:
| Average Annual | |||||
(In Millions) | (In Millions) | |||||
Entergy Arkansas |
|
|
| |||
|
|
|
| |||
|
|
|
| |||
|
|
|
| |||
$215 | ||||||
| ($130) to ($15) | ($63) | ||||
Entergy Louisiana | ($199) to ($98) | ($141) | ||||
Entergy Mississippi | ($16) to $8 | $ | ||||
Entergy New Orleans |
| ($12) |
|
Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy Mississippi does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation.
In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC ALJ's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the ALJ's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; an d states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate.
In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the ALJ's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations.
In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Louisiana, as well as t he named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity.
Transmission
In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs.
In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations.
Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences.
In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the petition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005.
In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion o f the proposal currently scheduled for August 2005.
Interconnection Orders
The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos, including $27 million for Entergy Mississippi. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy. To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators.
Available Flowgate Capacity Proceeding
On December 17, 2004, the FERC issued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised in a FERC audit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC program, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory.
Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy.
Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the AFC proceeding is currently scheduled to commence in August 2005.
Market and Credit Risks
Entergy Mississippi has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.
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 could produce estimates that would have a material impact on the presentation of Entergy Mississippi's financial position or results of operations.
Unbilled Revenue
As discussed in Note 1 to the domestic utility companies and System Energy financial statements, Entergy Mississippi records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month'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 including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regardi ng price such as the fuel cost recovery mechanism.
Pension and Other Postretirement Benefits
Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 10 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and worse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 6.75% in 2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to a 10% increase in health care costs in 2005 gradually decreasing each successive year, until it reaches a 4.5% annual increase in health care costs in 2011 and beyond.
In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities, and 4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities and 49% fixed income securities. Based on recent market trends, Entergy reduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 8.75% for 2002 and 2003 to 8.5% in 2004. The assumed rate of increase in future compensation levels used to calculate benefit obligations was 3.25% in 2002, 2003, and 2004.
Cost Sensitivity
The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (dollars in 2002 due to the net effect of the System Energy refund, partially offset by increased net income and money pool activity. Money pool activity increased operating cash flow due to Entergy Mississippi lending to the money pool in 2002 and 2001 versus borrowing from the money pool in 2000.
Entergy Mississippi's receivables from or (payables) to the money pool were as follows as of December 31 for each of the following years:
2002 | 2001 | 2000 | 1999 | ||||
(In Thousands) | |||||||
$8,702 | $11,505 | ($30,719) | ($40,622) |
See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.
Cash flow from operations decreased by $4.2 million in 2001 due to money pool activity offset by the net effect of the System Energy refund. Money pool activity decreased operating cash flow due to Entergy Mississippi lending to the money pool in 2001 versus borrowing from the money pool in 2000 and 1999.
Investing Activities
The decrease of $40.7 million in net cash flow used in investing activities in 2002 was primarily due to other temporary cash investments of $18.6 million made in 2001 that provided cash in 2002 when they matured.
The decrease of $103.7 million in net cash flow used in investing activities in 2001 was primarily due to the recovery in 2001 of deferred fuel costs. Entergy Mississippi treated these costs as regulatory investments because the MPSC allowed recovery of the accumulated fuel cost regulatory asset over longer than a twelve-month period. Entergy Mississippi's fuel recovery period changed effective January 2001, and Entergy Mississippi's fuel cost under-recoveries after that date are being recovered over less than a twelve-month period.
The decrease in net cash flow used in investing activities in 2001 was partially offset due to a temporary cash investment of $18.6 million made in 2001 and increased construction expenditures of $38.6 million due to various economic development and substation projects.
Financing Activities
The increase of $25.3 million in net cash flow provided by financing activities in 2002 was primarily due to an increase in net issuances of long-term debt, partially offset by an increase in dividends paid of $7.7 million.
The decrease of $50.9 million in net cash flow provided by financing activities in 2001 was primarily due to a decrease in net issuances of long-term debt.
See Note 7 to the domestic utility companies and System Energy financial statements for details on long-term debt.
Uses of Capital
Entergy Mississippi requires capital resources for:
construction and other capital investments;
debt and preferred stock maturities;
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, and existing debt obligations:
2003 | 2004 | 2005 | 2006-2007 | after 2007 | |||||
(In Millions) | |||||||||
Planned construction and | |||||||||
capital investment | $132 | $136 | $138 | N/A | N/A | ||||
Long-term debt maturities | $255 | $150 | $- | $- | $360 | ||||
Unconditional fuel and purchased | |||||||||
power obligations | $168 | $168 | $168 | $336 | $2,436 |
The planned capital investment estimate for Entergy Mississippi reflects capital required to support existing business and customer growth. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, market volatility, economic trends, and the ability to access capital. Management provides more information on construction expenditures and long-term debt and preferred stock maturities in Notes 5, 6, 7, and 9 to the domestic utility companies and System Energy financial statements.
As a wholly-owned subsidiary, Entergy Mississippi dividends its earnings to Entergy Corporation at a percentage determined monthly. Entergy Mississippi is restricted by its long-term debt indentures in the payment of cash dividends or other distributions on its common and preferred stock. As of December 31, 2002, Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $36.2 million.
Sources of Capital
Entergy Mississippi's sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt issuances; and
bank financing under new or existing facilities.
In 2002, Entergy Mississippi issued $175 million of long-term debt. The net proceeds from Entergy Mississippi's 2002 debt issuances were used to retire, at maturity, $70 million of 6.25% Series First Mortgage Bonds due February 1, 2003, and a portion of the $120 million 7.75% Series First Mortgage Bonds due February 15, 2003. Entergy Mississippi issued an additional $100 million of long-term debt in January 2003 that will be used to meet 2003 maturities. Entergy Mississippi is expected to continue refinancing or redeeming higher-cost debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred stock issuances by Entergy Mississippi require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements.
Short-term borrowings by Entergy Mississippi, including borrowings under the money pool, are limited to an amount authorized by the SEC, $160 million. Under the SEC order authorizing the short-term borrowing limits, Entergy Mississippi cannot incur new short-term indebtedness if the issuer's common equity would comprise less than 30% of its capital. Entergy Mississippi has a 364-day credit facility available expiring May 2003 in the amount of $25 million of which none was drawn at December 31, 2002. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Mississippi's short-term borrowing limits.
Significant Factors and Known Trends
Utility Restructuring
Major changes are occurring in the wholesale and retail electric utility business, including in the electric transmission business. The MPSC has recommended not pursuing open access at this time. At FERC, the pace of restructuring at the wholesale level has begun but has been delayed. It is too early to predict the ultimate effects of changes in U.S. energy markets. Restructuring issues are complex and are continually affected by events at the national, regional, state, and local levels. However, these changes may result, in the long-term, in fundamental changes in the way traditional integrated utilities and holding company systems, like the Entergy system, conduct their business. Some of these changes may be positive for Entergy, while others may not be.
State and Local Rate Regulation
The rates that Entergy Mississippi charges for its services are an important item influencing its financial position, results of operations, and liquidity. Entergy Mississippi is closely 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.
Pursuant to Entergy Mississippi's annual performance-based formula rate plan filing for the 2001 test year, the MPSC approved a stipulation between the MPSC Staff and Entergy Mississippi. The stipulation provided for a $1.95 million rate increase effective in May 2002.
In August 2002, Entergy Mississippi filed a rate case with the MPSC requesting a $68.8 million rate increase effective January 2003. Entergy Mississippi requested this increase as a result of capital investments and operation and maintenance expenditures necessary to replace and maintain aging electric facilities and to improve reliability and customer service. In December 2002, the MPSC issued a final order approving a joint stipulation entered into by Entergy Mississippi and the Mississippi Public Utilities Staff in October 2002. The final order results in a $48.2 million rate increase, which is based on an ROE midpoint of 11.75%. The order endorsed a new power management rider schedule designed to more efficiently collect capacity portions of purchased power costs. Also, the order provides for improvements in the return on equity formula and more robust performance measures for Entergy Mississippi's formula rate plan. Under the provisions of the order, Entergy Mississippi will make its next formula rate plan filing in March 2004.
In addition to rate proceedings, Entergy Mississippi's fuel costs recovered from customers are subject to regulatory scrutiny. Entergy Mississippi's retail rate matters and proceedings, including fuel cost recovery-related issues are discussed more thoroughly in Note 2 to the domestic utility companies and System Energy financial statements.
System Agreement Proceedings
The System Agreement provides for the integrated planning, construction, and operation of Entergy's electric generation and transmission assets throughout the retail service territories of the domestic utility companies. Under the terms of the System Agreement, generating capacity and other power resources are jointly operated by the domestic utility companies. The System Agreement provides, among other things, that parties having generating reserves greater than their load requirements (long companies) shall receive payments from those parties having deficiencies in generating reserves (short companies). Such payments are 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 and preference stock, and a fair rate of return on common equity investment. Under the System Agreement, these charges are based on costs associated with the long companies' steam electric generating units fueled by oil or gas. In addition, for all energy exchanged among the domestic utility companies under the System Agreement, the short companies are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
The LPSC and the Council commenced a proceeding at FERC in June 2001. In this proceeding, the LPSC and the Council allege that the rough production cost equalization required by FERC under the System Agreement and the Unit Power Sales Agreement has been disrupted by changed circumstances. The LPSC and the Council have requested that FERC amend the System Agreement or the Unit Power Sales Agreement or both to achieve full production cost equalization or to restore rough production cost equalization. Their complaint does not seek a change in the total amount of the costs allocated by either the System Agreement or the Unit Power Sales Agreement. In addition, the LPSC and the Council allege that provisions of the System Agreement relating to minimum run and must run units, the methodology of billing versus dispatch, and the use of a rolling twelve-month average of system peaks, increase costs paid by ratepayers in the LPSC and Council's jurisdictions. Several parties have filed interventions in the proceed ing, including the APSC and the MPSC. Entergy filed its response to the complaint in July 2001 denying the allegations of the LPSC and the Council. The APSC and the MPSC also filed responses opposing the relief sought by the LPSC and the Council.
In their complaint, the LPSC and the Council allege that Entergy Mississippi's annual production costs over the period 2002 to 2007 will be $27 million under to $13 million over the average for the domestic utility companies. This range of results is a function of assumptions regarding such things as future natural gas prices, the future market price of electricity, and other factors. In February 2002, the FERC set the matter for hearing and established a refund effective period consisting of the 15 months following September 13, 2001. Negotiations among the parties have not resolved the proceeding, and the proceeding is now set for hearing commencing in June 2003. The case had been set for trial commencing in February 2003; the extension of the schedule also extended the refund effective period by 120 days. If FERC grants the relief requested by the LPSC and the Council, the relief may result in a material increase in production costs allocated to companies whose costs currently are projected to be les s than the average and a material decrease in production costs allocated to companies whose costs currently are projected to exceed the average. Management believes that any changes in the allocation of production costs resulting from a FERC decision should result in similar rate changes for retail customers. Therefore, management does not believe that this proceeding will have a material effect on the financial condition of Entergy Mississippi, although neither the timing nor the outcome of the proceedings at FERC can be predicted at this time.
Market and Credit Risks
Entergy Mississippi has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.
Litigation Risks
The state of Mississippi has proven to be an unusually litigious environment. Judges and juries in Mississippi have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. In November 2002 the Mississippi Legislature passed House Bill 19, which was generally characterized as tort reform legislation. House Bill 19 included, among other things, provisions dealing with the venue of civil actions, the status of innocent sellers as defendants, limitations on the amount of punitive damages, and the elimination of a 15 percent appeal penalty. Entergy Mississippi uses legal and appropriate means to contest litigation threatened or filed against it but the litigation environment in this jurisdiction is a significant business risk.
Critical Accounting Estimates
The preparation of Entergy Mississippi's financial statements in conformity with generally accepted accounting principles requires management 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 estimates as critical accounting estimates because they are based on assumptions and measurements that involve an unusual degree of uncertainty, and there is the potential that different assumptions and measurements could produce estimates that are significantly different than those recorded in Entergy Mississippi's financial statements.
Pension and Other Postretirement Benefits
Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 11 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
Discount rates used in determining the future benefit obligations;
Projected health care cost trend rates;
Expected long-term rate of return on plan assets; and
Rate of increase in future compensation levels.
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and poor performance of the financial markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
In selecting an assumed discount rate, Entergy reviews market yields on high-quality corporate debt. Based on recent market trends, Entergy reduced its discount rate from 7.5% in 2000 and 2001 to 6.75% in 2002. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rates from a range of 8% gradually decreasing to 5% in 2001 to a range of 10% gradually decreasing to 4.5% in 2002.
In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its plan assets of roughly 65% equity securities and 35% fixed income securities. Based on recent market trends, Entergy decreased its expected long-term rate of return on plan assets from 9% in 2000 and 2001 to 8.75% for 2002. The trend of reduced inflation caused Entergy to reduce its assumed rate of increase in future compensation levels from 4.6% in 2000 and 2001 to 3.25% in 2002.
Cost Sensitivity
The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (in thousands):
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| Change in |
| Impact on 2004 |
| Impact on Projected |
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| Increase/(Decrease) | ||||
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Discount rate |
| (0.25%) |
| $598 |
| $6,213 |
Rate of return on plan assets |
| (0.25%) |
| $420 |
| - |
Rate of increase in compensation |
| 0.25% |
| $271 |
| $1,463 |
The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (dollars in thousands):
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| Impact on Accumulated |
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| Increase/(Decrease) | ||||
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Health care cost trend |
| 0.25% |
| $174 |
| $1,161 |
Discount rate |
| (0.25%) |
| $110 |
| $1,519 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
In accordance with SFAS No. 87, "Employers' Accounting for Pensions," 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 cost 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, Entergy accounts for the impact of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87.
Costs and Funding
Total pension cost for Entergy Mississippi in 2004 was $2.1 million. Entergy anticipates 2005 pension cost to increase to $4.4 million due to decrease in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. Entergy Mississippi contributed $1.8 million to its pension plan in 2004, and anticipates making $3.4 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, partially offset by the Pension Funding Equity Act relief passed in April 2004.
Entergy Mississippi's accumulated benefit obligation at December 31, 2004, 2003, and 2002 exceeded plan assets. As a result, Entergy Mississippi was required to recognize an additional minimum liability as prescribed by SFAS 87. At December 31, 2004, Entergy Mississippi increased its additional minimum liability to $23.5 million from $7.3 million at December 31, 2003. Entergy Mississippi increased its intangible asset for the unrecognized prior service cost to $3.3 million at December 31, 2004 from $0.9 million at December 31, 2003. Entergy Mississippi also increased the regulatory asset to $20.2 million at December 31, 2004 from $6.4 million at December 31, 2003. Net income for 2004, 2003, and 2002 was not impacted.
Total postretirement health care and life insurance benefit costs for Entergy Mississippi in 2004 were $3.8 million, including $1.7 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Mississippi expects 2005 postretirement health care and life insurance benefit costs to approximate $4.2 million, including $1.9 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the decrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate used to calculate benefit obligations.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Entergy Mississippi, Inc.:
We have audited the accompanying balance sheets of Entergy Mississippi, Inc. as of December 31, 2004 and 2003, and the related statements of income, retained earnings, and cash flows (pages 240 through 244 and applicable items in pages 284 through 348) for each of the three years in the period ended December 31, 2004. 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 auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Mississippi, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 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 effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control - - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 8, 2005
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ENTERGY MISSISSIPPI, INC. | ||||||
INCOME STATEMENTS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
OPERATING REVENUES | ||||||
Domestic electric | $1,213,629 | $1,035,360 | $991,095 | |||
OPERATING EXPENSES | ||||||
Operation and Maintenance: | ||||||
Fuel, fuel-related expenses, and | ||||||
gas purchased for resale | 335,271 | 155,168 | 318,350 | |||
Purchased power | 436,013 | 449,971 | 315,963 | |||
Other operation and maintenance | 178,007 | 174,192 | 170,052 | |||
Taxes other than income taxes | 53,443 | 47,734 | 47,993 | |||
Depreciation and amortization | 65,452 | 62,984 | 55,409 | |||
Other regulatory charges (credits) - net | (1,171) | 3,664 | (23,438) | |||
TOTAL | 1,067,015 | 893,713 | 884,329 | |||
OPERATING INCOME | 146,614 | 141,647 | 106,766 | |||
OTHER INCOME | ||||||
Allowance for equity funds used during construction | 4,402 | 4,576 | 3,844 | |||
Interest and dividend income | 2,550 | 1,030 | 4,213 | |||
Miscellaneous - net | (1,508) | (2,242) | (2,572) | |||
TOTAL | 5,444 | 3,364 | 5,485 | |||
INTEREST AND OTHER CHARGES | ||||||
Interest on long-term debt | 41,681 | 43,879 | 42,580 | |||
Other interest - net | 2,956 | 3,585 | 2,884 | |||
Allowance for borrowed funds used during construction | (3,116) | (3,942) | (3,467) | |||
TOTAL | 41,521 | 43,522 | 41,997 | |||
INCOME BEFORE INCOME TAXES | 110,537 | 101,489 | 70,254 | |||
Income taxes | 37,040 | 34,431 | 17,846 | |||
NET INCOME | 73,497 | 67,058 | 52,408 | |||
Preferred dividend requirements and other | 3,369 | 3,369 | 3,369 | |||
EARNINGS APPLICABLE TO | ||||||
COMMON STOCK | $70,128 | $63,689 | $49,039 | |||
See Notes to Respective Financial Statements. |
(Page left blank intentionally)
The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (in thousands):
ENTERGY NEW ORLEANS, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS Results of Operations Net Income (Loss) 2004 Compared to 2003 Net income increased $20.2 million primarily due to higher net revenue. 2003 Compared to 2002 Entergy New Orleans had net income of $7.9 million in 2003 compared to a net loss in 2002. The increase was due to higher net revenue and lower interest expense, partially offset by higher other operation and maintenance expenses and depreciation and amortization expenses. Net Revenue 2004 Compared to 2003 Net revenue, which is Entergy New Orleans' measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2004 to 2003.
| |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
revenue | $208.3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 10.6 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 8.3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 7.5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 3.7 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 0.6 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2004 net | $239.0 |
The increase in base rates was effective June 2003. The rate increase is discussed in Note 2 to the domestic utility companies and System Energy financial statements.
The volume/weather variance is primarily due to increased billed electric usage of 162 GWh in the industrial service sector. The increase was partially offset by milder weather in the residential and commercial sectors.
The 2004 deferrals variance is due to the deferral of voluntary severance plan and fossil plant maintenance expenses in accordance with a stipulation approved by the City Council in August 2004. The stipulation allows for the recovery of these costs through amortization of a regulatory asset. The voluntary severance plan and fossil plant maintenance expenses are being amortized over a five-year period that became effective January 2004 and January 2003, respectively. The formula rate plan is discussed in Note 2 to the domestic utility companies and System Energy financial statements.
The price applied to unbilled electric sales variance is due to an increase in the fuel price applied to unbilled sales.
Gross operating revenues, fuel and purchased power expenses, and other regulatory credits
Gross operating revenues increased primarily due to an increase in gross wholesale revenue as a result of an increase of $32.4 million in sales to affiliates and an increase of $28.7 million in fuel revenues due to higher fuel rates, in addition to the net revenue items mentioned above.
Fuel and purchased power expenses increased primarily due to an increase in electricity generated and power purchased coupled with an increase in the market prices of natural gas and purchased power.
Other regulatory credits increased primarily due to a stipulation approved by the City Council in August 2004, as discussed above.
2003 Compared to 2002
Net revenue, which is Entergy New Orleans' measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2003 to 2002.
(In Millions) | ||
2002 net revenue | $183.7 | |
Base rates | 15.9 | |
Rate refund provisions |
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Other | (0.4) | |
2003 net revenue | $208.3 |
The increase in base rates was effective June 2003. The rate increase is discussed in Note 2 to the domestic utility companies and System Energy financial statements.
Rate refund provisions increased net revenue due to larger accruals for potential rate actions and refunds in 2002.
Gross operating revenues and fuel and purchased power expenses
Gross operating revenues increased primarily due to an increase of $78.4 million in sales to affiliates. The increase was also attributable to a base rate increase and an increase in the market price of natural gas.
Fuel and purchased power expenses increased primarily due to an increase in the market price of natural gas.
Other Income Statement Variances
2004 Compared to 2003
Other operation and maintenance expenses decreased slightly primarily due to the $4.7 million voluntary severance program accruals in 2003. The decrease was offset by increases in customer service support costs and maintenance and outage costs at fossil plants.
The increase in miscellaneous income is primarily due to an asbestos insurance settlement in April 2004.
Interest on long-term debt decreased primarily due to long-term debt refinancing in the third quarter of 2003.
2003 Compared to 2002
Other operation and maintenance expenses increased primarily due to the following:
Depreciation and amortization expenses increased due to an increase in plant in service.
Miscellaneous income decreased primarily due to a gain on the sale of property at a non-operating plant site in 2002.
Other interest decreased primarily due to interest accrued in 2002 for potential rate actions and refunds and a true-up of those accruals in May 2003.
Income Taxes
The effective income tax rates for 2004, 2003, and 2002 were 37.5%, 42.8%, and 64.7%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rate. Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows:
2004 | 2003 | 2002 | |||||
(In Thousands) | |||||||
Cash and cash equivalents at beginning of period | $4,669 | $66,247 | $38,184 | ||||
Cash flow provided by (used in): | |||||||
Operating activities | 63,577 | 7,194 | 72,143 | ||||
Investing activities | (49,280) | (64,806) | (41,647) | ||||
Financing activities | (11,012) | (3,966) | (2,433) | ||||
Net increase (decrease) in cash and cash equivalents | 3,285 | (61,578) | 28,063 | ||||
Cash and cash equivalents at end of period | $7,954 | $4,669 | $66,247 |
Operating Activities
Cash flow from operations increased $56.4 million in 2004 primarily due to increased net income and the timing of collections of receivables.
Cash flow from operations decreased $64.9 million in 2003 primarily due to decreased fuel cost recoveries and the timing of collection of receivables due to an increase in retail customer receivable days outstanding.
Entergy New Orleans' receivables from the money pool were as follows as of December 31 for each of the following years:
2004 |
| 2003 |
| 2002 |
| 2001 |
(In Thousands) | ||||||
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$1,413 |
| $1,783 |
| $3,500 |
| $9,208 |
Money pool activity provided $0.4 million of Entergy New Orleans' operating cash flow in 2004, provided $1.7 million in 2003, and provided $5.7 million in 2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.
Investing Activities
Net cash used in investing activities decreased $15.5 million in 2004 primarily due to capital expenditures related to a turbine inspection project at a fossil plant in 2003 and decreased customer service spending.
Net cash used in investing activities increased $23.2 million in 2003 compared to 2002 primarily due to the maturity of $14.9 million of other temporary investments in 2002 and increased construction expenditures due to increased customer service spending.
2002 Compared to 2001
2002 Compared to 2001
Operating income increased by $10.3 million primarily due to:
Partially offsetting the increase were the following:
Other operation and maintenance expenses increased in 2002 due to:
2001 Compared to 2000
Operating income decreased by $32.3 million primarily due to:
Partially offsetting the decrease was an increase in net gas revenue of $17.5 million due to increased fuel recovery, partially offset by decreased sales volume.
Other operation and maintenance expenses increased primarily due to increases in:
The increase in other operation and maintenance expenses was partially offset by a decrease in administrative and general salaries expense of $2.2 million and a decrease in injuries and damage expense of $1.5 million.
Other Impacts on Earnings
2002 Compared to 2001
Other income and interest expense decreased earnings by $4.4 million in 2002 primarily due to:
2001 Compared to 2000
Interest on long-term debt increased earnings by $3.3 million primarily due to the issuance of $30 million of long-term debt in February 2001 and the issuance of $30 million of long-term debt in July 2000.
Income Taxes
The effective income tax rates for 2002, 2001, and 2000 were 64.7%, 66.7%, and 41.2%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate.
Other Income Statement Variances
2002 Compared to 2001
Operating revenues decreased $123.0 million primarily due to decreased fuel cost recovery revenues of $81.4 million and decreased gas revenue of $44.8 million. Corresponding to the decrease in fuel cost recovery revenues, fuel and purchased power expenses decreased by $139.5 million. These decreases were primarily due to a decrease in the market prices of natural gas and purchased power.
Other regulatory credits decreased $14.8 million primarily due to the completion of the Grand Gulf 1 Rate Deferral Plan in 2001. Also contributing to the decrease was an over-recovery of Grand Gulf 1-related costs in 2002 compared to an under-recovery in 2001 and the deferral in 2001 of capacity charges included in purchased power costs for summer capacity that Entergy New Orleans expected to recover in the future.
2001 Compared to 2000
Operating revenues decreased $9.4 million primarily due to:
Largely offsetting the decrease was an increase in fuel cost recovery revenue of $53.4 million primarily due to recovery of higher fuel and purchased power expenses.
Fuel and purchased power expenses increased $33.8 million primarily due to the increased market prices of natural gas and purchased power.
Other regulatory credits increased by $5.0 million primarily due to the deferral of capacity charges included in purchased power costs for summer capacity that Entergy New Orleans expects to recover in the future. The increase was also due to an under-recovery of Grand Gulf 1- related costs in 2001 compared to an over-recovery in 2000.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2002, 2001, and 2000 were as follows:
2002 | 2001 | 2000 | ||||
(In Thousands) | ||||||
Cash and cash equivalents at beginning of period | $ 38,184 | $ 6,302 | $ 4,454 | |||
Cash flow provided by (used in): | ||||||
Operating activities | 72,143 | 77,706 | 30,461 | |||
Investing activities | (41,647) | (74,061) | (47,712) | |||
Financing activities | (2,433) | 28,237 | 19,099 | |||
Net increase in cash and cash equivalents | 28,063 | 31,882 | 1,848 | |||
Cash and cash equivalents at end of period | $ 66,247 | $ 38,184 | $ 6,302 |
Operating Activities
Cash flow from operations decreased in 2002 compared to 2001 primarily due to the payment of the System Energy refund in the first quarter of 2002 in addition to a decrease in customer receivables due to the timing of collections. These decreases were offset by an increase in payables in 2002 compared to 2001 due to the timing of fuel payments.
Cash flow from operations increased in 2001 compared to 2000 primarily due to the net effect of the System Energy refund, partially offset by decreased net income.
Entergy New Orleans' receivables from or (payables) to the money pool were as follows as of December 31 for each of the following years:
2002 | 2001 | 2000 | 1999 | ||||
(In Thousands) | |||||||
$3,500 | $9,208 | ($5,734) | ($9,663) |
Money pool activity increased Entergy New Orleans' operating cash flows by $5.7 million in 2002, decreased operating cash flows by $14.9 million in 2001, and decreased operating cash flow by $3.9 million in 2000. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.
Investing Activities
The decrease in net cash used in investing activities in 2002 was primarily due to the maturity of $14.9 million of other temporary investments.
The increase in net cash used in investing activities in 2001 was primarily due to an increase in temporary investments made in 2001 and an increase in construction expenditures of $12.3 million. Construction expenditures increased primarily due to spending on the customer care system project, distribution substation projects, fossil projects, and City of New Orleans mandated gas projects.
Financing Activities
FinancingNet cash used in financing activities used a small amount of cashincreased $7.0 million in 2002 compared to providing cash in 20012004 primarily due to the net issuance of $30costs and expenses related to refinancing $75 million of long-term debt in 2001.
The2004 and an increase in net cash provided by financing activities in 2001 was primarily due the net issuance of $30$2.2 million of long-term debt in 2001 and a decrease in common stock dividends paid.
Net cash used in financing activities increased $1.5 million in 2003 primarily due to additional common stock dividends paid to Entergy Corporation of $8.7$2.2 million.
In July 2003, Entergy New Orleans issued $30 million of 3.875% Series First Mortgage Bonds due August 2008 and $70 million of 5.25% Series First Mortgage Bonds due August 2013. The proceeds from these issuances were used to redeem, prior to maturity, $30 million of 7% Series First Mortgage Bonds due July 2008, $40 million of 8% Series bonds due March 2006, and $30 million of 6.65% Series First Mortgage Bonds due March 2004. The issuances and redemptions are not shown on the cash flow statement because the proceeds from the issuances were placed in a trust for use in the redemptions and never held as cash by Entergy New Orleans.
See Note 75 to the domestic utility companies and System Energy financial statements for details on long-term debt.
Uses of Capital
Entergy New Orleans requires capital resources for:
Following are the amounts of Entergy New Orleans' planned construction and other capital investments and existing debt obligations:
| 2005 |
| 2006-2007 |
| 2008-2009 |
| After 2009 |
| Total |
| (In Millions) | ||||||||
Planned construction and |
|
|
|
|
|
|
|
|
|
capital investment (1) | $47 |
| $96 |
| N/A |
| N/A |
| $143 |
Long-term debt | $30 |
| $- |
| $30 |
| $170 |
| $230 |
Purchase obligations (2) | $182 |
| $346 |
| $200 |
| $1,215 |
| $1,943 |
(1) | Consists almost entirely of maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. |
(2) | 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 domestic utility companies and System Energy financial statements. |
2003 | 2004 | 2005 | 2006-2007 | After 2007 | |||||
(In Millions) | |||||||||
Planned construction and | |||||||||
capital investment | $51 | $53 | $54 | N/A | N/A | ||||
Long-term debt maturities | N/A | $30 | $30 | $40 | $130 | ||||
Unconditional fuel and purchased power |
|
|
|
|
|
In addition to these contractual obligations, Entergy New Orleans expects to contribute $15.7 million to its pension plans and $4.4 million to other postretirement plans in 2005.
The planned capital investment estimate for Entergy New Orleans reflects capital required to support existing business. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, and the ability to access capital. Management provides more information on construction expenditures and long-term debt and preferred stock maturities in Notes 5 and 6 7, and 9 to the domestic utility companies and System Energy financial statements.
As a wholly-owned subsidiary, Entergy New Orleans dividends its earnings to Entergy Corporation at a percentage determined monthly. Currently,In addition, all of Entergy New Orleans' retained earnings are currently available for distribution.
Sources of Capital
Entergy New Orleans' sources to meet its capital requirements include:
As shown in the Earnings Ratios presented in Item 1 of this Form 10-K, Entergy New Orleans' earnings for the twelve months ended December 31, 2002 and 2001 were not adequate to cover its fixed charges and preferred dividends. Under its mortgage covenants, Entergy New Orleans does not currently haveissued $75 million of First Mortgage Bonds in 2004 as follows:
Issue Date | Description | Maturity | Amount | |||
(In Thousands) | ||||||
August 2004 | 5.60% Series | September 2024 | $35,000 | |||
August 2004 | 5.65% Series | September 2029 | 40,000 | |||
$75,000 |
Proceeds from the capacityissuances in August 2004 were used to issue new incremental mortgage-backed debt. Sinceretire or redeem the settlement of Entergy New Orleans' last rate proceeding, which was approved by the City Council in 1998, its fixed charge coverage has declined and its debt ratio has increased. Whilefollowing First Mortgage Bonds:
Retirement Date |
|
|
| |||
(In Thousands) | ||||||
September 2004 | 7.55% Series | September 2023 | $30,000 | |||
September 2004 | 8.00% Series | March 2023 | 45,000 | |||
$75,000 |
In July 2004, Entergy New Orleans has made investments (some of which were required by agreemententered into a credit facility and Entergy Louisiana renewed its credit facility with the City Council) and incurred expenses necessary to improve customer service since its last rate proceeding, its base revenues have not increased. In an October 2002 report, Moody's Investors Service states that its rating outlook forsame lender. Both facilities will expire in April 2005. Entergy New Orleans is negative duecan borrow up to $14 million and Entergy Louisiana can borrow up to $15 million under their respective credit facilities, but at no time can the declining credit measures andtotal amount borrowed by the uncertaintytwo companies combined exceed $15 million. As of Entergy New Orleans' pending rate cas e. Moody's currently rates December 31, 2004, no borrowings were outstanding under the facilities.
Entergy New Orleans senior secured debt at Baa2.
In May 2002, Entergy New Orleans filed a cost of service study and revenue requirement filing with the City Council for the 2001 test year. The filing indicated that a revenue deficiency exists and that a $28.9 million electric rate increase and a $15.3 million gas rate increase are appropriate. The City Council has established a procedural schedule for consideration of the filing and hearings are scheduled to begin in May 2003. The procedural schedule provides for the City Council's decision with respect to Entergy New Orleans' filing by June 15, 2003. On March 13, 2003, Entergy New Orleans and the Advisors to the City Council presented to the City Council an agreement in principle that, if approved by the City Council, would resolve the proceeding. The agreement in principle, if approved by the City Council, would result in a $30.2 million base rate increase for Entergy New Orleans. A procedural schedule for the City Council's consideration of the agreement in principle has not been established. Entergy New Orleans' rates will remain at their current level until the earlier of a decision in the proceedingmay refinance or June 15, 2003. Absent constructive rate-making in its pending proceeding, it is likely that the cost of and access to the capital necessary to finance Entergy New Orleans' current level of service will be adversely affected.
The net proceeds of Entergy New Orleans' debt issuance in 2002 were used to redeem prior to maturity, $25 million of 7% Series First Mortgage Bonds due March 1, 2003. Entergy New Orleans is expected to continue refinancing or redeeming higher-cost 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 New Orleans require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy New Orleans has sufficient capacity under these tests to meet its foreseeable capital needs.
Short-term borrowings by Entergy New Orleans, including borrowings under the money pool, are limited to an amount authorized by the SEC, $100 million. Under restrictions contained in its articles of incorporation, Entergy New Orleans could incur approximately $38$40 million of new unsecured debt as of December 31, 2002.2004. Under theits SEC order authorizing the short-term borrowing limits,Order and without further SEC authorization, Entergy New Orleans cannot incur newadditional short-term indebtedness if itsunless (a) it and Entergy Corporation maintain a common equity would comprise lessratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy New Orleans (other than 30%preferred stock), as well as all outstanding securities of its capital.Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy New Orleans' short-term borrowing limits.
Significant Factors and Known Trends
State and Local Rate Regulatory Risks
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 closely 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.
In May 2003, the City Council approved a resolution allowing for a total increase of $30.2 million in electric and gas base rates effective June 1, 2003. In April 2004, Entergy New Orleans made filings with the City Council as required by the earnings review process prescribed by the Gas and Electric Formula Rate Plans approved by the City Council in 2003. The filings sought an increase in Entergy New Orleans' electric revenues of $1.2 million and an increase in Entergy New Orleans' gas revenues of $32,000. The Council Advisors and intervenors reviewed the filings, and filed their recommendations in July 2004. In August 2004, in accordance with the City Council's requirements for the formula rate plans, Entergy New Orleans made a filing with the City Council reflecting the parties' concurrence that no change in Entergy New Orleans' electric or gas rates is warranted. Later in August 2004, the City Council approved an unopposed settlement among Entergy New Orleans, the Council Advisors, and the intervenors in connection with the Gas and Electric Formula Rate Plans. In accordance with the resolution approving the settlement agreement, Entergy New Orleans' gas and electric base rates remain unchanged from levels set in May 2003. The resolution ordered Entergy New Orleans to defer $3.9 million relating to voluntary severance plan costs allocated to its electric operations and $1.0 million allocated to its gas operations, which amounts were accrued on its books in 2003, and to record on its books regulatory assets in those amounts to be amortized over five years effective January 2004. Entergy New Orleans also was ordered to defer $6.0 million of fossil plant maintenance expense incurred in 2003 and to record on its books a regulatory asset in that amount to be amortized over a five-year period effective January 2003.
Entergy New Orleans will file its formula rate plan for the year ended December 31, 2004 by May 1, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in effect based on the December 31, 2004 test year shall continue.
In May 2003, the City Council approved implementation of a generation performance-based rate calculation in the electric fuel adjustment clause under which Entergy New Orleans receives 10% of calculated fuel and purchased power cost savings in excess of $20 million, based on a defined benchmark, subject to a 13.25% return on equity limitation for electric operations as provided for in the electric formula rate plan. Entergy New Orleans bears 10% of any "negative" fuel and purchased power cost savings. In October 2004, Entergy New Orleans' annual evaluation report was submitted for the period June 2003 through May 2004. Additional savings associated with the first year generation performance-based rate calculation was $71 million of which Entergy New Orleans' share was $5.1 million.
In April 1999, a group of ratepayers filed a complaint against Entergy New Orleans, Entergy Corporation, Entergy Services, and Entergy Power in state court in Orleans Parish purportedly on behalf of all Entergy New Orleans ratepayers. The plaintiffs seek treble damages for alleged injuries arising from the defendants' alleged violations of Louisiana's antitrust laws in connection with certain costs passed on to ratepayers in Entergy New Orleans' fuel adjustment filings with the City Council. In particular, plaintiffs allege that Entergy New Orleans improperly included certain costs in the calculation of fuel charges and that Entergy New Orleans imprudently purchased high-cost fuel from other Entergy affiliates. Plaintiffs allege that Entergy New Orleans and the other defendant Entergy companies conspired to make these purchases to the detriment of Entergy New Orleans' ratepayers and to the benefit of Entergy's shareholders, in violation of Louisiana's antitrust laws. Plaintiffs also s eek to recover interest and attorneys' fees. Entergy filed exceptions to the plaintiffs' allegations, asserting, among other things, that jurisdiction over these issues rests with the City Council and FERC. In March 2004, the plaintiffs supplemented and amended their petition. If necessary, at the appropriate time, Entergy will also raise its defenses to the antitrust claims. The suit in state court has been stayed by stipulation of the parties pending a decision by the City Council in the proceeding discussed in the next paragraph.
Plaintiffs also filed this complaint with the City Council in order to initiate a review by the City Council of the plaintiffs' allegations and to force restitution to ratepayers of all costs they allege were improperly and imprudently included in the fuel adjustment filings. Testimony was filed on behalf of the plaintiffs in this proceeding asserting, among other things, that Entergy New Orleans and other defendants have engaged in fuel procurement and power purchasing practices and included costs in Entergy New Orleans' fuel adjustment that could have resulted in New Orleans customers being overcharged by more than $100 million over a period of years. Hearings were held in February and March 2002. In February 2004, the City Council approved a resolution that resulted in a refund to customers of $11.3 million, including interest, during the months of June through September 2004. The resolution concludes, among other things, that the record does not support an allegation that Enterg y New Orleans' actions or inactions, either alone or in concert with Entergy or any of its affiliates, constituted a misrepresentation or a suppression of the truth made in order to obtain an unjust advantage of Entergy New Orleans, or to cause loss, inconvenience, or harm to its ratepayers. The plaintiffs have appealed the City Council resolution to the state court in Orleans Parish. Oral argument on the plaintiffs' appeal was conducted in February 2005.
In addition to rate proceedings, Entergy New Orleans' fuel costs recovered from customers are subject to regulatory scrutiny.
Entergy New Orleans' retail and wholesale rate matters and proceedings, including fuel cost recovery- related issues, are discussed more thoroughly in Note 2 to the domestic utility companies and System Energy financial statements.
System Agreement Proceedings
The System Agreement provides fordomestic utility companies historically have engaged in the integratedcoordinated planning, construction, and operation of Entergy's electric generationgenerating and transmission assets throughoutfacilities under the retail service territoriesterms of an agreement called the System Agreement that has been approved by the FERC. Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies. Under the termscompanies in their execution of the System Agreement, generating capacity and other power resources are jointly operated by the domestic utility companies. Theseek support for local regulatory authority over System Agreement provides, among other things,issues. Regarding the proceeding at the LPSC, Entergy believes that parties having generating reserves greater than their load requirements (long companies) shall receive paymentsstate and local regulators are preempted by federal law from those parties having deficiencies in generating reserves (short companies). Such payments are at amounts sufficient to cover certain of the long companies' costs for intermediatereviewing and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred and preference stock, and a fair rate of return on common equity investment. Under thedeciding System Agreement these charges are based on costs associated with the long companies' steam electric generating units fueled by oil or gas. In addition,issues for all energy exchanged among the domestic utility companies under the System Agreement, the short companies are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
The LPSC and the Council commenced a proceeding at FERC in June 2001. In this proceeding,themselves. An unrelated case between the LPSC and Entergy Louisiana raised the Council allegequestion of whether a state regulator is preempted by federal law from reviewing and interpreting F ERC rate schedules that the rough production cost equalization required by FERC underare part of the System Agreement, and the Unit Power Sales Agreement has been disrupted by changed circumstances.from subsequently enforcing that interpretation. The LPSC and the Council have requested that FERC amend theinterpreted a System Agreement or the Unit Power Sales Agreement or both to achieve full production cost equalization or to restore rough production cost equalization. Their complaint does not seek a changerate schedule in the total amount ofunrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed the costs allocated by eitherLPSC's decision. In 2003, the System Agreement orU.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the Unit Power Sales Agreement. In addition, the LPSC and the Council allege that provisions of the System Agreement relating to minimum run and must run units, the methodology of billing versus dispatch, and the use of a rolling twelve-month average of system peaks, increase costs paid by ratepayers in the LPSC and Council's jurisdictions. Several parties have filed interventions in the proceed ing, including the APSC and the MPSC. Entergy filed its response to the complaint in July 2001 denying the allegationsdecisions of the LPSC and the Council.Louisiana Supreme Court.
In February 2004, a FERC ALJ issued an Initial Decision in the LPSC-initiated proceeding at the FERC. The APSC and the MPSC also filed responses opposingInitial Decision decided some issues in favor of the relief sought by the LPSC, and decided some issues against the Council.
In their complaint,relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the Council allegeFERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy New Orleans' annualLouisiana's production costs over the period 2002 to 2007 will be $7 million to $46 million over the average for the domestic utility companies. This rangepurposes of results is a function of assumptions regarding such things as future natural gas prices, the future market price of electricity, and other factors. In February 2002, the FERC set the matter for hearing and established a refund effective period consisting of the 15 months following September 13, 2001. Negotiations among the parties have not resolved the proceeding,calculating relative production costs; and the proceeding is now set for hearing commencing in June 2003. The case had been set for trial commencing in February 2003. The extensionInitial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the schedule also extendedcurrent method.
If the refund effective period by 120 days. If FERC grants the relief requested by the LPSC andin the Council,proceeding, the relief may result in a material increase in the total production costs allocatedthe FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs allocatedthe FERC allocates to companies whose costs currently are projected to exceed that average. If the average. FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility compan ies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.
An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu duri ng the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:
| Average Annual | ||
(In Millions) | (In Millions) | ||
Entergy Arkansas | $154 to $281 | $215 | |
Entergy Gulf States | ($130) to ($15) | ($63) | |
Entergy Louisiana | ($199) to ($98) | ($141) | |
Entergy Mississippi | ($16) to $8 | $1 | |
Entergy New Orleans | ($17) to ($5) | ($12) |
Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. Therefore, managementAlthough the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy New Orleans does not believe that this proceedingthe ultimate resolution of these proceedings will have a material effect on theits financial condition or results of operation.
In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC ALJ's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the ALJ's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; an d states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate.
In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the ALJ's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations.
In April 2004, the City Council issued a resolution directing Entergy New Orleans although neitherand Entergy Louisiana to notify the timing norCity Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Louisiana, as well as t he named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity.
Transmission
In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs.
In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations.
Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences.
In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the proceedingspetition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005.
In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion o f the proposal currently scheduled for August 2005.
Available Flowgate Capacity Proceeding
On December 17, 2004, the FERC canissued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised in a FERC audit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC program, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory.
Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy.
Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time.
On March 13, 2003, Entergy New Orleans and the Advisors to the City Council presented to the Council an agreement in principle that, if approved by the Council, would resolve Entergy New Orleans' pending rate proceeding. The agreement in principle, if approved by the Council, would result A hearing in the Council withdrawing as a complainantAFC proceeding is currently scheduled to commence in the FERC proceeding. A procedural schedule for the City Council's consideration of the agreement in principle has not been established.
August 2005.
Market and Credit Risks
Entergy New Orleans has certain market and credit risks inherent in its business. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.
State and Local Rate Regulatory Risks
The rates that Entergy New Orleans charges for its services are an important item influencing its financial position, results of operations, and liquidity. Entergy New Orleans is closely 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.
In addition to rate proceedings, Entergy New Orleans' fuel costs recovered from customers are subject to regulatory scrutiny.
Entergy New Orleans' retail and wholesale rate matters and proceedings, including fuel cost recovery- related issues, are discussed more thoroughly in Note 2 to the domestic utility companies and System Energy financial statements.
Environmental Risks
Entergy New Orleans' 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.
Litigation Risks
The territory in which Entergy New Orleans operates has proven to be an unusually litigious environment. Judges and juries in New Orleans have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy New Orleans uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment poses a significant business risk.
Critical Accounting Estimates
The preparation of Entergy New Orleans' 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 accounting estimates because they are based on assumptions and measurements that involve an unusuala high degree of uncertainty, and there is the potential that differentfor future changes in the assumptions and measurements could produce estimates that are significantly different than those recorded inwould have a material impact on the presentation of Entergy New Orleans' financial statements.position or results of operations.
Unbilled Revenue
As discussed in Note 1 to the domestic utility companies and System Energy financial statements, Entergy New Orleans records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month, including fuel price. 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 including changes to estimates such as line loss, which affects the estimate o f unbilled customer usage, and assumptions regarding price such as the fuel cost recovery mechanism.
Pension and Other Postretirement Benefits
Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 1110 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and poorworse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt.debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 7.5% in 2000 and 2001 to 6.75% in 2002.2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rates fromrate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to a range of 8%10% increase in health care costs in 2005 gradually decreasing to 5%each successive year, until it reaches a 4.5% annual increase in 2001 to a range of 10% gradually decreasing to 4.5%health care costs in 2002.2011 and beyond.
In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities, and 35%4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities and 49% fixed income securities. Based on recent market trends, Entergy decreasedreduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 9% in 2000 and 2001 to 8.75% for 2002.2002 and 2003 to 8.5% in 2004. The trend of reduced inflation caused Entergy to reduce its assumed rate of increase in future compensation levels from 4.6% in 2000 and 2001used to calculate benefit obligations was 3.25% in 2002.
2002, 2003, and 2004.
Cost Sensitivity
The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (in(dollars in thousands):
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| Impact on 2004 |
| Impact on Projected |
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| $227 |
| $2,694 |
Rate of return on plan assets |
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| $73 |
| - |
Rate of increase in compensation |
| 0.25% |
| $113 |
| $718 |
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The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (in(dollars in thousands):
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Health care cost trend |
| 0.25% |
| $157 |
| $973 |
Discount rate |
| (0.25%) |
| $50 |
| $1,279 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
In accordance with SFAS No. 87, "Employers' Accounting for Pensions," 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 cost 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, Entergy smoothesaccounts for the impact of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87.
Costs and Funding
Total pension cost for Entergy New Orleans in 20022004 was $3.0$4.6 million. Taking into account asset performance and the changes made in the actuarial assumptions, Entergy New Orleans does not anticipate 2003anticipates 2005 pension cost to be materially different from 2002.decrease to $4.2 million. Entergy New Orleans was not required to make contributionscontributed $2.1 million to its pension plan in 2004, and anticipates making $15.7 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, and does not anticipate fundingpartially offset by the Pension Funding Equity Act relief passed in 2003.April 2004.
Due to negative pension plan asset returns over the past several years, Entergy New Orleans' accumulated benefit obligation at December 31, 2004, 2003 and 2002 exceeded plan assets. As a result, Entergy New Orleans was required to recognize an additional minimum liability of $4.8 million as prescribed by SFAS 87. At December 31, 2004 Entergy New Orleans recorded anincreased its additional minimum liability to $16.9 million from $13.1 million at December 31, 2003. Entergy New Orleans decreased its intangible asset for the $1.8 million of unrecognized prior service cost andto $1.7 million at December 31, 2004 from $2.8 million at December 31, 2003. Entergy New Orleans increased the remaining $3regulatory asset to $15.2 million was recorded as a regulatory asset.at December 31, 2004 from $10.3 million at December 31, 2003. Net income for 2004, 2003, and 2002 waswere not impacted.
Total postretirement health care and life insurance benefit costs for Entergy New Orleans in 20022004 were $4.9 million. Because$4.3 million, including $1.3 million in savings due to the estimated effect of a number of factors, including the increased health care cost trend rate,future Medicare Part D subsidies. Entergy New Orleans expects 20032005 postretirement health care and life insurance benefit costs to approximate $5.8 million.$4.2 million, including $1.4 million in savings due to the estimated effect of future Medicare Part D subsidies.
REPORT OF INDEPENDENT AUDITORS' REPORT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Entergy New Orleans, Inc.:
We have audited the accompanying balance sheets of Entergy New Orleans, Inc. as of December 31, 20022004 and 2001,2003, and the related statements of operations, retained earnings, and cash flows (pages 228261 through 232266 and applicable items in pages 250284 through 303)348) for each of the three years in the period ended December 31, 2002.2004. 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 auditing standards generally accepted inof the United States of America.Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy New Orleans, Inc. as of December 31, 20022004 and 2001,2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20022004 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 effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control - - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 2003
ENTERGY NEW ORLEANS INC. STATEMENTS OF OPERATIONS For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING REVENUES Domestic electric $424,527 $502,672 $514,774 Natural gas 83,347 128,178 125,516 -------- -------- -------- TOTAL 507,874 630,850 640,290 -------- -------- -------- OPERATING EXPENSES Operation and Maintenance: Fuel, fuel-related expenses, and gas purchased for resale 163,323 240,781 253,869 Purchased power 158,191 220,268 173,371 Other operation and maintenance 98,511 92,023 87,254 Taxes other than income taxes 40,099 46,878 45,132 Depreciation and amortization 27,699 24,922 23,550 Other regulatory charges (credits) - net 2,701 (12,049) (7,058) Amortization of rate deferrals - 10,977 24,786 -------- -------- -------- TOTAL 490,524 623,800 600,904 -------- -------- -------- OPERATING INCOME 17,350 7,050 39,386 -------- -------- -------- OTHER INCOME Allowance for equity funds used during construction 1,835 1,987 1,190 Gain on sale of assets 1,985 - - Interest and dividend income 689 5,005 3,514 Miscellaneous - net (1,401) (2,675) (984) -------- -------- -------- TOTAL 3,108 4,317 3,720 -------- -------- -------- INTEREST AND OTHER CHARGES Interest on long-term debt 18,011 17,699 14,429 Other interest - net 4,939 1,962 1,462 Allowance for borrowed funds used during construction (1,840) (1,703) (900) -------- -------- -------- TOTAL 21,110 17,958 14,991 -------- -------- -------- INCOME (LOSS) BEFORE INCOME TAXES (652) (6,591) 28,115 Income taxes (422) (4,396) 11,597 -------- -------- -------- NET INCOME (LOSS) (230) (2,195) 16,518 Preferred dividend requirements and other 965 965 965 -------- -------- -------- EARNINGS (LOSS) APPLICABLE TO COMMON STOCK ($1,195) ($3,160) $15,553 ======== ======== ======== See Notes to Respective Financial Statements.
ENTERGY NEW ORLEANS, INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING ACTIVITIES Net income (loss) ($230) ($2,195) $16,518 Noncash items included in net income (loss): Amortization of rate deferrals - 10,977 24,786 Other regulatory charges (credits) - net 2,701 (12,049) (7,058) Depreciation and amortization 27,699 24,922 23,550 Deferred income taxes and investment tax credits 6,729 (24,198) (639) Allowance for equity funds used during construction (1,835) (1,987) (1,190) Gain on sale of assets (1,985) - - Changes in working capital: Receivables 10,540 33,183 (45,580) Fuel inventory (203) 1,123 (911) Accounts payable 18,070 (40,364) 29,592 Taxes accrued 1,999 (5,823) 5,394 Interest accrued (544) 913 1,163 Deferred fuel costs 4,686 38,430 (13,751) Other working capital accounts (4,971) 9,115 (223) Provision for estimated losses and reserves (3,348) (2,669) (365) Changes in other regulatory assets (3,061) 33,833 (11,637) Other 15,896 14,495 10,812 ------- ------- ------- Net cash flow provided by operating activities 72,143 77,706 30,461 ------- ------- ------- INVESTING ACTIVITIES Construction expenditures (58,341) (61,189) (48,902) Allowance for equity funds used during construction 1,835 1,987 1,190 Changes in other temporary investments - net 14,859 (14,859) - ------- ------- ------- Net cash flow used in investing activities (41,647) (74,061) (47,712) ------- ------- ------- FINANCING ACTIVITIES Proceeds from the issuance of long-term debt 24,332 29,761 29,564 Retirement of long-term debt (25,000) - - Dividends paid: Common stock (800) (800) (9,500) Preferred stock (965) (724) (965) ------- ------- ------- Net cash flow provided by (used in) financing activities (2,433) 28,237 19,099 ------- ------- ------- Net increase in cash and cash equivalents 28,063 31,882 1,848 Cash and cash equivalents at beginning of period 38,184 6,302 4,454 ------- ------- ------- Cash and cash equivalents at end of period $66,247 $38,184 $6,302 ======= ======= ======= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid/(received) during the period for: Interest - net of amount capitalized $19,961 $18,230 $14,331 Income taxes ($37,929) $47,380 $9,207 See Notes to Respective Financial Statements.
ENTERGY NEW ORLEANS INC. BALANCE SHEETS ASSETS December 31, 2002 2001 (In Thousands) CURRENT ASSETS Cash and cash equivalents: Cash $11,175 $5,237 Temporary cash investments - at cost, which approximates market 55,072 32,947 -------- -------- Total cash and cash equivalents 66,247 38,184 -------- -------- Other temporary investments - 14,859 Accounts receivable: Customer 24,901 33,827 Allowance for doubtful accounts (4,774) (4,273) Associated companies 4,901 10,527 Other 10,133 6,550 Accrued unbilled revenues 20,957 20,027 -------- -------- Total accounts receivable 56,118 66,658 -------- -------- Accumulated deferred income taxes 1,230 4,882 Fuel inventory - at average cost 3,284 3,081 Materials and supplies - at average cost 7,785 8,273 Prepayments and other 4,689 26,239 -------- -------- TOTAL 139,353 162,176 -------- -------- OTHER PROPERTY AND INVESTMENTS Investment in affiliates - at equity 3,259 3,259 -------- -------- UTILITY PLANT Electric 627,249 597,575 Natural gas 149,102 142,741 Construction work in progress 48,345 43,166 -------- -------- TOTAL UTILITY PLANT 824,696 783,482 Less - accumulated depreciation and amortization 403,379 396,535 -------- -------- UTILITY PLANT - NET 421,317 386,947 -------- -------- DEFERRED DEBITS AND OTHER ASSETS Regulatory assets: Unamortized loss on reacquired debt 556 761 Other regulatory assets 13,904 10,843 Other 4,855 2,051 -------- -------- TOTAL 19,315 13,655 -------- -------- TOTAL ASSETS $583,244 $566,037 ======== ======== See Notes to Respective Financial Statements.
ENTERGY NEW ORLEANS INC. BALANCE SHEETS LIABILITIES AND SHAREHOLDERS' EQUITY December 31, 2002 2001 (In Thousands) CURRENT LIABILITIES Accounts payable: Associated companies $23,228 $18,199 Other 36,681 23,640 Customer deposits 17,634 18,931 Taxes accrued 1,999 - Interest accrued 6,488 7,032 Deferred fuel costs 14,882 10,196 System Energy refund - 33,614 Other 9,702 1,799 -------- -------- TOTAL 110,614 113,411 -------- -------- DEFERRED CREDITS AND OTHER LIABILITIES Accumulated deferred income taxes and taxes accrued 22,245 25,326 Accumulated deferred investment tax credits 4,893 5,361 SFAS 109 regulatory liability - net 31,318 19,868 Other regulatory liabilities 1,311 - Accumulated provisions 2,454 5,802 Other 32,776 16,735 -------- -------- TOTAL 94,997 73,092 -------- -------- Long-term debt 229,191 229,097 SHAREHOLDERS' EQUITY Preferred stock without sinking fund 19,780 19,780 Common stock, $4 par value, authorized 10,000,000 shares; issued and outstanding 8,435,900 shares in 2002 and 2001 33,744 33,744 Paid-in capital 36,294 36,294 Retained earnings 58,624 60,619 -------- -------- TOTAL 148,442 150,437 -------- -------- Commitments and Contingencies TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $583,244 $566,037 ======== ======== See Notes to Respective Financial Statements.
ENTERGY NEW ORLEANS, INC. STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 2002 2001 2000 (In Thousands) Retained Earnings, January 1 $60,619 $64,579 $58,526 Add: Net income (loss) (230) (2,195) 16,518 Deduct: Dividends declared: Preferred stock 965 965 965 Common stock 800 800 9,500 ------- ------- ------- Total 1,765 1,765 10,465 ------- ------- ------- Retained Earnings, December 31 $58,624 $60,619 $64,579 ======= ======= ======= See Notes to Respective Financial Statements.
ENTERGY NEW ORLEANS, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
March 8, 2005
2002 | 2001 | 2000 | 1999 | 1998 | |
(In Thousands) | |||||
Operating revenues | $ 507,874 | $ 630,850 | $ 640,290 | $ 507,788 | $ 513,750 |
Net income (loss) | $ (230) | $ (2,195) | $ 16,518 | $ 18,961 | $ 16,137 |
Total assets | $ 583,244 | $ 566,037 | $ 559,231 | $ 485,746 | $ 471,904 |
Long-term obligations (1) | $ 229,191 | $ 229,097 | $ 199,031 | $ 169,083 | $ 169,018 |
ENTERGY NEW ORLEANS, INC. | ||||||
STATEMENTS OF OPERATIONS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
OPERATING REVENUES | ||||||
Domestic electric | $588,457 | $527,660 | $424,527 | |||
Natural gas | 147,411 | 126,356 | 83,347 | |||
TOTAL | 735,868 | 654,016 | 507,874 | |||
OPERATING EXPENSES | ||||||
Operation and Maintenance: | ||||||
Fuel, fuel-related expenses, and | ||||||
gas purchased for resale | 245,301 | 214,735 | 163,323 | |||
Purchased power | 256,190 | 231,787 | 158,191 | |||
Other operation and maintenance | 107,874 | 108,217 | 98,511 | |||
Taxes other than income taxes | 43,577 | 42,198 | 40,099 | |||
Depreciation and amortization | 29,657 | 30,004 | 27,699 | |||
Other regulatory charges (credits) - net | (4,670) | (843) | 2,701 | |||
TOTAL | 677,929 | 626,098 | 490,524 | |||
OPERATING INCOME | 57,939 | 27,918 | 17,350 | |||
OTHER INCOME | ||||||
Allowance for equity funds used during construction | 1,378 | 2,085 | 1,835 | |||
Interest and dividend income | 720 | 825 | 689 | |||
Miscellaneous - net | 270 | (1,453) | 584 | |||
TOTAL | 2,368 | 1,457 | 3,108 | |||
INTEREST AND OTHER CHARGES | ||||||
Interest on long-term debt | 15,357 | 17,436 | 18,011 | |||
Other interest - net | 1,253 | 350 | 4,939 | |||
Allowance for borrowed funds used during construction | (1,243) | (2,145) | (1,840) | |||
TOTAL | 15,367 | 15,641 | 21,110 | |||
INCOME (LOSS) BEFORE INCOME TAXES | 44,940 | 13,734 | (652) | |||
Income taxes | 16,868 | 5,875 | (422) | |||
NET INCOME (LOSS) | 28,072 | 7,859 | (230) | |||
Preferred dividend requirements and other | 965 | 965 | 965 | |||
EARNINGS (LOSS) APPLICABLE TO | ||||||
COMMON STOCK | $27,107 | $6,894 | ($1,195) | |||
See Notes to Respective Financial Statements. |
(1) Includes long-term debt (excluding currently maturing debt).
ENTERGY NEW ORLEANS, INC. | ||||||
STATEMENTS OF CASH FLOWS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
OPERATING ACTIVITIES | ||||||
Net income (loss) | $28,072 | $7,859 | ($230) | |||
Adjustments to reconcile net income to net cash flow provided by operating activities: | ||||||
Other regulatory charges (credits) - net | (4,670) | (843) | 2,701 | |||
Depreciation and amortization | 29,657 | 30,004 | 27,699 | |||
Deferred income taxes and investment tax credits | 39,782 | 15,401 | 6,729 | |||
Changes in working capital: | ||||||
Receivables | 9,162 | (41,308) | 10,540 | |||
Fuel inventory | 1,399 | (2,296) | (203) | |||
Accounts payable | (3,014) | 17,817 | 18,070 | |||
Taxes accrued | (13,056) | 1,372 | 5,603 | |||
Interest accrued | (1,455) | (276) | (544) | |||
Deferred fuel costs | (5,279) | (12,162) | 4,686 | |||
Other working capital accounts | 2,121 | (7,553) | (4,971) | |||
Provision for estimated losses and reserves | (1,305) | (1,634) | (3,348) | |||
Changes in other regulatory assets | (5,380) | (9,473) | (3,061) | |||
Other | (12,457) | 10,286 | 8,472 | |||
Net cash flow provided by operating activities | 63,577 | 7,194 | 72,143 | |||
INVESTING ACTIVITIES | ||||||
Construction expenditures | (51,264) | (66,285) | (58,341) | |||
Allowance for equity funds used during construction | 1,378 | 2,085 | 1,835 | |||
Changes in other temporary investments - net | 606 | (606) | 14,859 | |||
Net cash flow used in investing activities | (49,280) | (64,806) | (41,647) | |||
FINANCING ACTIVITIES | ||||||
Proceeds from the issuance of long-term debt | 72,640 | - - | 24,332 | |||
Retirement of long-term debt | (77,487) | - - | (25,000) | |||
Dividends paid: | ||||||
Common stock | (5,200) | (3,001) | (800) | |||
Preferred stock | (965) | (965) | (965) | |||
Net cash flow used in financing activities | (11,012) | (3,966) | (2,433) | |||
Net increase (decrease) in cash and cash equivalents | 3,285 | (61,578) | 28,063 | |||
Cash and cash equivalents at beginning of period | 4,669 | 66,247 | 38,184 | |||
Cash and cash equivalents at end of period | $7,954 | $4,669 | $66,247 | |||
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||
Cash paid/(received) during the period for: | ||||||
Interest - net of amount capitalized | $16,172 | $17,427 | $19,961 | |||
Income taxes | ($5,736) | ($13,530) | ($37,929) | |||
See Notes to Respective Financial Statements. |
ENTERGY NEW ORLEANS, INC. | ||||
BALANCE SHEETS | ||||
ASSETS | ||||
December 31, | ||||
2004 | 2003 | |||
(In Thousands) | ||||
CURRENT ASSETS | ||||
Cash and cash equivalents: | ||||
Cash | $2,998 | $28 | ||
Temporary cash investments - at cost, | ||||
which approximates market | 4,956 | 4,641 | ||
Total cash and cash equivalents | 7,954 | 4,669 | ||
Other temporary investments | - - | 606 | ||
Accounts receivable: | ||||
Customer | 47,356 | 44,663 | ||
Allowance for doubtful accounts | (3,492) | (3,104) | ||
Associated companies | 12,223 | 24,697 | ||
Other | 7,329 | 10,057 | ||
Accrued unbilled revenues | 24,848 | 21,113 | ||
Total accounts receivable | 88,264 | 97,426 | ||
Deferred fuel | 2,559 | - - | ||
Accumulated deferred income taxes | - - | 460 | ||
Fuel inventory - at average cost | 4,181 | 5,580 | ||
Materials and supplies - at average cost | 9,150 | 8,660 | ||
Prepayments and other | 3,467 | 8,050 | ||
TOTAL | 115,575 | 125,451 | ||
OTHER PROPERTY AND INVESTMENTS | ||||
Investment in affiliates - at equity | 3,259 | 3,259 | ||
UTILITY PLANT | ||||
Electric | 699,072 | 666,122 | ||
Natural gas | 183,728 | 167,011 | ||
Construction work in progress | 33,273 | 45,061 | ||
TOTAL UTILITY PLANT | 916,073 | 878,194 | ||
Less - accumulated depreciation and amortization | 435,519 | 420,745 | ||
UTILITY PLANT - NET | 480,554 | 457,449 | ||
DEFERRED DEBITS AND OTHER ASSETS | ||||
Regulatory assets: | ||||
Other regulatory assets | 40,354 | 27,222 | ||
Long term receivables | 2,492 | - | ||
Other | 20,540 | 16,246 | ||
TOTAL | 63,386 | 43,468 | ||
TOTAL ASSETS | $662,774 | $629,627 | ||
See Notes to Respective Financial Statements. | ||||
ENTERGY NEW ORLEANS, INC. | ||||
BALANCE SHEETS | ||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||
December 31, | ||||
2004 | 2003 | |||
(In Thousands) | ||||
CURRENT LIABILITIES | ||||
Currently maturing long-term debt | $30,000 | $ - | ||
Accounts payable: | ||||
Associated companies | 30,563 | 35,008 | ||
Other | 44,149 | 42,718 | ||
Customer deposits | 17,187 | 15,575 | ||
Taxes accrued | 2,592 | - - | ||
Accumulated deferred income taxes | 1,906 | - - | ||
Interest accrued | 4,757 | 6,212 | ||
Deferred fuel costs | - - | 2,720 | ||
Energy Efficiency Program provision | 6,611 | 6,356 | ||
Other | 3,477 | 2,088 | ||
TOTAL | 141,242 | 110,677 | ||
NON-CURRENT LIABILITIES | ||||
Accumulated deferred income taxes and taxes accrued | 47,062 | 39,486 | ||
Accumulated deferred investment tax credits | 3,997 | 4,441 | ||
SFAS 109 regulatory liability - net | 46,406 | 40,543 | ||
Other regulatory liabilities | - - | 954 | ||
Accumulated provisions | 9,323 | 10,628 | ||
Pension liability | 36,845 | 30,585 | ||
Long-term debt | 199,902 | 229,217 | ||
Other | 3,755 | 10,761 | ||
TOTAL | 347,290 | 366,615 | ||
Commitments and Contingencies | ||||
SHAREHOLDERS' EQUITY | ||||
Preferred stock without sinking fund | 19,780 | 19,780 | ||
Common stock, $4 par value, authorized 10,000,000 | ||||
shares; issued and outstanding 8,435,900 shares in 2004 | ||||
and 2003 | 33,744 | 33,744 | ||
Paid-in capital | 36,294 | 36,294 | ||
Retained earnings | 84,424 | 62,517 | ||
TOTAL | 174,242 | 152,335 | ||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $662,774 | $629,627 | ||
See Notes to Respective Financial Statements. |
ENTERGY NEW ORLEANS, INC. | ||||||
STATEMENTS OF RETAINED EARNINGS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
Retained Earnings, January 1 | $62,517 | $58,624 | $60,619 | |||
Add: | ||||||
Net income (loss) | 28,072 | 7,859 | (230) | |||
Deduct: | ||||||
Dividends declared: | ||||||
Preferred stock | 965 | 965 | 965 | |||
Common stock | 5,200 | 3,001 | 800 | |||
Total | 6,165 | 3,966 | 1,765 | |||
Retained Earnings, December 31 | $84,424 | $62,517 | $58,624 | |||
See Notes to Respective Financial Statements. |
ENTERGY NEW ORLEANS, INC. | ||||||||||
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | ||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||
(In Thousands) | ||||||||||
Operating revenues | $735,868 | $654,016 | $507,874 | $630,850 | $640,290 | |||||
Net Income (loss) | $28,072 | $7,859 | ($230) | ($2,195) | $16,518 | |||||
Total assets | $662,774 | $629,627 | $584,705 | $566,037 | $559,231 | |||||
Long-term obligations (1) | $199,902 | $229,217 | $229,191 | $299,097 | $199,031 | |||||
(1) Includes long-term debt (excluding currently maturing debt). | ||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||
(Dollars In Millions) | ||||||||||
Electric Operating Revenues: | ||||||||||
Residential | $184 | $178 | $170 | $190 | $188 | |||||
Commercial | 171 | 162 | 154 | 186 | 171 | |||||
Industrial | 34 | 27 | 25 | 32 | 25 | |||||
Governmental | 70 | 68 | 66 | 81 | 73 | |||||
Total retail | 459 | 435 | 415 | 489 | 457 | |||||
Sales for resale: | ||||||||||
Associated companies | 118 | 85 | 7 | 10 | 32 | |||||
Non-associated companies | 2 | 2 | 2 | 3 | 9 | |||||
Other | 9 | 6 | 1 | 1 | 17 | |||||
Total | $588 | $528 | $425 | $503 | $515 | |||||
Billed Electric Energy Sales (GWh): | ||||||||||
Residential | 2,139 | 2,133 | 2,158 | 1,981 | 2,178 | |||||
Commercial | 2,316 | 2,262 | 2,255 | 2,185 | 2,260 | |||||
Industrial | 575 | 413 | 409 | 414 | 384 | |||||
Governmental | 1,025 | 1,036 | 1,053 | 1,017 | 1,058 | |||||
Total retail | 6,055 | 5,844 | 5,875 | 5,597 | 5,880 | |||||
Sales for resale: | ||||||||||
Associated companies | 1,514 | 1,312 | 144 | 115 | 570 | |||||
Non-associated companies | 25 | 28 | 32 | 59 | 141 | |||||
Total | 7,594 | 7,184 | 6,051 | 5,771 | 6,591 | |||||
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
System Energy's principal asset consists of a 90% ownership and leasehold interest in Grand Gulf 1.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 1 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
OperatingNet Income
20022004 Compared to 20012003
OperatingNet income decreased by $21.3remained relatively unchanged, decreasing $0.06 million in 2002 primarily due2004.
2003 Compared to the following drivers:2002
Other operation and maintenance expenses increased in 2002 primarily due to:
Operating income was relatively flat in 2001 compared to 2000. The issuance of the final order related to System Energy's 1995 rate proceeding resulted in decreased operating revenues due to an increase in the provision for rate refund. Decreased decommissioning expenses and depreciation expenses, alsointerest charges primarily resulting from the final order, partially offset the decreased revenues.
Other Impacts on Earnings
2002 Compared to 2001
Other income andlower interest charges increased earnings by $40.7 million primarily due to:
2001 Compared to 2000
Other income and interest charges decreased earnings by $14.6 million primarily due to:
Income Taxes
The effective income tax rates for 2002, 2001,2004, 2003, and 20002002 were 42.4%, 27.3%41.7%, and 46.4%42.4%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate.
Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2002, 2001,2004, 2003, and 20002002 were as follows:
2002 | 2001 | 2000 | ||||
(In Thousands) | ||||||
Cash and cash equivalents at beginning of period | $49,579 | $ 202,218 | $ 35,152 | |||
Cash flow provided by (used in): | ||||||
Operating activities | 225,639 | 165,895 | 395,580 | |||
Investing activities | (28,873) | (47,634) | (58,767) | |||
Financing activities | (133,186) | (270,900) | (169,747) | |||
Net increase (decrease) in cash and cash equivalents | 63,580 | (152,639) | 167,066 | |||
Cash and cash equivalents at end of period | $113,159 | $ 49,579 | $ 202,218 |
2004 | 2003 | 2002 | |||||
(In Thousands) | |||||||
Cash and cash equivalents at beginning of period | $52,536 | $113,159 | $49,579 | ||||
Cash flow provided by (used in): | |||||||
Operating activities | 332,928 | 100,817 | 225,639 | ||||
Investing activities | (45,053) | (45,065) | (28,873) | ||||
Financing activities | (124,056) | (116,375) | (133,186) | ||||
Net increase (decrease) in cash and cash equivalents | 163,819 | (60,623) | 63,580 | ||||
Cash and cash equivalents at end of period | $216,355 | $52,536 | $113,159 |
Operating Activities
Cash flow from operations increased by $232.1 million in 20022004 primarily due to income tax refunds of $70.6 million in 2004 compared to income tax payments of $230.9 million in 2003. The increase was partially offset by money pool activity, as discussed below.
In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $430 million deduction for System Energy on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004 System Energy realized $144 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit.
Cash flow from operations decreased by $124.8 million in 20012003 primarily due to the effectsfollowing:
System Energy's receivables from the money pool were as follows as of December 31 for each of the following years:years:
2002 | 2001 | 2000 | 1999 | ||||
(In Thousands) | |||||||
$7,046 | $13,853 | $155,301 | $234,222 |
2004 |
| 2003 |
| 2002 |
| 2001 |
(In Thousands) | ||||||
|
|
|
|
|
|
|
$61,592 |
| $19,064 |
| $7,046 |
| $13,853 |
Money pool activity increasedused $42.5 million of System Energy's operating cash flows byin 2004, used $12.0 million in 2003, and provided $6.8 million $141.4 million, and $78.9 million in 2002, 2001, and 2000, respectively, because of decreases in cash loaned to the money pool.2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.
Investing Activities
Net cash used for investing activities was practically unchanged in 2004 compared to 2003 primarily because an increase in construction expenditures caused by a reclassification of inventory items to capital was significantly offset by the maturity of $6.5 million of other temporary investments that had been made in 2003, which provided cash in 2004.
The decreaseincrease of $16.2 million in net cash used in investing activities in 20022003 was primarily due to the following:
Partially offsetting the increases in net cash used in investing activities was a decrease in construction expenditures of $22.1 million in 2003 compared to 2002 primarily due to the power uprate project in 2002.
Financing Activities
The decreaseincrease of $7.7 million in net cash used in financing activities in 20022004 was primarily due to $5.5 million in costs related to System Energy refunding bonds associated with its Grand Gulf Lease Obligation in May 2004 and the retirement of $135.0$ 7.6 million of first mortgage bondslong-term debt 2004. The increase was partially offset by a decrease of $5.0 million in 2001. There was no net reductionthe January 2004 principal payment made on the Grand Gulf sale-leaseback compared to the January 2003 principal payment .
The decrease of first mortgage bonds in 2002.
The increase$16.8 million in net cash used in financing activities in 20012003 was primarily due to:
See Note 75 to the domestic utility companies and System Energy financial statements for details of long-term debt.
Uses of Capital
System Energy requires capital resources for:
Following are the amounts of System Energy's planned construction and other capital investments, existing debt and lease obligations, and other purchase obligations:
| 2005 |
| 2006-2007 |
| 2008-2009 |
| After 2009 |
| Total |
| (In Millions) | ||||||||
Planned construction and |
|
|
|
|
|
|
|
|
|
capital investment | $38 |
| $81 |
| N/A |
| N/A |
| $119 |
Long-term debt | $29 |
| $125 |
| $62 |
| $659 |
| $875 |
$28 |
| $38 |
| N/A |
| N/A |
| $66 |
2003 | 2004 | 2005 | 2006-2007 | after 2007 | |||||
(In Millions) | |||||||||
Planned construction and | |||||||||
capital investment | $13 | $15 | $19 | N/A | N/A | ||||
Long-term debt maturities | $11 | $6 | $25 | $126 | $732 | ||||
Nuclear fuel lease obligations (1) | $25 | $54 | N/A | N/A | N/A |
(1) |
|
System Energy expects to acquire additional fuel,contribute $9.3 million to pay interest,pension plans and $1.7 million to pay maturing debt. If such additional financing cannot be arranged, however, the lesseeother postretirement plans in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations.
2005.
The planned capital investment estimate for System Energy reflects capital required to support the existing business of System Energy. Management provides more information on construction expenditures and long-term debt and preferred stock maturities in Notes 5 6, 7, and 96 to the domestic utility companies and System Energy financial statements.
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:
System Energy had three-year letters of credit in place that were scheduled to expire in March 2003 securing certain of its obligations related to the sales/leasebacksale-leaseback of a portion of Grand Gulf 1.Gulf. System Energy replaced the letters of credit before their expiration with new three-year letters of credit totaling approximately $192$198 million that arewere backed by cash collateral. In December 2003, System Energy used approximately $192 million in March 2003 to provide this cash collateral.
Sourcesreplaced the cash-backed letters of Capital
System Energy's sources to meet its capital requirements include:
letters of credit. In 2002December 2004 System Energy issued $70 millionamended these letters of long-term debt. The net proceeds were usedcredit and they now expire in May 2009.
System Energy may refinance or redeem debt prior to meet an October 2002 debt maturity. 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 corporate charters, bond indentures and other agreements. System Energy has sufficient capacity under these tests to meet its foreseeable capital needs.
Short-term borrowingsBorrowings and securities issuances by System Energy are limited to amounts authorized by the SEC. The current short-term borrowing limitation, including borrowings under the money pool, are limited to an amount authorized by the SEC,is $140 million. Under theits SEC order authorizing the short-term borrowing limits,Orders and without further SEC authorization, System Energy cannot incur newadditional short-term indebtedness if itsunless (a) it and Entergy Corporation maintain a common equity would comprise less thanratio of at least 30% and (b) with the exception of its capital. In addition this order restrictsmoney pool borrowings, the security to be issued (if rated) and all outstanding securities of System Energy, from publicly issuing new long-term debt unlessas well as all outstanding securities of Entergy Corporation, that debt will beare rated, asare rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of System Energy's short-term borrowing limits.
Significant Factors and Known Trends
Market and Credit Risks
System Energy has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.
Interest Rate and Equity Price Risk - Decommissioning Trust Funds
System Energy's nuclear decommissioning trust funds expose it to fluctuations in equity prices and interest rates. The NRC requires System Energy to maintain trusts to fund the costs of decommissioning Grand Gulf 1.Gulf. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the Grand Gulf 1 trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 912 to the domestic utility companies and System Energy financial statements.
Nuclear Matters
System Energy owns and operates, through an affiliate, Grand Gulf 1.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, 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, 1, System Energy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
Litigation Risks
The states in which System Energy's customers operate 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. System Energy uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment poses a significant business risk.
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 accounting estimates because they are based on assumptions and measurements that involve an unusuala high degree of uncertainty, and there is the potential that differentfor future changes in the assumptions and measurements could produce estimates that are significantly different than those recorded inwould have a material impact on the presentation of System Energy's financial statements.
position or results of operations.
Nuclear Decommissioning Costs
Regulations require that Grand Gulf 1 be decommissioned after the facility is taken out of service, and funds are collected and deposited in trust funds during the facility's operating life in order to provide for this obligation. System Energy conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facility. See Note 98 to the domestic utility companies and System Energy financial statements for details regarding System Energy's most recent study and the obligations recorded by System Energy related to decommissioning. The following key assumptions have a significant effect on these estimates:
Cost Escalation Factors - System Energy's decommissioning studies include an assumption that decommissioning costs will escalate over present cost levels by an annual factor averaging approximately 5.5%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11%.
Timing - The date of the plant's retirement must be estimated and an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore" status for later decommissioning, as permitted by applicable regulations. System Energy's decommissioning studies for Grand Gulf 1 assume immediate decommissioning upon expiration of the original plant license. While the impact of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can significantlypossibly decrease the present value of these obligations.
Spent Fuel Disposal - Federal regulations require the Department of EnergyDOE to provide a permanent repository for the storage of spent nuclear fuel, and recent legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. However, until this site is available, 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 can have a significant impact (as much as 16% of estimated decommissioning costs). System Energy's decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant impact on cost estimates. The impact of these potential changes is not presently determinable. Entergy Arkansas'System Energy's decommissioning cost studies assume current technologies and regulations.
System Energy collects substantially all of the projected costs of decommissioning Grand Gulf 1 through rates charged to its customers. The amounts collected through rates, which are based upon decommissioning cost studies, are deposited in decommissioning trust funds. These collections plus earnings on the trust fund investments are estimated to be sufficient to fund the future decommissioning costs. Accordingly, decommissioning costs have almost no impact on System Energy's earnings, as accrued costs are offset by earnings on trust funds and collections from customers. If decommissioning cost study estimates were changed and approved by regulators, collections from customers would also change.
The obligation recorded by System Energy for decommissioning costs is classified as a deferred creditreported in the line item entitled "Decommissioning." ThePrior to the implementation of SFAS 143, the amount recorded for this obligation iswas comprised of collections from customers and earnings on the trust funds. The classification and recording of this obligation will change with the implementation of SFAS 143.
SFAS 143
System Energy implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs are System Energy's only asset retirement obligations, and the measurement and recording of System Energy's decommissioning obligations outlined above will changechanged significantly with the implementation of SFAS 143. The most significant differences in the measurement of these obligations are outlined below:
The net effect of implementing this standard for System Energy will bewas recorded as a regulatory asset, or liability, with no resulting impact on System Energy's net income. AssetsSystem Energy recorded this regulatory asset because its existing rate mechanism is based on a cost standard that allows System Energy to recover all ultimate costs of decommissioning from its customers. Upon implementation, assets and liabilities are expected to increaseincreased by approximately $140$138 million in 2003 as a result of recording the asset retirement obligation at its fair value of $292 million as determined under SFAS 143, reversing the previously recorded decommissioning liability of $154 million, increasing utility plant by $82 million, increasing accumulated depreciation by $36 million, and recording the related regulatory asset and liability.
of $92 million.
Pension and Other Postretirement Benefits
Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 1110 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and poorworse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt.debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 7.5% in 2000 and 2001 to 6.75% in 2002.2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rates fromrate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to a range of 8%10% increase in health care costs in 2005 gradually decreasing to 5%each successive year, until it reaches a 4.5% annual increase in 2001 to a range of 10% gradually decreasing to 4.5%health care costs in 2002.2011 and beyond.
In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities, and 35%4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities and 49% fixed income securities. Based on recent market trends, Entergy decreasedreduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 9% in 2000 and 2001 to 8.75% for 2002.2002 and 2003 to 8.5% in 2004. The trend of reduced inflation caused Entergy to reduce its assumed rate of increase in future compensation levels from 4.6% in 2000 and 2001used to calculate benefit obligations was 3.25% in 2002.
2002, 2003, and 2004.
Cost Sensitivity
The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (in(dollars in thousands):
|
| Change in |
| Impact on 2004 |
| Impact on Projected |
|
| Increase/(Decrease) | ||||
|
|
|
|
|
|
|
Discount rate |
| (0.25%) |
| $433 |
| $4,249 |
Rate of return on plan assets |
| (0.25%) |
| $130 |
| - |
Rate of increase in compensation |
| 0.25% |
| $204 |
| $1,421 |
|
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| |||
| ||||||
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| |||
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| |||
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The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (in(dollars in thousands):
|
|
|
| |||
| ||||||
|
|
|
| |||
|
|
|
|
|
|
|
|
|
| Impact on Accumulated |
|
| Increase/(Decrease) | ||||
|
|
|
|
|
|
|
Health care cost trend |
| 0.25% |
| $154 |
| $756 |
Discount rate |
| (0.25%) |
| $111 |
| $866 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
In accordance with SFAS No. 87, "Employers' Accounting for Pensions," 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 cost 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, Entergy smoothesaccounts for the impact of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87.
Costs and Funding
Total pension cost for System Energy in 20022004 was $2.3$4.6 million. Taking into account asset performance and the changes made in the actuarial assumptions, System Energy does not anticipate 2003anticipates 2005 pension cost to be materially different from 2002.increase to $4.8 million due to decrease in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. System Energy was not required to make contributionscontributed $3.7 million to its pension plan in 2004, and anticipates making $9.2 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, and does not anticipate fundingoffset by the Pension Funding Equity Act relief passed in 2003.April 2004.
Due to negative pension plan asset returns over the past several years, System Energy's accumulated benefit obligation at December 31, 2004, 2003, and 2002 exceeded plan assets. As a result, System Energy was required to recognize an additional minimum liability of $0.4 million as prescribed by SFAS 87. At December 31, 2004 System Energy recorded anincreased its additional minimum liability to $7.7 million from $7.4 million at December 31, 2003. System Energy decreased its intangible asset for theto $0.2 million at December 31, 2004 from $0.4 million of unrecognized prior service cost.at December 31, 2003. System Energy increased its regulatory asset to $15.2 million at December 31, 2004, from $7.0 million at December 31, 2003. Net income for 2004, 2003, and 2002 was not impacted.
Total postretirement health care and life insurance benefit costs for System Energy in 20022004 were $1.5 million, including $0.8 million in savings due to the estimated effect of future Medicare Part D subsidies. System Energy expects 2005 postretirement health care and life insurance benefit costs to approximate $1.7 million. Becausemillion, including $1 million in savings due to the estimated effect of a number of factors, includingfuture Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the increaseddecrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate System Energy expects 2003 costsused to approximate $2.7 million.
calculate benefit obligations.
REPORT OF INDEPENDENT AUDITORS' REPORT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
System Energy Resources, Inc.:
We have audited the accompanying balance sheets of System Energy Resources, Inc. as of December 31, 20022004 and 2001,2003, and the related statements of income, retained earnings, and cash flows (pages 243277 through 248282 and applicable items in pages 250284 through 303)348) for each of the three years in the period ended December 31, 2002.2004. 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 auditing standards generally accepted inof the United States of America.Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of System Energy Resources, Inc. as of December 31, 20022004 and 2001,2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20022004 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 8 to the notes to respective financial statements, in 2003 System Energy Resources, Inc. adopted the provisions of Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control - - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
DELOITTE & TOUCHE LLP
New Orleans, LouisianaFebruary 21, 2003
March 8, 2005
SYSTEM ENERGY RESOURCES, INC. INCOME STATEMENTS For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING REVENUES Domestic electric $602,486 $535,027 $656,749 -------- -------- -------- OPERATING EXPENSES Operation and Maintenance: Fuel, fuel-related expenses, and gas purchased for resale 36,456 37,010 42,369 Nuclear refueling outage expenses 10,723 13,275 14,423 Other operation and maintenance 98,264 85,491 88,257 Decommissioning 16,055 (13,493) 18,944 Taxes other than income taxes 25,992 26,134 30,517 Depreciation and amortization 112,093 53,414 127,904 Other regulatory charges - net 53,769 62,742 63,590 -------- -------- -------- TOTAL 353,352 264,573 386,004 -------- -------- -------- OPERATING INCOME 249,134 270,454 270,745 -------- -------- -------- OTHER INCOME Allowance for equity funds used during construction 2,449 1,769 1,482 Interest and dividend income 2,857 26,271 20,528 Miscellaneous - net 826 (1,190) (82) -------- -------- -------- TOTAL 6,132 26,850 21,928 -------- -------- -------- INTEREST AND OTHER CHARGES Interest on long-term debt 73,891 68,833 87,689 Other interest - net 2,748 69,185 30,830 Allowance for borrowed funds used during construction (902) (830) (854) -------- -------- -------- TOTAL 75,737 137,188 117,665 -------- -------- -------- INCOME BEFORE INCOME TAXES 179,529 160,116 175,008 Income taxes 76,177 43,761 81,263 -------- -------- -------- NET INCOME $103,352 $116,355 $93,745 ======== ======== ======== See Notes to Respective Financial Statements.
SYSTEM ENERGY RESOURCES, INC. | ||||||
INCOME STATEMENTS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
OPERATING REVENUES | ||||||
Domestic electric | $545,381 | $583,820 | $602,486 | |||
OPERATING EXPENSES | ||||||
Operation and Maintenance: | ||||||
Fuel, fuel-related expenses, and | ||||||
gas purchased for resale | 38,337 | 43,132 | 36,456 | |||
Nuclear refueling outage expenses | 12,655 | 12,695 | 10,723 | |||
Other operation and maintenance | 96,809 | 105,333 | 98,264 | |||
Decommissioning | 23,434 | 21,799 | 16,055 | |||
Taxes other than income taxes | 24,364 | 25,521 | 25,992 | |||
Depreciation and amortization | 127,081 | 109,528 | 112,093 | |||
Other regulatory charges (credits) - net | (10,433) | 27,400 | 53,769 | |||
TOTAL | 312,247 | 345,408 | 353,352 | |||
OPERATING INCOME | 233,134 | 238,412 | 249,134 | |||
OTHER INCOME | ||||||
Allowance for equity funds used during construction | 1,544 | 1,140 | 2,449 | |||
Interest and dividend income | 6,870 | 7,556 | 2,857 | |||
Miscellaneous - net | 841 | (1,194) | 826 | |||
TOTAL | 9,255 | 7,502 | 6,132 | |||
INTEREST AND OTHER CHARGES | ||||||
Interest on long-term debt | 58,561 | 62,802 | 73,891 | |||
Other interest - net | 367 | 1,818 | 2,748 | |||
Allowance for borrowed funds used during construction | (500) | (554) | (902) | |||
TOTAL | 58,428 | 64,066 | 75,737 | |||
INCOME BEFORE INCOME TAXES | 183,961 | 181,848 | 179,529 | |||
Income taxes | 78,013 | 75,845 | 76,177 | |||
NET INCOME | $105,948 | $106,003 | $103,352 | |||
See Notes to Respective Financial Statements. |
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SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002 2001 2000 (In Thousands) OPERATING ACTIVITIES Net income $103,352 $116,355 $93,745 Noncash items included in net income: Reserve for regulatory adjustments - (322,368) 54,598 Other regulatory charges - net 53,769 62,742 63,590 Depreciation, amortization, and decommissioning 128,148 39,921 146,848 Deferred income taxes and investment tax credits (38,246) 106,764 (71,212) Allowance for equity funds used during construction (2,449) (1,769) (1,482) Changes in working capital: Receivables 5,719 142,797 87,212 Accounts payable 14,767 (9,587) (7,401) Taxes accrued (44,122) 43,992 13,147 Interest accrued (4,568) 3,088 4,008 Other working capital accounts (6,108) (664) 20,754 Provision for estimated losses and reserves 163 16 (1,328) Changes in other regulatory assets 52,448 38,732 58,592 Other (37,234) (54,124) (65,491) -------- -------- -------- Net cash flow provided by operating activities 225,639 165,895 395,580 -------- -------- -------- INVESTING ACTIVITIES Construction expenditures (40,306) (40,144) (36,555) Allowance for equity funds used during construction 2,449 1,769 1,482 Nuclear fuel purchases (43,140) (37,639) - Proceeds from sale/leaseback of nuclear fuel 43,140 37,639 - Decommissioning trust contributions and realized change in trust assets (13,370) (16,147) (23,694) Changes in other temporary investments - net 22,354 (22,354) - Other - 29,242 - -------- -------- -------- Net cash flow used in investing activities (28,873) (47,634) (58,767) -------- -------- -------- FINANCING ACTIVITIES Proceeds from the issuance of long-term debt 69,505 - - Retirement of long-term debt (100,891) (151,800) (77,947) Dividends paid: Common stock (101,800) (119,100) (91,800) -------- -------- -------- Net cash flow used in financing activities (133,186) (270,900) (169,747) -------- -------- -------- Net increase (decrease) in cash and cash equivalents 63,580 (152,639) 167,066 Cash and cash equivalents at beginning of period 49,579 202,218 35,152 -------- -------- -------- Cash and cash equivalents at end of period $113,159 $49,579 $202,218 ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid/(received) during the period for: Interest - net of amount capitalized $77,190 $130,596 $109,046 Income taxes $156,957 ($107,831) $143,040 Noncash investing and financing activities: Change in unrealized depreciation of decommissioning trust assets ($12,931) ($5,931) ($1,506) See Notes to Respective Financial Statements.
SYSTEM ENERGY RESOURCES, INC. BALANCE SHEETS ASSETS December 31, 2002 2001 (In Thousands) CURRENT ASSETS Cash and cash equivalents: Cash $2,282 $15 Temporary cash investments - at cost, which approximates market Other 110,877 49,564 ---------- ---------- Total cash and cash equivalents 113,159 49,579 ---------- ---------- Other temporary investments - 22,354 Accounts receivable: Associated companies 64,852 70,755 Other 1,377 1,193 ---------- ---------- Total accounts receivable 66,229 71,948 ---------- ---------- Materials and supplies - at average cost 51,492 51,665 Deferred nuclear refueling outage costs 15,666 8,728 Prepayments and other 1,319 1,631 ---------- ---------- TOTAL 247,865 205,905 ---------- ---------- OTHER PROPERTY AND INVESTMENTS Decommissioning trust funds 138,985 138,546 ---------- ---------- UTILITY PLANT Electric 3,131,945 3,098,446 Property under capital lease 455,229 450,014 Construction work in progress 28,128 36,868 Nuclear fuel under capital lease 78,991 61,905 ---------- ---------- TOTAL UTILITY PLANT 3,694,293 3,647,233 Less - accumulated depreciation and amortization 1,514,921 1,416,337 ---------- ---------- UTILITY PLANT - NET 2,179,372 2,230,896 ---------- ---------- DEFERRED DEBITS AND OTHER ASSETS Regulatory assets: SFAS 109 regulatory asset - net 134,895 173,470 Unamortized loss on reacquired debt 45,026 48,381 Other regulatory assets 144,076 157,949 Other 11,191 8,894 ---------- ---------- TOTAL 335,188 388,694 ---------- ---------- TOTAL ASSETS $2,901,410 $2,964,041 ========== ========== See Notes to Respective Financial Statements.
SYSTEM ENERGY RESOURCES, INC. BALANCE SHEETS LIABILITIES AND SHAREHOLDER'S EQUITY December 31, 2002 2001 (In Thousands) CURRENT LIABILITIES Currently maturing long-term debt $11,375 $100,891 Accounts payable: Associated companies 4,851 2,404 Other 26,636 14,316 Taxes accrued 68,400 112,522 Accumulated deferred income taxes 5,322 2,360 Interest accrued 42,527 47,095 Obligations under capital leases 24,954 26,503 Other 1,928 1,583 ---------- ---------- TOTAL 185,993 307,674 ---------- ---------- DEFERRED CREDITS AND OTHER LIABILITIES Accumulated deferred income taxes and taxes accrued 439,540 498,404 Accumulated deferred investment tax credits 82,564 86,040 Obligations under capital leases 54,036 35,401 Other regulatory liabilities 172,111 135,878 Decommissioning 153,473 140,103 Accumulated provisions 868 705 Other 31,927 39,117 ---------- ---------- TOTAL 934,519 935,648 ---------- ---------- Long-term debt 888,665 830,038 SHAREHOLDER'S EQUITY Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2002 and 2001 789,350 789,350 Retained earnings 102,883 101,331 ---------- ---------- TOTAL 892,233 890,681 ---------- ---------- Commitments and Contingencies TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY $2,901,410 $2,964,041 ========== ========== See Notes to Respective Financial Statements.
SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 2002 2001 2000 (In Thousands) Retained Earnings, January 1 $101,331 $104,076 $102,131 Add: Net income 103,352 116,355 93,745 Deduct: Dividends declared 101,800 119,100 91,800 -------- -------- -------- Retained Earnings, December 31 $102,883 $101,331 $104,076 ======== ======== ======== See Notes to Respective Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
SYSTEM ENERGY RESOURCES, INC. | ||||||
STATEMENTS OF CASH FLOWS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
OPERATING ACTIVITIES | ||||||
Net income | $105,948 | $106,003 | $103,352 | |||
Adjustments to reconcile net income to net cash flow provided by operating activities: | ||||||
Other regulatory charges (credits) - net | (10,433) | 27,400 | 53,769 | |||
Depreciation, amortization, and decommissioning | 150,515 | 131,327 | 128,148 | |||
Deferred income taxes and investment tax credits | (178,535) | (35,207) | (38,246) | |||
Changes in working capital: | ||||||
Receivables | (41,067) | (8,025) | 5,719 | |||
Accounts payable | (5,324) | (1,232) | 14,767 | |||
Taxes accrued | 328,617 | (123,317) | (43,112) | |||
Interest accrued | 13,375 | (12,904) | (4,568) | |||
Other working capital accounts | 2,763 | 1,463 | (6,108) | |||
Provision for estimated losses and reserves | (1,404) | 2,914 | 163 | |||
Changes in other regulatory assets | 31,453 | 26,307 | 52,448 | |||
Other | (62,980) | (13,912) | (40,693) | |||
Net cash flow provided by operating activities | 332,928 | 100,817 | 225,639 | |||
INVESTING ACTIVITIES | ||||||
Construction expenditures | (32,303) | (18,195) | (40,306) | |||
Allowance for equity funds used during construction | 1,544 | 1,140 | 2,449 | |||
Nuclear fuel purchases | (45,497) | - | (43,140) | |||
Proceeds from sale/leaseback of nuclear fuel | 45,677 | - | 43,140 | |||
Decommissioning trust contributions and realized | ||||||
change in trust assets | (20,956) | (21,528) | (13,370) | |||
Changes in other temporary investments - net | 6,482 | (6,482) | 22,354 | |||
Net cash flow used in investing activities | (45,053) | (45,065) | (28,873) | |||
FINANCING ACTIVITIES | ||||||
Proceeds from the issuance of long-term debt | - | - | 69,505 | |||
Retirement of long-term debt | (13,973) | (11,375) | (100,891) | |||
Other financing activities | (5,483) | - | - | |||
Dividends paid: | ||||||
Common stock | (104,600) | (105,000) | (101,800) | |||
Net cash flow used in financing activities | (124,056) | (116,375) | (133,186) | |||
Net increase (decrease) in cash and cash equivalents | 163,819 | (60,623) | 63,580 | |||
Cash and cash equivalents at beginning of period | 52,536 | 113,159 | 49,579 | |||
Cash and cash equivalents at end of period | $216,355 | $52,536 | $113,159 | |||
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||
Cash paid/(received) during the period for: | ||||||
Interest - net of amount capitalized | $40,000 | $73,636 | $77,190 | |||
Income taxes | ($70,595) | $230,919 | $156,957 | |||
See Notes to Respective Financial Statements. | ||||||
SYSTEM ENERGY RESOURCES, INC. | ||||||
BALANCE SHEETS | ||||||
ASSETS | ||||||
December 31, | ||||||
2004 | 2003 | |||||
(In Thousands) | ||||||
CURRENT ASSETS | ||||||
Cash and cash equivalents: | ||||||
Cash | $399 | $2,918 | ||||
Temporary cash investments - at cost, | ||||||
which approximates market | 215,956 | 49,618 | ||||
Total cash and cash equivalents | 216,355 | 52,536 | ||||
Other temporary investments | - | 6,482 | ||||
Accounts receivable: | ||||||
Associated companies | 111,588 | 72,477 | ||||
Other | 3,733 | 1,777 | ||||
Total accounts receivable | 115,321 | 74,254 | ||||
Materials and supplies - at average cost | 53,427 | 63,047 | ||||
Deferred nuclear refueling outage costs | 9,510 | 2,979 | ||||
Prepayments and other | 1,007 | 1,031 | ||||
TOTAL | 395,620 | 200,329 | ||||
OTHER PROPERTY AND INVESTMENTS | ||||||
Decommissioning trust funds | 205,083 | 172,916 | ||||
UTILITY PLANT | ||||||
Electric | 3,232,314 | 3,205,895 | ||||
Property under capital lease | 469,993 | 466,521 | ||||
Construction work in progress | 28,743 | 31,344 | ||||
Nuclear fuel under capital lease | 65,572 | 47,242 | ||||
TOTAL UTILITY PLANT | 3,796,622 | 3,751,002 | ||||
Less - accumulated depreciation and amortization | 1,780,450 | 1,672,658 | ||||
UTILITY PLANT - NET | 2,016,172 | 2,078,344 | ||||
DEFERRED DEBITS AND OTHER ASSETS | ||||||
Regulatory assets: | ||||||
SFAS 109 regulatory asset - net | 96,047 | 115,633 | ||||
Other regulatory assets | 296,305 | 301,233 | ||||
Other | 19,578 | 12,269 | ||||
TOTAL | 411,930 | 429,135 | ||||
TOTAL ASSETS | $3,028,805 | $2,880,724 | ||||
See Notes to Respective Financial Statements. | ||||||
SYSTEM ENERGY RESOURCES, INC. | ||||||
BALANCE SHEETS | ||||||
LIABILITIES AND SHAREHOLDER'S EQUITY | ||||||
December 31, | ||||||
2004 | 2003 | |||||
(In Thousands) | ||||||
CURRENT LIABILITIES | ||||||
Currently maturing long-term debt | $25,266 | $6,348 | ||||
Accounts payable: | ||||||
Associated companies | 3,880 | - | ||||
Other | 21,051 | 30,255 | ||||
Taxes accrued | 46,468 | 55,585 | ||||
Accumulated deferred income taxes | 3,477 | 942 | ||||
Interest accrued | 42,998 | 29,623 | ||||
Obligations under capital leases | 27,716 | 31,266 | ||||
Other | 1,621 | 1,971 | ||||
TOTAL | 172,477 | 155,990 | ||||
NON-CURRENT LIABILITIES | ||||||
Accumulated deferred income taxes and taxes accrued | 421,466 | 290,964 | ||||
Accumulated deferred investment tax credits | 75,612 | 79,088 | ||||
Obligations under capital leases | 37,855 | 15,976 | ||||
Other regulatory liabilities | 210,863 | 213,093 | ||||
Decommissioning | 335,893 | 312,459 | ||||
Accumulated provisions | 2,378 | 3,782 | ||||
Long-term debt | 849,593 | 882,401 | ||||
Other | 28,084 | 33,735 | ||||
TOTAL | 1,961,744 | 1,831,498 | ||||
Commitments and Contingencies | ||||||
SHAREHOLDER'S EQUITY | ||||||
Common stock, no par value, authorized 1,000,000 shares; | ||||||
issued and outstanding 789,350 shares in 2004 and 2003 | 789,350 | 789,350 | ||||
Retained earnings | 105,234 | 103,886 | ||||
TOTAL | 894,584 | 893,236 | ||||
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY | $3,028,805 | $2,880,724 | ||||
See Notes to Respective Financial Statements. | ||||||
SYSTEM ENERGY RESOURCES, INC. | ||||||
STATEMENTS OF RETAINED EARNINGS | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
Retained Earnings, January 1 | $103,886 | $102,883 | $101,331 | |||
Add: | ||||||
Net income | 105,948 | 106,003 | 103,352 | |||
Deduct: | ||||||
Dividends declared | 104,600 | 105,000 | 101,800 | |||
Retained Earnings, December 31 | $105,234 | $103,886 | $102,883 | |||
See Notes to Respective Financial Statements. |
SYSTEM ENERGY RESOURCES, INC. | SYSTEM ENERGY RESOURCES, INC. | ||||||||||||||
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | ||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | |||||||||||
2002 | 2001 | 2000 | 1999 | 1998 | (Dollars In Thousands) | ||||||||||
(Dollars In Thousands) | |||||||||||||||
Operating revenues | $ 602,486 | $ 535,027 | $ 656,749 | $ 620,032 | $ 602,373 | $545,381 | $583,820 | $602,486 | $535,027 | $620,032 | |||||
Net income | $ 103,352 | $ 116,355 | $ 93,745 | $ 82,372 | $ 106,476 | ||||||||||
Net Income | $105,948 | $106,003 | $103,352 | $116,355 | $82,372 | ||||||||||
Total assets | $ 2,901,410 | $ 2,964,041 | $ 3,274,550 | $ 3,369,048 | $ 3,431,205 | $3,028,805 | $2,880,724 | $2,915,898 | $2,964,041 | $3,369,048 | |||||
Long-term obligations (1) | $ 942,701 | $ 865,439 | $ 947,991 | $ 1,122,178 | $ 1,182,616 | $887,448 | $898,377 | $942,701 | $865,439 | $1,122,178 | |||||
Electric energy sales (GWh) | 9,053 | 8,921 | 9,621 | 7,567 | 8,259 | 9,212 | 9,812 | 9,053 | 8,921 | 7,567 | |||||
(1) Included long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. | (1) Included long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. | ||||||||||||||
(1) Includes long-term debt (excluding current maturities) and noncurrent capital lease obligations.
ENTERGY ARKANSAS, ENTERGY GULF STATES, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND SYSTEM ENERGY
RESOURCES
NOTES TO RESPECTIVE FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
The accompanying separate financial statements of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (the "domestic utility companies") and System Energy are included in this document and result from these companies having registered securities with the SEC. These companies maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications, with no effect on net income or shareholders' equity.
Use of Estimates in the Preparation of Financial Statements
The preparation of the domestic utility companies' and System Energy's financial statements, in conformity with generally accepted accounting principles, requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. 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, and Entergy Mississippi generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, and Mississippi, respectively. Entergy Gulf States generates, transmits, and distributes electric power primarily to retail customers in Texas and Louisiana. Entergy Gulf States also distributes gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and gas to retail customers in the City of New Orleans, except for Algiers, where Entergy Louisiana is the electric power supplier.
System Energy's operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf 1. The capital costs are computed by allowing a return on System Energy's common equity funds allocable to its net investment in Grand Gulf 1, plus System Energy's effective interest cost for its debt allocable to its investment in Grand Gulf 1. System Energy's 1995 rate proceeding that was resolved in 2001 is discussed in Note 2 to the domestic utility companies and System Energy financial statements.
Entergy recognizes revenue from electric power and gas sales when it delivers power or gas to its customers. To the extent that deliveries have occurred but a bill has not been issued, the domestic utility companies accrue an estimate of the revenues for energy delivered since the latest billings. Entergy calculates 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 the domestic utility companies' various jurisdictions. Each month the estimated unbilled revenue amounts are recorded as revenue and a 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 so recorded and reversed.
The domestic utility companies' rate schedules include either fuel adjustment clauses or fixed fuel factors, both of which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Because the fuel adjustment clause mechanism allows monthly adjustments to recover fuel costs, Entergy Louisiana, Entergy New Orleans, and the Louisiana portion of Entergy Gulf States include a component of fuel cost recovery in their unbilled revenue calculations. 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. Effective January 2001, Entergy Mississippi's fuel factor includes an energy cost rider that is adjusted quarterly. As discussed in Note 2 to the domestic utility companies and System Energy financial statements, the MPSC approved Entergy Mississippi's deferral of the refund of fuel over-recoveries for the third quarter of 2004 that would have been refunded in the first quarter of 2005. The deferred amount plus carrying charges will be refunded in the second and third quarters of 2005. In the case of Entergy Arkansas and the Texas portion of Entergy Gulf States, their fuel under-recoveries are treated as regulatory investments in the cash flow statements because those companies are allowed by their regulatory jurisdictions to recover the fuel cost regulatory asset over longer than a twelve-month period, and the companies earn a carrying charge on the under-recovered balances.
System Energy's operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy's common equity funds allocable to its net investment in Grand Gulf, plus System Energy's effective interest cost for its debt allocable to its investment in Grand Gulf.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. The original cost of plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the domestic utility companies' and System Energy's plant is subject to mortgage liens.
Electric plant includes the portions of Grand Gulf 1 and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions.
Net property, plant, and equipment by company and functional category, as of December 31, 20022004 and 2001,2003, is shown below (in millions):below:
| Entergy | Entergy | Entergy | Entergy | Entergy | System | ||||||
(In Millions) | ||||||||||||
Production | ||||||||||||
Nuclear | $951 | $1,627 | $1,543 | $- | $- | $1,866 | ||||||
Other | 269 | 529 | 197 | 221 | 12 | - | ||||||
Transmission | 646 | 708 | 385 | 406 | 29 | 8 | ||||||
Distribution | 1,283 | 1,339 | 1,000 | 713 | 337 | - | ||||||
Other | 216 | 247 | 269 | 175 | 70 | 16 | ||||||
Construction work in progress | 226 | 332 | 189 | 90 | 33 | 29 | ||||||
Nuclear fuel (leased and owned) | 106 | 71 | 32 | - | - | 66 | ||||||
Asset retirement obligation | 24 | - | 42 | - | - | 31 | ||||||
Property, plant, and equipment - net | $3,721 | $4,853 | $3,657 | $1,605 | $481 | $2,016 |
| Entergy | Entergy | Entergy | Entergy | Entergy | System | ||||||
(In Millions) | ||||||||||||
Production | ||||||||||||
Nuclear | $940 | $1,638 | $1,593 | $- | $- | $1,941 | ||||||
Other | 326 | 583 | 205 | 228 | 17 | - | ||||||
Transmission | 636 | 647 | 369 | 380 | 26 | 9 | ||||||
Distribution | 1,184 | 1,197 | 923 | 632 | 294 | - | ||||||
Other | 214 | 238 | 266 | 166 | 75 | 17 | ||||||
Construction work in progress | 239 | 326 | 172 | 109 | 45 | 31 | ||||||
Nuclear fuel (leased and owned) | 110 | 64 | 65 | - | - | 47 | ||||||
Asset retirement obligation | 45 | 32 | 45 | - | - | 33 | ||||||
Property, plant, and equipment - net | $3,694 | $4,725 | $3,638 | $1,515 | $457 | $2,078 |
(1) This is reflected in accumulated depreciation and amortization on the balance sheet. The decommissioning liabilities related to Grand Gulf 1 and the 30% of River Bend previously owned by Cajun are reflected in the applicable balance sheets in "Deferred Credits and Other Liabilities - Decommissioning."
Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation rates on average depreciable property are shown below:
Entergy | Entergy | Entergy | Entergy | Entergy | System | |||||||
2004 | 3.2% | 2.1% | 2.9% | 2.5% | 2.8% | 2.9% | ||||||
2003 | 3.2% | 2.2% | 3.0% | 2.5% | 3.1% | 2.8% | ||||||
2002 | 3.2% | 2.4% | 3.0% | 2.5% | 3.1% | 2.8% |
Entergy | Entergy | Entergy | Entergy | Entergy | System | |
2002 | 3.2% | 2.4% | 3.0% | 2.5% | 3.1% | 2.8% |
2001 | 3.1% | 2.5% | 2.9% | 2.4% | 3.0% | 2.8% |
2000 | 3.2% | 2.4% | 3.0% | 2.5% | 3.1% | 3.3% |
Jointly-Owned Generating Stations
Certain Entergy subsidiaries jointly own electric generating facilities with third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2002,2004, the subsidiaries' investment and accumulated depreciation in each of these generating stations were as follows:
|
| Fuel-Type | Total MW Capability (1) | Ownership | Investment | Accumulated Depreciation |
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| Total |
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(In Millions) | |||||||||||||||||
Entergy Arkansas - | |||||||||||||||||
Independence | Unit 1 | Coal | 815 | 31.50% | $117 | $66 | Unit 1 | Coal | 815 | 31.50% | $117 | $73 | |||||
Common Facilities | Coal | 15.75% | 31 | 16 | Common Facilities | Coal | 15.75% | $31 | $18 | ||||||||
White Bluff | Units 1 and 2 | Coal | 1,620 | 57.00% | 418 | 244 | Units 1 and 2 | Coal | 1,635 | 57.00% | $428 | $264 | |||||
Entergy Gulf States - |
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Roy S. Nelson | Unit 6 | Coal | 550 | 70.00% | 404 | 227 | Unit 6 | Coal | 550 | 60.90% | $403 | $241 | |||||
Big Cajun 2 | Unit 3 | Coal | 575 | 42.00% | 229 | 119 | Unit 3 | Coal | 575 | 42.00% | $233 | $128 | |||||
Entergy Mississippi - | Units 1 and 2 and Common Facilities | Coal | 1,657 | 25.00% | 228 | 107 | |||||||||||
System Energy | Unit 1 | Nuclear | 1,282 | 90.00%(2) | 3,587 | 1,515 | |||||||||||
Entergy Mississippi - | |||||||||||||||||
Independence | Units 1 and 2 and Common Facilities | Coal | 1,630 | 25.00% | $232 | $116 | |||||||||||
System Energy - | |||||||||||||||||
Grand Gulf | Unit 1 | Nuclear | 1,270 | 90.00%(2) | $3,702 | $1,780 |
(1) "Total MW Capability" is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
(2) Includes an 11.5% leasehold interest held by System Energy. System Energy's Grand Gulf 1 lease obligations are discussed in Note 10
(1) | "Total Megawatt Capability" is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. |
(2) | Includes an 11.5% leasehold interest held by System Energy. System Energy's Grand Gulf lease obligations are discussed in Note 9 to the domestic utility companies and System Energy financial statements. |
Nuclear Refueling Outage Costs
The domestic utility companies and System Energy financial statements.
Nuclear Refueling Outage Costs
The domestic utility companies record nuclear refueling outage costs in accordance with regulatory treatment and the matching principle. These refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line. Except for the River Bend plant, the costs are deferred during the outage and amortized over the period to the next outage. In accordance with the regulatory treatment of the River Bend plant, the costs are accrued in advance and included in the cost of service used to establish retail rates. Entergy Gulf States relieves the accrualaccrued liability when it incurs costs during the next River Bend outage.
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. Although AFUDC increases both the plant balance and earnings, it is realized in cash through depreciation provisions included in rates.
Income Taxes
Entergy Corporation and the majority of its subsidiaries file a U.S. consolidated federal income tax return. Income taxes are allocated to the subsidiaries in proportion to their contribution to consolidated taxable income. SEC regulations require that no Entergy subsidiary pay more taxes than it would have paid if a separate income tax return had been filed. In accordance with SFAS 109, "Accounting for Income Taxes," deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities, and for certain credits available for carryforward.
Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the law or rate was enacted.
Investment tax credits are deferred and amortized based upon the average useful life of the related property, in accordance with ratemaking treatment.
Application of SFAS 71
The domestic utility companies and System Energy currently account for the effects of regulation pursuant to SFAS 71, "Accounting for the Effects of Certain Types of Regulation." This statement applies to the financial statements of a rate-regulated enterprise that meet three criteria. The enterprise must have rates that (i) are approved by a body empowered to set rates that bind customers (its regulator); (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. If an enterprise meets these criteria, it 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. A significant majority of Entergy's re gulatoryregulatory assets, net of related regulatory and deferred tax liabilities, earn a return on investment during their recovery periods. SFAS 71 requires that rate-regulated enterprises assess the probability of recovering their regulatory assets at each balance sheet date. 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.
SFAS 101, "Accounting for the Discontinuation of Application of FASB Statement No. 71," specifies how an enterprise that ceases to meet the criteria for application of SFAS 71 for all or part of its operations should report that event in its financial statements. In general, SFAS 101 requires that the enterprise report the discontinuation of the application of SFAS 71 by eliminating from its balance sheet all regulatory assets and liabilities related to the applicable segment. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs and therefore no longer qualifies for SFAS 71 accounting, it is possible that an impairment may exist that could require further write-offs of plant assets.
EITF 97-4: "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101" specifies that SFAS 71 should be discontinued at a date no later than when the effects of a transition to competition plan for all or a portion of the entity subject to such plan are reasonably determinable. Additionally, EITF 97-4 promulgates that regulatory assets to be recovered through cash flows derived from another portion of the entity that continues to apply SFAS 71 should not be written off; rather, they should be considered regulatory assets of the segment that will continue to apply SFAS 71.
Cash and Cash Equivalents
Entergy considers all unrestricted highly liquid debt instruments purchased with an original or remaining maturity of three months or less at date of purchase to be cash equivalents. Investments with original maturities of more than three months are classified as other temporary investments on the balance sheet.
Investments
Entergy applies the provisions of SFAS 115, "Accounting for Investments for Certain Debt and Equity Securities," in accounting for investments in decommissioning trust funds. As a result, Entergy records the decommissioning trust funds at their fair value on the consolidated balance sheet. As of December 31, 2002 and 2001, the fair valueBecause of the securities heldability of the domestic utility companies and System Energy to recover decommissioning costs in such funds differs from the amounts deposited plus the earnings on the deposits by the following (in millions):
2002 | 2001 | |
Entergy Arkansas | $35.3 | $69.8 |
Entergy Gulf States | $1.4 | $18.5 |
Entergy Louisiana | ($0.3 ) | $8.2 |
System Energy | ($14.5 ) | ($1.6 ) |
Inrates and in accordance with the regulatory treatment for decommissioning trust funds, Entergy Arkansas, Entergy Gulf States (for the regulated portion of River Bend), and Entergy Louisiana, and System Energy have recorded an offsetting amount of unrealized gains/(losses) on investment securities in accumulated depreciation.other regulatory liabilities/assets. For the nonregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. See Note 12 to the domestic utility companies and System Energy's offsetting amount of unrealized gains/(losses)Energy financial statements for details on investment securities is in other regulatory liabilities.
the de commissioning trust funds.
Derivatives and Hedging
Entergy implemented SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" on January 1, 2001. The statementActivities," requires that all derivatives be recognized in the balance sheet, either as assets or liabilities, at fair value.value, unless they meet the normal purchase, normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and if it is, the type of hedge transaction.
For cash-flow hedge transactions in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transaction, changes in the fair value of the derivative instrument are reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income are reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portions of all hedges are recognized in current-period earnings.
Contracts for commodities that will be delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, are not classified as derivatives. These contracts are exempted under the normal purchase, normal sales criteria of SFAS 133. 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 as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The ineffective portions of all hedges are recognized in current-period earnings.
Fair Values
The estimated fair values of the domestic utility companies' and System Energy's financial instruments and derivatives are determined using bid prices and market quotes. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that the domestic utility companies and System Energy could realize in a current market exchange. Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not accrue to the benefit or detriment of stockholders.
The domestic utility companies and System Energy consider the carrying amounts of most of their 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. Additional information regarding financial instruments and their fair values is included in Notes 5 6, and 76 to the domestic utility companies and System Energy financial statements.
Impairment of Long-Lived Assets
The domestic utility companies and System Energy periodically review their long-lived assets whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets.
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 Gulf States Utilities 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 over the estimated remaining economic life of River Bend.
Transition to Competition Liabilities
In conjunction with electric utility industry restructuring activity in Texas, regulatory mechanisms were established to mitigate potential stranded costs. Texas restructuring legislation allowsallowed depreciation on transmission and distribution assets to be directed toward generation assets. The liability recorded as a result of this mechanism is classified as "transition to competition" deferred credits.
credits on the balance sheet for Entergy Gulf States.
Reacquired Debt
The premiums and costs associated with reacquired debt of the domestic utility companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States) are being amortized over the life of the related new issuances, in accordance with ratemaking treatment.
Entergy Gulf States' Deregulated Operations
Entergy Gulf States does not apply regulatory accounting principles to its wholesale jurisdiction, Louisiana retail deregulated portion of River Bend, and the 30% interest in River Bend formerly owned by Cajun. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 16%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Gulf States 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 such incremental revenue above 4.6 cents per kWh between ratepayers and shareholders.
The results of these deregulated operations before interest charges for the years ended December 31, 2002, 2001,2004, 2003, and 20002002 are as follows (in thousands):follows:
2004 | 2003 | 2002 | |||
(In Thousands) | |||||
Operating revenues | $280,279 | $273,150 | $209,752 | ||
Operating expenses | |||||
Fuel, operation, and maintenance | 197,275 | 177,385 | 158,927 | ||
Depreciation and accretion | 30,653 | 47,566 | 40,092 | ||
Total operating expense | 227,928 | 224,951 | 199,019 | ||
Operating income | 52,351 | 48,199 | 10,733 | ||
Income tax expense | 20,414 | 17,722 | 4,503 | ||
Net income from deregulated utility operations | $31,937 | $30,477 | $6,230 |
The net investment associated with these deregulated operations as of December 31, 20022004 and 20012003 was approximately $805 million$830 and $822$838 million, respectively.
New Accounting PronouncementPronouncements
During 2004, Entergy adopted the provisions of FSP 106-2, "Accounting and Disclosure Requirements Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003," which is discussed further in Note 10 to the domestic utility companies and System Energy financial statements.
SFAS 151, "Inventory Costs - an amendment of ARB No. 43, Chapter 4" and SFAS 153, "Exchanges of Nonmonetary Assets", were also issued during the fourth quarter of 2004 and are effective for Entergy in 2006 and 2005, respectively. Entergy does not expect the impact of the adoption of these standards to be material.
During 2003, Entergy adopted the provisions of the following accounting standards: SFAS 143, "Accounting for Asset Retirement Obligations," which must be implemented by Januaryis discussed further in Note 8 to the domestic utility companies and System Energy financial statements; FIN 46, Consolidation of Variable Interest Entities," which is discussed further in Note 5 to the domestic utility companies and System Energy financial statements; and SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS 150, which became effective July 1, 2003, requires the recording of liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets, which primarily consists of decommissioning liabilities for Entergy. These liabilities will be recorded at their fair values (which are likelymandatorily redeemable financial instruments to be the present values of the estimated future cash outflows)classified and treated as liabilities in the period in which they are incurred, with an accompanying addition to the recorded costpresentation of the long-lived asset.financial position and results of operations. The asset retirement obligation will be accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives of the assets. The netonly effect of implementing SFAS 150 for Entergy is the inclusion of long-term debt and preferred stock with sinking fund under the liabilities caption in Entergy's balance sheet. Entergy's results of operations and cash flows were not affected by this standardstandard.
During 2003, Entergy also adopted the provisions of the following accounting standards: SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" and related interpretations by the Derivatives Implementation Group, and FIN 45, "Guarantor's Accounting and Disclosure Requirements for Entergy's regulated utilit ies will be recorded asGuarantees Including Indirect Guarantees of Indebtedness of Others". The adoption of these standards did not have a regulatory asset or liability, with no resulting impactmaterial effect on Entergy's net income. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking is expected to decrease earnings by $25 million as a result of a one-time cumulative effect of accounting change.
financial statements.
NOTE 2. RATE AND REGULATORY MATTERS
Electric Industry Restructuring and the Continued Application of SFAS 71
Although Arkansas and Texas enacted retail open access laws, the retail open access law in Arkansas has now been repealed. Retail open access in Entergy Gulf States' service territory in Texas has been delayed. Entergy also believes that significant issues remain to be addressed by Texas regulators, and the enacted law does not provide sufficient detail to allow Entergy Gulf States to reasonably determine the impact on Entergy Gulf States' regulated operations. Entergy therefore continues to apply regulatory accounting principles to the retail operations of all of the domestic utility companies. Following is a summary of the status of retail open access in the domestic utility companies' retail service territories.
Arkansas
(Entergy Arkansas)
In April 1999, the Arkansas legislature enacted Act 1556, the Arkansas Electric Consumer Choice Act, providing for competition in the electric utility industry through retail open access. In December 2001, the APSC recommended to the Arkansas General Assembly that legislation be enacted during the 2003 legislative session to either repeal Act 1556 or further delay retail open access until at least 2010. In February 2003, the Arkansas legislature voted to repeal Act 1556 and the repeal was signed into law by the governor.
Texas
(Entergy Gulf States)
Retail open access commenced in portions of Texas on January 1, 2002. The staff ofAs ordered by the PUCT, filed a petition to delay retail open access in Entergy Gulf States' service area, andJanuary 2003, Entergy Gulf States reached a settlement agreement with the PUCT to delay retail open access until at least September 15, 2002. In September 2002, the PUCT ordered Entergy Gulf States to file on January 24, 2003 afiled its proposal for an interim solution (retail open access without a FERC-approved RTO) if it appears by January 15, 2003 that a FERC-approved RTO will not be functional by January 1, 2004. On January 24, 2003, Entergy Gulf States filed its proposal,, which among other elements, includes:
included:
After considering the proposal, in an April 2003 order the PUCT is expectedset forth a sequence of proceedings and activities designed to consider this proposal on March 21, 2003.
initiate an interim solution. These proceedings and activities included initiating a proceeding to certify an independent organization to administer market protocols and ensure nondiscriminatory access to transmission and distribution systems.
This proposal takes into account that other regulatory approvals, including thatIn July 2004 the PUCT denied Entergy's application to certify Entergy's transmission organization as an independent organization under Texas law. In its order, the PUCT also ordered: the cessation of efforts to develop an interim solution for retail open access in Entergy Gulf States' Texas service territory, termination of the LPSCpilot project in that territory, and a delay in retail open access in that territory until either a FERC-approved RTO is in place or some other independent transmission entity is certified under Texas law. Several parties have appealed the SEC, are necessary prior to January 1, 2004.termination of the pilot program aspect of the order, claiming the issue was not properly a part of the proceeding.
Louisiana
(Entergy Gulf States and Entergy Louisiana)
In March 1999, the LPSC deferred making a decision on whether competition in the electric utility industry is in the public interest. However, the LPSC directed the LPSC staff, outside consultants, and counsel to work together to analyze and resolve issues related to competition and to recommend a plan for consideration by the LPSC. In July 2001, the LPSC staff submitted a final response to the LPSC. In its report the LPSC staff concluded that retail competition is not in the public interest at this time for any customer class. Nevertheless, the LPSC staff recommended that retail open access be made available for certain large industrial customers as early as January 2003. An eligible customer choosing to go to competition would be required to provide its utility with a minimum of six months notice prior to the date of retail open access. The LPSC staff report also recommended that all customers who do not currently co- or self-generate, or have co- or self-generation under construction as of a date to be specified by the LPSC, remain liable for their share of stranded costs. During its October 2001 meeting, the LPSC adopted dates by which a total of 800 MW of co- or self-generation could be developed in Louisiana without being affected by stranded costs. During its November 2001, meeting, the LPSC decided not to adopt a plan formove forward with retail open access for any customers at this time, buttime. The LPSC instead directed its staff to havehold collaborative group meetings concerning open access from time to time, and to have the LPSC staff monitor developments in neighboring states and to report to the LPSC regarding the progress of retail access developments in those states.
In September 2004, in response to a study funded by certain industrial customers that evaluated a limited industrial-only retail choice program, the LPSC asked the LPSC staff to solicit comments and obtain information from utilities, customers, and other interested parties concerning the potential costs and benefits of a limited choice program, the impact of such a program on other customers, as well as issues such as stranded costs and transmission service. Comments from interested parties were filed with the LPSC on January 14, 2005. The LPSC has not established a procedural framework for c onsideration of the comments. At this time, it is not certain what further action, if any, the LPSC might take in response to the information it received.
Mississippi
(Entergy Mississippi)
In May 2000, after two years of studies and hearings, the MPSC announced that it was suspending its docket studying the opening of the state's retail electricity markets to competition. The MPSC based its decision on its finding that competition could raise the electric rates paid by residential and small commercial customers. The final decision regarding the introduction of retail competition ultimately lies with the Mississippi Legislature, which is holding its 2003 session from January through March.Legislature. Management cannot predict when, or if, Mississippi will deregulate its retail electricity market.
New Orleans
(Entergy New Orleans)
Entergy New Orleans filed an electric transition to competition plan in September 1997. No procedural schedule has been established for consideration of that plan by the City Council.
Regulatory Assets
Other Regulatory Assets
The domestic utility companies and System Energy are subject to the provisions of SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. In addition to the regulatory assets that are specifically disclosed on the face of the balance sheets, the tables below provide detail of "Other regulatory assets" included on the balance sheets of the domestic utility companies and System Energy as of December 31, 20022004 and 20012003 (in millions).
| Entergy | Entergy | Entergy | Entergy | Entergy | System | ||||||
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 8) |
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Deferred distribution expenses -recovered through May 2008 |
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Deferred fossil plant maintenance expenses -recovered through December 2007 (Note 2) |
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Deferred fuel - non-current - recovered through rate riders when rates are redetermined annually |
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Depreciation re-direct - recovery begins at start of retail open access |
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DOE Decom. and Decontamination Fees - recovered through fuel rates until December 2006 (Note 8) |
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Incremental ice storm costs - recovered until 2032 |
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Low-level radwaste - recovery timing dependent upon pending lawsuit |
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Pension costs (Note 10) | 70.8 | - | 34.1 | 20.2 | 15.2 | 7.4 | ||||||
Postretirement benefits - recovered through 2013 (Note 10) |
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Provision for storm damages - recovered through cost of service |
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Removal costs - recovered through depreciation rates (Note 8) |
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Resource planning - recovery timing will be determined by the LPSC in a base rate proceeding (Note 2) |
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River Bend AFUDC - recovered through August 2025 (Note 1) |
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Sale-leaseback deferral - recovered through June 2014 (Note 9) |
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Spindletop gas storage facility - recovered through 2032 |
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Unamortized loss on reaquired debt - recovered over term of debt |
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Other - various | 11.0 | 19.3 | 27.3 | 6.1 | 10.8 | 0.5 | ||||||
Total | $400.2 | $285.0 | $302.5 | $82.7 | $40.4 | $296.3 |
| Entergy | Entergy | Entergy | Entergy | Entergy | System | ||||||
Asset Retirement Obligation (Note 8) | $203.7 | $36.2 | $132.3 | $- | $- | $92.7 | ||||||
Deferred fuel - non-current | 17.1 | - | - | 11.1 | - | - | ||||||
Depreciation re-direct (Note 1) | - | 79.1 | - | - | - | - | ||||||
DOE Decom. and Decontamination Fees (Note 8) |
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Incremental ice storm costs | 14.7 | - | - | - | - | - | ||||||
Low-level radwaste | 16.2 | 3.1 | - | - | - | - | ||||||
Pension costs (Note 10) | 41.7 | - | - | 6.4 | 10.4 | 7.1 | ||||||
Postretirement benefits (Note 10) | 21.5 | - | - | - | - | - | ||||||
Provision for storm damages | 25.3 | 57.4 | 40.9 | 3.5 | - | - | ||||||
Removal costs (Note 8) | 26.6 | 4.2 | - | 24.4 | 2.1 | 15.1 | ||||||
Resource planning (Note 2) | - | - | 5.8 | - | - | - | ||||||
River Bend AFUDC (Note 1) | - | 39.4 | - | - | - | - | ||||||
Sale-leaseback deferral (Note 9) | - | - | - | - | - | 131.7 | ||||||
Spindletop gas storage facility | - | 38.0 | - | - | - | - | ||||||
Unamortized loss on reaquired debt | 38.3 | 46.6 | 24.0 | 11.8 | 1.7 | 41.9 | ||||||
1994 FERC Settlement (Note 2) | - | - | - | - | - | 4.0 | ||||||
Other | 15.3 | 13.4 | 8.2 | 1.1 | 13.0 | 2.3 | ||||||
Total | $437.5 | $320.4 | $217.7 | $58.3 | $27.2 | $301.2 |
Deferred fuel costs
The domestic utility companies are allowed to recover certain fuel and purchased power costs through fuel mechanisms included in electric rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is recorded as "Deferred fuel costs" on the domestic utility companies' financial statements. The table below shows the amount of deferred fuel costs as of December 31, 20022004 and 20012003 that has beenEntergy expects to recover or will be recovered or (refunded)(refund) through the fuel mechanisms of the domestic utility companies.companies, subject to subsequent regulatory review.
2004 | 2003 | ||||
2002 | 2001 | (In Millions) | |||
(In Millions) | |||||
Entergy Arkansas | $(42.6) | $17.2 | $7.4 | $10.6 | |
Entergy Gulf States | $ 100.6 | $ 126.7 | $90.1 | $118.4 | |
Entergy Louisiana | $ (25.6 ) | $ (67.5 ) | $8.7 | $30.6 | |
Entergy Mississippi | $ 38.2 | $ 106.2 | ($22.8) | $89.1 | |
Entergy New Orleans | $ (14.9 ) | $ (10.2 ) | $2.6 | ($2.7) |
Entergy Arkansas
Entergy Arkansas' rate schedules include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve monthtwelve-month period commencing on April 1 of each year to develop an annual energy cost rate. The energy cost rate includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year.
As a result of reduced fuel and purchased power costs in 2001 and the accumulated over-recovery of 2001 energy costs, Entergy Arkansas decreased the energy cost rate effective April 2002. In September 2002,March 2004, Entergy Arkansas filed andwith the APSC approved an interim revision to theits energy cost rate effective October 2002 through March 2003. Entergy Arkansas reduced the energy cost rate to offset the accumulated over-recovery of energy costs through June 2002 and the projected over-recovery through December 2002. The revised energy cost rate will be effective through March 2003 when the annual energy cost rate redetermination will be filedrecovery rider for the period April 20032004 through March 2004.
2005. The filed energy cost rate, which accounts for 12 percent of a typical residential customer's bill using 1,000 kWh per month, increased 16 percent due primarily to the elimination of a credit contained in the prior year's rate to refund previously over-recovered fuel costs. Also included in the current year's energy cost calculation is a decrease in rates of $3.9 million as a result of the operation of a revised energy allocation method between the retail and wholesale sectors resulting from the APSC's approval of a life-of-resources power purchase agreement with Entergy New Orleans.
Entergy Gulf States (Texas)
In the Texas jurisdiction, Entergy Gulf States' rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, not recovered in base rates. Under the current methodology, semi-annual revisions of the fixed fuel factor aremay be made in March and September based on the market price of natural gas. Entergy Gulf States will likely continue to use this methodology until the start of retail open access.access, which has been delayed. The amounts collected under Entergy Gulf States' fixed fuel factor and any interim surcharge implemented until the date retail open access commences are subject to fuel reconciliation proceedings before the PUCT. In the Texas jurisdiction, Entergy Gulf States' deferred electric fuel costs are $91.8$78.6 million as of December 31, 2002,2004, which includes the following:
| ||
(In Millions) | ||
| ||
Items to be addressed as part of unbundling | $29.0 | |
Imputed capacity charges | $ | |
Other | $ |
The PUCT has ordered that the imputed capacity charges be excluded from fuel rates and therefore recovered through base rates. It is uncertain, however, as to when and if Entergy Gulf States will initiatefiled a baseretail electric rate case and fuel proceeding beforewith the PUCT. ThePUCT in August 2004. As discussed below, the PUCT dismissed the rate case and fuel reconciliation proceeding in October 2004 indicating that Entergy Gulf States is still subject to a rate freeze based on the current PUCT-approved settlement agreement delayingstipulating that a rate freeze would remain in effect until retail open access commenced in Texas requires aEntergy Gulf States' service territory, unless the rate freeze duringis lifted by the delay period. If Entergy Gulf States goes to retail open access withoutPUCT prior thereto. Without a Texas base rate proceeding, it is possible that Entergy Gulf States will not be allowed to recover these imputed capacity charges.charges in Texas retail rates in the future. Entergy Gulf States believes the PUCT has misinterpreted the settlement and has appealed the PUCT order to the Travis County District Court and also intends to pursue other ava ilable remedies as discussed in"Electric Industry Restructuring and the Continued Application of SFAS 71." The dismissal of the rate case does not preclude Entergy Gulf States from seeking the reconciliation of fuel and purchased power costs of $288 million incurred from September 2003 through March 2004 when, at the appropriate time, similar costs are reconciled in the future.
In January 2001, Entergy Gulf States filed with the PUCT a fuel reconciliation case covering the period from March 1999 through August 2000. Entergy Gulf States was reconciling approximately $583.0$583 million of fuel and purchased power costs. As part of this filing, Entergy Gulf States requested authority to collect $28.0$28 million, plus interest, of under-recovered fuel and purchased power costs. The PUCT decided inIn August 2002, to reducethe PUCT reduced Entergy Gulf States' request to approximately $6.3 million, including interest through July 31, 2002. Approximately $4.7 million of the total reduction to the requested surcharge relates to nuclear fuel costs that the PUCT deferred ruling on at thisthat time. In October 2002, Entergy Gulf States appealed the PUCT's final order in Texas District Court. In its appeal, Entergy Gulf States is challenging the PUCT's disallowance of approximately $4.2 million related to imputed capacity costs and its disallowance related to costs for energy delivered from the 30% non-regulatednon-regulate d share of River Bend. No assurance can be given asThe case was argued before the Travis County Texas District Court in August 2003 and the Travis County District Court judge affirmed the PUCT's order. In October 2003, Entergy Gulf States appealed this decision to the final outcomeCourt of this proceeding.Appeals. Oral argument before the appellate court occurred in September 2004 and the matter is still pending.
In September 2002,2003, Entergy Gulf States filed an application with the PUCT forto implement an $87.3 million interim fuel surcharge, to collect $53.9 million, including interest, and $6.3 million from the January 2001 fuel reconciliation proceeding discussed above, ofto collect under-recovered fuel and purchased power expenses incurred from MarchSeptember 2002 through August 2002.2003. Hearings were held in October 2003 and the PUCT issued an order in December 2003 allowing for the recovery of $87 million. The surcharge was collected over a twelve-month period that began in January 2004.
In September 2004, Entergy Gulf States filed an application with the PUCT to implement a $27.8 million interim fuel surcharge, including interest, to collect under-recovered fuel and purchased power expenses incurred from September 2003 through July 2004. Entergy Gulf States proposed to collect the surcharge over an 11-montha six-month period beginning in February 2003. ExpensesJanuary 2005. In December 2004, the PUCT approved the surcharge consistent with Entergy Gulf States' request. Amounts collected through thisthough the interim fuel surcharge, withwhich will be implemented over the exception of expenses already reconciled in prior proceedings,six-month period commencing January 2005, are subject to reviewfinal reconciliation in a future fuel reconciliation proceeding.
Entergy Gulf States Entergy Louisiana,(Louisiana) and Entergy New OrleansLouisiana
TheIn Louisiana, jurisdiction of Entergy Gulf States Entergy Louisiana, and Entergy New OrleansLouisiana recover electric fuel and purchased power costs on a two-month lag. Thefor the upcoming month based upon the level of such costs from the prior month. In Louisiana, jurisdiction of Entergy Gulf States' and Entergy New Orleans'purchased gas rate schedulesadjustments include estimates for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations.reconciliations of actual fuel costs incurred with fuel cost revenues billed to customers.
In August 2000, the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Louisiana pursuant to a November 1997 LPSC general order. The time period that is the subject of the audit is January 1, 2000 through December 31, 2001. In September 2003, the LPSC staff issued its audit report and recommended a disallowance with regard to one item. The issue relates to the alleged failure to uprate Waterford 3 in a timely manner, a claim that also has been raised in the summer 2001, 2002, and 2003 purchased power proceedings. The LPSC staff has submitted several requests for information fromquantified the possible disallowance as between $7.6 and $14 million. Entergy Louisiana and it is expected thatnotified the LPSC staffthat it will issue its audit reportcontest the recommendation. The procedural schedule in the springcase has been suspended.A status conference for the purpose of 2003, following whichestablishing a new procedural schedule will be established.set when the current hearings in the Power Purchase Agreement proceedings at the FERC are conc luded. The FERC hearings in that matter concluded in November 2004.If the LPSC approves the proposed settlement (discussed below under"Retail Rate Proceedings"), the issue of a proposed imprudence disallowance relating to the uprate will be resolved and will no longer be at issue in this proceeding.
In January 2003, the LPSC openedauthorized its staff to initiate a docketproceeding to investigateaudit the fuel adjustment clause practicesfilings of Entergy Gulf States and its affiliates.affiliates pursuant to a November 1997 LPSC general order. The investigationaudit will include a review of the reasonableness of charges flowed by Entergy Gulf States through its fuel adjustment clause in Louisiana for the period subsequent to 1994. No assurance can be given at this time as toJanuary 1, 1995 through December 31, 2002. Discovery is underway, but a detailed procedural schedule extending beyond the timing or outcome of this proceeding.discovery stage has not yet been established, and the LPSC staff has not yet issued its audit report.
Entergy Mississippi
Entergy Mississippi's rate schedules include an energy cost recovery rider which is adjusted quarterly to reflect accumulated over- or under-recoveries from the second prior quarter. In May 2003, Entergy Mississippi filed and the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Under the MPSC's order, Entergy Mississippi deferred until 2004 the collection of fuel under-recoveries for the first and second quarters of 2003 that would have been collected in the third and fourth quarters of 2003, respectively. The deferred fuel balances asamount of December 31, 2002 and 2001 reflect$77.6 million plus carrying charges was collected through the 24-monthenergy cost recovery of $136.7 million of under-recoveriesrider over a twelve-month period that began in January 2001 as2004.
In January 2005, the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Entergy Mississippi's fuel over-recoveries for the third quarter of 2004 of $21.3 million will be deferred from the first quarter 2005 energy cost recovery rider adjustment calculation. The deferred amount of $21.3 million plus carrying charges will be refunded through the energy cost recovery rider in the second and third quarters of 2005 at a rate of 45% and 55%, respectively.
Entergy New Orleans
Entergy New Orleans' electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations, including carrying charges. Entergy New Orleans' gas rate schedules include estimates for the MPSC.billing month adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations, including carrying charges.
In June and November 2004, the City Council passed resolutions implementing a package of measures developed by Entergy New Orleans and the Council Advisors to protect customers from potential gas price spikes during the 2004 - 2005 winter heating season. These measures include: maintaining Entergy New Orleans' financial hedging plan for its purchase of wholesale gas, and deferral of collection of up to $6.2 million of gas costs associated with a cap on the purchased gas adjustment in November and December 2004 and in the event that the average residential customer's gas bill were to exceed a threshold level. The deferrals resulting from these caps will receive accelerated recovery over a seven-month period beginning in April 2005.
In November 2004, the City Council directed Entergy New Orleans to confer with the Council Advisors regarding possible modification of the current gas cost collection mechanism in order to address concerns regarding its fluctuations particularly during the winter heating season.
Retail Rate Proceedings
Filings with the APSC (Entergy Arkansas)
March 2002 Settlement Agreement
In May 2002, the APSC approved a settlement agreement submitted by Entergy Arkansas, the APSC staff, and the Arkansas Attorney General. Provisions of the agreement are discussed below under "Retail Rates," "Transition Cost Account," and "December 2000 Ice Storm Cost Recovery."
Retail Rates
As discussedNo significant retail rate proceedings are pending in "December 2000 Ice Storm Cost Recovery" below, Entergy Arkansas was scheduled to file a general rate proceeding in February 2002, in which Entergy Arkansas would have sought an increase in rates. The March 2002 settlement agreement states, however, that Entergy Arkansas will not file an application seeking to increase base rates prior to January 2003.
Transition Cost Account
A 1997 settlement provided for the collection of earnings in excess of an 11% return on equity in a transition cost account (TCA) to offset stranded costs if retail open access were implemented. In May 2002, Entergy Arkansas filed its 2001 earnings evaluation report with the APSC. In June 2002, the APSC approved a contribution of $5.9 million to the TCA. A principal provision in the March 2002 settlement agreement was to offset $137.4 million of ice storm recovery costs with the TCA on a rate class basis. In accordance with the settlement agreement and following the APSC's approval of the 2001 earnings review, Entergy Arkansas filed to return $18.1 million of the TCA to certain large general service class customers that paid more into the TCA than their allocation of storm costs. The APSC approved the return of funds to the large general service customer class in the form of refund checks in August 2002. As part of the implementation of the March 2002 settlement agreement provisions, the TCA procedure ceased with the 2001 earnings evaluation.
December 2000 Ice Storm Cost Recovery
In mid- and late December 2000, two separate ice storms left 226,000 and 212,500 Entergy Arkansas customers, respectively, without electric power in its service area. Entergy Arkansas filed a proposal to recover costs plus carrying charges associated with power restoration caused by the ice storms. In an order issued in June 2001, the APSC decided not to give final approval to Entergy's proposed storm cost recovery rider outside of a fully developed cost-of-service study in a general rate proceeding. The APSC action resulted in the deferral in 2001 of storm damage costs expensed in 2000 as reflected in Entergy Arkansas' financial statements.
Entergy Arkansas filed its final storm damage cost determination, which reflected costs of approximately $195 million. In the March 2002 settlement, the parties agreed that $153 million of the ice storm costs would be classified as incremental ice storm expenses that can be offset against the TCA, and any excess of ice storm costs over the amount available in the TCA would be deferred and amortized over 30 years, although such excess costs were not allowed to be included as a separate component of rate base. The allocated ice storm expenses exceeded the available TCA funds by $15.8 million and was recorded as a regulatory asset in June 2002. Of the remaining ice storm costs, $32.2 million will be addressed through established ratemaking procedures, including $22.2 million classified as capital additions. $3.8 million of the ice storm costs will not be recovered through rates.
Decommissioning Cost Recovery
The APSC ordered Entergy Arkansas to cease collection of funds to decommission ANO 1 and 2 effective with the calendar year 2001, and approved the continued cessation of collection of funds during 2003. The APSC based its decision on the approval of Entergy's application with the NRC to extend the license of ANO 1 by 20 years, anticipated approval of a 20 year license extension for ANO 2, and the conclusion that the funds previously collected will be sufficient to decommission the units. This decision will be reviewed annually and reflected in Entergy Arkansas' filing of its annual determination of the nuclear decommissioning rate rider. An updated decommissioning cost study for ANO 1 and 2 will be filed with the APSC in March 2003.at this time.
Filings with the PUCT and Texas Cities (Entergy Gulf States)
Retail Rates
Entergy Gulf States is operating in Texas under the terms of a June 1999December 2001 settlement agreement.agreement approved by the PUCT. The settlement provided for a base rate freeze that has remained in effect during the delay in the implementation of retail open access in Entergy Gulf States' Texas service territory. In view of the PUCT order in July 2004 to further delay retail open access in the Texas service territory, Entergy Gulf States filed a retail electric rate case and fuel reconciliation proceeding with the PUCT in August 2004 seeking the following:
In addition, Entergy Gulf States' fuel reconciliation filing made in conjunction with the base rate case sought to reconcile approximately $288 million in fuel and purchased power costs incurred during the period September 2003 through March 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case and fuel reconciliation proceeding indicating that Entergy Gulf States is still subject to a rate freeze based on a PUCT-approved agreement in 2001 stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless the rate freeze is lifted by the PUCT prior thereto. Entergy Gulf States believes the PUCT has misinterpreted the settlement and has appealed the PUCT order to the Travis County District Court and intends to pursue other available remedies.
Recovery of River Bend Costs
In March 1998, the PUCT disallowed recovery of $1.4 billion of company-wide abeyed River Bend plant costs, which have been held in abeyance since 1988. Entergy Gulf States appealed the PUCT's decision on this matter to the Travis County District Court in Texas. A 1999 settlement agreement limits potential recovery of the remaining plant asset to $115 million as of January 1, 2002, less depreciation after that date. Entergy Gulf States accordingly reduced the value of the plant asset in 1999. Entergy Gulf States has also agreed that it will not seek recovery of the abeyed plant costs through any additional charge to Texas ratepayers. In an interim order approving this agreement, however, the PUCT recognized that any additional River Bend investment found prudent, subject to the $115 million cap, could be used as an offset against stranded benefits, should legislation be passed requiring Entergy Gulf States to return stranded benefits to retail customers.
In April 2002, the Travis County District Court issued an order affirming the PUCT's order on remand disallowing recovery of the abeyed plant costs. Entergy Gulf States has appealed this ruling to the Third District Court of Appeals. TheIn July 2003, the Third District Court of Appeals heard oral argumentunanimously affirmed the judgment of the Travis County District Court. After considering the progress of the proceeding in November 2002 but has not yet issuedlight of the decision of the Court of Appeals, Entergy Gulf States accrued for the loss that would be associated with a final, decision.non-appealable decision disallowing the abeyed plant costs. The financial statement impactnet carrying value of the retail rate settlement agreement on the remaining abeyed plant costs will ultimately depend on several factors, includingwas $107.7 million at the possible discontinuancetime of SFAS 71 accounting treatment forthe Court of Appeals decision. Accrual of the $107.7 million loss was recorded in the second quarter of 2003 as miscellaneous other income (deductions) and reduced net income by $65.6 million after-tax. In September 2004, the Texas generation business, the determination of the market value of generation assets,Supreme Court denied Entergy Gulf States' petition for review, and any future legislation in Texas addressing the pass-through or sharing of any stranded benefits with Texas ratepayers. While Entergy Gulf States expects to prevail in its lawsuit, no assurance can be given that additional reserves or write-offs will not be required infiled a motion for rehearing. In February 2005, the future.
Texas Supreme Court denied the motion for rehearing, and the proceeding is now final.
Filings with the LPSC
Proposed Settlement (Entergy Gulf States and Entergy Louisiana)
In September 2004, the LPSC consolidated various dockets that were the subject of settlement discussions between the LPSC staff and Entergy Gulf States and Entergy Louisiana. The LPSC directed its staff to continue the settlement discussions and submit any proposed settlement to the LPSC for its consideration. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement that currently includes an offer to refund $76 million to Entergy Gulf States' Louisiana customers, with no immediate change in current base rates and to refund $14 million to Entergy Louisiana's customers. If the LPSC approves the proposed settlement, Entergy Gulf States will be regulated under a three-year formula rate plan that, among other provisions, establishes a ROE mid-point of 10.65% and permits Entergy Gulf States to recover incremental capacity costs without filing a traditional base rate proceeding. The settle ment resolves all issues in, and will result in the dismissal of, Entergy Gulf States' fourth, fifth, sixth, seventh, and eighth annual earnings reviews, Entergy Gulf States' ninth post-merger earnings review and revenue requirement analysis, a fuel review for Entergy Gulf States, dockets established to consider issues concerning power purchases for Entergy Gulf States and Entergy Louisiana for the summers of 2001, 2002, 2003, and 2004, and a docket concerning retail issues arising under the Entergy System Agreement. The settlement does not include the System Agreement case pending at FERC. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.
Annual Earnings Reviews (Entergy Gulf States)
In May 2002, Entergy Gulf States filed its ninth and last required post-merger analysis with the LPSC. The filing included an earnings review filing for the 2001 test year that resulted in a rate decrease of $11.5 million, which was implemented effective June 2002. In its latest testimony, in December 2003, the LPSC staff recommended a rate refund of $30.6 million and a prospective rate reduction of approximately $50 million. Hearings concluded in May 2004. Should the LPSC approve the proposed settlement discussed above, the ninth post-merger analysis would be resolved.
In December 2002, the LPSC approved a settlement between Entergy Gulf States and the LPSC staff pursuant to which Entergy Gulf States agreed to make a base rate refund of $16.3 million, including interest, and to implement a $22.1 million prospective base rate reduction effective January 2003. The settlement discharged any potential liability relatingfor claims that relate to remaining issues that arose in Entergy Gulf States' fourth, fifth, sixth, seventh, and eighth post-merger earnings reviews.reviews, with the exception of certain issues related to the calculation of the River Bend Deregulated Asset Plan percentage. Entergy Gulf States made the refund in February 2003. In addition to resolving and discharging all liability associated withShould the fourth through eighth earnings reviews,LPSC approve the proposed settlement provides that discussed above, the outstanding issue in these proceedings would be resolved.
Retail Rates
(Entergy Gulf States shall be authorized to continue to reflect in rates a ROE of 11.1% until a different ROE is authorized by a final resolution disposing of all issues in the proceeding that was commenced with Entergy Gulf States' May 2002 filing.States)
In May 2002,July 2004, Entergy Gulf States filed its ninth and last required post-merger analysis with the LPSC. The filing includedLPSC an earnings review filingapplication for a change in its rates and charges seeking an increase of $9.1 million in gas base rates in order to allow Entergy Gulf States an opportunity to earn a fair and reasonable rate of return. Entergy Gulf States also is seeking approval of certain proposed rate design, rate schedule, and policy changes. Discovery is underway, and a decision is expected during the 2001 test year that resulted inthird quarter of 2005.
(Entergy Louisiana)
In January 2004, Entergy Louisiana made a rate decrease of $11.5 million, which was implemented effective June 2002. The filing also containedwith the LPSC requesting a prospective revenue requirement study based on the 2001 test year that shows that a prospectivebase rate increase of approximately $21.7$167 million. In that filing, Entergy Louisiana noted that approximately $73 million would be appropriate. Both components of the base rate increase was attributable to the acquisition of a generating station and certain power purchase agreements that, based on current natural gas prices, would produce fuel and purchased power savings for customers that substantially mitigate the impact of the requested base rate increase. The filing are subjectalso requested an allowed ROE midpoint of 11.4%. Entergy Louisiana's previously authorized ROE mid-point currently in effect is 10.5%. Hearings concluded in December 2004. Based on the evidence submitted at the hearing, the LPSC staff is recommending approximately a $7 million base rate increase. The LPSC staff proposed the implementation of a formula rate plan that includes a provision for the recovery of incremental capacity costs, including those related to reviewthe proposed Per ryville acquisition, without filing a traditional base rate proceeding. A decision by the LPSC and may resultis expected in changes in rates other than those sought in the filing. A procedural schedule has been adopted and hearings are scheduled for October 2003.
Formula Rate Plan Filings (Entergy Louisiana)
In July 2002, the LPSC approved a settlement between Entergy Louisiana and the LPSC Staff in Entergy Louisiana's 2000 and 2001 formula rate plan proceedings. Entergy Louisiana agreedmid- to a $5 million rate reduction effective August 2001. The prospective rate reduction was implemented beginning in August 2002 and the refund for the retroactive period occurred in September 2002. As part of the settlement, Entergy Louisiana's current rates, including its previously authorized ROE midpoint of 10.5%, remain in effect until changed pursuant to a new formula rate plan filing or a revenue requirement analysis to be filed by June 30, 2003.
In May 1997, Entergy Louisiana made its second annual performance-based formula rate plan filing with the LPSC for the 1996 test year. This filing resulted in a rate reduction of approximately $54.5 million, which was implemented in July 1997. At the same time, rates were reduced by an additional $0.7 million and by an additional $2.9 million effective March 1998. Upon completion of the hearing process in December 1998, the LPSC issued an order requiring an additional rate reduction and refund based upon the LPSC's contention that it could interpret and enforce an FERC rate schedule. The resulting amounts were not quantified, although they are expected to be immaterial. Entergy Louisiana appealed this order and obtained a preliminary injunction pending a final decisionlate-March 2005 on appeal. The Louisiana Supreme Court rendered a non-unanimous decision in April 2002 affirming the LPSC's order. Entergy Louisiana filed with the U.S. Supreme Court an application for writ of certiorari, which application was supporte d by an amicus curiae brief filed on behalf of the United States of America by the Solicitor General and the General Counsel and Solicitor for the FERC. The U.S. Supreme Court granted certiorari in January 2003, and the case will be argued during the last week of April 2003.
these issues.
Filings with the MPSC (Entergy Mississippi)
Pursuant to Entergy Mississippi's annual performance-based formula rate plan filing for the 2001 test year, the MPSC approved a stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi. The stipulation provided for a $1.95 million rate increase effective in May 2002.
In August 2002, Entergy Mississippi filedis operating under a rate case with the MPSC requesting a $68.8 million rate increase effective January 2003. Entergy Mississippi requested this increase as a result of capital investments and operation and maintenance expenditures necessary to replace and maintain aging electric facilities and to improve reliability and customer service. In December 2002 order issued by the MPSC issued a final order approving a joint stipulation entered into by Entergy Mississippi and the Mississippi Public Utilities Staff in October 2002. The final order results in a $48.2 million rate increase, or about a 5.3% increase in overall retail revenues, which is based on an ROE of 11.75%.MPSC. The order endorsed a new power management rider schedule designed to more efficiently collect capacity portions of purchased power costs. Also, the order provides for improvements in the return on equity formula and more robust performance measures forEntergy Mississippi's formula rate plan. Under the provisions of Entergy Mississippi's formula rate plan, a bandwidth is placed around the order,benchmark ROE, and if Entergy Mississippiwill makeMississippi earns outside of the bandwidth (as well as outside of a range-of-no-change at each edge of the bandwidth), then Entergy Mississippi's rates will be adjusted, though on a prospective basis only. Under Mississippi law and Entergy Mississippi's formula rate plan, however, if Entergy Mississippi's earned ROE is above the top of the range-of-no-change at the top of the formula rate plan bandwidth, then Entergy Mississippi's " Allowed ROE" for the next twelve-month period is the point halfway between such earned ROE and the top of the bandwidth; and Entergy Mississippi's retail rates are set at that halfway-point ROE level. In the situation where Entergy Mississippi's earned ROE is not above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the top of the range-of-no-change at the top of the bandwidth.
Entergy Mississippi made its nextannual formula rate plan filing duringwith the MPSC in March 2004.
2004 based on a 2003 test year. In April 2004, the MPSC approved a joint stipulation entered into between the Mississippi Public Utilities Staff and Entergy Mississippi that provides for no change in rates based on a performance adjusted ROE mid-point of 10.77%, establishing an allowed regulatory earnings range of 9.3% to 12.2%.
Grand Gulf Accelerated Recovery Tariff (GGART)
In September 1998, FERC approved the GGART for Entergy Mississippi's allocable portion of Grand Gulf, which was filed with FERC in August 1998. The GGART providesprovided for the acceleration of Entergy Mississippi's Grand Gulf purchased power obligation in an amount totaling $221.3 million over the period October 1, 1998 through June 30, 2004.
In May 2003, the MPSC authorized the cessation of the GGART effective July 1, 2003. Entergy Mississippi filed notice of the change with FERC, and the FERC approved the filing on July 30, 2003. Entergy Mississippi accelerated a total of $168.4 million of Grand Gulf purchased power obligation costs under the GGART over the period October 1, 1998 through June 30, 2003.
Filings with the City Council (Entergy New Orleans)
Formula Rate ProceedingsPlans
In May 2002,2003, the City Council approved a resolution allowing for a total increase of $30.2 million in electric and gas base rates effective June 1, 2003. In April 2004, Entergy New Orleans made filings with the City Council as required by the earnings review process prescribed by the Gas and Electric Formula Rate Plans approved by the City Council in 2003. The filings sought an increase in Entergy New Orleans' electric revenues of $1.2 million and an increase in Entergy New Orleans' gas revenues of $32,000. The Council Advisors and intervenors reviewed the filings, and filed their recommendations in July 2004. In August 2004, in accordance with the City Council's requirements for the formula rate plans, Entergy New Orleans made a cost of service study and revenue requirement filing with the City Council forreflecting the 2001 test year. The filing indicatedparties' concurrence that a revenue deficiency exists and that a $28.9 millionno change in Entergy New Orleans' electric rate increase and a $15.3 millionor gas rate increase are appropriate. Additionally,rates is warranted. Later in August 2004, the City Council approved an unopposed settlement among Entergy New Orleans, has proposed a $6.0 million public benefit fund. The Citythe Council has established a procedural schedule for consideration ofAdvisors, and the filingintervenors in connection with the Gas and hearings are scheduled to beginElectric Formula Rate Plans. In accordance with the resolution approving the settlement agreement, Entergy New Orleans' gas and electric base rates remain unchanged from levels set in May 2003. The procedural schedule provides for the City Council's decision with respect to Entergy New Orleans' filing by June 15, 2003. On March 13, 2003, Entergy New Orleans and the Advisors to the City Council presented to the City Council an agreement in principle that, if approved by the City Council, would resolve the proceeding. The agreement in principle, if approved by the City Council, would result in a $30.2 million base rate increase for Entergy New Orleans. A procedural schedule for the City Council's consideration of the agreement in principle has not been established. Entergy New Orleans' rates will remain at their current level until the earlier of a decision in the proceeding or June 15, 2003.
Natural Gas
In a resolution adopted in August 2001, the City Council ordered Entergy New Orleans to account for $36defer $3.9 million of certain natural gasrelating to voluntary severance plan costs chargedallocated to its electric operations and $1.0 million allocated to its gas distribution customers from July 1997 through May 2001. The resolution suggests that refunds mayoperations, which amounts were accrued on its books in 2003, and to record on its books regulatory assets in those amounts to be due to the gas distribution customers ifamortized over five years effective January 2004. Entergy New Orleans cannot account satisfactorily for these costs. also was ordered to defer $6.0 million of fossil plant maintenance expense incurred in 2003 and to record on its books a regulatory asset in that amount to be amortized over a five-year period effective January 2003.
Entergy New Orleans filed a responsewill file its formula rate plan for the year ended December 31, 2004 by May 31, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in September 2001, which is still being evaluated byeffect based on the December 31, 2004 test year shall continue.
In May 2003, the City Council.Council approved implementation of a generation performance-based rate calculation in the electric fuel adjustment clause under which Entergy New Orleans has documentedreceives 10% of calculated fuel and purchased power cost savings in excess of $20 million, based on a full reconciliationdefined benchmark, subject to a 13.25% return on equity limitation for electric operations as provided for in the natural gas costs during that period.electric formula rate plan. Entergy New Orleans has filed for a hearing on this matter. The presentation made to the City Council on March 13, 2003 regarding the agreement in principle that would resolvebears 10% of any "negative" fuel and purchased power cost savings. In October 2004, Entergy New Orleans' rate proceeding also included proposed terms for resolution of this proceeding, if approved by the City Council. A procedural scheduleannual evaluation report was submitted for the City Council's considerationperiod June 2003 through May 2004. Savings associated with the first year generation performance-based rate calculation was $71 million of the agreement has not been established. The ultimate outcome of the proceeding cannot be predicted at this time.
which Entergy New Orleans' share was $5.1 million.
Fuel Adjustment Clause Litigation
In April 1999, a group of ratepayers filed a complaint against Entergy New Orleans, Entergy Corporation, Entergy Services, and Entergy Power in state court in Orleans Parish purportedly on behalf of all Entergy New Orleans ratepayers. The plaintiffs seek treble damages for alleged injuries arising from the defendants' alleged violations of Louisiana's antitrust laws in connection with certain costs passed on to ratepayers in Entergy New Orleans' fuel adjustment filings with the City Council. In particular, plaintiffs allege that Entergy New Orleans improperly included certain costs in the calculation of fuel charges and that Entergy New Orleans imprudently purchased high-cost fuel from other Entergy affiliates. Plaintiffs allege that Entergy New Orleans and the other defendant Entergy companies conspired to make these purchases to the detriment of Entergy New Orleans' ratepayers and to the benefit of Entergy's shareholders, in violation of Louisiana's antitrust laws. Plaintiffs also seekse ek to recover inter estinterest and attorneys' fees. Entergy filed exceptions to the plaintiffs' allegations, asserting, among other things, that jurisdiction over these issues rests with the City Council and FERC. In March 2004, the plaintiffs supplemented and amended their petition. If necessary, at the appropriate time, Entergy will also raise its defenses to the antitrust claims. At present, theThe suit in state court ishas been stayed by stipulation of the parties.parties pending a decision by the City Council in the proceeding discussed in the next paragraph.
Plaintiffs also filed this complaint with the City Council in order to initiate a review by the City Council of the plaintiffs' allegations and to force restitution to ratepayers of all costs they allege were improperly and imprudently included in the fuel adjustment filings. Testimony was filed on behalf of the plaintiffs in this proceeding in April 2000 and has been supplemented. The testimony, as supplemented, asserts,asserting, among other things, that Entergy New Orleans and other defendants have engaged in fuel procurement and power purchasing practices and included costs in Entergy New Orleans' fuel adjustment that could have resulted in Entergy New Orleans customers being overcharged by more than $100 million over a period of years. In June 2001, the City Council's advisors filed testimony on these issues in which they allege that Entergy New Orleans ratepayers may have been overcharged by more than $32 million, the vast majority of which is reflected in the plaintiffs' claim. However, it is not clear precisely wh at periods and damages are being alleged in the proceeding. Entergy intends to defend this matter vigorously, both in court and before the City Council. Hearings were held in February and March 2002. The parties have submitted post-hearing briefs and the matter has been submitted toIn February 2004, the City Council forapproved a decision. In October 2002,resolution that resulted in a refund to customers of $11.3 million, including interest, during the plaintiffs filed a motion to re-openmonths of June through September 2004. The resolution concludes, among other things, that the evidentiary record does not support an allegation tha t Entergy New Orleans' actions or inactions, either alone or in concert with Entergy or any of its affiliates, constituted a misrepresentation or a suppression of the alternative, a motiontruth made in order to obtain an unjust advantage of Entergy New Orleans, or to cause loss, inconvenience or harm to its ratepayers. Management believes that it has adequately provided for a new trial seeking to re-open the record to accept certain testimony filed byliability associated with this proceeding. The plaintiffs have appealed the City Council advisorsresolution to the state court in a separate proceeding atOrleans Parish. Oral argument on the FERC. The ultimate outcome of the lawsuit and the City Council proceeding cannot be predicted at this time.plaintiffs' appeal was conducted in February 2005.
Purchased Power for Summer 2000, 2001, 2002 and 20022003 (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)
The domestic utility companies requested that the APSC, the LPSC, the MPSC, and the City Council approve the sale of power by Entergy Gulf States from its unregulated 30% interest in River Bend formerly owned by Cajun to the domestic utility companies during the summer of 2000. These applications were approved subject to subsequent prudence reviews. In addition, Entergy Gulf States and Entergy Louisiana)
In March 2001, Entergy Louisiana and Entergy Gulf States filed an applicationapplications with the LPSC for authorization to purchase capacity and electric power from third partiesparticipate in contracts that would be executed by the Entergy System to meet the summer peak load requirements for the summer of 2000, and filed similar applications for the summers of 2001 and 2002. The LPSC approved these applications, with reservation of its rights to review the prudence of the purchases and the appropriate categorization of the costs as either capacity or energy charges for purposes of recovery.
The LPSC reviewed the 2000 purchases and found that Entergy Louisiana's and Entergy Gulf States' costs were prudently incurred, but decided that approximately 34% of the costs should be categorized as capacity charges, and therefore should be recovered through base rates and not through the fuel adjustment clause. In November 2000, the LPSC ordered refunds of $11.1 million for Entergy Louisiana and $3.6 million for Entergy Gulf States, for which adequate provisions previously had been made.2001. In May 2001, the LPSC determined that 24% of Entergy Louisiana's and Entergy Gulf States' costs relating to summer 2001 purchases should be categorized as capacity charges. Subsequently, the LPSC raised certain prudence issues related to the 2001 purchases. The administrative law judge (ALJ) presiding over the case issued a Preliminary Recommendation regarding prudence issues involve approximately $6 million of Entergy Louisiana costsprimarily associated with the power uprates at the Waterford 3 and approximately $5 million of EntergyGrand Gulf States costs. The LPSC has questioned innuclear units. In the prudence review the Entergy system's contract mix and raised issues relating to potential upra tes at nuclear facilities. Hearings on those issues were conducted in May 2002 and briefs have been filed by the parties. Those costsevent that are categorized as capacity charges willsuch decision becomes final, additional calculations would be included in the cost of service usedrequired to determine the base rates of Entergy Louisiana and Entergy Gulf States. In 2001, these companies recorded a regulatory assetpotential refund obligation for the capacity charges incurred in both 2000periods 2001, 2002 and 2001.2003. The regulatory assets were not allowedALJ also concluded that Entergy should be permitted the opportunity to be included as a separate componentrecover the expenses of the uprate s through appropriate rate base, but are being amortized as a component of cost of service as discussed above. The capacity charges for 2000 were amortized through May 2002 for Entergy Gulf States and through July 2002 for Entergy Louisiana. The capacity charges for 2001 are being amortized over a twelve-month period, which began in June 2002 for Entergy Gulf States and in August 2002 for Entergy Louisiana.
proceedings.
In March 2002 and 2003, Entergy Louisiana and Entergy Gulf States filed an application with the LPSC for the approval of capacity and energy purchases for the summersummers of 2002 and 2003, respectively, similar to the applications filed for the summers of 2000 and 2001. Entergy Louisiana, Entergy Gulf States, and theThe LPSC staff reached a settlement in which those parties agreedordered that 14% of Entergy Louisiana's and Entergy Gulf States' costs relating to summer 2002 purchases shouldbe categorized as capacity charges, and that 11% of Entergy Louisiana's and Entergy Gulf States' costs relating to summer 2003 power purchases, the price of which was stated on the basis of $/MWh, be categorized as capacity charges. The LPSC approveddid not allow the settlement at its July 2002 public meeting.capacity charges to be set up as a regulatory asset, but authorized Entergy Louisiana and Entergy Gulf States to include these costs in any base rate case for their respective test years. Prudence issues relating to summer 2002 and 2003 purchases were resolved in a subsequent settlementsettlements approved by the LPSC at its September 2002 open session.LPSC. In the event that decisionsthe LPSC adopts the ALJ's recomm endation relating to potential uprates at nuclear facilities are found to have been imprudent in the summer 2001 case, this settlement reservesand such decision becomes final following an appeal or the expiration of appeal delays, these settlements reserve the LPSC's right to propose in a future case disa llowancesdisallowances relating to the effect that such uprates would have had on the summer 2002 and summer 2003 firm energy contracts, while Entergy Gulf States and Entergy Louisiana reserve their right to oppose any such proposal.
No refunds were ordered in the summer 2002 settlement, although with respect to the capacity costs to be incurred pursuant to a particular purchased power contract, Entergy Louisiana agreed in the settlement to forgo recovery of approximately $0.8 million in 2002, $1.3 million in 2003, and $1.0 million in 2004, and Entergy Gulf States agreed to forgo recovery of approximately $0.5 million in 2002, $0.9 million in 2003, and $0.7 million in 2004. All other purchases for the summers of 2002 and 2003 were found to be prudent. Issues relating to the reasonableness of the long-term planning process were moved from the summer 2002 case into a separate sub-docket. Issues relatingIn the summer 2003 settlement, the LPSC also reserved its right to investigate any alleged imprudence regarding the needSystem's decision to spin off the ISES and Ritchie generating units to an unregulated affiliate, Entergy Power, Inc.
Should the LPSC approve the proposed settlement discussed above, all issues arising out of the purchased power cases for the summers of 2001, 2002, and potential scope of that proceeding are currently under review.2003 would be resolved.
Grand Gulf 1 Deferrals and Retained Shares
(FERC Settlement(Entergy Arkansas)
Under the settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf 1-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' cost from its retained share.
(Entergy Louisiana)
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 Louisiana's share of capacity and energy from Grand Gulf 1, 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 1 capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause 4.6 cents per kWh for the energy related to its retained portion of these costs. Non-fuel operation and maintenance costs for Grand Gulf 1 are recovered through Entergy Louisiana's base rates. 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 New Orleans)
Under various rate settlements with the Council in 1986, 1988, and 1991, Entergy New Orleans agreed to absorb and not recover from ratepayers a total of $96.2 million of its Grand Gulf 1 costs. Entergy New Orleans was permitted to implement annual rate increases in decreasing amounts each year through 1995, and to defer certain costs and related carrying charges for recovery on a schedule extending from 1991 through 2001. As of December 31, 2001, the entire deferred amount has been recovered through rates.
System Energy's 1995 Rate Proceeding (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
System Energy applied to FERC in May 1995 for a rate increase, and implemented the increase in December 1995. The request sought changes to System Energy's rate schedule, including increases in the revenue requirement associated with decommissioning costs, the depreciation rate, and the rate of return on common equity. The request proposed a 13% return on common equity. In July 2000, FERC approved a rate of return of 10.58% for the period December 1995 to the date of FERC's decision, and prospectively adjusted the rate of return to 10.94% from the date of FERC's decision. FERC's decision also changed other aspects of System Energy's proposed rate schedule, including the depreciation rate and decommissioning costs and their methodology. FERC accepted System Energy's compliance tariff in November 2001. System Energy made refunds to the domestic utility companies in December 2001.
In accordance with regulatory accounting principles, during the pendency of the case, System Energy recorded reserves for potential refunds against its revenues. Upon the order becoming final, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy recorded entries to spread the impacts of FERC's order to the various revenue, expense, asset, and liability accounts affected, as if the order had been in place since commencement of the case in 1995. System Energy also recorded an additional reserve amount against its revenue, to adjust its estimate of the impact of the order, and recorded additional interest expense on that reserve. System Energy also recorded reductions in its depreciation and its decommissioning expenses to reflect the lower levels in FERC's order, and reduced tax expense affected by the order.
Entergy Arkansas refunded $54.3 million, including interest, through the issuance of refund checks in March 2002 as approved by the APSC.
Entergy Louisiana refunded $4.9 million, including interest, to its customers through a credit on the September 2002 bills as approved by the LPSC.
Entergy Mississippi's allocation of the proposed System Energy wholesale rate increase was $21.6 million annually. In July 1995, Entergy Mississippi filed a schedule with the MPSC that deferred the retail recovery of the System Energy rate increase. The deferral plan, which was approved by the MPSC, began in December 1995, the effective date of the System Energy rate increase, and was effective until the issuance of the final order by FERC. Entergy Mississippi revised the deferral plan two times during the pendency of the System Energy proceeding. As a result of the final resolution of the FERC order and in accordance with Entergy Mississippi's second revised deferral plan, refunds to Entergy Mississippi from System Energy, including interest, have been credited against deferral balances and a refund of the remaining $14.8 million in excess of the deferral balances were included as credits to the amounts billed to Entergy Mississippi's customers in October 2001 through September 2002 under its Grand Gulf Riders.
Entergy New Orleans' allocation of the proposed System Energy wholesale rate increase was $11.1 million annually. In February 1996, Entergy New Orleans filed a plan with the Council to defer 50% of the amount of the System Energy rate increase. In December 2001, the Council approved a refund to customers. The total amount of the refund to Entergy New Orleans' customers was $43 million. In anticipation of the FERC order, Entergy New Orleans advanced the refunding of $10 million in February 2001 to customers to assist with unexpected high energy bills. The total refund was also reduced by an additional $6 million which was used for the establishment of a public benefits and payments assistance program. The remaining $27 million was refunded through the issuance of refund checks during the first quarter of 2002.
FERC Settlement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
In November 1994, FERC approved an agreement settling a long-standing dispute involving income tax allocation procedures of System Energy. In accordance with the agreement, System Energy has been refundingrefunded a total of approximately $62 million, plus interest, to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans through June 2004. System Energy also reclassified from utility plant to other deferred debits approximately $81 million of other Grand Gulf 1 costs. Although such costs arewere excluded from rate base, System Energy is amortizingamortized and recoveringrecovered these costs over a 10-year period. Interest on the $62 million refund and the loss of the return on the $81 million of other Grand Gulf 1 costs is reducingreduced Entergy's and System Energy's net income by approximately $10 million annually.
NOTE 3. INCOME TAXES
Income tax expenses for 2002, 2001,2004, 2003, and 20002002 consist of the following (in thousands):following:
Entergy | Entergy | Entergy | Entergy | Entergy | System | |||||||
2004 | Arkansas | Gulf States | Louisiana | Mississippi | New Orleans | Energy | ||||||
(In Thousands) | ||||||||||||
Current: | ||||||||||||
Federal (a)(b) | $14,490 | $42,436 | $2,439 | ($23,568) | ($19,259) | $222,622 | ||||||
State (a)(b) | 8,727 | 7,944 | 1,957 | (1,221) | (3,655) | 33,926 | ||||||
Total (a)(b) | 23,217 | 50,380 | 4,396 | (24,789) | (22,914) | 256,548 | ||||||
Deferred -- net | 70,674 | 63,615 | 80,207 | 63,234 | 40,226 | (175,059) | ||||||
Investment tax credit | ||||||||||||
adjustments -- net | (4,827) | (5,707) | (5,128) | (1,405) | (444) | (3,476) | ||||||
Recorded income tax expense | $89,064 | $108,288 | $79,475 | $37,040 | $16,868 | $78,013 |
Entergy | Entergy | Entergy | Entergy | Entergy | System | |||||||
2003 | Arkansas | Gulf States | Louisiana | Mississippi | New Orleans | Energy | ||||||
(In Thousands) | ||||||||||||
Current: | ||||||||||||
Federal (a) | $40,632 | ($11,535) | ($745,724) | ($2,969) | ($7,655) | $95,670 | ||||||
State (a) | 16,306 | (1,503) | (16,243) | 2,565 | (1,871) | 15,382 | ||||||
Total (a) | 56,938 | (13,038) | (761,967) | (404) | (9,526) | 111,052 | ||||||
Deferred -- net | 53,309 | 36,652 | 864,656 | 36,240 | 15,853 | (31,731) | ||||||
Investment tax credit | ||||||||||||
adjustments -- net | (4,951) | (12,078) | (5,281) | (1,405) | (452) | (3,476) | ||||||
Recorded income tax expense | $105,296 | $11,536 | $97,408 | $34,431 | $5,875 | $75,845 |
Entergy | Entergy | Entergy | Entergy | Entergy | System | |||||||
2002 | Arkansas | Gulf States | Louisiana | Mississippi | New Orleans | Energy | ||||||
(In Thousands) | ||||||||||||
Current: | ||||||||||||
Federal (a) | $13,206 | $66,227 | $43,048 | $21,817 | ($7,103) | $99,429 | ||||||
State (a) | 3,243 | 11,345 | 1,867 | 3,969 | (47) | 14,994 | ||||||
Total (a) | 16,449 | 77,572 | 44,915 | 25,786 | (7,150) | 114,423 | ||||||
Deferred -- net | 59,963 | (4,210) | 45,253 | (6,529) | 7,196 | (34,770) | ||||||
Investment tax credit | ||||||||||||
adjustments -- net | (5,008) | (7,365) | (5,403) | (1,411) | (468) | (3,476) | ||||||
Recorded income tax expense | $71,404 | $65,997 | $84,765 | $17,846 | ($422) | $76,177 |
(a) | |
(b) | In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $1.171 billion deduction for Entergy Arkansas, a $674 million deduction for Entergy Gulf States, a $505 million deduction for Entergy Louisiana, a $145 million deduction for Entergy Mississippi, a $31 million deduction for Entergy New Orleans, and a $430 million deduction for System Energy on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004, Entergy Arkansas realized $173 million, Entergy Gulf States realized $69 million, Entergy Louisiana realized $100 million, Entergy Mississippi realized $36 million, and System Energy realized $144 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. Entergy believes that its contingency provision established in its financial statements will sufficiently cover its risk associated with this issue. |
Total income taxes differ from the amounts computed by applying the statutory income tax rate to income before taxes. The reasons for the differences for the years 2004, 2003, and 2002 2001, and 2000 are (in thousands):are:
Entergy | Entergy | Entergy | Entergy | Entergy | System | |||||||
2004 | Arkansas | Gulf States | Louisiana | Mississippi | New Orleans | Energy | ||||||
(In Thousands) | ||||||||||||
Computed at statutory rate (35%) | $80,946 | $105,194 | $72,440 | $38,688 | $15,729 | $64,386 | ||||||
Increases (reductions) in tax | ||||||||||||
resulting from: | ||||||||||||
State income taxes net of | ||||||||||||
federal income tax effect | 12,204 | 8,289 | 6,411 | 3,845 | 1,158 | 7,665 | ||||||
Regulatory differences - | ||||||||||||
utility plant items | 13,775 | 6,951 | 10,052 | (1,482) | 1,373 | 10,528 | ||||||
Amortization of investment | ||||||||||||
tax credits | (4,827) | (5,316) | (5,128) | (1,405) | (444) | (3,476) | ||||||
Flow-through/permanent | ||||||||||||
differences | (9,127) | (7,080) | (3,576) | (2,114) | (878) | (993) | ||||||
Other -- net | (3,907) | 250 | (724) | (492) | (70) | (97) | ||||||
Total income taxes | $89,064 | $108,288 | $79,475 | $37,040 | $16,868 | $78,013 | ||||||
Effective Income Tax Rate | 38.5% | 36.0% | 38.4% | 33.5% | 37.5% | 42.4% |
Entergy | Entergy | Entergy | Entergy | Entergy | System | |||||||
2003 | Arkansas | Gulf States | Louisiana | Mississippi | New Orleans | Energy | ||||||
(In Thousands) | ||||||||||||
Computed at statutory rate (35%) | $80,957 | $18,934 | $85,247 | $35,522 | $4,807 | $63,647 | ||||||
Increases (reductions) in tax | ||||||||||||
resulting from: | ||||||||||||
State income taxes net of | ||||||||||||
federal income tax effect | 12,987 | 473 | 7,764 | 3,000 | 21 | 7,765 | ||||||
Regulatory differences - | ||||||||||||
utility plant items | 15,994 | 13,260 | 10,568 | (930) | 2,045 | 11,530 | ||||||
Amortization of investment | ||||||||||||
tax credits | (4,951) | (8,797) | (5,281) | (1,404) | (452) | (3,476) | ||||||
Flow-through/permanent | ||||||||||||
differences | 1,090 | (10,625) | (2,012) | (1,112) | (625) | (420) | ||||||
Benefit of Entergy Corp. expenses | (1,145) | (888) | - | - | - | (3,408) | ||||||
Other -- net | 364 | (821) | 1,122 | (645) | 79 | 207 | ||||||
Total income taxes | $105,296 | $11,536 | $97,408 | $34,431 | $5,875 | $75,845 | ||||||
Effective Income Tax Rate | 45.5% | 21.3% | 40.0% | 33.9% | 42.8% | 41.7% |
Entergy | Entergy | Entergy | Entergy | Entergy | System | |||||||
2002 | Arkansas | Gulf States | Louisiana | Mississippi | New Orleans | Energy | ||||||
(In Thousands) | ||||||||||||
Computed at statutory rate (35%) | $72,467 | $84,064 | $80,317 | $24,589 | ($228) | $62,836 | ||||||
Increases (reductions) in tax | ||||||||||||
resulting from: | ||||||||||||
State income taxes net of | ||||||||||||
federal income tax effect | 8,784 | 6,401 | 6,065 | 2,069 | 551 | 7,049 | ||||||
Regulatory differences - | ||||||||||||
utility plant items | 10,615 | 2,738 | 6,875 | (3,032) | 1,125 | 11,453 | ||||||
Amortization of investment | ||||||||||||
tax credits | (5,008) | (6,528) | (5,403) | (1,411) | (468) | (3,476) | ||||||
Flow-through/permanent | ||||||||||||
differences | (10,687) | (15,000) | (1,878) | (1,453) | (538) | (1,183) | ||||||
Benefit of Entergy Corp. expenses | (3,428) | (3,830) | (180) | (2,331) | (434) | (191) | ||||||
Other -- net | (1,339) | (1,848) | (1,031) | (585) | (430) | (311) | ||||||
Total income taxes | $71,404 | $65,997 | $84,765 | $17,846 | ($422) | $76,177 | ||||||
Effective Income Tax Rate | 34.5% | 27.5% | 36.9% | 25.4% | 64.7% | 42.4% |
Significant components of net deferred and long-term accrued tax liabilities as of December 31, 20022004 and 20012003 are as follows (in thousands):follows:
Entergy | Entergy | Entergy | Entergy | Entergy | System | |||||||
2004 | Arkansas | Gulf States | Louisiana | Mississippi | New Orleans | Energy | ||||||
(In Thousands) | ||||||||||||
Deferred and Long-term Accrued Tax Liabilities: | ||||||||||||
Net regulatory assets/(liabilities) | ($128,594) | ($479,158) | ($169,675) | ($22,864) | $44,867 | ($223,391) | ||||||
Plant-related basis differences - net | (1,237,303) | (1,388,391) | (921,976) | (389,558) | (103,733) | (471,026) | ||||||
Power purchase agreements | - | - | (971,676) | - | - | - | ||||||
Rate refunds | (39,163) | - | (17,736) | (49,124) | (14,375) | - | ||||||
Deferred fuel | (2,899) | (36,017) | (1,286) | (6,424) | (3,873) | - | ||||||
Other reserves | 2,686 | (33,916) | 27,421 | 5,856 | (323) | (80,597) | ||||||
Other | (80,980) | (20,781) | (68,381) | (16,516) | (2,982) | (11,851) | ||||||
Total | (1,486,253) | (1,958,263) | (2,123,309) | (478,630) | (80,419) | (786,865) | ||||||
Deferred Tax Assets: | ||||||||||||
Accumulated deferred investment | ||||||||||||
tax credit | 26,936 | 34,359 | 36,989 | 5,235 | 1,538 | 28,922 | ||||||
Sale and leaseback | - | - | 82,410 | - | - | 144,745 | ||||||
NOL carryforward | 300,249 | 164,749 | 164,840 | 34,642 | 18,973 | - | ||||||
Unbilled/Deferred revenues | - | 17,001 | - | 10,193 | - | - | ||||||
Pension-related items | - | 14,499 | 13,039 | - | 10,656 | 6,737 | ||||||
Reserve for regulatory adjustments | - | 131,112 | - | - | - | - | ||||||
Rate refund | - | 32,932 | - | - | - | 170,222 | ||||||
Customer deposits | 40,880 | 33,425 | 17,479 | 15,777 | 91 | - | ||||||
Nuclear decommissioning | 12,070 | - | 2,833 | - | - | - | ||||||
Other | 11,801 | 10,721 | 13,021 | 2,386 | 193 | 11,296 | ||||||
Total | 391,936 | 438,798 | 330,611 | 68,233 | 31,451 | 361,922 | ||||||
Net deferred tax liability | ($1,094,317) | ($1,519,465) | ($1,792,698) | ($410,397) | ($48,968) | ($424,943) | ||||||
Entergy | Entergy | Entergy | Entergy | Entergy | System | |||||||
2003 | Arkansas | Gulf States | Louisiana | Mississippi | New Orleans | Energy | ||||||
(In Thousands) | ||||||||||||
Deferred and Long-term Accrued Tax Liabilities: | ||||||||||||
Net regulatory assets/(liabilities) | ($157,147) | ($478,254) | ($195,074) | ($34,738) | $38,834 | ($246,519) | ||||||
Plant-related basis differences, net | (798,641) | (1,095,206) | (806,955) | (284,550) | (74,041) | (332,197) | ||||||
Power purchase agreements | - | - | (945,495) | - | - | - | ||||||
Deferred fuel | (4,154) | (45,762) | - | (40,091) | (1,109) | - | ||||||
Long term taxes accrued | (26,611) | (55,155) | - | (52,646) | (17,491) | (57,239) | ||||||
Other | (85,528) | (26,012) | (67,272) | (21,806) | (1,728) | (11,497) | ||||||
Total | (1,072,081) | (1,700,389) | (2,014,796) | (433,831) | (55,535) | (647,452) | ||||||
Deferred Tax Assets: | ||||||||||||
Accumulated deferred investment | ||||||||||||
tax credit | 28,836 | 36,192 | 38,962 | 5,773 | 1,709 | 30,251 | ||||||
Sale and leaseback | - | - | 83,539 | - | - | 139,595 | ||||||
NOL carryforward | - | - | 104,489 | - | - | - | ||||||
Unbilled/Deferred revenues | - | 11,959 | - | 7,357 | - | - | ||||||
Pension-related items | 5,453 | 11,474 | 12,562 | - | 9,324 | 7,354 | ||||||
Reserve for regulatory adjustments | - | 138,933 | - | - | - | - | ||||||
Rate refund | 2,351 | 23,184 | 789 | 379 | 3,977 | 170,222 | ||||||
Customer deposits | 37,778 | 35,840 | 16,804 | 18,085 | 84 | - | ||||||
Nuclear decommissioning | 13,171 | - | 2,833 | - | - | - | ||||||
Other | 6,399 | 26,147 | 26,096 | 9,722 | 1,415 | 8,124 | ||||||
Total | 93,988 | 283,729 | 286,074 | 41,316 | 16,509 | 355,546 | ||||||
Net deferred tax liability | ($978,093) | ($1,416,660) | ($1,728,722) | ($392,515) | ($39,026) | ($291,906) | ||||||
As of December 31, 2004, federal net operating loss carryforwards were $766.9 million for Entergy Arkansas, $447.5 million for Entergy Gulf States, $195.7 million for Entergy Louisiana, $40.9 million for Entergy Mississippi, and $54.9 million for Entergy New Orleans. If the federal net operating loss carryforwards are not utilized, they will expire in the year 2023.
As of December 31, 2004, state net operating loss carryforwards were $1.9 billion for Entergy Louisiana, $278 million for Entergy Gulf States, $11 million for Entergy New Orleans, and $638 million for Entergy Arkansas. If the state net operating loss carryforwards are not utilized, they will expire in the years 2016 through 2018 for Entergy Louisiana, 2018 for Entergy Gulf States, 2018 for Entergy New Orleans, and 2008 for Entergy Arkansas.
NOTE 4. LINES OF CREDIT AND RELATED SHORT-TERM BORROWINGS (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
The short-term borrowings of the domestic utility companies and System EnergyEntergy's subsidiaries are limited to amounts authorized by the SEC. The current limits authorized are effective through November 30, 2004.2007. In addition to borrowing from commercial banks, the domestic utility companies and System EnergyEntergy's subsidiaries are authorized under the SEC order to borrow from the Entergy System Money Pool (money pool).Entergy's money pool. The money pool is an inter-company borrowing arrangement designed to reduce the domestic utility companies'Entergy's subsidiaries' dependence on external short-term borrowings. Borrowings from the money pool and external borrowings combined may not exceed the SEC authorized limits. As of December 31, 2002, there were no borrowings fromUnder the money pool or outstanding from external sources forSEC Order and without further SEC authorization, the domestic utility companies and System Energy. Energy cannot incur additional short-term indebtedness unless (a) the issuer and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of the issuer (other than preferred stock of Entergy Gulf States and Entergy New Orleans), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade.
The following are the SEC-authorizedSEC authorized limits for short-term borrowings and the outstanding short-term borrowings from the money pool for the domestic utility companies and System Energy as o fof December 31, 2002:2004:
Authorized | Borrowings | ||
(In Millions) | |||
Entergy Arkansas | $235 | - | |
Entergy Gulf States | $340 | $59.7 | |
Entergy Louisiana | $225 | - | |
Entergy Mississippi | $160 | - | |
Entergy New Orleans | $100 | - | |
System Energy | $140 | - |
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|
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Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy MississippiNew Orleans each have 364-day credit facilities available as follows:
|
| Amount of | Amount Drawn as of | |||
Entergy Arkansas |
| $ | - | |||
Entergy Louisiana |
| $15 | - | |||
Entergy Mississippi | May | $25 million | - | |||
Entergy New Orleans | April 2005 | $14 million(a) | - |
(a) The combined amount borrowed by Entergy Louisiana and Entergy New Orleans under these facilities at any one time cannot exceed $15 million.
The 364-day credit facilities have variable interest rates and the average commitment fee is 0.13%.
The Entergy Arkansas facility requires it to maintain total shareholder's equity of at least 25% of its total assets.
NOTE 5. LONG - TERM DEBT (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
Long-term debt as of December 31, 2004 and 2003 consisted of:
2004 | 2003 | ||
(In Thousands) | |||
Entergy Arkansas | |||
Mortgage Bonds: | |||
6.125% Series due July 2005 | $100,000 | $100,000 | |
5.4% Series due May 2018 | 150,000 | 150,000 | |
5.0% Series due July 2018 | 115,000 | 115,000 | |
7.0% Series due October 2023 | 175,000 | 175,000 | |
6.7% Series due April 2032 | 100,000 | 100,000 | |
6.0% Series due November 2032 | 100,000 | 100,000 | |
5.9% Series due June 2033 | 100,000 | 100,000 | |
6.38% Series due November 2034 | 60,000 | - | |
Total mortgage bonds | 900,000 | 840,000 | |
Governmental Bonds (a): | |||
6.3% Series due 2016, Pope County (h) | 19,500 | 19,500 | |
5.6% Series due 2017, Jefferson County | 45,500 | 45,500 | |
6.3% Series due 2018, Jefferson County (h) | 9,200 | 9,200 | |
6.3% Series due 2020, Pope County | 120,000 | 120,000 | |
6.25% Series due 2021, Independence County (h) | 45,000 | 45,000 | |
5.05% Series due 2028, Pope County (b) | 47,000 | 47,000 | |
Total governmental bonds | 286,200 | 286,200 | |
Other Long-Term Debt | |||
Long-term DOE Obligation (c) | 156,332 | 154,409 | |
8.5% Junior Subordinated Deferrable Interest Debentures | - | 61,856 | |
Unamortized Premium and Discount - - Net | (4,390) | (4,708) | |
Other | 621 | 621 | |
Total Long-Term Debt | 1,338,763 | 1,338,378 | |
Less Amount Due Within One Year | 147,000 | - | |
Long-Term Debt Excluding Amount Due Within One Year | $1,191,763 | $1,338,378 | |
Fair Value of Long-Term Debt (d) | $1,224,942 | $1,235,278 | |
2004 | 2003 | ||
(In Thousands) | |||
Entergy Gulf States | |||
Mortgage Bonds: | |||
8.25% Series due April 2004 | $- | $292,000 | |
6.77% Series due August 2005 | 98,000 | 98,000 | |
Libor + 0.9% Series due June 2007 | - | 275,000 | |
5.2% Series due December 2007 | - | 200,000 | |
3.6% Series due June 2008 | 325,000 | 325,000 | |
Libor + 0.4% Series due December 2009 | 225,000 | - | |
4.875% Series due November 2011 | 200,000 | - | |
6.0% Series due December 2012 | 140,000 | 140,000 | |
5.6% Series due December 2014 | 50,000 | - | |
5.25% Series due August 2015 | 200,000 | 200,000 | |
6.2% Series due July 2033 | 240,000 | 240,000 | |
Total mortgage bonds | 1,478,000 | 1,770,000 | |
Governmental Bonds (a): | |||
5.45% Series due 2010, Calcasieu Parish | 22,095 | 22,095 | |
6.75% Series due 2012, Calcasieu Parish | 48,285 | 48,285 | |
6.7% Series due 2013, Pointe Coupee Parish | 17,450 | 17,450 | |
5.7% Series due 2014, Iberville Parish | 21,600 | 21,600 | |
7.7% Series due 2014, West Feliciana Parish | 94,000 | 94,000 | |
5.8% Series due 2015, West Feliciana Parish | 28,400 | 28,400 | |
7.0% Series due 2015, West Feliciana Parish | 39,000 | 39,000 | |
7.5% Series due 2015, West Feliciana Parish | 41,600 | 41,600 | |
9.0% Series due 2015, West Feliciana Parish | 45,000 | 45,000 | |
5.8% Series due 2016, West Feliciana Parish | 20,000 | 20,000 | |
5.65% Series due 2028, West Feliciana Parish (e) | - | 62,000 | |
6.6% Series due 2028, West Feliciana Parish | 40,000 | 40,000 | |
Total governmental bonds | 417,430 | 479,430 | |
Other Long-Term Debt | |||
8.75% Junior Subordinated Deferrable Interest Debentures | 87,629 | 87,629 | |
Unamortized Premium and Discount - - Net | (2,397) | (2,596) | |
Other | 8,816 | 9,150 | |
Total Long-Term Debt | 1,989,478 | �� | 2,343,613 |
Less Amount Due Within One Year | 98,000 | 354,000 | |
Long-Term Debt Excluding Amount Due Within One Year | $1,891,478 | $1,989,613 | |
Fair Value of Long-Term Debt (d) | $1,999,249 | $2,438,997 | |
2004 | 2003 | ||
(In Thousands) | |||
Entergy Louisiana | |||
Mortgage Bonds: | |||
6.5% Series due March 2008 | $- | $115,000 | |
5.09% Series due November 2014 | 115,000 | - | |
5.5% Series due April 2019 | 100,000 | - | |
7.6% Series due April 2032 | 150,000 | 150,000 | |
6.4% Series due October 2034 | 70,000 | - | |
Total mortgage bonds | 435,000 | 265,000 | |
Governmental Bonds (a): | |||
7.5% Series due 2021, St. Charles Parish (h) | 50,000 | 50,000 | |
7.0% Series due 2022, St. Charles Parish (h) | 24,000 | 24,000 | |
7.05% Series due 2022, St. Charles Parish (h) | 20,000 | 20,000 | |
5.95% Series due 2023, St. Charles Parish (h) | 25,000 | 25,000 | |
6.2% Series due 2023, St. Charles Parish (h) | 33,000 | 33,000 | |
6.875% Series due 2024, St. Charles Parish (h) | 20,400 | 20,400 | |
6.375% Series due 2025, St. Charles Parish | 16,770 | 16,770 | |
5.35% Series due 2029, St. Charles Parish (i) | - | - | |
Auction Rate due 2030, St. Charles Parish (h) | 60,000 | 60,000 | |
4.9% Series due 2030, St. Charles Parish (f) (g) | 55,000 | 55,000 | |
Total governmental bonds | 304,170 | 304,170 | |
Other Long-Term Debt: | |||
Waterford 3 Lease Obligation 7.45% (Note 9) | 247,725 | 262,534 | |
9.0% Junior Subordinated Deferrable Interest Debentures | - | 72,165 | |
Unamortized Premium and Discount - Net | (1,200) | (1,373) | |
Total Long-Term Debt | 985,695 | 902,496 | |
Less Amount Due Within One Year | 55,000 | 14,809 | |
Long-Term Debt Excluding Amount Due Within One Year | $930,695 | $887,687 | |
|
| ||
Fair Value of Long-Term Debt (d) | $762,782 | $668,700 |
2004 | 2003 | ||
(In Thousands) | |||
Entergy Mississippi | |||
6.2% Series due May 2004 | $- | $75,000 | |
6.45% Series due April 2008 | - | 80,000 | |
4.35% Series due April 2008 | 100,000 | 100,000 | |
4.65% Series due May 2011 | 80,000 | - | |
5.15% Series due February 2013 | 100,000 | 100,000 | |
4.95% Series due June 2018 | 95,000 | 95,000 | |
7.7% Series due July 2023 | - | 60,000 | |
6.0% Series due November 2032 | 75,000 | 75,000 | |
7.25% Series due December 2032 | 100,000 | 100,000 | |
6.25% Series due April 2034 | 100,000 | - | |
Total mortgage bonds | 650,000 | 685,000 | |
Governmental Bonds (a): | |||
7.0% Series due 2022, Warren County | - | 8,095 | |
7.0% Series due 2022, Washington County | - | 7,935 | |
4.60% Series due 2022, Mississippi Business Finance Corp. | 16,030 | - | |
Auction Rate due 2022, Independence County (h) | 30,000 | 30,000 | |
Total governmental bonds | 46,030 | 46,030 | |
Other Long-Term Debt: | |||
Unamortized Premium and Discount - Net | (957) | (1,074) | |
Total Long-Term Debt | 695,073 | 729,956 | |
Less Amount Due Within One Year | - | 75,000 | |
Long-Term Debt Excluding Amount Due Within One Year | $695,073 | $654,956 | |
Fair Value of Long-Term Debt (d) | $716,201 | $771,402 |
2004 | 2003 | ||
(In Thousands) | |||
Entergy New Orleans | |||
Mortgage Bonds: | |||
8.125% Series due July 2005 | $30,000 | $30,000 | |
3.875% Series due August 2008 | 30,000 | 30,000 | |
5.25% Series due August 2013 | 70,000 | 70,000 | |
6.75% Series due October 2017 | 25,000 | 25,000 | |
8.0% Series due March 2023 | - | 45,000 | |
7.55% Series due September 2023 | - | 30,000 | |
5.6% Series due September 2024 | 35,000 | - | |
5.65% Series due September 2029 | 40,000 | - | |
Total mortgage bonds | 230,000 | 230,000 | |
Other Long-Term Debt: | |||
Unamortized Premium and Discount - Net | (98) | (783) | |
Total Long-Term Debt | 229,902 | 229,217 | |
Less Amount Due Within One Year | 30,000 | - | |
Long-Term Debt Excluding Amount Due Within One Year | $199,902 | $229,217 | |
| |||
Fair Value of Long-Term Debt (d) | $231,957 | $239,816 |
2004 | 2003 | ||
(In Thousands) | |||
System Energy | |||
Mortgage Bonds: | |||
4.875% Series due October 2007 | $70,000 | $70,000 | |
Total mortgage bonds | 70,000 | 70,000 | |
Governmental Bonds (a): | |||
5.875% Series due 2022, Mississippi Business Finance Corp. | 216,000 | 216,000 | |
5.9% Series due 2022, Mississippi Business Finance Corp. | 102,975 | 102,975 | |
7.3% Series due 2025, Claiborne County | - | 7,625 | |
6.2% Series due 2026, Claiborne County | 90,000 | 90,000 | |
Total governmental bonds | 408,975 | 416,600 | |
Other Long-Term Debt: | |||
Grand Gulf Lease Obligation 5.01% (Note 9) | 397,119 | 403,468 | |
Unamortized Premium and Discount - Net | (1,235) | (1,319) | |
Total Long-Term Debt | 874,859 | 888,749 | |
Less Amount Due Within One Year | 25,266 | 6,348 | |
Long-Term Debt Excluding Amount Due Within One Year | $849,593 | $882,401 | |
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| ||
Fair Value of Long-Term Debt (d) | $470,187 | $489,436 |
(a) | Consists of pollution control revenue bonds and environmental revenue bonds. |
(b) | The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on September 1, 2005 and can then be remarketed. |
(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) | The fair value excludes lease obligations and long-term DOE obligations, and includes debt due within one year. It is determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. |
(e) | The bonds had a mandatory tender date of September 1, 2004. Entergy Gulf States purchased the bonds from the holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time. |
(f) | |
(g) | The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on June 1, 2005 and can then be remarketed. |
(h) | The bonds are secured by a series of collateral first mortgage bonds. |
(i) | The bonds in the principal amount of $110.95 million had a mandatory tender date of October 1, 2003. Entergy Louisiana purchased the bonds from the holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time. |
The annual long-term debt maturities (excluding lease obligations) for debt outstanding as of December 31, 2004, for the next five years are as follows:
Entergy | Entergy | Entergy | Entergy | Entergy | System | |||||||
(In Thousands) | ||||||||||||
2005 | $147,000 | $98,000 | $55,000 | - | $30,000 | - | ||||||
2006 | - | - | - | - | - | - | ||||||
2007 | - | - | - | - | - | $70,000 | ||||||
2008 | $621 | $325,000 | - | $100,000 | $30,000 | - | ||||||
2009 | - | $225,000 | - | - | - | - |
The long-term securities issuances of Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and System Energy are limited to amounts authorized by the SEC. Under their SEC orders and without further SEC authorization, Entergy Gulf States, Entergy Louisiana, and Entergy Mississippi cannot incur additional indebtedness or issue other securities unless (a) the issuer and Entergy Corporation maintain a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all its outstanding securities of the issuer (other than preferred stock of Entergy Gulf States), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade.
Junior Subordinated Deferrable Interest Debentures and Implementation of FIN 46 (Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana)
Entergy implemented FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" effective December 31, 2003. FIN 46 requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among their investors. Variable interest entities (VIEs), generally, are entities that do not have sufficient equity to permit the entity to finance its operations without additional financial support from its equity interest holders and/or the group of equity interest holders are collectively not able to exercise control over the entity. The primary beneficiary is the party that absorbs a majority of the entity's expected losses, receives a majority of its expected residual returns, or both as a result of holding the variable interest. A company may have an interest in a VIE through ownership or other contractual rights or obligations.
Entergy Louisiana Capital I, Entergy Arkansas Capital I, and Entergy Gulf States Capital I (Trusts) were established as financing subsidiaries of Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States, respectively, (the parent company or companies, collectively) for the purposes of issuing common and preferred securities. The Trusts issued Cumulative Quarterly Income Preferred Securities (Preferred Securities) to the public and issued common securities to their parent companies. Proceeds from such issues were used to purchase junior subordinated deferrable interest debentures (Debentures) from the parent company. The Debentures held by each Trust are its only assets. Each Trust uses interest payments received on the Debentures owned by it to make cash distributions on the Preferred Securities and common securities. The parent companies fully and unconditionally guaranteed payment of distributions on the Preferred Securities issued by the respective Trusts. Prior to the app lication of FIN 46, each parent company consolidated its interest in its Trust. Because each parent company's share of expected losses of its Trust is limited to its investment in its Trust, the parent companies are not considered the primary beneficiaries and therefore de-consolidated their interest in the Trusts upon application of FIN 46 with no significant impacts to the financial statements. The parent companies' investment in the Trusts and the Debentures issued by each parent company are included in Other Property and Investments and Long-Term Debt, respectively.
Tax Exempt Bond Audit (Entergy Louisiana)
In November 2000, the Internal Revenue Service (IRS) began an audit of certain Tax Exempt Bonds issued by St. Charles Parish, State of Louisiana (the Issuer). The Bonds were issued to finance previously unfinanced acquisition costs expended by Entergy Louisiana to acquire certain radioactive solid waste disposal facilities (the Facilities) at the Waterford Steam Electric Generating Station. In January 2002, the IRS issued a preliminary adverse determination that the Bonds were not tax exempt. The stated basis for this determination was that radioactive waste did not constitute "solid waste" within the provisions of the Internal Revenue Code and therefore the Facilities did not qualify as solid waste disposal facilities. In a "technical advice memorandum," issued in October 2004 to the parish, the IRS National Office concurred with the preliminary adverse determination. The Issuer and Entergy Louisiana intend to continue to vigorously contest this matter.
NOTE 6. PREFERRED PREFERENCE, AND COMMON STOCK (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)
Preferred Stock
The number of shares authorized and outstanding and dollar value of preferred stock for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans as of December 31, 20022004 and 20012003 are presented below. Only the two Entergy Gulf States series "with sinking fund" contain mandatory redemption requirements. All other series of the U.S. Utilities are redeemable at Entergy's option at the call prices presented. Dividends paid on all of Entergy's preferred stock series are eligible for the dividends received deduction.The dividends received deduction is limited by Internal Revenue Code section 244 for the following preferred stock series: Entergy Arkansas 4.72%, Entergy Gulf States 4.40%, Entergy Louisiana 4.96%, Entergy Mississippi 4.56%, and Entergy New Orleans 4.75%.
Shares |
| Call Price Per | |||||||
| 2004 | 2003 | 2004 | 2003 | 2004 | ||||
Entergy Arkansas Preferred Stock | |||||||||
Without sinking fund: | |||||||||
Cumulative, $100 par value: | |||||||||
4.32% Series | 70,000 | 70,000 | $7,000 | $7,000 | $103.65 | ||||
4.72% Series | 93,500 | 93,500 | 9,350 | 9,350 | $107.00 | ||||
4.56% Series | 75,000 | 75,000 | 7,500 | 7,500 | $102.83 | ||||
4.56% 1965 Series | 75,000 | 75,000 | 7,500 | 7,500 | $102.50 | ||||
6.08% Series | 100,000 | 100,000 | 10,000 | 10,000 | $102.83 | ||||
7.32% Series | 100,000 | 100,000 | 10,000 | 10,000 | $103.17 | ||||
7.80% Series | 150,000 | 150,000 | 15,000 | 15,000 | $103.25 | ||||
7.40% Series | 200,000 | 200,000 | 20,000 | 20,000 | $102.80 | ||||
7.88% Series | 150,000 | 150,000 | 15,000 | 15,000 | $103.00 | ||||
Cumulative, $0.01 par value: | |||||||||
$1.96 Series (a) | 600,000 | 600,000 | 15,000 | 15,000 | $25.00 | ||||
Total without sinking fund | 1,613,500 | 1,613,500 | $116,350 | $116,350 |
Shares |
| Call Price Per | |||||||
| 2004 | 2003 | 2004 | 2003 | 2004 | ||||
Entergy Gulf States Preferred Stock | |||||||||
Preferred Stock | |||||||||
Authorized 6,000,000 shares, | |||||||||
Without sinking fund: | |||||||||
4.40% Series | 51,173 | 51,173 | $5,117 | $5,117 | $108.00 | ||||
4.50% Series | 5,830 | 5,830 | 583 | 583 | $105.00 | ||||
4.40% 1949 Series | 1,655 | 1,655 | 166 | 166 | $103.00 | ||||
4.20% Series | 9,745 | 9,745 | 975 | 975 | $102.82 | ||||
4.44% Series | 14,804 | 14,804 | 1,480 | 1,480 | $103.75 | ||||
5.00% Series | 10,993 | 10,993 | 1,099 | 1,099 | $104.25 | ||||
5.08% Series | 26,845 | 26,845 | 2,685 | 2,685 | $104.63 | ||||
4.52% Series | 10,564 | 10,564 | 1,056 | 1,056 | $103.57 | ||||
6.08% Series | 32,829 | 32,829 | 3,283 | 3,283 | $103.34 | ||||
7.56% Series | 308,830 | 308,830 | 30,883 | 30,883 | $101.80 | ||||
Total without sinking fund | 473,268 | 473,268 | $47,327 | $47,327 | |||||
With sinking fund: | |||||||||
Adjustable Rate-A, 7.0% (b) | 84,000 | 96,020 | $8,400 | $9,602 | $100.00 | ||||
Adjustable Rate-B, 7.0% (b) | 90,000 | 112,500 | 9,000 | 11,250 | $100.00 | ||||
Total with sinking fund | 174,000 | 208,520 | $17,400 | $20,852 | |||||
Fair Value of Preferred Stock with Sinking Fund (c) |
|
|
Shares |
| Call Price Per | |||||||
| 2004 | 2003 | 2004 | 2003 | 2004 | ||||
Entergy Louisiana Preferred Stock | |||||||||
Without sinking fund: | |||||||||
Cumulative, $100 par value: | |||||||||
4.96% Series | 60,000 | 60,000 | $6,000 | $6,000 | $104.25 | ||||
4.16% Series | 70,000 | 70,000 | 7,000 | 7,000 | $104.21 | ||||
4.44% Series | 70,000 | 70,000 | 7,000 | 7,000 | $104.06 | ||||
5.16% Series | 75,000 | 75,000 | 7,500 | 7,500 | $104.18 | ||||
5.40% Series | 80,000 | 80,000 | 8,000 | 8,000 | $103.00 | ||||
6.44% Series | 80,000 | 80,000 | 8,000 | 8,000 | $102.92 | ||||
7.84% Series | 100,000 | 100,000 | 10,000 | 10,000 | $103.78 | ||||
7.36% Series | 100,000 | 100,000 | 10,000 | 10,000 | $103.36 | ||||
Cumulative, $25 par value: | |||||||||
8.00% Series | 1,480,000 | 1,480,000 | 37,000 | 37,000 | $25.00 | ||||
Total without sinking fund | 2,115,000 | 2,115,000 | $100,500 | $100,500 |
| Shares |
| Call Price Per | ||||||
| 2004 | 2003 | 2004 | 2003 | 2004 | ||||
Entergy Mississippi Preferred Stock | |||||||||
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 | ||||
7.44% Series | 100,000 | 100,000 | 10,000 | 10,000 | $102.81 | ||||
8.36% Series | 200,000 | 200,000 | 20,000 | 20,000 | $100.00 | ||||
Total without sinking fund | 503,807 | 503,807 | $50,381 | $50,381 |
Shares |
| Call Price Per | |||||||
| 2004 | 2003 | 2004 | 2003 | 2004 | ||||
Entergy New Orleans Preferred Stock | |||||||||
Without sinking fund: | |||||||||
Cumulative, $100 par value: | |||||||||
4.75% Series | 77,798 | 77,798 | $7,780 | $7,780 | $105.00 | ||||
4.36% Series | 60,000 | 60,000 | 6,000 | 6,000 | $104.58 | ||||
5.56% Series | 60,000 | 60,000 | 6,000 | 6,000 | $102.59 | ||||
Total without sinking fund | 197,798 | 197,798 | $19,780 | $19,780 |
(a) | The total dollar value represents the liquidation value of $25 per share. |
(b) | Represents weighted-average annualized rates for 2004 and 2003. |
(c) | Fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. There is an additional disclosure of fair value of financial instruments in Note 11 to the domestic utility companies and System Energy financial statements. |
Changes in theEntergy Gulf States' preferred stock with sinking fund retirements were 34,500 shares in 2004 and preference stock of Entergy Gulf States2003, and Entergy Louisiana during the last three years were:18,579 shares in 2002.
Number of Shares | |||
2002 | 2001 | 2000 | |
Preference stock retirements | |||
Entergy Gulf States | - | - | (6,000,000) |
Preferred stock retirements | |||
Entergy Gulf States | |||
$100 par value | (18,579) | (49,237) | (76,585) |
Entergy Louisiana | |||
$100 par value | - | (350,000) | - |
Entergy Gulf States has annual sinking fund requirements of $3.45 million through 20072009 for its preferred stock outstanding. Entergy Gulf States has the annual non-cumulative option to redeem, at par, additional amounts of certain series of its outstanding preferred stock.
Common Stock
In December 2002, Entergy Louisiana repurchased 18,202,573 shares of its no par value common stock from Entergy Corporation for $120 million.
NOTE 6. COMPANY-OBLIGATED REDEEMABLE PREFERRED SECURITIES (Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana)
Entergy Louisiana Capital I, Entergy Arkansas Capital I, and Entergy Gulf States Capital I (Trusts) were established as financing subsidiaries of Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States, respectively, for the purpose of issuing common and preferred securities. The Trusts issue Cumulative Quarterly Income Preferred Securities (Preferred Securities) to the public and issue common securities to their parent companies. Proceeds from such issues are used to purchase junior subordinated deferrable interest debentures (Debentures) from the parent company. The Debentures held by each Trust are its only assets. Each Trust uses interest payments received on the Debentures owned by it to make cash distributions on the Preferred Securities.
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The Preferred Securities of the Trusts mature in the years 2045 and 2046. The Preferred Securities are currently redeemable at 100% of their principal amount at the option of Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States. Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States have, pursuant to certain agreements, fully and unconditionally guaranteed payment of distributions on the Preferred Securities issued by their respective trusts. Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States are the owners of all of the common securities of their individual Trusts, which constitute 3% of each Trust's total capital.
NOTE 7. LONG - TERM DEBTCOMMON EQUITY (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and System Energy)
Dividend Restrictions
Long-term debt as of December 31, 2002 and 2001 consisted of:
The annual long-term debt maturities (excluding lease obligations) and annual cash sinking fund requirements for debt outstanding as of December 31, 2002, for the next five years are as follows:
Entergy | Entergy | Entergy | Entergy | Entergy | System | |
(In Thousands) | ||||||
2003 | $255,000 | $293,000 | $260,950 | $255,000 | - | - |
2004 | - | $654,000 | - | $150,000 | $30,000 | - |
2005 | $262,000 | $98,000 | $55,000 | - | $30,000 | - |
2006 | - | - | - | - | $40,000 | - |
2007 | $100,000 | $200,000 | - | - | - | $70,000 |
(a) Not included are other sinking fund requirements of approximately $30.2 million annually, which may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements.
On January 31, 2003, Entergy Mississippi issued $100 million of 5.15% Series First Mortgage Bonds due 2013. The net proceeds will be used to redeem, at maturity, a portion of the $120 million 7.75% Series First Mortgage Bonds due February 15, 2003, and to redeem prior to maturity the $65 million 6.625% Series First Mortgage Bonds due November 1, 2003 and the $25 million 8.25% Series First Mortgage Bonds due July 1, 2004.
NOTE 8. DIVIDEND RESTRICTIONS (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, System Energy)
Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of the domestic utility companies and System Energy restrict the payment of cash dividends or other distributions on their common and preferred stock. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. As of December 31, 2002,2004, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $296.1$394.9 million and $36.2$68.5 million, respectively.
NOTE 9.8. COMMITMENTS AND CONTINGENCIES
The domestic utility companies and System Energy are involved in a number of legal, tax, and regulatory proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of their business. While management is unable to predict the outcome of such proceedings, it is not expected that the ultimate resolution of these matters will have a material adverse effect on Entergy Arkansas', Entergy Gulf States', Entergy Louisiana's, Entergy Mississippi's, Entergy New Orleans', or System Energy's results of operations, cash flows, or financial condition.
Capital Requirements and Financing (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
The domestic utility companies and System Energy plan to spend approximately $2.8 billion on construction and other capital investments during 2003-2005. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and the ability to access capital. The domestic utility companies' and System Energy's estimated construction and other capital expenditures by year for 2003-2005 are as follows:
On July 25, 2002, the Board authorized Entergy Arkansas and Entergy Operations to replace the ANO 1 steam generator and reactor vessel closure head. Management estimates the cost of the fabrication and replacement to be approximately $235 million, of which approximately $135 million will be incurred through 2004. These amounts are reflected in the above table. Management expects that the replacement will occur during a planned refueling outage in 2005. Additional capital investments are possible during these years, but they will be discretionary in nature. The domestic utility companies and System Energy will focus their planned spending on projects that will support continued reliability improvements and customer growth.
The domestic utility companies and System Energy will also require $2.3 billion during the period 2003-2005 to meet long-term debt and preferred stock maturities and cash sinking fund requirements. Long-term debt maturities as of December 31, 2002 for the domestic utility companies and System Energy for 2003 through 2005 are as follows:
Company | 2003 | 2004 | 2005 | |||
Entergy Arkansas | $255 million | - | $262 million | |||
Entergy Gulf States | $293 million | $654 million | $98 million | |||
Entergy Louisiana | $261 million | - | $55 million | |||
Energy Mississippi | $255 million | $150 million | - | |||
Entergy New Orleans | - | $30 million | $30 million | |||
System Energy | - | - | - |
The domestic utility companies and System Energy plan to meet these requirements primarily with internally generated funds and cash on hand, supplemented by proceeds from the issuance of new debt and outstanding credit facilities. In the fourth quarter of 2002, the domestic utility companies, except Entergy New Orleans, issued a total of $640 million of debt with maturities ranging from 2007 to 2032. Approximately $71 million of the proceeds of the debt issued in the fourth quarter were used to retire, in 2002, debt that was scheduled to mature in 2003, and the remainder will be used to meet certain 2003 maturities as they occur. Entergy Mississippi issued an additional $100 million of debt in January 2003 that matures in 2013. The proceeds will be used to repay, prior to maturity, debt of Entergy Mississippi that is scheduled to mature in 2003 and 2004. Certain companies may also continue the reacquisition or refinancing of all or a portion of certain outstanding series of preferred stock and long-term debt.
Fuel Supply Agreements
(Entergy Arkansas and Entergy Mississippi)
Entergy Arkansas has a long-term contract for the supply of low-sulfur coal for Independence (which is also 25% owned by Entergy Mississippi). This contract, which expires in 2011, provides for approximately 90% of Independence's expected annual coal requirements. Additional requirements are satisfied by spot market purchases. Entergy Arkansas has entered into one- to three-year contracts for approximately 52% of White Bluff's coal supply needs. Entergy Arkansas has an additional 20% of its 2003 coal requirement committed in a number of one- to two-year contracts. Additional coal requirements for both Independence and White Bluff are satisfied by spot market or over the counter purchases. Additionally, Entergy Arkansas has a long-term railroad transportation contract for the delivery of coal to both White Bluff and Independence that expires in 2011.
(Entergy Gulf States)
Entergy Gulf States has a contract for a supply of low-sulfur coal for Nelson Unit 6, which should be sufficient to satisfy the fuel requirements for that unit at current consumption rates. The contract, which expires at the end of the first quarter of 2003, includes options to extend supply to 2010 if all price re-openers are accepted. If both parties cannot agree upon a price, then the contract terminates.
Effective April 1, 2000, Louisiana Generating LLC assumed ownership of Cajun's interest in the Big Cajun generating facilities, in which Entergy Gulf States owns a 42% interest. The management of Louisiana Generating LLC has advised Entergy Gulf States that it has executed coal supply and transportation contracts that should provide an adequate supply of coal for the operation of Big Cajun 2, Unit 3 for the foreseeable future.
(EntergyVidalia Purchased Power Agreement (Entergy Louisiana)
In June 1992, Entergy Louisiana agreed to a 20-year natural gas supply contract, in which Entergy Louisiana agreed to purchase natural gas in annual amounts equal to approximately one-third of its projected annual fuel requirements for certain generating units. Annual demand charges associated with this contract are estimated to be $7.6 million. Such charges aggregate $76 million for the years 2003 through 2012.
Power Purchase Agreements
(Entergy Louisiana)
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 $147.7 million in 2004, $112.6 million in 2003, and $104.2 million in 2002, $86.0 million in 2001, and $58.6 million in 2000.2002. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $79.5$125.3 million in 2003,2005, and a total of $2.7$3.5 billion for the years 20042006 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 monthly rates by $11 million each year for up to ten years, beginning in October 2002. The provisions of the settlement also provide that the LPSC shall not recognize or use Entergy Louisiana's use of the cash benefits from the tax treatment in setting any of Entergy Louisiana's rates. Therefore, to the extent Entergy Louisiana's use of the proceeds would ordinarily have reduced its rate base, no change in rate base shall be reflected for ratemaking purposes.
System Fuels (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
The domestic utility companies that are owners of System Fuels have made loans to System Fuels to finance its fuel procurement, delivery, and storage activities. The following loans outstanding to System Fuels as of December 31, 20022004 mature in 2008:
| Ownership | Loan Outstanding | ||
Entergy Arkansas | 35% | $11.0 million | ||
Entergy Louisiana | 33% | $14.2 million | ||
Entergy Mississippi | 19% | $5.5 million | ||
Entergy New Orleans | 13% | $3.3 million |
Nuclear Insurance (Entergy(Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
Third Party Liability Insurance
The Price-Anderson Act limitsprovides insurance for the public liabilityin the event of a nuclear power plant owner foraccident. The costs of this insurance are borne by the nuclear power industry. Originally passed by Congress in 1957 and most recently amended in 1988, the Price-Anderson Act requires nuclear power plants to show evidence of financial protection in the event of a single nuclear incident to approximately $9.5 billion. Protection for this liability is provided through a combinationaccident. This protection must consist of private insurance underwritten by American Nuclear Insurers (ANI) (currently $300 million for each reactor) and an industry assessment program. In addition, liability arising out of terrorist acts will be covered by ANI subject to one industry aggregate limit of $300 million, with a conditional option for one shared industry aggregate limit reinstatement of $300 million. (Theretwo levels:
1. | The primary level is private insurance underwritten by American Nuclear Insurers and provides liability insurance coverage of $300 million. If this amount is not sufficient to cover claims arising from the accident, the second level, Secondary Financial Protection, applies. An industry-wide aggregate limitation of $300 million exists for domestically-sponsored terrorist acts. There is no limitation for foreign-sponsored terrorist acts. |
2. | Within the Secondary Financial Protection level, each nuclear plant must pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, up to a maximum of $100.6 million per reactor per incident. This consists of a $95.8 million maximum retrospective premium plus a five percent surcharge that may be applied, if needed, at a rate that is presently set at $10 million per year per nuclear power reactor. There are no domestically- or foreign-sponsored terrorism limitations. |
Currently, 104 nuclear reactors are no terrorism limitations underparticipating in the Price Anderson Secondary Financial Protection program which responds upon the exhaustion- 103 operating reactors and one closed reactor that still stores used nuclear fuel on site. The product of ANI coverage). Under the assessment program, the maximum payment requirement for eachretrospective premium assessment to the nuclear incident would be $88.1 million perpower industry and the number of nuclear power reactors provides over $10 billion in insurance coverage to compensate the public in the event of a nuclear power reactor payable at a rate of $10 million per licensed reactor per incident per year. accident.
Entergy Arkansas has two licensed reactors and Entergy Gulf States, Entergy Louisiana, and System Energy each have one licensed reactor. As a co-licenseereactor (10% of Grand Gulf 1 with System Energy, SMEPAis owned by a non-affiliated company (SMEPA), which would share on a pro-rata basis in 10%any retrospective premium assessment under the Price-Anderson Act).
An additional but temporary contingent liability exists for all nuclear power reactor owners because of this obligation. In addition, each owner/licensee of the five nuclear units participates in a private insurance progr am that provides coverage for worker tort claims filed forprevious Nuclear Worker Tort (long-term bodily injury caused by exposure to nuclear radiation exposure.while employed at a nuclear power plant) insurance program that was in place from 1988 to 1998. The program provides for a maximum premium assessment of approximatelyexposure to each reactor is $3 million for each licensed reactor inand will only be applied if such claims exceed the event that losses exceedprogram's accumulated reserve funds. This contingent premium assessment feature will expire with the Nuclear Worker Tort program's expiration, which is scheduled for 2008.
Property Insurance
The domestic utility companies' and System Energy'sEntergy's nuclear owner/licenseeslicensee subsidiaries are also members of certain mutual insurance programscompanies that provide coverage for property damage coverage, including decontamination and premature decommissioning expense, to the members' nuclear generating plants. These programs are underwritten by Nuclear Electric Insurance Limited (NEIL). As of December 31, 2002,2004, the domestic utility companies and System Energy were insured against such losses upper the following structures:
ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3
Note: ANO 1 and 2 share in the Primary Layer with one policy in common.
In addition, Waterford 3 and Grand Gulf are also covered under NEIL's Accidental Outage Coverage program. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL property damage loss, subject to $2.3 billion for eacha deductible. The following summarizes this coverage as of their nuclear units.In addition, the domestic utility companies' and System Energy's nuclear owner/licensees are members of the NEIL insurance program that covers certain replacement power and business interruption costs incurred due to prolonged nuclear unit outages. December 31, 2003:
Waterford 3
Grand Gulf
Under the property damage and replacement power/business interruptionaccidental outage insurance programs, theEntergy's nuclear owner/licenseesplants could be subject to assessments ifshould losses exceed the accumulated funds available to the insurers.from NEIL. As of December 31, 2002,2004, the maximum amountsamount of such possible assessments were:per occurrence were $15.1 million for Entergy Arkansas, - $24.9 million;$11.1 million for Entergy Gulf States, - $18.8 million;$13.0 million for Entergy Louisiana, - $19.1 million;$0.06 million for Entergy Mississippi, - $1.4 million;$0.06 million for Entergy New Orleans, - $0.7 million; and $11.5 million for System Energy - $16.5 million.Energy.
Entergy maintains property insurance for each of its nuclear units in excess of the NRC's minimum requirement of $1.06 billion per site for nuclear power plant licensees of $1.06 billion per site.licensees. NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.
Effective November 15, 2001, inIn the event that one or more acts of domestically-sponsored terrorism cause accidentalcauses property damage under one or more ofor all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first accidental 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 sourcesources applicable to such losses. There is no aggregate limit involving one or more acts of foreign-sponsored terrorism.
Spent Nuclear Fuel (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy)
The nuclear owner/licensees of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy provide for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected companies entered into contracts with the DOE, whereby the DOE will furnish disposal service 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 company that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2002 of $153 million for the one-time fee. 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.
Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. After twenty years of study, the DOE, in February 2002, formally recommended, and President Bush approved, Yucca Mountain, Nevada as the permanent spent fuel repository. DOE will now proceed with the licensing and, if the license is granted by the NRC, eventual construction of the repository will begin and receipt of spent fuel may begin as early as approximately 2010. Considerable uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from the U.S. Utility's facilities for storage or disposal. As a result, future expenditures will be required to increase spent fuel storage capacity at the U.S. Utility's nuclear plant sites.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are responsible for their own spent fuel storage. Current on-site spent fuel storage capacity at Grand Gulf 1 and River Bend is estimated to be sufficient until approximately 2006 and 2004, respectively, at which time dry cask storage facilities will be placed into service. The spent fuel storage capacity at Waterford 3 was recently expanded through the replacement of the existing storage racks with higher density storage racks. This expansion should provide sufficient storage for Waterford 3 until after 2010. An ANO storage facility using dry casks began operation in 1996 and has been expanded since and will be further expanded as needed.
Nuclear Decommissioning and Other Retirement Costs (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy)
SFAS 143, "Accounting for Asset Retirement Obligations," which was implemented effective January 1, 2003, requires the recording of liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets.
Total approved decommissioning costsThese liabilities are recorded at their fair values (which is 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 rate recovery purposes asthis present value obligation. The amounts added to the carrying amounts of December 31, 2002,the long-lived assets are depreciated over the useful lives of the assets. The net effect of implementing this standard for Entergy Arkansas', Entergy Gulf States', Entergy Louisiana's,the rate-regulated business of the domestic utility companies and System Energy's nuclear power plants, excluding SMEPA's shareEnergy was recorded as a regulatory asset, with no resulting impact on Entergy's net income. Entergy recorded these regulatory assets because existing rate mechanisms in each jurisdiction are based on the principle that Entergy will recover all ultimate costs of Grand Gulf 1,decommissioning from customers. As a result of this treatment, SFAS 143 is expected to be earnings neut ral to the rate-regulated business of the domestic utility companies and System Energy.
Upon implementation of SFAS 143 in 2003, assets and liabilities increased $1.1 billion for the U.S. Utility segment as a result of recording the asset retirement obligations at their fair values of $1.1 billion as determined under SFAS 143, increasing utility plant by $287 million, reducing accumulated depreciation by $361 million and recording the related regulatory assets of $422 million. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking decreased earnings in the first quarter of 2003 by $21 million net-of-tax as a result of a cumulative effect of accounting change. In accordance with ratemaking treatment and as required by SFAS 71, the depreciation provisions for the domestic utility companies and System Energy include a component for removal costs that are as follows:
Thenot asset retirement obligations under SFAS 143. In accordance with regulatory accounting principles, the domestic utility companies and System Energy have been recording decommissioning liabilities for these plantsrecorded regulatory as sets (liabilities) in the estimated decommissioning costs are collected from customers or as earnings on the trust funds are realized. Effective January 1, 2003, Entergy adopted SFAS 143, "Accounting for Asset Retirement Obligations." The provisions of this statement will result in a different amount of decommissioning costs being recorded than under the method described above in use priorfollowing amounts to December 31, 2002. Entergy expects to adjust for financial reporting purposes this different level of decommissioning expense to the level previously being recorded through the use of regulatory assets/regulatory liabilities for a substantial portionreflect their estimates of the decommissioningdifference between estimated incurred removal costs associated with the units listed above. The decommissioning liabilities recorded are discussed below.
Decommissioningand estimated removal costs recovered in rates are deposited in trust funds and reported at market value based upon market quotes or as determined by widely used pricing services. These trust fund assets largely offset the accumulated decommissioning liability that ispreviously recorded as a component of accumulated depreciationdepreciation:
|
| December 31, | ||
|
| 2004 |
| 2003 |
|
| (In Millions) | ||
|
|
|
|
|
Entergy Arkansas |
| $34.9 |
| $26.6 |
Entergy Gulf States |
| $0.9 |
| $4.2 |
Entergy Louisiana |
| ($34.6) |
| ($26.8) |
Entergy Mississippi |
| $32.7 |
| $24.4 |
Entergy New Orleans |
| $1.3 |
| $2.1 |
System Energy |
| $17.1 |
| $15.1 |
The cumulative decommissioning liabilities and expenses recorded in 2004 by Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana, and are recordedSystem Energy were as deferred credits by System Energy. The liability associated with the trust funds received from Cajun with the transfer of Cajun's 30% share of River Bend is also recorded as a deferred credit by follows:
|
|
|
|
| Change in Cash Flow Estimate |
|
| |
| (In Thousands) | |||||||
|
|
|
|
|
|
|
| |
ANO 1 and ANO 2 | $567.5 |
| $32.9 |
| ($107.7) |
| $492.7 | |
River Bend | $298.8 |
| $19.7 |
| ($166.4) |
| $152.1 | |
Waterford 3 | $325.3 |
| $22.0 |
| - |
| $347.3 | |
Grand Gulf | $312.5 |
| $23.4 |
| - |
| $335.9 |
Entergy Gulf States.periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment.
In the first quarter of 2004, Entergy periodically reviews and updatesArkansas recorded a revision to its estimated decommissioning costs. Entergy is presently under-recovering decommissioning costs for ANO 1, ANO 2, Grand Gulf 1, Waterford 3, and the Louisiana-regulated portion of River Bend. Under-recovery for Grand Gulf 1 and Waterford 3 is based on the existence of more recent estimates reflecting higher costs. Under-recovery of ANO 1, ANO 2, and River Bend is based on suspension of decommissioning collections under the assumption that the lives of those plants have been or will be extended.
In June 2001, Entergy Arkansas received notification from the NRC of approval forcost liability in accordance with a renewed operating license authorizing operations at ANO 1 through May 2034. In October 2000, the APSC ordered Entergy Arkansas to reflect 20-year license extensions in its determination of the ANO 1 and ANO 2 decommissioning revenue requirements for rates to be effective January 1, 2001. Entergy Arkansas will not make additional contributions to the trust funds in 2003 for ANO 1 and ANO 2 based on the extension of the ANO 1 license, the assumption that the ANO 2 license will be extended, and that the existing decommissioning trust funds, together with their expected future earnings, will meet the estimated decommissioning costs. An updatednew decommissioning cost study for ANO 1 and 2 as a result of revised decommissioning costs and changes in assumptions regarding the timing of when the decommissioning of the plants will be filedbegin. The revised estimate resulted in a $107.7 million reduction in its decommissioning liability, along with a $19.5 million reduction in utility plant and an $88.2 million reduction in the APSC in March 2003.related regulatory asset.
In December 2002,the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected an expected life extension for the plant. The revised estimate resulted in a $166.4 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $49.6 million reduction in non-utility property, a $40.1 million reduction in the related regulatory asset, and the LPSC reached a settlementregulatory liability of $17.7 million. For the fourth through eighth post-merger earnings reviews. Among other things, the settlement includes suspension of collections for decommissioning the Louisiana-regulated portion of River Bend beginning January 1, 2003, based upon an assumptionnot subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the operating license andtime of adoption of SFAS 143 with the useful liferemainder recorded as miscellaneous other income of $27.7 million.
If SFAS 143 had been applied by Entergy Gulf States for the portion of River Bend will be extended. Accordingnot subject to cost-based ratemaking during prior periods, the settlement agreement, infollowing impacts would have resulted:
Year Ended | ||
Entergy Gulf States | ||
Earnings applicable to common stock - as reported | $169,190 | |
Pro forma effect of SFAS 143 | ($2,227) | |
Earnings applicable to common stock - pro forma | $166,963 |
Entergy maintains decommissioning trust funds that are committed to meeting the event thatcosts of decommissioning the NRC formally notifies Entergy thatnuclear power plants. The fair values of the decommissioning funding for River Bend is or would become inadequate, Entergy Gulf States would be permitted recognition in ratestrust funds and asset retirement obligation-related regulatory assets of decommissioning expense at a level sufficient to address reasonably the NRC's concern as expressed in the notification. The decommissioning liability for the 30% share of River Bend formerly owned by Cajun was fully funded by a transfer of $132 million to the River Bend Decommissioning Trust at the completion of Cajun's bankruptcy proceedings.
Entergy Louisiana prepared a decommissioning cost update for Waterford 3 in 1999 and produced a revised decommissioning cost update of $481.5 million. This cost update was filed with the LPSC in the third quarter of 2000.
System Energy included updated decommissioning costs (based on the updated 1994 study) in its 1995 rate increase filing with FERC. Rates requested in this proceeding were placed into effect in December 1995, subject to refund. In July 2000, FERC issued an order approving a lower decommissioning cost than what was requested by System Energy in the 1995 filing. System Energy adjusted its collection to the FERC-approved level of $341 million in the third quarter of 2001. A 1999 decommissioning cost update of $540.8 million for System Energy's 90% share of Grand Gulf has not yet been filed with FERC.
The cumulative liabilities and decommissioning expenses recorded in 2002 by Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy wereas of December 31, 2004 are as follows:
|
| Decommissioning |
| Regulatory |
|
| (In Millions) | ||
|
|
|
|
|
ANO 1 & ANO 2 |
| $383.8 |
| $141.2 |
River Bend |
| $291.0 |
| - |
Waterford 3 |
| $172.1 |
| $141.6 |
Grand Gulf |
| $205.1 |
| $97.3 |
In 2000, ANO's decommissioning expense was $3.8 million. River Bend's decommissioning expense was $6.2 million in both 2001 and 2000, and Waterford 3's decommissioning expense was $10.4 million for both years. Grand Gulf 1's 2001 decommissioning expense, which included the effect of the FERC-ordered refund, was ($23.8 million); its 2000 decommissioning expense was $18.9 million.
The Energy Policy Act of 1992 contains a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning (D&D) of the DOE's past uranium enrichment operations. Annual assessments (in 2002 dollars), which will be adjusted annually for inflation, are for 15 years andin 2004 were $4.2$4.4 million for Entergy Arkansas, $1.0$1.1 million for Entergy Gulf States, $1.6 million for Entergy Louisiana, and $1.6$1.8 million for System Energy in 2002.2004. The Energy Policy Act calls for cessation of annual D&D assessments not later than October 24, 2007. At December 31, 2002, four2004, two years of assessments were remaining. D&D fees are included in other current liabilities and other non-current liabilities and, as of December 31, 2002,2004, recorded liabilities were $16.7$8.8 million for Entergy Arkansas, $4.0$1.9 million for Entergy Gulf States, $6.4$3.3 million for Entergy Louisiana, and $6.3$3.3 million for System Energy. Regulatory assets in the financial statements offset these liabilities, with the exce ptionexception of Entergy Gulf States' 30% non-regulated portion. FERC requires that utilities treat these assessments as costs of fuel as theyThese a ssessments are amortized and recover these costsrecovered through rates in the same manner as other fuel costs.
Income Taxes
Entergy is currently under audit by the IRS with respect to tax returns for tax periods subsequent to 1995 and through 2001, and is subject to audit by the IRS and other taxing authorities for subsequent tax periods. The amount and timing of any tax assessments resulting from these audits are uncertain, and could have a material effect on Entergy's financial position and results of operations. Entergy believes that the contingency provisions established in its financial statements will sufficiently cover the risk associated with tax matters. Certain material audit matters as to which management believes there is a reasonable possibility of a future tax assessment are discussed below. See Note 3 to the domestic utility companies and System Energy financial statements for additional discussion of income taxes.
Depreciable Property Lives
During the years 1997 through 2004, Entergy subsidiaries, Entergy Services, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy Resources reflected changes in tax depreciation methods with respect to certain types of depreciable property (e.g. street lighting, billing meters, and various generation plant equipment). As of December 31, 2004, the cumulative effect of these changes results in additional depreciation deductions generating a cash flow benefit of $45 million for Entergy Arkansas, $38 million for Entergy Gulf States, $32 million for Entergy Louisiana, $19 million for Entergy Mississippi, $6 million for Entergy New Orleans, and $12 million for System Energy. As of December 31, 2004, the related IRS interest exposure if the deduction is ultimately disallowed is $13 million for Entergy Arkansas, $11 million for Entergy Gulf States, $9 million for Entergy Louisiana, $6 million for Entergy Mississippi, $2 million for Entergy New Orleans, and $3 million for System Energy. This benefit reverses over time and will also fluctuate with each year's addition to those types of assets. Due to the temporary nature of the tax benefit, the potential interest charge represents the total net exposure of the domestic utility companies and System Energy.
For the years under audit, 1996-2001, the IRS challenged Entergy's classification of these assets and proposed adjustments to the depreciation deductions taken. Entergy disagrees with the position of the IRS and has protested the disallowance of these deductions to the Office of IRS Appeals. Entergy expects to receive a Notice of Deficiency in 2005 for this item, and plans to vigorously contest this matter. Entergy believes that the contingency provision established in its financial statements sufficiently covers the risk associated with this item.
Mark to Market of Certain Power Contracts
In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts. The most significant of these is the contract to purchase power from the Vidalia hydroelectric project. The new tax accounting method has provided a cumulative cash flow benefit of approximately $790 million as of December 31, 2004. The related IRS interest exposure is $93 million at December 31, 2004. This benefit is expected to reverse in the years 2005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. Due to the temporary nature of the tax benefit, the potential interest charge represents Entergy's net earnings exposure. Entergy Louisiana's 2001 tax return is currently under examination by the IRS, though no adjustments have yet been proposed with respect to the mark to market election. Entergy believes that the contingency provision established in its financial statements will sufficiently cover the risk associated with this issue.
CashPoint Bankruptcy (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)
In 2003 the domestic utility companies entered an agreement with CashPoint Network Services (CashPoint) under which CashPoint was to manage a network of payment agents through which Entergy's utility customers could pay their bills. The payment agent system allows customers to pay their bills at various commercial or governmental locations, rather than sending payments by mail. Approximately one-third of Entergy's utility customers use payment agents.
On April 19, 2004, CashPoint failed to pay funds due to the domestic utility companies that had been collected through payment agents. The domestic utility companies then obtained a temporary restraining order from the Civil District Court for the Parish of Orleans, State of Louisiana, enjoining CashPoint from distributing funds belonging to Entergy, except by paying those funds to Entergy. On April 22, 2004, a petition for involuntary Chapter 7 bankruptcy was filed against CashPoint by other creditors in the United States Bankruptcy Court for the Southern District of New York. In response to these events, the domestic utility companies expanded an existing contract with another company to manage all of their payment agents. The domestic utility companies filed proofs of claim in the CashPoint bankruptcy proceeding in September 2004. Although Entergy cannot precisely determine at this time the amount that CashPoint owes to the domestic utility companies that may not be repaid, it has accrued an estim ate of loss based on current information. If no cash is repaid to the domestic utility companies, an event Entergy does not believe is likely, the current estimates of maximum exposure to loss are approximately as follows:
Amount | ||
(In Millions) | ||
Entergy Arkansas | $1.8 | |
Entergy Gulf States | $7.7 | |
Entergy Louisiana | $8.8 | |
Entergy Mississippi | $4.3 | |
Entergy New Orleans | $2.4 |
Environmental Issues (Entergy Gulf States)
Entergy Gulf States has been designated as a PRP for the cleanup of certain hazardous waste disposal sites. Entergy Gulf States is currently negotiating with the EPA and state authorities regarding the cleanup of these sites. As of December 31, 2002,2004, Entergy Gulf States does not expect the remaining clean-up costs to exceed its recorded liability of $12$1.5 million for the remaining sites at which the EPA has designated Entergy Gulf States as a PRP.
City Franchise Ordinances (Entergy New Orleans)
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to franchise ordinances. These ordinances contain a continuing option for the city to purchase Entergy New Orleans' electric and gas utility properties.
Street Lighting Lawsuit (Entergy New Orleans)
In February 2002, the City of New Orleans (City) filed a petition against Entergy New Orleans in state court in Orleans Parish, seeking declaratory relief, injunctive relief, an unspecified amount of monetary damages, and attorney and consulting fees and costs. The City's petition alleged that Entergy New Orleans had breached its obligations to the City related to the provision of street lighting maintenance services. After mediation, the City dismissed its lawsuit with prejudice on October 28, 2002, and any amounts that may be owed by Entergy New Orleans will be determined by an independent third party audit. Management believes that Entergy New Orleans does not owe the City any net amount under the street lighting contract, and will vigorously assert its rights in the audit.
Waterford 3 Lease Obligations (Entergy(Entergy Louisiana)
On September 28, 1989, Entergy Louisiana entered into three identical transactions for the sale and leaseback of undivided interests (aggregating approximately 9.3%) in Waterford 3. In July 1997, Entergy Louisiana caused the lessors to issue $307.6 million aggregate principal amount of Waterford 3 Secured Lease Obligation Bonds, 8.76%8.09% Series due 2017, to refinance the outstanding bonds originally issued to finance the purchase of the undivided interests by the lessors. The lease payments were reduced to reflect the lower interest costs. Upon the occurrence of certain events, Entergy Louisiana may be obligated to pay amounts sufficient to permit the termination of the lease transactions and may be required to assume the outstanding bonds issued to finance, in part, the lessors' acquisition of the undivided interests in Waterford 3.
Employment Litigation (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy New Orleans, System Energy, or their affiliates, are defendants in numerous lawsuits filed by former employees asserting that they were wrongfully terminated and/or discriminated against on the basis of age, race, sex, and/or sex.other protected characteristics. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, System Energy, and their affilitatesaffiliates are vigorously defending these suits and deny any liability to the plaintiffs. Nevertheless, no assurance can be given as to the outcome of these cases.
Asbestos and Hazardous Material Litigation (Entergy Gulf States, Entergy Louisiana, Entergy New Orleans)
Numerous lawsuits have been filed in federal and state courts in Texas, Louisiana, and LouisianaMississippi primarily by contractor employees in the 1950-1980 timeframe against Entergy Gulf States, Entergy Louisiana, and Entergy New Orleans, and Entergy Mississippi as premises owners of power plants, for damages caused by alleged exposure to asbestos or other hazardous material. Many other defendants are named in these lawsuits as well. Since 1992, the Entergy companies have resolved over 3 thousand claims for nominal amounts that in the aggregate total less than $13 million, including defense costs. Some of this loss has been offset by reimbursement from insurers. Presently, there are over 3 thousand claims pending and reservesapproximately 480 lawsuits involving approximately 10,000 claims. Management believes that adequate provisions have been established that should be adequate to cover any exposure. Additionally, negotiations continue with insurers to recover more reimbursement, while new coverage is being secured to minimize anticipated future potential exposures. Management believes that loss exposure has been and will continue to be handled successf ullysuccessfully so that the ultimate resolution of these matters will not be material, in the aggregate, to its financial position or resultsresult s of operation.
Grand Gulf 1-Related- Related Agreements
Capital Funds Agreement (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 90% interest in Grand Gulf, 1, 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.
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 90% share of capacity and energy from Grand Gulf 1 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 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 so long as the unit remains in commercial operation. The agreement will remain in effect until terminated by the parties and the termination is approved by FERC, most likely upon Grand Gulf 1'sGulf's retirement from service. Monthly obligations are based on actual capacity and energy costs. The average monthly payments for payments2004 under the agreement are approximately $16$16.6 million for Entergy Arkansas, $6$6.7 million for Entergy Louisiana, $14$13.7 million for EntergyEnt ergy Mississippi, and $7$8.1 million for Entergy New Orleans.
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.) System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Since commercial operation of Grand Gulf 1, 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' responsibilities and obligations with respect to Grand Gulf under the Availability Agreement. FERC's decision allocating a portion of Grand Gulf 1 capacity and energy to Entergy Arkansas supersedes the Reallocation Agreement as it relates to Grand Gulf 1. 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' obligation to System Energy's lenders under the assignments referred to in the preceding paragraph. Entergy ArkansasArka nsas would be liable fo rfor its share of such amounts if Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans were unable to meet their contractual obligations. No payments of any amortization amounts will be required so long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future.
Reimbursement Agreement (System Energy)
In December 1988, System Energy entered into two separate, but identical, arrangements for the sale and leaseback of an approximate aggregate 11.5% ownership interest in Grand Gulf 1.Gulf. In connection with the equity funding of the sale and leaseback arrangements, letters of credit are required to be maintained to secure certain amounts payable for the benefit of the equity investors by System Energy under the leases. The previous letters of credit were due to expire on March 20, 2003, and were replaced early in March 2003. The newcurrent letters of credit are effective until March 2006,May 29, 2009.
Under the provisions of the reimbursement agreement relating to the letters of credit, System Energy has agreed to a number of covenants regarding the maintenance of certain capitalization and are backed byfixed charge coverage ratios. System Energy agreed, during the term of the reimbursement agreement, to maintain a ratio of debt to total liabilities and equity less than or equal to 70%. In addition, System Energy must maintain, with respect to each fiscal quarter during the term of the reimbursement agreement, a ratio of adjusted net income to interest expense of at least 1.50 times earnings. As of December 31, 2004, System Energy's debt ratio was approximately $192 million of cash collateral.32.5%, and its fixed charge coverage ratio for 2004 was approximately 4.12, calculated, in each case, as prescribed in the reimbursement agreement.
NOTE 10.9. LEASES (Entergy(Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
General
As of December 31, 2002,2004 the domestic utility companies had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities (excluding nuclear fuel leases and the sale and leaseback transactions) with minimum lease payments as follows:
Capital Leases | ||||
| Entergy | Entergy | ||
(In Thousands) | ||||
2005 | $9,610 | $50 | ||
2006 | 5,682 | 42 | ||
2007 | 3,427 | 11 | ||
2008 | 1,754 | - | ||
2009 | 237 | - | ||
Years thereafter | 2,606 | - | ||
Minimum lease payments | 23,316 | 103 | ||
Less: Amount representing interest | 3,386 | 2 | ||
Present value of net minimum lease payments | $19,930 | $101 |
Capital Leases
Operating Leases | |||||||||
| Entergy | Entergy | Entergy | Entergy | |||||
(In Thousands) | |||||||||
2005 | $23,743 | $26,744 | $9,974 | $7,421 | |||||
2006 | 20,029 | 23,942 | 5,647 | 6,596 | |||||
2007 | 17,563 | 17,223 | 5,109 | 3,552 | |||||
2008 | 14,977 | 9,742 | 3,546 | 3,039 | |||||
2009 | 8,622 | 9,108 | 2,346 | 2,676 | |||||
Years thereafter | 54,339 | 115,216 | 2,524 | 11,068 | |||||
Minimum lease payments | $139,273 | $201,975 | $29,146 | $34,352 |
Rental Expense | |||||||
| Entergy | Entergy | Entergy | Entergy | |||
(In Millions) | |||||||
2004 | $17.4 | $24.4 | $11.9 | $3.4 | |||
2003 | $19.4 | $26.5 | $13.8 | $5.4 | |||
2002 | $20.8 | $25.8 | $13.6 | $5.4 |
Operating Leases
Rental expense amounted to $20.8 million, $21.1 million, and $18.9 million for Entergy Arkansas; $17.6 million, $22.0 million, and $18.9 million for Entergy Gulf States; and $11.2 million, $11.7 million, and $7.9 million for Entergy Louisiana in 2002, 2001, and 2000, respectively. In addition to the above rental expense, railcar operating lease payments whichand oil tank facilities lease payments are recorded in fuel expense in accordance with regulatory treatment. Railcar operating lease payments were $9.3 million in 2004, $6.8 million in 2003, and $8.3 million in 2002 $12.2 million in 2001, and $12.5 million in 2000 for Entergy Arkansas and $2.0 million in 2002 and $2.82004, $1.8 million in 20012003, and 2000$2.0 million in 2002 for Entergy Gulf States. The railcarOil tank facilities lease payments are recorded as fuel expense in accordance with regulatory treatment.for Entergy Mississippi were $3.2 million for 2004 and $3.1 million for each of the years 2003 and 2002.
Nuclear Fuel Leases
As of December 31, 2002,2004, arrangements to lease nuclear fuel existed in an aggregate amount up to $140$150 million for Entergy Arkansas, $105 million for Entergy Gulf States, $80 million for each of Entergy Gulf States and Entergy Louisiana, and $95$110 million for System Energy. As of December 31, 2002,2004, the unrecovered cost base of nuclear fuel leases amounted to approximately $88.1$93.9 million for Entergy Arkansas, $41.4$71.2 million for Entergy Gulf States, $50.9$31.7 million for Entergy Louisiana, and $79.0$65.6 million for System Energy. The lessors finance the acquisition and ownership of nuclear fuel through loans made under revolving credit agreements, the issuance of commercial paper, and the issuance of intermediate-term notes. The credit agreements for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy each have a termination datesdate of November 2003, November 2003, December 2004, and November 2003, respectively. SuchOctober 30, 2006. The termination dates may be extended from time to time with the consent of the lenders. The intermediate-term notes issued pursuant to these fuel lease arrangementsa rrangements have varying maturities through MarchFebruary 15, 2006.2009. It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. However, if such additional financing cannot be arranged, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations.obligations in accordance with the fuel lease.
Lease payments are based on nuclear fuel use. The table below represents the total nuclear fuel lease payments (principal and interest) as well as the separate interest component charged to operations in 2002, 2001,2004, 2003, and 2000:2002:
2004 | 2003 | 2002 | |||||||||
Lease |
| Lease |
| Lease |
| ||||||
(In Millions) | |||||||||||
Entergy Arkansas | $53.0 | $4.3 | $49.9 | $3.3 | $49.6 | $3.2 | |||||
Entergy Gulf States | 29.7 | 3.2 | 27.8 | 3.0 | 29.2 | 3.0 | |||||
Entergy Louisiana | 36.1 | 2.5 | 32.3 | 2.4 | 32.9 | 2.6 | |||||
System Energy | 27.8 | 2.8 | 32.0 | 3.1 | 26.1 | 2.5 | |||||
Total | $146.6 | $12.8 | $142.0 | $11.8 | $137.8 | $11.3 |
Sale and Leaseback Transactions
Waterford 3 Lease Obligations (Entergy Louisiana)
In 1989, Entergy Louisiana sold and leased back 9.3% of its interest in Waterford 3 for the aggregate sum of $353.6 million. The lease has an approximate term of 28 years. The lessors financed the sale-leaseback through the issuance of Waterford 3 Secured Lease Obligation Bonds. The lease payments made by Entergy Louisiana are sufficient to service the debt.
In 1994, Entergy Louisiana did not exercise its option to repurchase the 9.3% interest in Waterford 3. As a result, Entergy Louisiana issued $208.2 million of non-interest bearing first mortgage bonds as collateral for the equity portion of certain amounts payable under the lease.
In 1997, the lessors refinanced the outstanding bonds used to finance the purchase of Waterford 3 at lower interest rates, which reduced the annual lease payments.
Upon the occurrence of certain events, Entergy Louisiana may be obligated to assume the outstanding bonds used to finance the purchase of 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 (including preferred stock) 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, 2002,2004, Entergy Louisiana's total equity capital (including preferred stock) was 46.28%51.33% of adjusted capitalization and its fixed charge coverage ratio for 20022004 was 3.14.3.76.
As of December 31, 2002,2004, Entergy Louisiana had future minimum lease payments (reflecting an overall implicit rate of 7.45%) in connection with the Waterford 3 sale and leaseback transactions, which are recorded as long-term debt, as follows (in thousands):follows:
(In Thousands) | ||
2005 | $14,554 | |
2006 | 18,261 | |
2007 | 18,754 | |
2008 | 22,606 | |
2009 | 32,452 | |
Years thereafter | 334,062 | |
Total | 440,689 | |
Less: Amount representing interest | 192,964 | |
Present value of net minimum lease payments | $247,725 |
Grand Gulf 1 Lease Obligations (System(System Energy)
In December 1988, System Energy sold 11.5% of its undivided ownership interest in Grand Gulf 1 for the aggregate sum of $500 million. Subsequently, System Energy leased back its interest in the unit for a term of 26-1/26 1/2 years. System Energy has the option of terminating the lease and repurchasing the 11.5% interest in the unit at certain intervals during the lease. Furthermore, at the end of the lease term, System Energy has the option of renewing the lease or repurchasing the 11.5% interest in Grand Gulf.
In May 2004 System Energy caused the Grand Gulf 1.lessors to refinance the outstanding bonds that they had issued to finance the purchase of their undivided interest in Grand Gulf. The refinancing is at a lower interest rate, and System Energy's lease payments have been reduced to reflect the lower interest costs.
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 recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and is recording this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance at the end of the lease term. The amount of this net regulatory asset was $79.5$75.4 million and $88.7$83.2 million as of December 31, 20022004 and 2001,2003, respectively.
As of December 31, 2002,2004, System Energy had future minimum lease payments (reflecting an implicit rate of 7.02%5.01%), which are recorded as long-term debt as follows (in thousands):follows:
(In Thousands) | ||
2005 | $45,423 | |
2006 | 46,019 | |
2007 | 46,552 | |
2008 | 47,128 | |
2009 | 47,760 | |
Years thereafter | 302,402 | |
Total | 535,284 | |
Less: Amount representing interest | 138,165 | |
Present value of net minimum lease payments | $397,119 |
NOTE 11.10. RETIREMENT AND OTHER POSTRETIREMENT BENEFITS (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
Pension Plans
TheEntergy's domestic utility companies and System Energy haveEntergy participate in two of Entergy's pension plans,plans: "Entergy Corporation Retirement Plan for Non-Bargaining Employees,"Employees" and "Entergy Corporation Retirement Plan for Bargaining Employees,Employees." covering substantially all of their employees. The pension plans are noncontributoryEntergy Corporation and provide pension benefits that are based on employees' credited service and compensation during the final years before retirement. The domestic utility companies and System Energyits subsidiaries fund pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. As of December 31, 2002, Entergy2004 and 2003, Entergy's domestic utility companies and System Energy recognized an additional minimum pension liability for the excess of the accumulated benefit obligation over the fair market value of plan assets. In accordance with FASBSFAS 87, an offsetting intangible asset, up to the amount of any unrecognized prior service cost, was also recorded, with the remaining offset to the liability recorded as a regulatory asset, reflective of the recovery mechanism for pension costs in Entergy's jurisdictions. Entergy's domestic utility companies' and System Energy's pension costs are recovered from customers as a component of cost of service in each of its jurisdictions. Entergy uses a December 31 measurement date for its pension plans.
Components of Net Pension Cost
Total 2002, 2001,2004, 2003, and 20002002 pension cost of the domestic utility companies and System Energy, including amounts capitalized, included the following components (in thousands):components:
| Entergy | Entergy | Entergy | Entergy | Entergy | System | ||||||
(In Thousands) | ||||||||||||
Service cost - benefits earned |
|
|
|
|
|
| ||||||
Interest cost on projected |
|
|
|
|
|
| ||||||
Expected return on assets | (36,913) | (39,682) | (27,510) | (14,716) | (2,568) | (4,556) | ||||||
Amortization of transition asset | - | - | - | - | - | (319) | ||||||
Amortization of prior service cost | 1,662 | 1,511 | 650 | 513 | 226 | 67 | ||||||
Recognized net loss | 3,952 | 405 | 1,344 | 794 | 898 | 788 | ||||||
Net pension cost | $16,488 | $398 | $3,283 | $2,121 | $4,590 | $4,555 |
| Entergy | Entergy | Entergy | Entergy | Entergy | System | ||||||
(In Thousands) | ||||||||||||
Service cost - benefits earned |
|
|
|
|
|
| ||||||
Interest cost on projected |
|
|
|
|
|
| ||||||
Expected return on assets | (38,712) | (41,784) | (28,919) | (15,434) | (2,616) | (3,944) | ||||||
Amortization of transition asset | - | - | - | - | - | (319) | ||||||
Amortization of prior service cost | 1,737 | 1,931 | 789 | 584 | 236 | 73 | ||||||
Recognized net loss | 256 | 150 | - | 83 | - | 27 | ||||||
Curtailment loss | 5,305 | 2,133 | 2,748 | 1,065 | 129 | 944 | ||||||
Special termination benefits | 5,543 | 2,857 | 2,619 | 811 | 367 | 1,720 | ||||||
Net pension cost | $18,294 | $1,783 | $3,634 | $1,859 | $3,613 | $5,843 |
| Entergy | Entergy | Entergy | Entergy | Entergy | System | ||||||
(In Thousands) | ||||||||||||
Service cost - benefits earned |
|
|
|
|
|
| ||||||
Interest cost on projected |
|
|
|
|
|
| ||||||
Expected return on assets | (40,514) | (43,827) | (30,300) | (16,197) | (2,763) | (3,775) | ||||||
Amortization of transition asset | - | - | - | - | - | (319) | ||||||
Amortization of prior service cost | 1,743 | 1,923 | 744 | 705 | 269 | 72 | ||||||
Net pension cost (income) | $2,074 | ($6,776) | ($3,908) | ($1,508) | $3,046 | $2,329 |
The funded status ofPension Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the domestic utility companies and System Energy's pension plansBalance Sheet as of December 31, 20022004 and 2001 was (in thousands):2003
| Entergy | Entergy | Entergy | Entergy | Entergy | System | ||||||
(In Thousands) | ||||||||||||
Change in Projected Benefit | ||||||||||||
Obligation (PBO) | ||||||||||||
Balance at 12/31/03 | $565,004 | $467,707 | $340,212 | $190,184 | $67,866 | $79,033 | ||||||
Service cost | 11,941 | 9,693 | 7,009 | 3,615 | 1,569 | 3,386 | ||||||
Interest cost | 35,846 | 28,471 | 21,790 | 11,915 | 4,465 | 5,189 | ||||||
Actuarial loss | 46,590 | 17,687 | 32,309 | 13,200 | 8,169 | 9,175 | ||||||
Benefits paid | (34,565) | (27,348) | (22,218) | (12,771) | (3,719) | (1,784) | ||||||
Balance at 12/31/04 | $624,816 | $496,210 | $379,102 | $206,143 | $78,350 | $94,999 | ||||||
Change in Plan Assets | ||||||||||||
Fair value of assets at 12/31/03 | $423,214 | $448,490 | $316,669 | $169,958 | $29,565 | $45,375 | ||||||
Actual return on plan assets | 39,265 | 42,380 | 31,046 | 16,268 | 2,849 | 8,667 | ||||||
Employer contributions | 5,342 | 17 | 3,907 | 1,823 | 2,118 | 3,742 | ||||||
Benefits paid | (34,565) | (27,348) | (22,218) | (12,771) | (3,719) | (1,784) | ||||||
Fair value of assets at 12/31/04 | $433,256 | $463,539 | $329,404 | $175,278 | $30,813 | $56,000 | ||||||
Funded status | ($191,560) | ($32,671) | ($49,698) | ($30,865) | ($47,537) | ($38,999) | ||||||
Amounts not yet recognized | ||||||||||||
in the balance sheet | ||||||||||||
Unrecognized transition asset | - | - | - | - | - | (277) | ||||||
Unrecognized prior service cost | 8,177 | 5,938 | 3,762 | 2,692 | 1,263 | 286 | ||||||
Unrecognized net loss | 133,821 | 38,628 | 75,962 | 36,825 | 26,357 | 20,298 | ||||||
Prepaid/(accrued) pension cost | ||||||||||||
recognized in the balance sheet | ($49,562) | $11,895 | $30,026 | $8,652 | ($19,917) | ($18,692) | ||||||
Amounts recognized in | ||||||||||||
the balance sheet | ||||||||||||
Prepaid/(accrued) pension liability | ($49,562) | $11,895 | $30,026 | $8,652 | ($19,917) | ($18,692) | ||||||
Additional minimum pension liability | (81,161) | - | (38,871) | (23,492) | (16,928) | (7,678) | ||||||
Intangible asset | 10,313 | - | 4,759 | 3,308 | 1,698 | 247 | ||||||
Regulatory asset | 70,848 | - | 34,112 | 20,184 | 15,230 | 7,431 | ||||||
Net amount recognized | ($49,562) | $11,895 | $30,026 | $8,652 | ($19,917) | ($18,692) |
| Entergy | Entergy | Entergy | Entergy | Entergy | System | |||||||
(In Thousands) | |||||||||||||
Change in Projected Benefit | |||||||||||||
Obligation (PBO) | |||||||||||||
Balance at 12/31/02 | $476,276 | $420,644 | $297,144 | $167,175 | $57,085 | $59,418 | |||||||
Service cost | 11,156 | 8,788 | 6,369 | 3,411 | 1,539 | 3,142 | |||||||
Interest cost | 33,009 | 27,708 | 20,028 | 11,339 | 3,958 | 4,200 | |||||||
Amendment | 121 | 96 | - | 5 | - | 5 | |||||||
Actuarial loss | 62,444 | 31,342 | 30,844 | 17,133 | 7,417 | 9,984 | |||||||
Benefits paid | (28,445) | (25,611) | (19,332) | (10,634) | (2,559) | (366) | |||||||
Curtailment loss | 4,900 | 1,883 | 2,540 | 944 | 59 | 930 | |||||||
Special termination benefits | 5,543 | 2,857 | 2,619 | 811 | 367 | 1,720 | |||||||
Balance at 12/31/03 | $565,004 | $467,707 | $340,212 | $190,184 | $67,866 | $79,033 | |||||||
Change in Plan Assets | |||||||||||||
Fair value of assets at 12/31/02 | $367,080 | $380,999 | $261,785 | $144,947 | $32,384 | $34,041 | |||||||
Actual return on plan assets | 84,579 | 93,102 | 74,216 | 35,645 | (260) | 11,700 | |||||||
Benefits paid | (28,445) | (25,611) | (19,332) | (10,634) | (2,559) | (366) | |||||||
Fair value of assets at 12/31/03 | $423,214 | $448,490 | $316,669 | $169,958 | $29,565 | $45,375 | |||||||
Funded status | ($141,790) | ($19,217) | ($23,543) | ($20,226) | ($38,301) | ($33,658) | |||||||
Amounts not yet recognized | |||||||||||||
in the balance sheet | |||||||||||||
Unrecognized transition asset | - | - | - | - | - | (596) | |||||||
Unrecognized prior service cost | 9,839 | 7,449 | 4,412 | 3,206 | 1,489 | 353 | |||||||
Unrecognized net loss | 93,535 | 24,044 | 48,533 | 25,970 | 19,367 | 16,021 | |||||||
Prepaid/(accrued) pension cost | |||||||||||||
recognized in the balance sheet | ($38,416) | $12,276 | $29,402 | $8,950 | ($17,445) | ($17,880) | |||||||
Amounts recognized in | |||||||||||||
the balance sheet: | |||||||||||||
Prepaid/(accrued) pension liability | ($38,416) | $12,276 | $29,402 | $8,950 | ($17,445) | ($17,880) | |||||||
Additional minimum pension liability | (54,948) | - | - | (7,301) | (13,140) | (7,426) | |||||||
Intangible asset | 13,291 | - | - | 937 | 2,774 | 365 | |||||||
Regulatory asset | 41,657 | - | - | 6,364 | 10,366 | 7,061 | |||||||
Net amount recognized | ($38,416) | $12,276 | $29,402 | $8,950 | ($17,445) | ($17,880) |
Other Postretirement Benefits
The domestic utility companies and System Energy also currently provide health care and life insurance benefits for retired employees. Substantially all employees may become eligible for these benefits if they reach retirement age while still working for Entergy. Entergy uses a December 31 measurement date for its postretirement benefit plans.
Effective January 1, 1993, Entergy adopted SFAS 106, which required a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. At January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $241.4 million for Entergy (other than Entergy Gulf States) and $128 million for Entergy Gulf States. Such obligations are being amortized over a 20-year period that began in 1993.
Entergy Arkansas, the portion of Entergy Gulf States regulated by the PUCT, Entergy Mississippi, and Entergy New Orleans have received regulatory approval to recover SFAS 106 costs through rates. Entergy Arkansas began recovery in 1998, pursuant to an APSC order. This order also allowed Entergy Arkansas to amortize a regulatory asset (representing the difference between SFAS 106 costs and cash expenditures for other postretirement benefits incurred for a five-year period that began January 1, 1993) over a 15-year period that began in January 1998.
The LPSC ordered the portion of Entergy Gulf States regulated by the LPSC and Entergy Louisiana to continue the use of the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions. However, the LPSC retains the flexibility to examine individual companies' accounting for postretirement benefits to determine if special exceptions to this order are warranted.
Pursuant to regulatory directives, Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, the portion of Entergy Gulf States regulated by the PUCT, and System Energy fund postretirement benefit obligations collected in rates. System Energy is funding, on behalf of Entergy Operations, postretirement benefits associated with Grand Gulf 1.Gulf. Entergy Louisiana and Entergy Gulf States continue to recover a portion of these benefits regulated by the LPSC and FERC on a pay-as-you-go basis. The assets
Components of the various postretirement benefit plans other than pensions include common stocks, fixed-income securities,Net Other Postretirement Benefit Cost
Total 2004, 2003, and a money market fund.
Total 2002 2001, and 2000 other postretirement benefit costs of the domestic utility companies and System Energy, including amounts capitalized and deferred, included the following components (in thousands):components:
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| System | |
|
| (In Thousands) | ||||||||||
Service cost - benefits earned |
|
|
|
|
|
|
|
|
|
|
|
|
Interest cost on APBO |
| 10,075 |
| 11,050 |
| 6,641 |
| 3,222 |
| 3,204 |
| 1,430 |
Expected return on assets |
| (6,210) |
| (4,995) |
| - |
| (2,554) |
| (2,263) |
| (1,362) |
Amortization of transition |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
| 27 |
| - |
| 98 |
| 16 |
| 38 |
| (361) |
Recognized net loss |
| 3,937 |
| 1,620 |
| 2,003 |
| 1,503 |
| 522 |
| 358 |
Net other postretirement benefit |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| System |
|
| (In Thousands) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |
Service cost - benefits earned |
|
|
|
|
|
|
|
|
|
|
|
|
Interest cost on APBO |
| 10,637 |
| 11,314 |
| 6,780 |
| 3,459 |
| 3,436 |
| 1,352 |
Expected return on assets |
| (4,859) |
| (4,349) |
| - |
| (2,186) |
| (2,010) |
| (1,088) |
Amortization of transition |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
| 143 |
| 163 |
| 82 |
| 51 |
| 52 |
| (140) |
Recognized net loss |
| 3,497 |
| 1,575 |
| 1,496 |
| 1,160 |
| 475 |
| 350 |
Curtailment loss | 9,276 | 6,301 | 5,041 | 1,259 | 996 | 2,524 | ||||||
Special termination benefits | 794 | 512 | 452 | 73 | 28 | 284 | ||||||
Net other postretirement benefit |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| System |
|
| (In Thousands) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |
Service cost - benefits earned |
|
|
|
|
|
|
|
|
|
|
|
|
Interest cost on APBO |
| 9,448 |
| 9,734 |
| 6,242 |
| 3,099 |
| 3,264 |
| 1,150 |
Expected return on assets |
| (3,889) |
| (4,232) |
| - |
| (2,088) |
| (1,959) |
| (1,023) |
Amortization of transition |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
| 245 |
| 278 |
| 141 |
| 87 |
| 89 |
| 24 |
Recognized net (gain)/loss |
| 873 |
| 135 |
| 75 |
| 335 |
| (55) |
| 11 |
Net other postretirement benefit |
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement Benefit Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet as of December 31, 2004 and 2003:
| Entergy | Entergy | Entergy | Entergy | Entergy | System | ||||||
(In Thousands) | ||||||||||||
Change in APBO | ||||||||||||
Balance at 12/31/03 | $187,259 | $194,205 | $112,675 | $57,786 | $55,062 | $25,466 | ||||||
Service cost | 3,860 | 5,328 | 2,371 | 1,213 | 662 | 1,389 | ||||||
Interest cost | 10,075 | 11,050 | 6,641 | 3,222 | 3,204 | 1,430 | ||||||
Actuarial loss | 10,714 | 9,086 | 8,175 | 6,787 | 3,624 | 1,441 | ||||||
Benefits paid | (15,964) | (13,832) | (9,843) | (5,307) | (5,967) | (1,719) | ||||||
Plan amendments (a) | (18,279) | (6,406) | (5,546) | (6,894) | (2,582) | (1,125) | ||||||
Plan participant contributions | 1,693 | 1,833 | 1,323 | 771 | 846 | 20 | ||||||
Balance at 12/31/04 | 179,358 | 201,264 | 115,796 | 57,578 | 54,849 | 26,902 | ||||||
Change in Plan Assets | ||||||||||||
Fair value of assets at 12/31/03 | $68,876 | $59,511 | $- | $28,932 | $33,158 | $16,821 | ||||||
Actual return on plan assets | 5,657 | 4,773 | - | 2,154 | 2,340 | 1,495 | ||||||
Employer contributions | 16,729 | 14,540 | 8,520 | 5,521 | 4,870 | 4,691 | ||||||
Plan participant contributions | 1,693 | 1,833 | 1,323 | 771 | 846 | 20 | ||||||
Benefits paid | (15,964) | (13,832) | (9,843) | (5,307) | (5,967) | (1,719) | ||||||
Fair value of assets at 12/31/04 | $76,991 | $66,825 | $- | $32,071 | $35,247 | $21,308 | ||||||
Funded status | ($102,367) | ($134,439) | ($115,796) | ($25,507) | ($19,602) | ($5,594) | ||||||
Amounts not yet recognized | ||||||||||||
in the balance sheet | ||||||||||||
Unrecognized transition obligation | 6,567 | 30,310 | 3,057 | 2,810 | 13,929 | 119 | ||||||
Unrecognized prior service cost | (4,013) | - | 919 | (1,015) | 418 | (2,805) | ||||||
Unrecognized net loss | 79,185 | 57,089 | 44,723 | 28,429 | 15,620 | 9,699 | ||||||
Prepaid/(accrued) postretirement benefit cost recognized in the |
|
|
|
|
|
|
(a) | Reflects plan design changes, including a change in participation assumption for certain bargaining employees at Entergy Arkansas and Entergy Mississippi, effective January 1, 2004. |
| Entergy | Entergy | Entergy | Entergy | Entergy | System | ||||||
(In Thousands) | ||||||||||||
Change in APBO | ||||||||||||
Balance at 12/31/02 | $164,258 | $167,678 | $107,398 | $53,398 | $54,646 | $21,410 | ||||||
Service cost | 6,560 | 5,701 | 3,322 | 1,866 | 948 | 1,553 | ||||||
Interest cost | 10,637 | 11,314 | 6,780 | 3,459 | 3,436 | 1,352 | ||||||
Actuarial loss | 20,340 | 24,731 | 13,445 | 6,004 | 4,536 | 3,104 | ||||||
Benefits paid | (11,523) | (11,411) | (7,816) | (4,040) | (4,761) | (616) | ||||||
Plan amendments (a) | (14,561) | (11,479) | (16,862) | (4,659) | (5,146) | (4,260) | ||||||
Plan participant contributions | 1,905 | 1,663 | 1,126 | 604 | 750 | 78 | ||||||
Curtailment loss | 8,849 | 5,496 | 4,830 | 1,081 | 625 | 2,561 | ||||||
Special termination benefits | 794 | 512 | 452 | 73 | 28 | 284 | ||||||
Balance at 12/31/03 | $187,259 | $194,205 | $112,675 | $57,786 | $55,062 | $25,466 | ||||||
Change in Plan Assets | ||||||||||||
Fair value of assets at 12/31/02 | $49,076 | $50,001 | $- | $23,420 | $28,490 | $13,569 | ||||||
Actual return on plan assets | 6,290 | 6,587 | - | 2,979 | 2,614 | 1,475 | ||||||
Benefits paid | (11,523) | (11,411) | (7,816) | (4,040) | (4,761) | (616) | ||||||
Employer contributions | 23,128 | 12,671 | 6,690 | 5,969 | 6,065 | 2,315 | ||||||
Plan participant contributions | 1,905 | 1,663 | 1,126 | 604 | 750 | 78 | ||||||
Fair value of assets at 12/31/03 | $68,876 | $59,511 | $- | $28,932 | $33,158 | $16,821 | ||||||
Funded status | ($118,383) | ($134,694) | ($112,675) | ($28,854) | ($21,904) | ($8,645) | ||||||
Amounts not yet recognized | ||||||||||||
in the balance sheet | ||||||||||||
Unrecognized transition obligation | 21,928 | 41,305 | 10,822 | 9,136 | 19,088 | 134 | ||||||
Unrecognized prior service cost | - | - | - | - | - | (2,040) | ||||||
Unrecognized net loss | 71,855 | 49,401 | 38,551 | 22,745 | 12,595 | 8,748 | ||||||
Prepaid/(accrued) postretirement | ||||||||||||
benefit cost recognized in the | ||||||||||||
balance sheet | ($24,600) | ($43,988) | ($63,302) | $3,027 | $9,779 | ($1,803) |
(a) | Reflects plan design changes, including a change in the participation assumption for non-bargaining employees effective August 1, 2003. |
Pension and Other Postretirement Plans' Assets
Entergy's pension and postretirement plans weighted-average asset allocations by asset category at December 31, 2004 and 2003 are as follows:
| Pension |
| Postretirement | ||||
| 2004 |
| 2003 |
| 2004 |
| 2003 |
|
|
|
|
|
|
|
|
Domestic Equity Securities | 46% |
| 56% |
| 38% |
| 37% |
International Equity Securities | 21% |
| 14% |
| 14% |
| 0% |
Fixed Income Securities | 31% |
| 28% |
| 47% |
| 60% |
Other | 2% |
| 2% |
| 1% |
| 3% |
Entergy'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 funded statusmix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense.
In the optimization study, Entergy formulates assumptions (or hires a consultant to provide such analysis) about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes. The future market assumptions used in the optimization study are determined by examining historical market characteristics of the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period.
The optimization analysis utilized in Entergy's latest study produced the following approved asset class target allocations.
| Pension |
| Postretirement |
|
|
|
|
Domestic Equity Securities | 45% |
| 37% |
International Equity Securities | 20% |
| 14% |
Fixed Income Securities | 31% |
| 49% |
Other (Cash and GACs) | 4% |
| 0% |
These allocation percentages combined with each asset class' expected investment return produced an aggregate return expectation for the five years following the study of 7.6% for pension assets, 5.4% for taxable postretirement assets, and 7.2% for non-taxable postretirement assets. These returns are not inconsistent with Entergy's disclosed expected pre-tax return on assets of 8.5% over the life of the respective liabilities.
Since precise allocation targets are inefficient to manage security investments, the following ranges were established to produce an acceptable economically efficient plan to manage to targets:
Pension | Postretirement | ||
Domestic Equity Securities | 45% to 55% | 32% to 42% | |
International Equity Securities | 15% to 25% | 9% to 19% | |
Fixed Income Securities | 25% to 35% | 44% to 54% | |
Other | 0% to 10% | 0% to 5% |
Accumulated Pension Benefit Obligation
The accumulated benefit obligation for the domestic utility companies and System Entergy as December 31, 2004 and 2003 was:
|
| December 31, | ||
|
| 2004 |
| 2003 |
|
| (In Thousands) | ||
Entergy Arkansas |
| $558,283 |
| $509,382 |
Entergy Gulf States |
| $449,986 |
| $426,320 |
Entergy Louisiana |
| $341,681 |
| $309,066 |
Entergy Mississippi |
| $189,119 |
| $174,245 |
Entergy New Orleans |
| $69,202 |
| $59,610 |
System Energy |
| $79,641 |
| $64,661 |
Estimated Future Benefit Payments
Based upon the assumptions used to measure the company's pension and postretirement benefit obligation at December 31, 2004, and including pension and postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid over the next ten years will be as follows:
Estimated Future | Entergy | Entergy | Entergy | Entergy | Entergy | System | ||||||
(In Thousands) | ||||||||||||
Year(s) | ||||||||||||
2005 | $34,240 | $26,852 | $21,707 | $12,630 | $3,634 | $1,764 | ||||||
2006 | $34,660 | $27,037 | $21,790 | $12,771 | $3,648 | $1,783 | ||||||
2007 | $35,332 | $27,358 | $21,956 | $13,000 | $3,676 | $1,814 | ||||||
2008 | $36,266 | $27,885 | $22,290 | $13,326 | $3,731 | $1,859 | ||||||
2009 | $37,674 | $28,718 | $22,840 | $13,821 | $3,823 | $1,927 | ||||||
2010 - 2014 | $227,605 | $167,679 | $130,644 | $82,964 | $21,870 | $11,552 |
Estimated Future | Entergy | Entergy | Entergy | Entergy | Entergy | System | ||||||
(In Thousands) | ||||||||||||
Year(s) | ||||||||||||
2005 | $13,588 | $12,638 | $8,528 | $4,127 | $4,565 | $1,311 | ||||||
2006 | $12,989 | $12,280 | $8,182 | $3,849 | $4,162 | $1,390 | ||||||
2007 | $13,362 | $12,901 | $8,402 | $3,993 | $4,268 | $1,464 | ||||||
2008 | $13,500 | $13,381 | $8,545 | $4,095 | $4,353 | $1,522 | ||||||
2009 | $13,707 | $13,808 | $8,642 | $4,133 | $4,443 | $1,620 | ||||||
2010 - 2014 | $67,855 | $74,755 | $43,297 | $22,011 | $21,774 | $9,788 |
Contributions
The domestic utility companies and System Energy expect to contribute the following to the pension and other postretirement plans in 2005:
Entergy | Entergy | Entergy | Entergy | Entergy | System | |||||||
(In Thousands) | ||||||||||||
Pension Contributions | $20,560 | $18,948 | $2,622 | $3,416 | $15,667 | $9,266 | ||||||
Other Postretirement |
|
|
|
|
|
|
Additional Information
The change in the minimum pension liability had no effect on other comprehensive income at the domestic utility companies and System Energy in 2004 or 2003. The change in the minimum pension liability included in regulatory assets at each of the domestic utility companies and System Energy's other postretirement benefit plansEnergy was as of December 31, 2002follows for 2004 and 2001 was (in thousands):2003:
Entergy Arkansas | Entergy Gulf States | Entergy | Entergy | Entergy | System | |||||||
(In Thousands) | ||||||||||||
2004 | $29,191 | $- | $34,112 | $13,820 | $4,865 | $370 | ||||||
2003 | $22,600 | $- | ($38,755) | ($3,446) | $7,395 | $7,061 |
Actuarial Assumptions
The assumed health care cost trend rate used in measuring the APBO of the domestic utility companies and System Energy was 10% for 2003,2005, gradually decreasing each successive year until it reaches 4.5% in 20092011 and beyond. The assumed health care cost trend rate used in measuring the Net Other Postretirement Benefit Cost of the domestic utility companies and System Energy was 10% for 2004, gradually decreasing each successive year until it reaches 4.5% in 2010 and beyond. A one percentage point change in the assumed health care cost trend rate for 20022004 would have the following effects (in thousands):effects:
|
| 1 Percentage Point Increase |
| 1 Percentage Point Decrease | ||||
2004 |
|
|
| Impact on the |
|
|
| Impact on the |
|
| Increase (Decrease) | ||||||
|
|
|
|
|
|
|
|
|
Entergy Arkansas |
| $14,980 |
| $1,548 |
| ($13,825) |
| ($1,378) |
Entergy Gulf States |
| $19,685 |
| $2,205 |
| ($17,932) |
| ($1,918) |
Entergy Louisiana |
| $9,930 |
| $1,021 |
| ($9,146) |
| ($907) |
Entergy Mississippi |
| $4,785 |
| $479 |
| ($4,418) |
| ($428) |
Entergy New Orleans |
| $3,998 |
| $362 |
| ($3,726) |
| ($327) |
System Energy |
| $3,152 |
| $448 |
| ($2,821) |
| ($384) |
The significant actuarial assumptions used in determining the pension PBO and the SFAS 106 APBO for 2002, 2001,2004, 2003, and 20002002 were as follows:
2004 |
| 2003 |
| 2002 | |
Weighted-average discount rate: |
|
|
|
|
|
Pension | 6.00% |
| 6.25% |
| 6.75% |
Other postretirement | 6.00% |
| 6.71% |
| 6.75% |
Weighted-average rate of increase |
|
|
|
|
|
Expected long-term rate of |
|
|
|
|
|
Taxable assets | 5.50% |
| 5.50% |
| 5.50% |
Non-taxable assets | 8.50% |
| 8.75% |
| 8.75% |
The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2004, 2003, and 2002 were as follows:
2004 |
| 2003 |
| 2002 | |
|
|
|
|
|
|
Weighted-average discount rate | |||||
Pension | 6.25% |
| 6.75% |
| 7.50% |
Other postretirement | 6.71% | 6.75% | 7.50% | ||
Weighted-average rate of increase |
|
|
|
|
|
Expected long-term rate of |
|
|
|
|
|
Taxable assets | 5.50% |
| 5.50% |
| 5.50% |
Non-taxable assets | 8.75% |
| 8.75% |
| 9.00% |
The domestic utility companies' and System Energy's remaining pension transition assets are being amortized over the greater of the remaining service period of active participants or 15 years ending in 2005, and itstheir SFAS 106 transition obligations are being amortized over 20 years.years ending in 2012.
Voluntary Severance Program
In the second half of 2003, the domestic utility companies and System Energy offered a voluntary severance program to certain groups of employees. As a result of this program, in the fourth quarter 2003 the domestic utility companies and System Energy recorded additional pension and postretirement costs (including amounts capitalized) of $53.9 million for special termination benefits and plan curtailment charges. These amounts are included in the net pension cost and net postretirement benefit cost for the year ended December 31, 2003.
Medicare Prescription Drug, Improvement and Modernization Act of 2003
In December 2003, the President signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 into law. The Act introduces a prescription drug benefit under Medicare (Part D), starting in 2006, as well as a federal subsidy to employers who provide a retiree prescription drug benefit that is at least actuarially equivalent to Medicare Part D. At December 2003, specific authoritative guidance on the accounting for the federal subsidy was pending. As allowed by Financial Accounting Standards Board Staff Position No. FAS 106-1, Entergy elected to record an estimate of the effects of the Act in accounting for its postretirement benefit plans at December 31, 2003, under SFAS 106 and in providing disclosures required by SFAS No. 132 (revised 2003), Employers' Disclosures about Pensions and Other Postretirement Benefits. At December 31, 2003, based on actuarial analysis of prescription drug benefits, estimated future Medicare subsidies were expected to reduce the Dec ember 31, 2003 Accumulated Postretirement Benefit Obligation by $56 million. For the year ended December 31, 2003 the impact of the Act on net postretirement benefit cost was immaterial, as it reflected only one month's impact of the Act.
In 2004, Entergy continued to record the expected effects of the Act in accounting for its postretirement benefit plans. In mid-2004, the Financial Accounting Standards Board issued Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which was effective for Entergy's June 30, 2004 interim reporting.
In August 2004, the Centers for Medicare and Medicaid Services issued proposed regulations to implement the new Medicare law. A ruling from the Centers for Medicare and Medicaid Services was issued in late January 2005 with final guidance expected later this year.
The actuarially estimated effect of future Medicare subsidies was as follows:
|
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| System |
|
| Arkansas |
| Gulf States |
| Louisiana |
| Mississippi |
| New Orleans |
| Energy |
|
| Increase (Decrease) | ||||||||||
Impact on 12/31/2003 APBO |
| ($28,824) |
| ($25,603) |
| ($16,194) |
| ($9,888) |
| ($8,035) |
| ($3,811) |
Impact on 12/31/2004 APBO |
| ($35,928) |
| ($31,846) |
| ($20,085) |
| ($12,227) |
| ($9,742) |
| ($4,982) |
Impact on 2004 other postretirement benefit cost |
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 12.11. RISK MANAGEMENT AND DERIVATIVES
Market and Commodity Risks
In the normal course of business, the domestic utility companies and System Energy are exposed to a number of market and commodity risks including power price risk, fuel price risk, foreign currency exchange rate risk, and equity price and interest rate risks. Market risk is the potential loss that the domestic utility companies and System Energy may incur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
The domestic utility companies and System Energy manage these risks through both contractual arrangements and derivatives. Contractual risk management tools include long-term power and fuel purchase agreements. The domestic utility companies and System Energy also use a variety of commodity and financial derivatives, including natural gas and electricity futures, forwards and options, and foreign currency forwards to manage the following risks:
Gains and losses realized from derivative transactions used to manage power and fuel price risk are included in fuel costs recovered through rates. Accordingly, these gains and losses are accounted for as regulatory assets and liabilities prior to transaction maturity. Power price risk is managed primarily through the purchase of short-term forward contracts that are accounted for as normal purchases. Any option premiums paid to manage power price risk are booked with an offsetting regulatory asset or liability. The volume of these purchases is based on Entergy's demand forecast.
Entergy manages fuel price risk for its Louisiana jurisdictions (Entergy Louisiana, Entergy New Orleans, and the Louisiana portion of Entergy Gulf States) and Entergy Mississippi primarily through the purchase of short-term swaps. These swaps are marked-to-market with offsetting regulatory assets or liabilities. The notional volumes of these swaps are based on a portion of projected purchases of gas for the summer (electric generation) and winter (gas distribution at Entergy Gulf States and Entergy New Orleans) peak seasons.
Entergy Gulf States manages foreign currency exchange rate risk associated with the acquisition of nuclear fuel through the purchase of forwards that are accounted for as cash flow hedges. The notional volumes of these forwards are based on forecasted purchases and the realized gain or loss from these forwards is included in the capitalized cost of the applicable batches of nuclear fuel.
There Gains totaling approximately $6.4 million were no forwardrealized during 2004 on the maturity of cash flow hedges. These realized gains resulted from foreign currency hedges related to Euro-denominated nuclear fuel acquisition contracts, at Entergy Gulf States that matured in 2002. During 2003, forward contracts with unrealizedand related gains of $2.8 million at December 31, 2002 will mature, at which time the final gain or loss on these contracts will belosses, when realized, are included in the capitalized cost of nuclear fuel. The maximum length of time over which Entergy Gulf States is currently hedging the variability in future cash flows for forecasted transactions (excluding interest rate swaps) at December 31, 2002 is approximately 18 months. The ineffective portion of the change in the value of Entergy Gulf States' cash flow hedges during 20022004 was insignificant. Entergy Gulf States has no outstanding cash flow hedges as of December 31, 2004.
NOTE 12. DECOMMISSIONING TRUST FUNDS
Entergy Arkansas
Entergy Arkansas holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held at December 31, 2004 and 2003 are summarized as follows:
2004 | Fair | Total | Total | |||
(In Millions) | ||||||
Equity | $189.5 | $66.6 | $1.6 | |||
Debt Securities | 194.3 | 4.3 | 1.9 | |||
Total | $383.8 | $70.9 | $3.5 | |||
2003 | ||||||
Equity | $168.3 | $47.2 | $- | |||
Debt Securities | 192.2 | 7.0 | 1.2 | |||
Total | $360.5 | $54.2 | $1.2 |
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 at December 31, 2004:
Equity Securities | Debt Securities | |||||||
Fair | Gross | Fair | Gross | |||||
(In Millions) | ||||||||
Less than 12 months | $0.7 | $- | $87.4 | $1.6 | ||||
More than 12 months | 12.2 | 1.6 | 12.2 | 0.3 | ||||
Total | $12.9 | $1.6 | $99.6 | $1.9 |
The fair value of debt securities, summarized by contractual maturities, at December 31, 2004 is as follows:
Fair | ||
(In Millions) | ||
less than 1 year | $32.5 | |
1 year - 5 years | 128.3 | |
5 years - 10 years | 30.2 | |
10 years - 15 years | 3.3 | |
15 years - 20 years | - | |
20 years+ | - | |
Total | $194.3 |
During the year ended December 31, 2004, the proceeds from the dispositions of securities amounted to $1.7 million with gross gains of $17,098 and gross losses of $18,274.
Entergy Gulf States
Entergy Gulf States holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held at December 31, 2004 and 2003 are summarized as follows:
2004 | Fair | Total | Total | |||
(In Millions) | ||||||
Equity | $138.1 | $20.4 | $0.8 | |||
Debt Securities | 152.9 | 8.8 | 0.2 | |||
Total | $291.0 | $29.2 | $1.0 | |||
2003 | ||||||
Equity | $119.4 | $8.0 | $0.2 | |||
Debt Securities | 148.5 | 10.4 | 1.0 | |||
Total | $267.9 | $18.4 | $1.2 |
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 at December 31, 2004:
Equity Securities | Debt Securities | |||||||
Fair | Gross | Fair | Gross | |||||
(In Millions) | ||||||||
Less than 12 months | $0.6 | $- | $10.0 | $0.1 | ||||
More than 12 months | 10.5 | 0.8 | 2.3 | 0.1 | ||||
Total | $11.1 | $0.8 | $12.3 | $0.2 |
The fair value of debt securities, summarized by contractual maturities, at December 31, 2004 is as follows:
Fair | ||
(In Millions) | ||
less than 1 year | $8.7 | |
1 year - 5 years | 42.0 | |
5 years - 10 years | 51.3 | |
10 years - 15 years | 37.7 | |
15 years - 20 years | 11.0 | |
20 years+ | 2.2 | |
Total | $152.9 |
During the year ended December 31, 2004, the proceeds from the dispositions of securities amounted to $2.9 million with gross gains of $790 and gross losses of $98,852.
Entergy Louisiana
Entergy Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held at December 31, 2004 and 2003 are summarized as follows:
2004 | Fair | Total | Total | |||
(In Millions) | ||||||
Equity | $92.5 | $17.1 | $2.5 | |||
Debt Securities | 79.6 | 2.8 | 0.8 | |||
Total | $172.1 | $19.9 | $3.3 | |||
2003 | ||||||
Equity | $74.6 | $6.0 | $- | |||
Debt Securities | 77.4 | 3.3 | 0.1 | |||
Total | $152.0 | $9.3 | $0.1 |
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows at December 31, 2004:
Equity Securities | Debt Securities | |||||||
Fair | Gross | Fair | Gross | |||||
(In Millions) | ||||||||
Less than 12 months | $0.3 | $- | $28.9 | $0.6 | ||||
More than 12 months | 15.5 | 2.5 | 8.2 | 0.2 | ||||
Total | $15.8 | $2.5 | $37.1 | $0.8 |
The fair value of debt securities, summarized by contractual maturities, at December 31, 2004 is as follows:
Fair | ||
(In Millions) | ||
less than 1 year | $38.8 | |
1 year - 5 years | 17.6 | |
5 years - 10 years | 12.4 | |
10 years - 15 years | 4.8 | |
15 years - 20 years | 6.0 | |
20 years+ | - | |
Total | $79.6 |
During the year ended December 31, 2004, the proceeds from the dispositions of securities amounted to $4.3 million with gross gains of $244,250 and gross losses of $25,882.
System Energy
System Energy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held at December 31 2004 and 2003 are summarized as follows:
2004 | Fair | Total | Total | |||
(In Millions) | ||||||
Equity | $127.0 | $15.0 | $7.2 | |||
Debt Securities | 78.1 | 1.9 | 0.6 | |||
Total | $205.1 | $16.9 | $7.8 | |||
2003 | ||||||
Equity | $103.4 | $5.5 | $9.9 | |||
Debt Securities | 69.5 | 2.6 | 0.3 | |||
Total | $172.9 | $8.1 | $10.2 |
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 at December 31, 2004:
Equity Securities | Debt Securities | |||||||
Fair | Gross | Fair | Gross | |||||
(In Millions) | ||||||||
Less than 12 months | $0.4 | $- | $40.4 | $0.5 | ||||
More than 12 months | 50.4 | 7.2 | 2.0 | 0.1 | ||||
Total | $50.8 | $7.2 | $42.4 | $0.6 |
The fair value of debt securities, summarized by contractual maturities, at December 31, 2004 is as follows:
Fair | ||
(In Millions) | ||
less than 1 year | $4.8 | |
1 year - 5 years | 22.4 | |
5 years - 10 years | 30.0 | |
10 years - 15 years | 7.9 | |
15 years - 20 years | 6.9 | |
20 years+ | 6.1 | |
Total | $78.1 |
During the year ended December 31, 2004, the proceeds from the dispositions of securities amounted to $7.5 million and gross gains of $32,362 and gross losses of $58,755.
Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy
Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy evaluate unrealized gains and losses at the end of each period to determine whether an other than temporary impairment has occurred. This analysis considers the length of time that a security has been in a loss position, the current performance of that security, and whether decommissioning costs are recovered in rates. No significant impairments were recorded in 2004 and 2003 as a result of these evaluations.
Due to the regulatory treatment of decommissioning collections and trust fund earnings, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy record regulatory assets or liabilities for unrealized gains and losses on trust investments. For the unregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains or losses in other deferred credits.
NOTE 13. TRANSACTIONS WITH AFFILIATES (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
Each domestic utility company purchases electricity from and sells electricity to the other domestic utility companies, and System Energy and Entergy Power (in the case of Entergy Arkansas) under rate schedules filed with FERC. In addition, theThe domestic utility companies and System Energy purchase fuel from System Fuels; receive management, technical, advisory, operating, and administrative services from Entergy Services; and receive management, technical, and operating services from Entergy Operations. Pursuant to SEC rules under PUHCA and the Federal Power Act, these transactions are on an "at cost" basis,basis. In addition, Entergy Power sells electricity to Entergy Arkansas, Entergy Louisiana, and are eliminated in the consolidated financial statements of Entergy.Entergy New Orleans, and RS Cogen sells electricity to Entergy Louisiana and Entergy New Orleans.
As described in Note 1 to the domestic utility companies and System Energy financial statements, all of System Energy's operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
Additionally, as described in Note 4 to the domestic utility companies and System Energy financial statements, the domestic utility companies and System Energy participate in the Entergy System Money PoolEntergy's money pool and earn interest income from the Money Pool.money pool. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also receive interest income from System Fuels, Inc.
The tables below contain the various affiliate transactions amongof the domestic utility companies, and System Energy, (in millions).and other Entergy affiliates.
Intercompany Revenues
Entergy | Entergy | Entergy | Entergy | Entergy | System | |
2002 | $ 172.6 | $28.8 | $ 8.8 | $ 70.6 | $ 7.1 | $ 602.5 |
2001 | $ 250.2 | $75.2 | $ 26.1 | $ 118.3 | $ 10.0 | $ 535.0 |
2000 | $ 255.3 | $93.7 | $ 20.8 | $ 88.1 | $ 31.6 | $ 656.7 |
|
| Entergy |
| Entergy |
| Entergy | | Entergy |
| Entergy |
| System |
|
| (In Millions) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
| $256.8 |
| $52.5 |
| $96.6 |
| $47.6 |
| $117.8 |
| $545.4 |
2003 |
| $242.3 |
| $42.8 |
| $102.4 |
| $27.6 |
| $85.5 |
| $583.8 |
2002 |
| $172.6 |
| $28.8 |
| $8.8 |
| $70.6 |
| $7.1 |
| $602.5 |
Intercompany Operating Expenses
| Entergy | Entergy | Entergy | Entergy | Entergy | System |
2002 | $ 284.6 | $211.1 | $ 277.3 | $298.6 | $166.7 | $ 11.7 |
2001 | $ 262.9 | $274.8 | $ 298.1 | $535.2 | $ 231.7 | $ 9.5 |
2000 | $ 387.9 | $239.4 | $ 388.5 | $388.2 | $ 177.0 | $ 10.1 |
|
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| System |
|
|
|
| (In Millions) | ||||||||
|
| (1) |
|
|
| (2) |
|
|
| (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
| $467.5 |
| $558.2 |
| $491.8 |
| $484.4 |
| $228.4 |
| $109.4 |
2003 |
| $460.6 |
| $438.6 |
| $444.6 |
| $458.6 |
| $211.2 |
| $118.0 |
2002 |
| $456.7 |
| $321.2 |
| $389.7 |
| $298.6 |
| $166.7 |
| $109.0 |
Operating Expenses Paid or Reimbursed to Entergy Operations
Entergy | Entergy | Entergy | System | |
2002 | $ 172.1 | $110.1 | $ 112.4 | $97.3 |
2001 | $ 141.4 | $102.7 | $ 104.6 | $75.8 |
2000 | $ 163.0 | $116.0 | $ 113.2 | $92.6 |
(1) | Includes $2.3 million in 2004, $0.1 million in 2003, and $0.7 million in 2002 for power purchased from Entergy Power. |
(2) | Includes power purchased from Entergy Power and RS Cogen LLC in 2004 of $9.1 million and $33.0 million, respectively, and in 2003 of $5.9 million and $19.1 million, respectively. |
(3) | Includes power purchased from Entergy Power and RS Cogen LLC in 2004 of $9.0 million and $10.6 million, respectively, and in 2003 of $5.7 million and $6.9 million, respectively. |
Intercompany Interest Income
Entergy | Entergy | Entergy | Entergy | Entergy | System | |
2002 | $ 1.0 | $ 0.3 | $ 0.7 | $ 0.4 | $ 0.2 | $ 0.9 |
2001 | $ 0.8 | $ 0.5 | $ 2.2 | $ 0.5 | $ 0.3 | $ 6.3 |
2000 | $ 1.5 | $ 0.6 | $ 2.0 | $ 0.9 | $ 0.4 | $ 6.9 |
|
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| System |
|
| (In Millions) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
| $0.6 |
| $0.4 |
| $1.1 |
| $0.6 |
| $0.2 |
| $0.6 |
2003 |
| $0.6 |
| $0.4 |
| $1.2 |
| $0.3 |
| $0.2 |
| $0.1 |
2002 |
| $1.0 |
| $0.3 |
| $0.7 |
| $0.4 |
| $0.2 |
| $0.9 |
NOTE 14. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
The business of the domestic utility companies and System Energy is subject to seasonal fluctuations with the peak periods occurring during the third quarter. Operating results for the four quarters of 20022004 and 20012003 were:
Operating Revenue
Entergy Arkansas | Entergy Gulf States | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | System Energy |
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| System | |
(In Thousands) |
| (In Thousands) | ||||||||||||||||
2002: | ||||||||||||||||||
2004: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||
First Quarter | $377,823 | $463,904 | $369,963 | $191,690 | $102,947 | $142,330 |
| $363,461 |
| $638,996 |
| $488,046 |
| $236,829 |
| $169,767 |
| $127,168 |
Second Quarter | 367,926 | 567,563 | 483,389 | 261,743 | 121,422 | 142,892 |
| $405,509 |
| $685,313 |
| $555,511 |
| $289,573 |
| $186,337 |
| $132,720 |
Third Quarter | 474,873 | 648,849 | 528,052 | 316,745 | 157,417 | 156,930 |
| $481,103 |
| $840,630 |
| $668,240 |
| $390,337 |
| $200,036 |
| $144,052 |
Fourth Quarter | 340,488 | 503,563 | 433,948 | 220,917 | 126,088 | 160,334 |
| $403,072 |
| $717,445 |
| $515,189 |
| $296,890 |
| $179,728 |
| $141,441 |
2001: | ||||||||||||||||||
2003: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||
First Quarter | $393,800 | $734,476 | $548,914 | $256,158 | $204,015 | $151,166 |
| $362,749 |
| $584,354 |
| $462,361 |
| $227,369 |
| $140,907 |
| $141,985 |
Second Quarter | 453,108 | 730,893 | 547,784 | 274,148 | 160,309 | 152,902 |
| $394,884 |
| $700,635 |
| $569,580 |
| $261,899 |
| $154,065 |
| $144,764 |
Third Quarter | 541,556 | 714,488 | 473,342 | 354,518 | 167,137 | 66,276 |
| $469,925 |
| $777,182 |
| $646,503 |
| $309,739 |
| $203,751 |
| $141,239 |
Fourth Quarter | 388,312 | 468,703 | 331,873 | 208,917 | 99,389 | 164,683 |
| $362,112 |
| $577,566 |
| $487,126 |
| $236,353 |
| $155,293 |
| $155,832 |
Operating Income (Loss)
Entergy Arkansas | Entergy Gulf States | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | System Energy |
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| System | |
(In Thousands) |
| (In Thousands) | ||||||||||||||||
2002: | ||||||||||||||||||
2004: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||
First Quarter | $55,731 | $74,486 | $75,888 | $16,928 | $(1,675) | $59,940 |
| $48,566 |
| $88,312 |
| $48,318 |
| $22,724 |
| $15,487 |
| $57,767 |
Second Quarter | 69,394 | 133,741 | 134,481 | 29,253 | 13,151 | 59,122 |
| $80,669 |
| $101,832 |
| $84,357 |
| $42,157 |
| $22,880 |
| $59,585 |
Third Quarter | 138,887 | 125,543 | 108,837 | 50,451 | 19,283 | 65,014 |
| $123,910 |
| $127,838 |
| $87,130 |
| $52,003 |
| $24,450 |
| $59,601 |
Fourth Quarter | 38,197 | 17,960 | (2,564) | 10,134 | (13,409) | 65,058 |
| $40,590 |
| $41,437 |
| $41,710 |
| $29,730 |
| ($4,878) |
| $56,181 |
2001: | ||||||||||||||||||
2003: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||
First Quarter | $71,647 | $126,182 | $39,267 | $14,524 | $4,218 | $60,594 |
| $67,130 |
| $75,693 |
| $89,362 |
| $30,096 |
| ($1,887) |
| $55,739 |
Second Quarter | 104,118 | 111,562 | 88,913 | 31,647 | 9,373 | 61,281 |
| $92,939 |
| $99,150 |
| $91,304 |
| $44,625 |
| $17,311 |
| $54,029 |
Third Quarter | 163,538 | 118,201 | 192,528 | 34,302 | 2,653 | 83,906 |
| $135,790 |
| $146,063 |
| $108,232 |
| $53,173 |
| $28,230 |
| $65,791 |
Fourth Quarter | 40,387 | 41,247 | 3,922 | 9,839 | (9,194) | 64,673 |
| $1,330 |
| ($13,136) |
| $13,325 |
| $13,753 |
| ($15,736) |
| $62,853 |
Net Income (Loss)
|
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| Entergy |
| System |
|
| (In Thousands) | ||||||||||
2004: |
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
| $19,276 |
| $41,728 |
| $21,211 |
| $8,637 |
| $7,114 |
| $24,664 |
Second Quarter |
| $43,277 |
| $55,591 |
| $43,713 |
| $20,808 |
| $12,319 |
| $25,532 |
Third Quarter |
| $67,944 |
| $82,456 |
| $45,496 |
| $27,873 |
| $13,189 |
| $27,505 |
Fourth Quarter |
| $11,713 |
| $12,489 |
| $17,075 |
| $16,179 |
| ($4,550) |
| $28,247 |
2003: |
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
| $27,145 |
| $11,792(a) |
| $43,807 |
| $12,316 |
| ($4,327) |
| $23,735 |
Second Quarter |
| $47,537 |
| ($20,124) |
| $45,713 |
| $22,350 |
| $9,580 |
| $22,820 |
Third Quarter |
| $69,319 |
| $82,283 |
| $57,863 |
| $25,804 |
| $14,118 |
| $28,515 |
Fourth Quarter |
| ($17,992) |
| ($31,389) |
| ($1,229) |
| $6,588 |
| ($11,512) |
| $30,933 |
Entergy Arkansas | Entergy Gulf States | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | System Energy | |
(In Thousands) | ||||||
2002: | ||||||
First Quarter | $22,838 | $28,038 | $29,494 | $5,829 | $(3,940) | $26,727 |
Second Quarter | 19,247 | 65,236 | 75,845 | 12,752 | 3,199 | 25,250 |
Third Quarter | 74,664 | 64,489 | 50,063 | 26,213 | 9,307 | 25,640 |
Fourth Quarter | 18,894 | 16,315 | (10,693) | 7,614 | (8,796) | 25,735 |
2001: | ||||||
First Quarter | $28,978 | $59,046 | $6,859 | $4,535 | $474 | $20,798 |
Second Quarter | 47,038 | 51,382 | 37,034 | 15,673 | 3,369 | 21,202 |
Third Quarter | 82,401 | 52,353 | 101,515 | 18,748 | (308) | 37,793 |
Fourth Quarter | 19,768 | 16,663 | (12,858) | 664 | (5,730) | 36,562 |
(a) | Entergy Gulf States' net income before the cumulative effect of accounting change for the first quarter of 2003 was $33,125. |
Item 2.Properties
Information regarding the registrant's properties is included in Part I. Item 1. - Business under the sections titled "Property""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 20022004 are discussed in Part I. Item 1. - Business under the sections titled "Rate Matters""Retail Rate Regulation", "Environmental Regulation""Wholesale Rate Matters","Environmental Regulation", and "Litigation"and"Litigation" in this report.
Item 4.Submission of Matters to a Vote of Security Holders
During the fourth quarter of 2002,2004, no matters were submitted to a vote of the security holders of Entergy Corporation.Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy Resources.
DIRECTORS AND EXECUTIVE OFFICERS OF ENTERGY CORPORATION
Directors
Information required by this item concerning directors of Entergy Corporation is set forth under the heading "Proposal 1--Election of Directors" contained in the Proxy Statement of Entergy Corporation, (the "Proxy Statement"), to be filed in connection with its Annual Meeting of Stockholders to be held May 9, 2003,13, 2005, ("Annual Meeting"), and is incorporated herein by reference. Information required by this item concerning officers and directors of the remaining registrants is reported in Part III of this document.
Executive Officers
Name | Age | Position | Period | |
J. Wayne Leonard (a) |
| Chief Executive Officer and Director of Entergy Corporation |
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| 1999-Present | |||
Richard J. Smith (a) |
| Group President, Utility Operations of Entergy Corporation, | 2001-Present | |
Director of Entergy Arkansas, Entergy Gulf States, Entergy | 2001-Present | |||
Senior Vice President, Transition Management of Entergy | 2000-2001 | |||
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Leo P. Denault (a) | 45 | Executive Vice President and Chief Financial Officer of | 2004-Present | |
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Vice President , Corporate Development and Strategic |
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Curtis L. Hebert, Jr. (a) |
| Executive Vice President, External Affairs of Entergy | 2001-Present | |
Chairman and Commissioner of the Federal Energy | 1997-2001 |
Mark T. Savoff (a) | 48 | Executive Vice President of Entergy Corporation | 2004-Present | |
|
| |||
Executive Vice President of Entergy Services, Inc. | 2003-Present | |||
President, General Electric Power Systems - | 2000-2003 | |||
|
| Executive Vice President, General Counsel and Secretary of |
| |
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Vice President, |
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Nathan E. Langston (a) |
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Vice President and Chief Accounting Officer of Entergy | 1998-2001 | |||
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Senior Vice President & Chief Human Resources Officer, | 2000-2001 | |||
President, US Region and Vice President, Global Human | 1997-2000 | |||
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Each officer of Entergy Corporation is elected yearly by the Board of Directors.
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, Chicago Stock, and Pacific Exchanges under the ticker symbol ETR.
Entergy Corporation's stock price as of February 28, 20032005 was $45.55.$69.12. The high and low prices of Entergy Corporation's common stock for each quarterly period in 20022004 and 20012003 were as follows:
2002 | 2001 | 2004 | 2003 | |||||||||||
High | Low | High | Low | High | Low | High | Low | |||||||
(In Dollars) | (In Dollars) | |||||||||||||
First | 43.88 | 38.25 | 42.88 | 32.56 | 60.20 | 56.01 | 49.55 | 42.26 | ||||||
Second | 46.85 | 41.05 | 44.67 | 36.82 | 59.92 | 50.64 | 54.38 | 45.90 | ||||||
Third | 44.95 | 32.12 | 40.95 | 33.60 | 61.98 | 54.43 | 54.99 | 47.75 | ||||||
Fourth | 46.42 | 36.80 | 39.50 | 35.10 | 68.67 | 60.08 | 57.24 | 51.06 |
Consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in 20022004 and 2001.2003. In 2002,2004, dividends of $0.33$0.45 per share were paid in the first three quarters, and a dividend of $0.35$0.54 per share was paid in the fourth quarter. In 2001,2003, dividends of $0.315$0.35 per share were paid in the first threeand second quarters, and a dividenddividends of $0.33$0.45 per share waswere paid in the third and fourth quarter.
Entergy has two plans that grant stock options, equity awards, and incentive awards to key employees of the Entergy subsidiaries. The Equity Ownership Plan is a shareholder-approved stock-based compensation plan. The Equity Awards Plan is a Board-approved stock-based compensation plan. The following table summarizes information about Entergy's stock options awarded under these plans.
Number of Securities to be Issued Upon Exercise of Outstanding Options Equity Ownership Plan 3,963,349 $ 34.96 8,614,275 Equity Awards Plan 15,979,765 36.07 5,671,792 Total 19,943,114 $ 35.85 14,286,067
Plan
Weighted Average Exercise Price
Number of Securities Remaining Available for Future Issuance
quarters.
As of February 28, 2003,2005, there were 57,06251,561 stockholders of record of Entergy Corporation.
Entergy Corporation's future ability to pay dividends is discussed in Note 87 to the consolidated financial statements. In addition to the restrictions described in Note 8,7, PUHCA provides that, without approval of the SEC, the unrestricted, undistributed retained earnings of any Entergy Corporation subsidiary are not available for distribution to Entergy Corporation's common stockholders until such earnings are made available to Entergy Corporation through the declaration of dividends by such subsidiaries.
Unregistered Sales of Equity Securities and Use Of Proceeds
Issuer Purchases of Equity Securities (1)
Period |
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10/01/2004-10/31/2004 |
| 2,135,000 |
| $62.05 |
| 2,135,000 |
| $1,293,054,803 |
11/01/2004-11/30/2004 |
| 2,931,000 |
| $65.55 |
| 2,931,000 |
| $1,124,355,785 |
12/01/2004-12/31/2004 |
| 4,183,800 |
| $66.24 |
| 4,183,800 |
| $999,999,962(2) |
Total |
| 9,249,800 |
| $65.04 |
| 9,249,800 |
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(1) | In accordance with Entergy's stock-based compensation plans, Entergy periodically grants stock options to its 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. See Note 7 to the consolidated financial statements for additional discussion of the stock-based compensation plan. Entergy's management has been authorized to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans, and this authorization does not have an expiration date. In August 2004, Entergy announced a program under which Entergy Corporation will repurchase up to $1.5 billion of its common stock. The program extends through the end of 2006. This repurchase program is incremental to the existing authority to repurchase shares to fund the exercise of employee stock options. The amount of repurchases under the program may vary as a result of material changes in business results or capital spending, or as a result of material new investment opportunities. |
(2) | Maximum amount of shares that may yet be repurchased relates only to the $1.5 billion plan and 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 Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, 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 domestic utility companies and System Energy to Entergy Corporation during 20022004 and 2001,2003, were as follows:
2002 | 2001 | 2004 | 2003 | |||
(In Millions) | (In Millions) | |||||
Entergy Arkansas | $125.9 | $82.5 | $85.8 | $69.6 | ||
Entergy Gulf States | $91.2 | $83.7 | $94.3 | $68.1 | ||
Entergy Louisiana | $271.4 | $134.6 | $116.5 | $145.5 | ||
Entergy Mississippi | $27.3 | $19.6 | $46.8 | $31.7 | ||
Entergy New Orleans | $0.8 | $5.2 | $3.0 | |||
System Energy | $101.8 | $119.1 | $104.6 | $105.0 |
Information with respect to restrictions that limit the ability of the domestic utility companies and System Energy to pay dividends is presented in Note 87 to the domestic utility companies and System Energy financial statements.
Item 6.Selected Financial Data
Refer to "SELECTED"SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., ENTERGY GULF STATES, INC.,ENTERGY LOUISIANA, INC., ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., 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"MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., ENTERGY GULF STATES,INC., ENTERGY LOUISIANA, INC., ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., and SYSTEM ENERGY RESOURCE,RESOURCES, INC."
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
Refer to "MANAGEMENT'S"MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS-Significant Factors and Known Trends - Market and Credit Risks OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., ENTERGY GULF STATES, INC., ENTERGY LOUISIANA, INC., ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., and SYSTEM ENERGY RESOURCES, INC."
Item 8.Financial Statements and Supplementary Data
Refer to "TABLE"TABLE OF CONTENTS - Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, 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, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, or System Energy.
Item 9A.Controls and Procedures
Disclosure Controls and Procedures
Internal Control Over Financial Reporting
The managements of PricewaterhouseCoopers, would have caused PricewaterhouseCoopers to make reference to the subject matter of the disagreement in connection with its reports.
Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy initially reportedResources (individually "Registrant" and collectively the change"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 accountantsaccordance 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, 2004. In making this assessment, each management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework.
Based on each management's assessment and the criteria set forth by COSO, each Registrant's management believes that each Registrant maintained effective internal control over financial reporting as of December 31, 2004.
The Registrants' registered public accounting firm has issued an attestation report on each management's assessment of each Registrant's 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
Entergy Corporation and Subsidiaries
New Orleans, Louisiana
We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that Entergy Corporation and Subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
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 accounting principles generally accepted in the United States of America. 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, management's assessment that Entergy Corporation and Subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Entergy Corporation and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 8, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Entergy Arkansas, Inc.
New Orleans, Louisiana
We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that Entergy Arkansas, Inc. (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
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 accounting principles generally accepted in the United States of America. 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, management's assessment that Entergy Arkansas, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Entergy Arkansas, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 8, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Entergy Gulf States, Inc.
New Orleans, Louisiana
We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that Entergy Gulf States, Inc. (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
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 accounting principles generally accepted in the United States of America. 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, management's assessment that Entergy Gulf States, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Entergy Gulf States, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 8, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Entergy Louisiana, Inc.
New Orleans, Louisiana
We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that Entergy Louisiana, Inc. (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
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 accounting principles generally accepted in the United States of America. 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, management's assessment that Entergy Louisiana, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Entergy Louisiana, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 8, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Entergy Mississippi, Inc.
New Orleans, Louisiana
We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that Entergy Mississippi, Inc. (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
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 accounting principles generally accepted in the United States of America. 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, management's assessment that Entergy Mississippi, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Entergy Mississippi, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 8, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Entergy New Orleans, Inc.
New Orleans, Louisiana
We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that Entergy New Orleans, Inc. (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
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 accounting principles generally accepted in the United States of America. 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, management's assessment that Entergy New Orleans, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Entergy New Orleans, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 8, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
System Energy Resources, Inc.
New Orleans, Louisiana
We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that System Energy Resources, Inc. (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
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 accounting principles generally accepted in the United States of America. 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, management's assessment that System Energy Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, System Energy Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 8, 2005
Item 9B.Other Information
On March 9, 2005 Entergy Corporation borrowed $15 million under its $965 million, 3-year credit facility, dated as of May 13, 2004, among Entergy Corporation, Citibank, N.A., as Administrative Agent and LC Issuing Bank, ABN AMRO Bank, N.V., as LC Issuing Bank, and several banks party thereto (the 3-Year Facility). Entergy Corporation described material terms of the 3-Year Facility in its Report on Form 8-K on August 13, 2001. The Form 8-K contained a letter from PricewaterhouseCoopers10-Q for the quarterly period ended June 30, 2004, and filed the agreement as Exhibit 4(d).
In addition to the Securities3-Year Facility, Entergy Corporation also maintains (i) a $500 million, 5-year credit facility, dated as of December 14, 2004, among Entergy Corporation, Citibank, N.A., as bank and Exchange Commission stating that it agreed withadministrative agent, and several banks party thereto (the 5-Year Facility); and (ii) Credit Agreements, dated as of May 31, 2002 and November 24, 2003, among Entergy Corporation, Bayerische Hypo-und Vereinsbank AG, New York Branch, as Bank, and Bayerische Hypo-und Vereinsbank AG, New York Branch, as Administrative Agent (the Hypo Term Loans). The table below includes the statements concerning their firm made therein.borrowings outstanding and capacity available under these facilities as of March 7, 2005.
|
|
| Letters | Capacity |
(In Millions) | ||||
3-Year Facility | $965 | $403 | $50 | $512 |
5-Year Facility | $500 | $75 | - | $425 |
Hypo Term Loans | $95 | $95 | - | - |
PART III
Item 10.Directors and Executive Officers of the Registrants (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
All officers and directors listed below held the specified positions with their respective companies as of the date of filing this report.report, unless otherwise noted.
Name Age Position Period ENTERGY ARKANSAS, INC. Directors Hugh T. McDonald 44 President and Chief Executive Officer of 2000-Present Entergy Arkansas Director of Entergy Arkansas 2000-Present Senior Vice President, Retail of Entergy 1999-2000 Services, Inc. Director, Regulatory Affairs - TX of 1995-1999 Entergy Gulf States Donald C. Hintz See information under the Entergy Corporation Officers Section in Part I. Richard J. Smith See information under the Entergy Corporation Officers Section in Part I. C. John Wilder See information under the Entergy Corporation Officers Section in Part I.OfficersTheodore Bunting 44 Vice President and Chief Financial 2002 - Present Officer of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans Vice President and Chief Financial 2000 - 2002 Officer - Operations of Entergy Services Director, Utility Operations of Entergy 1999 - 2000 Services Partner with Public Energy Services, Inc. 1997 - 1999 John Thomas Kennedy 43 Vice President - State Governmental 2000-Present Affairs of Entergy Arkansas Attorney at Law, Russellville, Arkansas 1985-2000 Steve K. Strickland 46 Vice President - Regulatory Affairs of 2002 - Present Entergy Arkansas Director, Regulatory Affairs of Entergy 1995 - 2002 Arkansas Frank F. Gallaher See information under the Entergy Corporation Officers Section in Part I. Joseph T. Henderson See information under the Entergy Corporation Officers Section in Part I. Nathan E. Langston See information under the Entergy Corporation Officers Section in Part I. William E. Madison See information under the Entergy Corporation Officers Section in Part I. Hugh T. McDonald See information under the Entergy Arkansas Directors Section above. Steven C. McNeal See information under the Entergy Corporation Officers Section in Part I. Richard J. Smith See information under the Entergy Corporation Officers Section in Part I. Michael G. Thompson See information under the Entergy Corporation Officers Section in Part I.ENTERGY GULF STATES, INC. DirectorsE. Renae Conley 45 Director of Entergy Gulf States and 2000-Present Entergy Louisiana President and Chief Executive Officer - 2000-Present LA of Entergy Gulf States and Entergy Louisiana Vice President, Investor Relations of 1999-2000 Entergy Services President of Cincinnati Gas & Electric, 1998-1999 (a subsidiary of Cinergy Corp.) Chief Executive Officer of Cadence LLC (a 1997-1998 subsidiary of Cinergy Corp.) Joseph F. Domino 54 Director of Entergy Gulf States 1999-Present President and Chief Executive Officer - 1998-Present TX of Entergy Gulf States Director - Southwest Franchise of Entergy 1997-1998 Gulf States Donald C. Hintz See information under the Entergy Corporation Officers Section in Part I. Richard J. Smith See information under the Entergy Corporation Officers Section in Part I. C. John Wilder See information under the Entergy Corporation Officers Section in Part I.OfficersJack Blakley 48 Vice President - Regulatory Affairs, TX 2002 - Present of Entergy Gulf States Director - Regulatory Affairs, TX of 1999 - 2002 Entergy Gulf States Director - System Regulatory Strategy of 1996 - 1999 Entergy Services Murphy A. Dreher 50 Vice President - State Governmental 1999-Present Affairs - LA of Entergy Gulf States and Entergy Louisiana Legislative Executive - Governmental 1995-1998 Affairs of Entergy Gulf States Randall W. Helmick 48 Vice President - Operations - LA of 1998-Present Entergy Gulf States and Entergy Louisiana Director of Special Projects of London 1997-1998 Electricity Eduardo Melendreras 45 Vice President, Customer Service and 2001-Present Commercial and Industrial Accounts of Entergy Gulf States and Entergy Louisiana Director - Jurisdictional Accounts of 2000-2001 Entergy Services Director - Large Industrial Sales & 1996-2000 Service of Entergy Gulf States J. Parker McCollough 51 Vice President - State Governmental 1996-Present Affairs - TX of Entergy Gulf States Wade H. Stewart 57 Vice President, Regulatory Affairs - LA 2000-Present of Entergy Gulf States and Entergy Louisiana Director, Regulatory Affairs - LA of 1995-2000 Entergy Gulf States and Entergy Louisiana Theodore Bunting See information under the Entergy Arkansas Officers Section above. E. Renae Conley See information under the Entergy Gulf States Directors Section above. Joseph F. Domino See information under the Entergy Gulf States Directors Section above. Frank F. Gallaher See information under the Entergy Corporation Officers Section in Part I. Joseph T. Henderson See information under the Entergy Corporation Officers Section in Part I. Nathan E. Langston See information under the Entergy Corporation Officers Section in Part I. William E. Madison See information under the Entergy Corporation Officers Section in Part I. Steven C. McNeal See information under the Entergy Corporation Officers Section in Part I. Richard J. Smith See information under the Entergy Corporation Officers Section in Part I. Michael G. Thompson See information under the Entergy Corporation Officers Section in Part I.ENTERGY LOUISIANA, INC. DirectorsE. Renae Conley See information under the Entergy Gulf States Directors Section above. Donald C. Hintz See information under the Entergy Corporation Officers Section in Part I. Richard J. Smith See information under the Entergy Corporation Officers Section in Part I. C. John Wilder See information under the Entergy Corporation Officers Section in Part I.OfficersTheodore Bunting See information under the Entergy Arkansas Officers Section above. E. Renae Conley See information under the Entergy Gulf States Directors Section above. Murphy A. Dreher See information under the Entergy Gulf States Officers Section above. Frank F. Gallaher See information under the Entergy Corporation Officers Section in Part I. Randall W. Helmick See information under the Entergy Gulf States Officers Section above. Joseph T. Henderson See information under the Entergy Corporation Officers Section in Part I. Nathan E. Langston See information under the Entergy Corporation Officers Section in Part I. William E. Madison See information under the Entergy Corporation Officers Section in Part I. Steven C. McNeal See information under the Entergy Corporation Officers Section in Part I. Eduardo Melendreras See information under the Entergy Gulf States Officers Section above. Richard J. Smith See information under the Entergy Corporation Officers Section in Part I. Michael G. Thompson See information under the Entergy Corporation Officers Section in Part I. Wade H. Stewart See information under the Entergy Gulf States Officers Section above.ENTERGY MISSISSIPPI, INC. DirectorsCarolyn C. Shanks 41 President and Chief Executive Officer of 1999-Present Entergy Mississippi Director of Entergy Mississippi 1999-Present Vice President of Finance and 1997-1999 Administration of Entergy Mississippi Donald C. Hintz See information under the Entergy Corporation Officers Section in Part I. Richard J. Smith See information under the Entergy Corporation Officers Section in Part I. C. John Wilder See information under the Entergy Corporation Officers Section in Part I.OfficersBill F. Cossar 64 Vice President - State Governmental 1987-Present Affairs of Entergy Mississippi Robert C. Grenfell 49 Vice President - Regulatory Affairs, MS 2002 - Present of Entergy Mississippi Director, Regulatory Affairs of Entergy 1994 - 2002 Mississippi Haley R. Fisackerly 37 Vice President - Customer Service of 2002 - Present Entergy Mississippi Director - System Regulatory Strategy of 1999 - 2002 Entergy Services Governmental Affairs Executive of Entergy 1995 - 1999 Services Will L. Mayo 55 Vice President - State Governmental 2002 - Present Affairs of Entergy Mississippi Director - Economic Development of 1997 - 2002 Entergy Mississippi Theodore Bunting See information under the Entergy Arkansas Officers Section above. Frank F. Gallaher See information under the Entergy Corporation Officers Section in Part I. Joseph T. Henderson See information under the Entergy Corporation Officers Section in Part I. Nathan E. Langston See information under the Entergy Corporation Officers Section in Part I. William E. Madison See information under the Entergy Corporation Officers Section in Part I. Steven C. McNeal See information under the Entergy Corporation Officers Section in Part I. Carolyn C. Shanks See information under the Entergy Mississippi Directors Section above. Richard J. Smith See information under the Entergy Corporation Officers Section in Part I. Michael G. Thompson See information under the Entergy Corporation Officers Section in Part I.ENTERGY NEW ORLEANS, INC. DirectorsDaniel F. Packer 55 Chief Executive Officer Entergy New 1998-Present Orleans President and Director of Entergy New 1997-Present Orleans Donald C. Hintz See information under the Entergy Corporation Officers Section in Part I. Richard J. Smith See information under the Entergy Corporation Officers Section in Part I. C. John Wilder See information under the Entergy Corporation Officers Section in Part I.OfficersElaine Coleman 53 Vice President, External Affairs of 1998-Present Entergy New Orleans Director of Customer Service of Entergy 1998 Services Lead Customer Service Manager of Entergy 1995-1998 Services Theodore Bunting See information under the Entergy Arkansas Officers Section above. Frank F. Gallaher See information under the Entergy Corporation Officers Section in Part I. Joseph T. Henderson See information under the Entergy Corporation Officers Section in Part I. Nathan E. Langston See information under the Entergy Corporation Officers Section in Part I. William E. Madison See information under the Entergy Corporation Officers Section in Part I. Steven C. McNeal See information under the Entergy Corporation Officers Section in Part I. Daniel F. Packer See information under the Entergy New Orleans Directors Section above. Richard J. Smith See information under the Entergy Corporation Officers Section in Part I. Michael G. Thompson See information under the Entergy Corporation Officers Section in Part I.SYSTEM ENERGY RESOURCES, INC. DirectorsJerry W. Yelverton 58 Director, President and Chief Executive 1999-Present Officer of System Energy Senior Vice President of Nuclear of 1997-1998 Entergy Services Executive Vice President and Chief 1996-1998 Operating Officer of Entergy Operations In addition, Mr. Yelverton is an executive officer and/or director of various other wholly owned subsidiaries of Entergy Corporation and its operating companies. Donald C. Hintz See information under the Entergy Corporation Officers Section in Part I. C. John Wilder See information under the Entergy Corporation Officers Section in Part I.OfficersJoseph L. Blount 56 Secretary of System Energy and Entergy 1991-Present Operations Joseph T. Henderson See information under the Entergy Corporation Officers Section in Part I. Nathan E. Langston See information under the Entergy Corporation Officers Section in Part I. Steven C. McNeal See information under the Entergy Corporation Officers Section in Part I. C. John Wilder See information under the Entergy Corporation Officers Section in Part I. Jerry W. Yelverton See information under the System Energy Directors Section above.
Name | Age | Position | Period | ||
ENTERGYARKANSAS, INC. | |||||
Directors | |||||
Hugh T. McDonald | 46 | President and Chief Executive Officer of Entergy Arkansas | 2000-Present | ||
Director of Entergy Arkansas | 2000-Present | ||||
Senior Vice President, Retail of Entergy Services, Inc. | 1999-2000 | ||||
Leo P. Denault | See information under the Entergy Corporation Officers Section in Part I. | ||||
Mark T. Savoff | See information under the Entergy Corporation Officers Section in Part I. | ||||
Richard J. Smith | See information under the Entergy Corporation Officers Section in Part I. | ||||
Officers | |||||
Jay A. Lewis | 43 | Vice President and Chief Financial Officer - Utility Operations Group of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans | 2004-Present | ||
Director, Accounting Policy and Research of Entergy Services, Inc. | 1999 - 2004 | ||||
Leo P. Denault | See information under the Entergy Corporation Officers Section in Part I. | ||||
Curtis L. Hebert, Jr. | See information under the Entergy Corporation Officers Section in Part I. | ||||
Nathan E. Langston | See information under the Entergy Corporation Officers Section in Part I. | ||||
J. Wayne Leonard | See information under the Entergy Corporation Officers Section in Part I. | ||||
William E. Madison | See information under the Entergy Corporation Officers Section in Part I. | ||||
Hugh T. McDonald | See information under the Entergy Arkansas Directors Section above. | ||||
Mark T. Savoff | See information under the Entergy Corporation Officers Section in Part I. | ||||
Robert D. Sloan | See information under the Entergy Corporation Officers Section in Part I. | ||||
Richard J. Smith | See information under the Entergy Corporation Officers Section in Part I. | ||||
Gary J. Taylor | See information under the Entergy Corporation Officers Section in Part I. | ||||
ENTERGY GULF STATES, INC. | ||||
Directors | ||||
E. Renae Conley | 47 | Director of Entergy Gulf States and Entergy Louisiana | 2000-Present | |
President and Chief Executive Officer - LA of Entergy Gulf States and Entergy Louisiana | 2000-Present | |||
Vice President, Investor Relations of Entergy Services | 1999-2000 | |||
Joseph F. Domino | 56 | Director of Entergy Gulf States | 1999-Present | |
President and Chief Executive Officer - TX of Entergy Gulf States | 1998-Present | |||
Leo P. Denault | See information under the Entergy Corporation Officers Section in Part I. | |||
Mark T. Savoff | See information under the Entergy Corporation Officers Section in Part I. | |||
Richard J. Smith | See information under the Entergy Corporation Officers Section in Part I. | |||
Officers | ||||
E. Renae Conley | See information under the Entergy Gulf States Directors Section above. | |||
Leo P. Denault | See information under the Entergy Corporation Officers Section in Part I. | |||
Joseph F. Domino | See information under the Entergy Gulf States Directors Section above. | |||
Curtis L. Hebert, Jr. | See information under the Entergy Corporation Officers Section in Part I. | |||
Nathan E. Langston | See information under the Entergy Corporation Officers Section in Part I. | |||
J. Wayne Leonard | See information under the Entergy Corporation Officers Section in Part I. | |||
Jay A. Lewis | See information under the Entergy Arkansas Officers Section above. | |||
William E. Madison | See information under the Entergy Corporation Officers Section in Part I. | |||
Mark T. Savoff | See information under the Entergy Corporation Officers Section in Part I. | |||
Robert D. Sloan | See information under the Entergy Corporation Officers Section in Part I. | |||
Richard J. Smith | See information under the Entergy Corporation Officers Section in Part I. | |||
Gary J. Taylor | See information under the Entergy Corporation Officers Section in Part I. | |||
ENTERGY LOUISIANA, INC. | ||||
Directors | ||||
E. Renae Conley | See information under the Entergy Gulf States Directors Section above. | |||
Leo P. Denault | See information under the Entergy Corporation Officers Section in Part I. | |||
Mark T. Savoff | See information under the Entergy Corporation Officers Section in Part I. | |||
Richard J. Smith | See information under the Entergy Corporation Officers Section in Part I. | |||
Officers | ||||
E. Renae Conley | See information under the Entergy Gulf States Directors Section above. | |||
Leo P. Denault | See information under the Entergy Corporation Officers Section in Part I. | |||
Curtis L. Hebert, Jr. | See information under the Entergy Corporation Officers Section in Part I. | |||
Nathan E. Langston | See information under the Entergy Corporation Officers Section in Part I. | |||
J. Wayne Leonard | See information under the Entergy Corporation Officers Section in Part I. | |||
Jay A. Lewis | See information under the Entergy Arkansas Officers Section above. | |||
William E. Madison | See information under the Entergy Corporation Officers Section in Part I. | |||
Mark T. Savoff | See information under the Entergy Corporation Officers Section in Part I. | |||
Robert D. Sloan | See information under the Entergy Corporation Officers Section in Part I. | |||
Richard J. Smith | See information under the Entergy Corporation Officers Section in Part I. | |||
Gary J. Taylor | See information under the Entergy Corporation Officers Section in Part I. | |||
ENTERGY MISSISSIPPI, INC. | ||||
Directors | ||||
Carolyn C. Shanks | 43 | President and Chief Executive Officer of Entergy Mississippi | 1999-Present | |
Director of Entergy Mississippi | 1999-Present | |||
Leo P. Denault | See information under the Entergy Corporation Officers Section in Part I. | |||
Mark T. Savoff | See information under the Entergy Corporation Officers Section in Part I. | |||
Richard J. Smith | See information under the Entergy Corporation Officers Section in Part I. | |||
Officers | ||||
Leo P. Denault | See information under the Entergy Corporation Officers Section in Part I. | |||
Curtis L. Hebert, Jr. | See information under the Entergy Corporation Officers Section in Part I. | |||
Nathan E. Langston | See information under the Entergy Corporation Officers Section in Part I. | |||
J. Wayne Leonard | See information under the Entergy Corporation Officers Section in Part I. | |||
Jay A. Lewis | See information under the Entergy Arkansas Officers Section above. | |||
William E. Madison | See information under the Entergy Corporation Officers Section in Part I. | |||
Mark T. Savoff | See information under the Entergy Corporation Officers Section in Part I. | |||
Carolyn C. Shanks | See information under the Entergy Mississippi Directors Section above. | |||
Robert D. Sloan | See information under the Entergy Corporation Officers Section in Part I. | |||
Richard J. Smith | See information under the Entergy Corporation Officers Section in Part I. | |||
Gary J. Taylor | See information under the Entergy Corporation Officers Section in Part I. | |||
ENTERGY NEW ORLEANS, INC. | ||||
Directors | ||||
Daniel F. Packer | 57 | Chief Executive Officer Entergy New Orleans | 1998-Present | |
President of Entergy New Orleans | 1997-Present | |||
Director of Entergy New Orleans | 1996-Present | |||
Leo P. Denault | See information under the Entergy Corporation Officers Section in Part I. | |||
Mark T. Savoff | See information under the Entergy Corporation Officers Section in Part I. | |||
Richard J. Smith | See information under the Entergy Corporation Officers Section in Part I. | |||
Officers | ||||
Leo P. Denault | See information under the Entergy Corporation Officers Section in Part I. | |||
Curtis L. Hebert, Jr. | See information under the Entergy Corporation Officers Section in Part I. | |||
Nathan E. Langston | See information under the Entergy Corporation Officers Section in Part I. | |||
J. Wayne Leonard | See information under the Entergy Corporation Officers Section in Part I. | |||
Jay A. Lewis | See information under the Entergy Arkansas Officers Section above. | |||
William E. Madison | See information under the Entergy Corporation Officers Section in Part I. | |||
Daniel F. Packer | See information under the Entergy New Orleans Directors Section above. | |||
Mark T. Savoff | See information under the Entergy Corporation Officers Section in Part I. | |||
Robert D. Sloan | See information under the Entergy Corporation Officers Section in Part I. | |||
Richard J. Smith | See information under the Entergy Corporation Officers Section in Part I. | |||
Gary J. Taylor | See information under the Entergy Corporation Officers Section in Part I. |
SYSTEM ENERGY RESOURCES, INC. | |||||
Directors | |||||
Gary J. Taylor | 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. | ||||
Steven C. McNeal | Director of System Energy | 2004-Present | |||
Vice President and Treasurer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy | 1998-Present | ||||
Officers | |||||
Theodore Bunting | 46 | Vice President and Chief Financial Officer - Nuclear Operations of System Energy | 2004 - Present | ||
Vice President and Chief Financial Officer of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans | 2002 - 2004 | ||||
Vice President and Chief Financial Officer - Operations of Entergy Services | 2000 - 2002 | ||||
Director, Utility Operations of Entergy Services | 1999 - 2000 | ||||
Leo P. Denault | See information under the Entergy Corporation Officers Section in Part I. | ||||
Curtis L. Hebert, Jr. | See information under the Entergy Corporation Officers Section in Part I. | ||||
Nathan E. Langston | See information under the Entergy Corporation Officers Section in Part I. | ||||
J. Wayne Leonard | See information under the Entergy Corporation Officers Section in Part I. | ||||
William E. Madison | See information under the Entergy Corporation Officers Section in Part I. | ||||
Mark T. Savoff | See information under the Entergy Corporation Officers Section in Part I. | ||||
Robert D. Sloan | See information under the Entergy Corporation Officers Section in Part I. | ||||
Richard J. Smith | See information under the Entergy Corporation Officers Section in Part I. | ||||
Gary J. Taylor | See information under the Entergy Corporation Officers Section in Part I. | ||||
Each director and officer of the applicable Entergy company is elected yearly to serve by the unanimous consent of the sole stockholder, Entergy Corporation, at its annual meeting.
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. Wilkinson (Chairman)
Kathleen A. Murphy
James R. Nichols
William A. Percy, II
Bismark A. Steinhagen
All Audit Committee members are independent. For purposes of independence of members of the Audit Committee, an independent director also may not accept directly or indirectly any consulting, advisory or other compensatory fee from Entergy or be affiliated with Entergy as defined in SEC rules. All Audit Committee members possess the level of financial literacy and accounting or related financial management expertise required by the NYSE rules. Steven V. Wilkinson qualifies as an "audit committee financial expert," as that term is defined in the SEC rules.
Code of Ethics
The Board of Directors has adopted a Code of Business Conduct and Ethics for Members of the Board of Directors. The code is available through Entergy'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 required to abide by the Codes. Non-bargaining employees are required to acknowledge annually that they understand and abide by the Code of Entegrity. The Code of Business Conduct and Ethics for Employees and the Code of Entegrity are available through Entergy's website (www.entergy.com) or upon written requ est.
Source of Nominations to the Board of Directors; Nominating Procedure
The Corporate Governance Committee has adopted a policy on consideration of potential director nominees. The Committee will consider nominees from a variety of sources, including nominees suggested by shareholders, executive officers, fellow board members, or a third party firm retained for that purpose. It applies the same procedures to all nominees regardless of the source of the nomination.
Any party wishing to make a nomination should provide a written resume of the proposed candidate, detailing relevant experience and qualifications, as well as a list of references. The Committee will review the resume and may contact references. It will decide based on the resume and references whether to proceed to a more detailed investigation. If the Committee determines that a more detailed investigation of the candidate is warranted, it will invite the candidate for a personal interview, conduct a background check on the candidate, and assess the ability of the candidate to provide any special skills or characteristics identified by the Committee or the Board.
Section 16(a) Beneficial Ownership Reporting Compliance
Information called for by this item concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held on May 9, 2003,13, 2005, under the heading "Section 16(a) Beneficial Ownership Reporting Compliance", which information is incorporated herein by reference.
Item 11.Executive Compensation
ENTERGY CORPORATION
Information called for by this item concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement under the headings "Executive Compensation Tables", "General Information About Nominees", "Director Compensation", and "Comparison of Five Year Cumulative Total Return", all of which information is incorporated herein by reference.
ENTERGY ARKANSAS, ENTERGY GULF STATES, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND SYSTEM ENERGY
Summary Compensation Table
The following table includes the Chief Executive Officer, and the four other most highly compensated executive officers in office as of December 31, 20022004, and two additional executive officers who would have been included in the table but retired or resigned during the year at Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy (collectively, the "Named Executive Officers"). This determination was based on total annual base salary and bonuses from all Entergy sources earned by each officer for the year 2002.2004. See Item 10, "Directors and Executive Officers of the Registrants," for information on the principal positions of the Named Executive Officers in the table below.
Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy
As shown in Item 10, most Named Executive Officers are employed by several Entergy companies. Because it would be impracticable to allocate such officers' salaries among the various companies, the table below includes the aggregate compensation paid by all Entergy companies.
Long-Term Compensation Annual Compensation Awards Payouts Other Restricted Securities
Long-Term Compensation
Annual Compensation
Awards
Payouts
Name
Year
Salary
Bonus(a) Other
Annual
Comp.Restricted
Stock
AwardsSecurities
Underlying
Options(d)
LTIP
Payouts(e) All
Other
Comp.E. Renae Conley
2004
$345,912
$272,220
$18,867
(b)
18,400 shares
$724,200
$30,537
CEO-Entergy Louisiana
2003
334,453
200,000
31,087
(b)
33,092
460,088
15,413
CEO-LA-Entergy Gulf
States2002
321,500
320,000
88,946
(b)
40,000
331,114
15,211
Leo P. Denault
2004
$463,631
$490,000
$15,330
(b)
40,000 shares
$557,634
$29,518
2003
286,824
217,402
4,551
(b)
30,600
190,170
13,308
2002
275,834
210,000
15,750
(b)
20,500
153,202
13,041
Joseph F. Domino
2004
$274,242
$172,813
$28,787
(b)
18,189 shares
$304,164
$12,214
CEO-TX-Entergy Gulf
States2003
265,626
200,765
46,480
(b)
10,500
190,170
11,912
2002
255,295
210,070
63,361
(b)
22,000
153,202
13,568
Donald C. Hintz (f)
2004
$348,847
$236,798
$204,941
(b)
20,000 shares
$2,136,390
$8,465,499
2003
660,793
605,115
80,295
(b)
140,000
1,748,333
33,797
2002
629,423
754,800
206,963
(b)
160,000
1,408,470
34,318
J. Wayne Leonard
2004
$1,088,769
$1,540,000
$46,344
(b)
220,000 shares
$4,634,880
$48,199
2003
1,038,461
1,197,800
26,152
(b)
195,000
2,944,560
73,639
2002
962,500
1,450,400
5,257
(b)
330,600
2,372,160
20,517
Hugh T. McDonald
2004
$288,847
$197,400
$25,927
(b)
10,000 shares
$304,164
$12,596
CEO-Entergy Arkansas
2003
264,201
195,000
32,276
(b)
21,199
190,170
12,134
2002
247,373
185,000
56,295
(b)
22,000
182,854
14,867
Daniel F. Packer
2004
$260,748
$164,375
$27,090
(b)
10,000 shares
$304,164
$11,122
CEO-Entergy New Orleans
2003
253,628
190,000
58,519
(b)
8,000
190,170
3,204
2002
244,776
95,000
17,705
(b)
20,000
153,202
13,469
Mark T. Savoff
2004
$500,001
$490,000
$24,607
(b)
31,800 shares
$405,552
$21,293
2003
19,231
-
51,485
(b)
-
-
865
Carolyn C. Shanks
2004
$283,885
$213,900
$14,297
(b)
10,000 shares
$304,164
$11,800
CEO-Entergy Mississippi
2003
263,758
195,000
92,825
$152,160 (b)(c)
14,000
190,170
12,132
2002
252,478
200,000
77,460
(b)
20,000
153,202
14,138
Richard J. Smith
2004
$494,806
$490,000
$11,840
(b)
63,600 shares
$1,231,140
$56,186
2003
473,019
380,867
64,371
(b)
72,777
674,795
23,128
2002
443,269
466,200
28,862
(b)
95,000
454,664
20,699
Gary J. Taylor
2004
$414,356
$411,600
$29,170
(b)
40,000 shares
$1,013,880
$9,987
CEO-System Energy
2003
394,615
316,400
78,575
(b)
26,900
539,836
7,240
2002
342,788
277,925
48,892
(b)
34,600
336,056
16,156
C. John Wilder (f)
2004
$106,174
$ -
$5,358
(b)
- shares
$ -
$5,171
2003
568,731
461,153
153,373
(b)
80,000
779,082
51,614
2002
521,923
549,080
156,683
(b)
131,366
627,634
24,459
(a)
(b) All Annual Stock Underlying LTIP Other Name Year Salary Bonus Comp. Awards Options Payouts Comp. E. Renae Conley 2002 $321,500 $320,000 $88,946 (c) 40,000 shares $331,114 $15,211 CEO-Entergy Louisiana 2001 308,769 486,186 46,240 (c) 34,600 - 10,742 CEO-LA-Entergy Gulf States 2000 282,642 280,000 41,573 (c) 20,000 181,109 8,559 Joseph F. Domino 2002 $255,295 $210,070 $63,361 (c) 22,000 shares $153,202 $13,568 CEO-TX-Entergy Gulf States 2001 245,384 292,583 48,254 (c) 14,800 - 7,150 2000 235,358 180,732 51,399 (c) 20,000 142,314 7,084 Donald C. Hintz 2002 $629,423 $754,800 $206,963 (c) 160,000 shares $1,408,470 $34,318 2001 599,423 779,000 198,321 (c) 160,000 - 21,605 2000 570,096 743,000 104,399 (c) 175,000 1,181,837 26,516 Jerry D. Jackson 2002 $491,281 $513,150 $19,261 (c) 75,898 shares $627,634 $17,600 2001 475,345 576,382 19,646 (c) 80,000 - 17,378 2000 458,223 554,214 58,758 (c) 58,500 1,181,575 15,162 J. Wayne Leonard 2002 $962,500 $1,450,400 $5,257 (c) 330,600 shares $2,372,160 $20,517 2001 897,500 1,684,800 3,709 $7,400,000(c)(d) 330,600 - - 2000 836,538 1,190,000 11,646 (c) 330,600 2,410,413 - Hugh T. McDonald 2002 $247,373 $185,000 $56,295 (c) 22,000 shares $182,854 $14,867 CEO-Entergy Arkansas 2001 231,335 333,078 118,502 (c) 14,800 - 18,664 2000 209,400 165,000 53,808 (c) 34,600 172,773 54,878 Daniel F. Packer 2002 $244,776 $95,000 $17,705 (c) 20,000 shares $153,202 $13,469 CEO-Entergy New Orleans 2001 228,209 262,881 15,410 (c) 14,800 - 7,055 2000 219,432 167,382 16,433 (c) 20,000 196,929 6,658 Carolyn C. Shanks 2002 $252,478 $200,000 $77,460 (c) 20,000 shares $153,202 $14,138 CEO-Entergy Mississippi 2001 241,085 287,672 17,140 (c) 14,800 - 7,206 2000 231,193 182,530 2,594 (c) 20,000 104,241 4,858 C. John Wilder 2002 $521,923 $549,080 $156,683 (c) 131,366 shares $627,634 $24,459 2001 493,128 600,000 158,059 (c) 87,700 - 16,284 2000 468,392 619,370 148,540 (c) 87,700 953,006 13,919 Jerry W. Yelverton 2002 $464,798 $658,350 $180,186 (c) 85,000 shares $627,634 $28,455 CEO-System Energy 2001 443,269 540,000 145,389 (c) 65,000 - 14,697 2000 408,846 510,000 4,197 $201,875(c)(d) 58,900 503,482 12,732
Amounts include the value of restricted shares that vested in 2000 and 2002 (see note (c) below) under Entergy's Equity Ownership Plan.Includes the following:
2002 benefit accruals under the Defined Contribution Restoration Plan as follows: Ms. Conley $5,510; Mr. Domino $2,592; Mr. Hintz $22,499; Mr. Jackson $16,135; Mr. Leonard $20,517; Mr. McDonald $2,043; Mr. Packer $1,642; Ms. Shanks $2,485; Mr. Wilder $14,553; and Mr. Yelverton $13,158.2002 employer contributions to the System Savings Plan as follows: Ms. Conley $9,701; Mr. Domino $10,976; Mr. Hintz $11,819; Mr. Jackson $1,465; Mr. McDonald $12,824; Mr. Packer $11,827; Ms. Shanks $11,653; Mr. Wilder $9,906; and Mr. Yelverton $15,297.
Performance unit (equivalent to shares of Entergy common stock) awards in 2002 are reported under the "Long-Term Incentive Plan Awards" table, and reference is made to this table for information on the aggregate number of performance units awarded during 2002 and the vesting schedule for such units. At December 31, 2002, the number and value of the aggregate performance unit holdings were as follows: Ms. Conley 17,500 units, $797,825; Mr. Domino 7,300 units, $332,807; Mr. Hintz 66,500 units, $3,031,735; Mr. Jackson 29,700 units, $1,354,023; Mr. Leonard 212,000 units, $9,665,080; Mr. McDonald 7,300 units, $332,807; Mr. Packer 7,300 units, $332,807; Ms. Shanks 7,300 units, $332,807; Mr. Wilder 29,700 units, $1,354,023; and Mr. Yelverton 33,700 units, $1,536,383. Accumulated dividends are paid on performance units when vested. The value of performance unit holdings as of December 31, 2002 is determined by multiplying the total number of units held by the closing market price of Entergy com mon stock on the New York Stock Exchange Composite Transactions on December 31, 2002 ($45.59 per share). The value of stock for which restrictions were lifted in 2002 and 2000, and the applicable portion of accumulated cash dividends, are reported in the LTIP payouts column in the above table.In addition to the performance units granted under the Equity Ownership Plan, in January 2001, Mr. Leonard was granted 200,000 restricted stock units. 50,000 of the restricted stock units vest on each of December 31, 2001, December 31, 2002, December 31, 2003 and December 31, 2004, based on continued service with Entergy. Accumulated dividends will not be paid on Mr. Leonard's restricted stock units when vested. Mr. Yelverton was granted 10,000 restricted stock units in 2000. Restrictions were lifted on 3,000 units in 2001 and 2002, and the remaining 4,000 units in 2003. Accumulated dividends will not be paid. The value these individuals may realize is dependent upon both the number of units that vest and the future market price of Entergy common stock.2004 Other Annual Compensation includes the following:
(1)
Payments for personal financial counseling as follows: Ms. Conley $10,000; Mr. Denault $7,615; Mr. Domino $7,725; Mr. Hintz $10,643; Mr. Leonard $15,000; Mr. McDonald $4,500; Mr. Packer $7,871; Ms. Shanks $3,500; Mr. Smith $7,800; Mr. Taylor $9,762; and Mr. Wilder $1,856.
(2)
Payments for annual physical exams as follows: Ms. Conley $2,319; Mr. Denault $2,729; Mr. Domino $2,729; Mr. Hintz $1,404; Mr. Leonard $7,389; Mr. Packer $4,161; Mr. Savoff $3,681; Mr. Smith $1,594; and Mr. Taylor $2,246.
(3)
Personal use of company aircraft as follows: Mr. Domino $1,210; Mr. Hintz $2,442; Mr. Leonard $8,473; Mr. McDonald $1,176; Mr. Packer $855; Ms. Shanks $1,694; Mr. Smith $924; Mr. Taylor $6,203; and Mr. Wilder $1,178.
(4)
Payments for club dues as follows: Mr. Domino $5,056; Mr. Hintz $2,165; Mr. Leonard $68; Mr. McDonald $9,621; Mr. Packer $5,130; Ms. Shanks $4,708; Mr. Taylor $938; and Mr. Wilder $204.
(5)
A relocation payment to Mr. Savoff for $20,926.
(6)
Travel expenses related to volunteer service to Mr. Domino for $3,727.
(7)
Home security monitoring to Ms. Shanks for $180.
(8)
Tax gross up payments as follows: Ms. Conley $6,548; Mr. Denault $4,986; Mr. Domino $8,140; Mr. Hintz $188,287; Mr. Leonard $15,414; Mr. McDonald $10,630; Mr. Packer $9,073; Ms. Shanks $4,215; Mr. Smith $1,522; Mr. Taylor $10,021; and Mr. Wilder $2,120.
(b)
Performance unit (equivalent to shares of Entergy common stock) awards in 2004 are reported under the "Long-Term Incentive Plan Awards" table, and reference is made to this table for information on the aggregate number of performance units awarded during 2004 and the vesting schedule for such units. At December 31, 2004, the number and value of the aggregate performance unit holdings were as follows: Ms. Conley 19,600 units, $1,324,764; Mr. Denault 33,400 units, $2,257,506; Mr. Domino 10,000 units, $675,900; Mr. Hintz 25,500 units, $1,723,545; Mr. Leonard 165,600 units, $11,192,904; Mr. McDonald 10,000 units, $675,900; Mr. Packer 10,000 units, $675,900; Mr. Savoff 33,100 units, $2,237,229; Ms. Shanks 13,000 units, $878,670; Mr. Smith 41,500 units, $2,804,985; and Mr. Taylor 40,300 units, $2,723,877. Accumulated dividends are paid on performance units when vested. The value of performance unit holdings as of December 31, 2004 is determined by multiplying the total number of units held by the closing market price of Entergy common stock on the New York Stock Exchange Composite Transactions on December 31, 2004 ($67.59 per share). The value of units for which restrictions were lifted in 2004, 2003 and 2002, and the applicable portion of accumulated cash dividends, are reported in the LTIP payouts column in the above table.
(c)
In addition to the performance units granted under the Equity Ownership Plan, Ms. Shanks was granted 3,000 restricted units in 2003. Restrictions will be lifted on 1,200 units in 2006 and the remaining 1,800 units in 2011, based on continued service with Entergy. Accumulated dividends will not be paid. The value Ms. Shanks may realize is dependent upon both the number of units that vest and the future market price of Entergy common stock.
(d)
Amounts include the value of performance units that vested in 2004, 2003 and 2002 (see note (b) above) under Entergy's Equity Ownership Plan.
(e)
All Other Compensation includes the following:
(1)
2004 benefit accruals under the Defined Contribution Restoration Plan as follows: Ms. Conley $21,930; Mr. Denault $20,808; Mr. Domino $3,511; Mr. Hintz $3,535; Mr. Leonard $39,222; Mr. McDonald $3,898; Mr. Packer $2,865; Mr. Savoff $12,510; Ms. Shanks $3,098; Mr. Smith $47,409; Mr. Taylor $5,091; and Mr. Wilder $956.
(2)
2004 employer contributions to the System Savings Plan as follows: Ms. Conley $8,607; Mr. Denault $8,710; Mr. Domino $8,703; Mr. Hintz $7,994; Mr. Leonard $8,977; Mr. McDonald $8,698; Mr. Packer $8,257; Mr. Savoff $8,783; Ms. Shanks $8,702; Mr. Smith $8,777; Mr. Taylor $4,896; and Mr. Wilder $4,215.
(3)
A 2004 lump sum award made under the System Executive Retirement Plan to Mr. Hintz in the amount of $8,453,970. For a description of the System Executive Retirement Plan, see the discussion under "Executive Retirement and Benefit Plans - - System Executive Retirement Plan."
(f)
Mr. Hintz retired in April 2004. Mr. Wilder resigned in February 2004.
Option Grants in
20022004The following table summarizes option grants during
20022004 to the Named Executive Officers. The absence, in the table below, of any Named Executive Officer indicates that no options were granted to such officer.Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy
Individual Grants
Potential Realizable
Potential Realizable
% of Total
Value
Individual Grants
Value
Number of
Options
at Assumed Annual
Number of
% of Total
at Assumed Annual
Securities
Granted to
Exercise
Rates of Stock
Securities
Options
Rates of Stock
Underlying
Employees
Price
Price Appreciation
Underlying
Granted to
Exercise
Price Appreciation
Options
in
(per
Expiration
for Option Term(b)
Options
Employees
Price (per
Expiration
for Option Term(b)
Name
Granted (a)
2002
share) (a)
Date
5%
10%
Granted (a)
in 2004
share) (a)
Date
5%
10%
E. Renae Conley
40,000
0.5%
$ 41.69
2/11/12
$1,048,745
$2,657,725
18,400
1.0%
$58.60
3/02/14
$678,099
$1,718,437
Leo P. Denault
40,000
2.1%
58.60
3/02/14
1,474,129
3,735,732
Joseph F. Domino
22,000
0.3%
41.69
2/11/12
576,810
1,461,749
10,000
0.5%
58.60
3/02/14
368,532
933,933
Donald C. Hintz
160,000
2.0%
41.69
2/11/12
4,194,979
10,630,900
Jerry D. Jackson
50,000
0.6%
41.69
2/11/12
1,310,931
3,322,156
12,949 (c)
0.2%
46.37
1/27/10
272,375
646,414
4,610 (c)
0.2%
59.02
1/28/09
73,874
162,917
3,811 (c)
0.1%
45.67
2/01/03
1,421
2,787
1,601 (c)
0.1%
65.22
1/28/09
24,022
52,055
4,056 (c)
0.1%
45.67
1/27/04
10,054
20,149
1,308 (c)
0.1%
65.26
1/28/09
19,637
42,554
5,082 (c)
0.1%
45.67
1/27/10
105,283
249,864
670 (c)
0.1%
65.25
1/25/11
15,546
35,490
Donald C. Hintz
20,000
1.1%
58.60
3/02/14
737,065
1,867,866
J. Wayne Leonard
330,600
4.1%
41.69
2/11/12
8,667,875
21,966,097
220,000
11.6%
58.60
3/02/14
8,107,710
20,546,528
Hugh T. McDonald
22,000
0.3%
41.69
2/11/12
576,810
1,461,749
10,000
0.5%
58.60
3/02/14
368,532
933,933
Daniel F. Packer
20,000
0.2%
41.69
2/11/12
524,372
1,328,862
10,000
0.5%
58.60
3/02/14
368,532
933,933
Mark T. Savoff
31,800
1.7%
58.60
3/02/14
1,171,933
2,969,907
Carolyn C. Shanks
20,000
0.2%
41.69
2/11/12
524,372
1,328,862
10,000
0.5%
58.60
3/02/14
368,532
933,933
C. John Wilder
87,700
1.1%
41.69
2/11/12
2,299,373
5,827,062
8,666 (c)
0.1%
46.45
1/27/10
180,225
426,740
1,109 (c)
0.0%
43.85
1/27/10
20,076
46,891
3,891 (c)
0.1%
43.85
1/28/09
58,959
134,054
5,000 (c)
0.1%
43.90
1/28/09
75,849
172,458
5,000 (c)
0.1%
44.00
1/28/09
76,022
172,851
15,000 (c)
0.2%
43.90
1/28/09
227,548
517,375
5,000 (c)
0.1%
43.88
1/28/09
75,815
172,380
Jerry W. Yelverton
85,000
1.0%
41.69
2/11/12
2,228,582
5,647,665
Richard J. Smith
63,600
3.4%
58.60
3/02/14
2,343,865
5,939,814
Gary J. Taylor
40,000
2.1%
58.60
3/02/14
1,474,129
3,735,732
Options were granted on February 11, 2002, pursuant to the Equity Ownership Plan. All options granted on this datehave an exercise price equal to the closing price of Entergy common stock on the New York Stock Exchange Composite Transactions on February 11, 2002. These options will vest in equal increments, annually, over a three-year period beginning in 2003.Calculation based on the market price of the underlying securities assuming the market price increases over the option period and assuming annual compounding. The column presents estimates of potential values based on simple mathematical assumptions. The actual value, if any, a Named Executive Officer may realize is dependent upon the market price on the date of option exercise.During 2002, Mr. Jackson and Mr. Wilder converted presently exercisable stock options into an equivalent total of phantom stock units and reload stock options. They accomplished this by exercising stock options, paying the exercise price for these options by surrendering shares of Entergy stock, and deferring the taxable gain into phantom stock units. Additional options, as indicated above, were granted pursuant to the reload feature of this "stock for stock" exercise method. Under the reload mechanism, eligible participants are granted an additional number of options equal to the number of shares surrendered to pay the exercise price. The reloaded stock options vest immediately and have an exercise price equal to the price of Entergy common stock on the New York Stock Exchange Composite Transactions on the date of exercise of the original options. The reloaded options retain the original grant's expiration date. The reload feature is proposed to be removed from the Equity Ownership P lan as described in Proposal 2 in the Proxy Statement. If the proposal is approved by the Stockholders, reloads will no longer be available for options granted after February 13, 2003.
(a)
Options were granted on March 2, 2004, pursuant to the Equity Ownership Plan. All options granted on this datehave an exercise price equal to the closing price of Entergy common stock on the New York Stock Exchange Composite Transactions on March 2, 2004. These options will vest in equal increments, annually, over a three-year period beginning in 2005, based on continued service with Entergy.
(b)
Calculation based on the market price of the underlying securities assuming the market price increases over the option period and assuming annual compounding. The column presents estimates of potential values based on simple mathematical assumptions. The actual value, if any, a Named Executive Officer may realize is dependent upon the market price on the date of option exercise.
(c)
During 2004, Mr. Domino converted presently exercisable stock options into Entergy stock and reload stock options. He accomplished this by exercising stock options, paying the exercise price and all applicable taxes for these shares by surrendering shares of Entergy stock. Additional options, as indicated above, were granted pursuant to the reload feature of this "stock for stock" exercise method. Under the reload mechanism, eligible participants are granted an additional number of options equal to the number of shares surrendered to pay the exercise price. The reloaded stock options vest immediately and have an exercise price equal to the price of Entergy common stock on the New York Stock Exchange Composite Transactions on the date of exercise of the original options. The reloaded options retain the original grant's expiration date. The reload feature was removed from the Equity Ownership Plan as approved by the Stockholders in May 2003. Reloads are no longer availabl e for options granted after February 13, 2003.
Aggregated Option Exercises in
20022004 and December 31,20022004 Option ValuesThe following table summarizes the number and value of all unexercised options held by the Named Executive Officers. The absence, in the table below, of any Named Executive Officer indicates that no options are held by such officer.
Number of Securities Value of Unexercised Underlying Unexercised Options In-the-Money Options Shares Acquired Value as of December 31, 2002 as of December 31, 2002(b) Name on Exercise Realized (a) Exercisable Unexercisable Exercisable Unexercisable E. Renae Conley - $ - 32,366 69,734 $531,717 $504,753 Joseph F. Domino - - 33,253 38,534 587,807 321,165 Donald C. Hintz 30,000 624,375 384,499 405,001 6,411,858 4,070,235 Jerry D. Jackson 45,927 930,553 118,304 122,834 1,279,375 1,093,644 J. Wayne Leonard - - 585,600 661,200 9,916,842 5,671,994 Hugh T. McDonald - - 24,500 43,401 436,784 431,111 Daniel F. Packer 30,083 492,005 4,933 36,534 42,374 313,365 Carolyn C. Shanks 10,351 163,659 4,933 36,534 42,374 313,365 C. John Wilder 108,041 1,943,277 75,824 175,401 355,895 1,504,658 Jerry W. Yelverton 57,766 913,970 - 147,968 - 1,147,271
Based on the difference between the closing price of Entergy's common stock on the New York Stock Exchange Composite Transactions on the exercise date and the option exercise price.Based on the difference between the closing price of Entergy's common stock on the New York Stock Exchange Composite Transactions on December 31, 2002, and the option exercise price.
Number of
Securities Underlying
Value of Unexercised
Unexercised Options
In-the-Money Options
Shares Acquired
Value
as of December 31, 2004
as of December 31, 2004 (b)
Name
on Exercise
Realized (a)
Exercisable
Unexercisable
Exercisable
Unexercisable
E. Renae Conley
-
$ -
85,858
47,734
$2,376,930
$881,007
Leo P. Denault
-
-
42,322
53,368
896,883
687,797
Joseph F. Domino
14,667
464,974
39,975
24,334
925,393
441,831
Donald C. Hintz
147,588
4,552,699
630,000
-
17,776,875
-
J. Wayne Leonard
-
-
1,201,600
460,200
41,668,356
7,840,180
Hugh T. McDonald
-
-
42,665
25,334
1,128,347
464,971
Daniel F. Packer
-
-
30,799
22,001
859,748
386,004
Mark T. Savoff
-
-
-
31,800
-
285,882
Carolyn C. Shanks
21,467
572,052
17,999
26,001
453,296
478,564
Richard J. Smith
-
-
150,537
120,268
3,720,385
1,947,463
Gary J. Taylor
13,333
293,326
58,699
69,468
1,620,626
1,073,323
C. John Wilder
222,430
3,649,306
-
-
-
-
(a)
Based on the difference between the closing price of Entergy's common stock on the New York Stock Exchange Composite Transactions on the exercise date and the option exercise price.
(b)
Based on the difference between the closing price of Entergy's common stock on the New York Stock Exchange Composite Transactions on December 31, 2004, and the option exercise price.
Long-Term Incentive Plan Awards in
20022004The following table summarizes the awards of performance units (equivalent to shares of Entergy common stock) granted under the Equity Ownership Plan in
20022004 to the Named Executive Officers.
Estimated Future Payouts Under
Non-Stock Price-Based Plans (# of units) (a) (b)
Number of
Performance Period Until
Estimated Future Payouts Under
Non-Stock Price-Based Plans (# of units) (a) (b)Name
Units
Maturation or Payout
Threshold
Target
Maximum
Number of
UnitsPerformance Period Until
Maturation or Payout
Threshold
Target
MaximumE. Renae Conley
10,000
1/1/02-12/31/04
1,300
5,000
10,000
8,000
1/1/04-12/31/06
400
3,200
8,000
Leo P. Denault
15,800
1/1/04-12/31/06
700
6,322
15,800
Joseph F. Domino
4,200
1/1/02-12/31/04
600
2,100
4,200
4,000
1/1/04-12/31/06
200
1,600
4,000
Donald C. Hintz
38,000
1/1/02-12/31/04
4,800
19,000
38,000
3,600
1/1/04-12/31/06
200
1,456
3,600
Jerry D. Jackson
17,000
1/1/02-12/31/04
2,200
8,500
17,000
J. Wayne Leonard
64,000
1/1/02-12/31/04
8,000
32,000
64,000
85,200
1/1/04-12/31/06
3,500
34,100
85,200
Hugh T. McDonald
4,200
1/1/02-12/31/04
600
2,100
4,200
4,000
1/1/04-12/31/06
200
1,600
4,000
Daniel F. Packer
4,200
1/1/02-12/31/04
600
2,100
4,200
4,000
1/1/04-12/31/06
200
1,600
4,000
Mark T. Savoff
16,500
1/1/04-12/31/06
700
6,600
16,500
Carolyn C. Shanks
4,200
1/1/02-12/31/04
600
2,100
4,200
4,000
1/1/04-12/31/06
200
1,600
4,000
C. John Wilder
17,000
1/1/02-12/31/04
2,200
8,500
17,000
Jerry W. Yelverton
17,000
1/1/02-12/31/04
2,200
8,500
17,000
Richard J. Smith
16,500
1/1/04-12/31/06
700
6,600
16,500
Gary J. Taylor
16,500
1/1/04-12/31/06
700
6,600
16,500
- Benefit Plans
Performance units awarded will vest at the end of a three-year period, subject to the attainment of approved performance goals for Entergy. Restrictions
(a)
Performance units awarded will vest at the end of a three-year period, subject to the attainment of approved performance goals for Entergy. Actual awards are
liftedbased upon the achievement of the cumulative result of these goals for the performance period. The value any Named Executive Officer may realize is dependent upon the number of units that vest, the future market price of Entergy common stock, and the dividends paid during the performance period.(b)
The threshold, target, and maximum levels correspond to the achievement of 10%, 100%, and 250%, respectively, of Equity Ownership Plan goals. Achievement of a threshold, target, or maximum level would result in the award of the number of units indicated in the respective column. Achievement of a level between these three specified levels would result in the award of a number of units calculated by means of interpolation.
Executive
Officer may realize is dependent upon the number of units that vest, the future market price of Entergy common stock,Retirement andthe dividends paid during the performance period.The threshold, target, and maximum levels correspond to the achievement of 25%, 100%, and 200%, respectively, of Equity Ownership Plan goals. Achievement of a threshold, target, or maximum level would result in the award of the number of units indicated in the respective column. Achievement of a level between these three specified levels would result in the award of a number of units calculated by means of interpolation.
Pension Plan TablesEntergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy
The Named Executive Officers are eligible to participate in three types of non-qualified retirement benefit plans. The first type of plan is one that provides retirement income, and includes the qualified retirement plan combined with the Pension Equalization Plan, the Supplemental Retirement Plan, and the System Executive Retirement Plan. In these plans, an executive is typically enrolled in one or more plans but only paid the amount due under the plan that provides the highest benefit, except that participants in the Supplemental Retirement Plan are also eligible for benefits under the Pension Equalization Plan. The second type of plan provides for payments in the event of a change in control, and includes the System Executive Continuity Plans. Finally, the Executive Deferred Compensation Plan and the Equity Ownership Plan allow for deferral of earned income.
Qualified Retirement Plan Combined with Pension Equalization Plan. Entergy Corporation has a tax-qualified defined benefit plan, which, combined with a non-qualified Pension Equalization Plan (PEP), provides for a retirement benefit calculated by multiplying the number of years of employment by 1.5%, which is then multiplied by the final average pay as defined in the plans, and currently includes base salary plus annual bonus. The normal form of benefit for a single executive employee is a lifetime annuity and for a married executive employee is a reduced benefit with a 50% surviving spouse annuity. Retirement benefits are not subject to any deduction for social security.
The maximum benefit under the qualified pension plan is limited by Sections 401 and 415 of the Internal Revenue Code of 1986, as amended; however, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy have elected to participate in the PEP sponsored by Entergy Corporation. Under the PEP, certain executives, including the Named Executive Officers, would receive an additional amount to compensate for the benefit that would have been payable under the qualified pension plan, except for the Internal Revenue Code Sections 401 and 415 limitations discussed above. The PEP also includes as earnings for purposes of calculating PEP benefits a Named Executive Officer's Executive Annual Incentive Plan bonus and any base salary or bonus the Named Executive Officer elects to defer.
As of December 31, 2004, the credited actual years of service under the combined plans were for Ms. Conley (5), Mr. Denault (5), Mr. Domino (34), Mr. Leonard (6), Mr. McDonald (22), Mr. Packer (22), Mr. Savoff (1), Ms. Shanks (21), Mr. Smith (5), and Mr. Taylor (4). Because they entered into PEP agreements granting additional years of service, the total credited years of service under the PEP were for Ms. Conley (22), Mr. Smith (28), and Mr. Taylor (23). Mr. Hintz retired during 2004 with 32 years of service.
The following table shows the annual retirement benefits that would be paid at normal retirement (age 65 or later) and includes covered compensation for the executive officers included in the salary column of the Summary Compensation Table above.
Retirement Income Plan Table
Annual
Covered
Years of Service
Compensation
15
20
25
30
35
$200,000
$45,000
$60,000
$75,000
$90,000
$105,000
300,000
67,500
90,000
112,500
135,000
157,500
400,000
90,000
120,000
150,000
180,000
210,000
500,000
112,500
150,000
187,500
225,000
262,500
750,000
168,750
225,000
281,250
337,500
393,750
1,000,000
225,000
300,000
375,000
450,000
525,000
1,250,000
281,250
375,000
468,750
562,500
656,250
1,500,000
337,500
450,000
562,500
675,000
787,500
Annual
Covered
Compensation
Years of Service15
20
25
30
35
$100,000
$ 22,500
$ 30,000
$ 37,500
$ 45,000
$ 52,500
200,000
45,000
60,000
75,000
90,000
105,000
300,000
67,500
90,000
112,500
135,000
157,500
400,000
90,000
120,000
150,000
180,000
210,000
500,000
112,500
150,000
187,500
225,000
262,500
650,000
146,250
195,000
243,750
292,500
341,250
950,000
213,750
285,000
356,250
427,500
498,750
All of the Named Executive OfficersSupplemental Retirement Plan (SRP).Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy participate inathe Supplemental RetirementIncomePlanaof Entergy Corporation and Subsidiaries. Executives may participate in the SRP, which is an unfunded defined benefit plan, at the invitation of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy. Mr. Packer is the only named executive officer who is currently a participant in the plan. The SRP provides that,providesunder certain circumstances, a participant may receive a monthly retirement benefit payment foremployees120 months. The amount of monthly payment shall not exceed 2.5% of the participant's average basic annual pay (as defined in the SRP).System Executive Retirement Plan (SERP).This executive plan is an unfunded defined benefit plan for participating executives, including all of the executive officers named in the Summary Compensation Table (except for Mr. Leonard, who receives non-qualified supplemental retirement benefits under the terms of his retention contract, which are described below). Executive officers can choose, at retirement,
from Entergy based upon (1) generally allbetween the retirement benefits paid under the SERP or those payable under the non-qualified supplemental retirement plans discussed above, and in which they participate. SERP benefits are calculated by multiplying the covered pay times the maximum pay replacement ratios of 55%, 60% or 65% (dependent on job rating at retirement) that are attained at 30 years of credited service. The current maximum pay replacement ratio at 20 years of credited servicebeginningfor Ms. Conley, Mr. Denault, Mr. Savoff, Mr. Smith and Mr. Taylor is 50%. The current maximum pay replacement rat io atage 21 throughtermination, with a forty-year maximum, multiplied by (2) 1.5%, multiplied by (3) the final average compensation. Final average compensation20 years of credited service for Mr. Domino, Mr. McDonald, Mr. Packer and Ms. Shanks isbased on the highest consecutive 60 months45%. The ratios are reduced for each year ofcovered compensation in the last 120 months of service.employment below 30 years. The normal form of benefit for a single employee is a lifetime annuity, and for a married employee is a50% joint and survivor annuity. Other actuarially equivalent options are available to each retiree. Retirement benefits are not subject to any deduction for Social Security or other offset amounts. The amount of the Named Executive Officers' annual compensation covered by the plan as of December 31, 2002, is represented by the salary column in the Summary Compensation Table above.
The credited years of service under the Retirement Income Plan, as of December 31, 2002, for the following Named Executive Officers is as follows: Mr. Domino 32; Mr. Jackson 23; Mr. Leonard 4; Mr. McDonald 20; Mr. Packer 20; Ms. Shanks 19; and Mr. Yelverton 23. The credited years of service under the Retirement Income Plan, as of December 31, 2002 for the following Named Executive Officers, as a result of entering into supplemental retirement agreements, is as follows: Ms. Conley 20; Mr. Hintz 31; and Mr. Wilder 19.
The maximum benefit under the Retirement Income Plan is limited by Sections 401 and 415 of the Internal Revenue Code of 1986, as amended; however, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy have elected to participate in the Pension Equalization Plan sponsored by Entergy Corporation. Under this plan, certain executives, including the Named Executive Officers, would receive an additional amount equal to the benefit that would have been payable under the Retirement Income Plan, except for the Sections 401 and 415 limitations discussed above.
In addition to the Retirement Income Plan discussed above, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy participate inthe Supplemental Retirement Plan of Entergy Corporation and Subsidiaries and the Post-Retirement Plan of Entergy Corporation and Subsidiaries. Participation is limited to one of these two plans and is at the invitation of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy. The participant may receive from the appropriate Entergy company a monthly benefit payment not in excess of .025 (under the Supplemental Retirement Plan) or .0333 (under the Post-Retirement Plan) times the participant's average basic annual salary (as defined in the plans) for a maximum of 120 months. Mr. Hintz, Mr. Packer and Mr. Yelverton have entered into a Supplemental Retirement Plan participation contract, and Mr. Jackson has entered into a Post-Retirement Plan part icipation contract. Current estimates indicate that the annual payments to each Named Executive Officer under the above plans would be less than the payments to that officer under the System Executive Retirement Plan discussed below.
System Executive Retirement Plan Table (1)
Annual
Covered
Compensation
Years of Service10
15
20
25
30+
$ 200,000
$ 60,000
$ 90,000
$ 100,000
$ 110,000
$ 120,000
300,000
90,000
135,000
150,000
165,000
180,000
400,000
120,000
180,000
200,000
220,000
240,000
500,000
150,000
225,000
250,000
275,000
300,000
600,000
180,000
270,000
300,000
330,000
360,000
700,000
210,000
315,000
350,000
385,000
420,000
1,000,000
300,000
450,000
500,000
550,000
600,000
(1) Covered pay includes the average of the highest three years of annual base pay and incentive awards earned by the executive during the ten years immediately preceding his retirement. Benefits shown are based on a target replacement ratio of 50% based on the years of service and covered compensation shown. The benefits for 10, 15, and 20 or more years of service at the 45% and 55% replacement levels would decrease (in the case of 45%) or increase (in the case of 55%) by the following percentages: 3.0%, 4.5%, and 5.0%, respectively.
In 1993, Entergy Corporation adopted the System Executive Retirement Plan (SERP). This plan was amended in 1998. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are participating employers in the SERP. The SERP is an unfunded defined benefit plan offered at retirement to certain senior executives, which would currently include all the Named Executive Officers (except for Mr. Leonard). Participating executives choose, at retirement, between the retirement benefits paid under provisions of the SERP or those payable under the Supplemental Retirement Plan or the Post-Retirement Plan discussed above. The plan was amended in 1998 to provide that covered pay is the average of the highest three years annual base pay and incentive awards earned by the executive during the ten years immediately preceding his retirement. Benefits paid under the SERP are calculated by multiplying the covered pay times target pay replacement ratios (45%, 50%, or 55%, dependent on job rating at retirement) that are attained, according to plan design, at 20 years of credited service. The target ratios are increased by 1% for each year of service over 20 years, up to a maximum of 30 years of service. In accordance with the SERP formula, the target ratios are reduced for each year of service below 20 years. The credited years of service under this plan are identical to the years of service for Named Executive Officers (other than Ms. Conley, Mr. Jackson, Mr. Wilder and Mr. Yelverton) disclosed above in the section entitled "Pension Plan Tables-Retirement Income Plan Table". Ms. Conley, Mr. Jackson, Mr. Wilder, and Mr. Yelverton have 3 years, 29 years, 4 years, and 33 years, respectively, of credited service under this plan.
The amended plan provides that a single employee receives a lifetime annuity and a married employee receives thereduced benefit with a 50% surviving spouse annuity.Other actuarially equivalent options are available to each retiree. SERP benefits areThese retirement payments may be offset by any and all defined benefit plan payments fromEntergy. SERP benefitsthe Company and from prior employers. These payments are not subject toSocial Securitysocial security offsets.
Eligibility for and receiptReceipt of benefits under any of theexecutivesupplemental retirement plans described aboveareis contingent upon several factors. The participant must agree, without the specific consent of the Entergy company for which such participant was last employed, not to take employment after retirement with any entity that is in competition with, or similar in nature to, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy or any affiliate thereof. Eligibility for benefits is forfeitable for various reasons, including violation of an agreement with Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy,certain resignationsor for resignation or termination of employment for any reason before orcertain terminations of employmentafter normal retirement age and withoutCompanythe employer's permission.The credited years of service for the Named Executive Officers under the SERP are as follows: Ms. Conley (5), Mr. Denault (5), Mr. Domino (34), Mr. McDonald (22), Mr. Packer (22), Mr. Savoff (1), Ms. Shanks (21), Mr. Smith (5), and Mr. Taylor (14). Mr. Hintz retired in 2004 with 32 credited years of service under the SERP.
Upon retirement, and subject to existing deferral elections and the provisions of Internal Revenue Code Section 409A, executives are able to receive the value of their SERP, SRP, or PEP benefit paid either as a lump sum or a series of annual payments. The following table shows the annual retirement benefits that would be paid at normal retirement (age 65 or later) under the SERP.
SystemExecutive Retirement Plan Table (1)
Annual
Covered
Years of Service
Compensation
10
15
20
25
30+
$250,000
$75,000
$112,500
$125,000
$137,500
$150,000
500,000
150,000
225,000
250,000
275,000
300,000
750,000
225,000
337,500
375,000
412,500
450,000
1,000,000
300,000
450,000
500,000
550,000
600,000
1,500,000
450,000
675,000
750,000
825,000
900,000
2,000,000
600,000
900,000
1,000,000
1,100,000
1,200,000
2,500,000
750,000
1,125,000
1,250,000
1,375,000
1,500,000
3,000,000
900,000
1,350,000
1,500,000
1,650,000
1,800,000
(1)
Covered pay includes the average of the highest three years of annual base pay and incentive awards earned by the executive during the ten years immediately preceding his retirement. Benefits shown are based on a target replacement ratio of 50% based on the years of service and covered compensation shown. The benefits for 10, 15, and 20 or more years of service at the 45% and 55% replacement levels would decrease (in the case of 45%) or increase (in the case of 55%) by the following percentages: 3.0%, 4.5%, and 5.0%, respectively.
System Executive Continuity Plans. All Named Executive Officers participate in one of Entergy's two System Executive Continuity Plans. However, if Mr. Leonard receives benefits under the change in control protections of his retention contract, which is described below, he will not also receive benefits under the Continuity Plans. Each plan provides severance pay and benefits under specified circumstances following a change in control. In the event a participant's employment is involuntarily terminated without cause or if a participant terminates for good reason during the change in control period, the named executive officers will be entitled to:
Participants in the Continuity Plans are subject to post-employment restrictive covenants, including noncompetition provisions that run for two years for Named Executive Officers but extend to three years if permissible under applicable law.
Deferred Compensation Plans. Executives are eligible to defer earned income through participation in Entergy's Executive Deferred Compensation Plan ("EDCP") or by purchasing phantom units of Entergy stock at fair market value under the Equity Ownership Plan ("EOP"). Executives may under the EDCP defer receipt of base salary, amounts due under the executive plans described above, annual bonuses, performance units, and approved incentive compensation such as restricted units and signing bonuses. The investment options available to executives under the EDCP are similar to those currently available under the Savings Plan of Entergy Corporation and Subsidiaries, except that executives may not invest in Entergy stock under the EDCP. Executives may under the EOP defer receipt of annual bonuses, performance units, restricted units, and pre-2003 option gains.
Compensation of Directors
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. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy currently have no non-employee directors, and none of the current directors of these companies
(1) Covered pay includes the average of the highest three years of annual base pay and incentive awards earned by the executive during the ten years immediately preceding his retirement. Benefits shown are based on a target replacement ratio of 50% based on the years of service and covered compensation shown. The benefits for 10, 15, and 20 or more years of service at the 45% and 55% replacement levels would decrease (in the case of 45%) or increase (in the case of 55%) by the following percentages: 3.0%, 4.5%, and 5.0%, respectively.
In 1993, Entergy Corporation adopted the System Executive Retirement Plan (SERP). This plan was amended in 1998. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are participating employers in the SERP. The SERP is an unfunded defined benefit plan offered at retirement to certain senior executives, which would currently include all the Named Executive Officers (except for Mr. Leonard). Participating executives choose, at retirement, between the retirement benefits paid under provisions of the SERP or those payable under the Supplemental Retirement Plan or the Post-Retirement Plan discussed above. The plan was amended in 1998 to provide that covered pay is the average of the highest three years annual base pay and incentive awards earned by the executive during the ten years immediately preceding his retirement. Benefits paid under the SERP are calculated by multiplying the covered pay times target pay replacement ratios (45%, 50%, or 55%, dependent on job rating at retirement) that are attained, according to plan design, at 20 years of credited service. The target ratios are increased by 1% for each year of service over 20 years, up to a maximum of 30 years of service. In accordance with the SERP formula, the target ratios are reduced for each year of service below 20 years. The credited years of service under this plan are identical to the years of service for Named Executive Officers (other than Ms. Conley, Mr. Jackson, Mr. Wilder and Mr. Yelverton) disclosed above in the section entitled "Pension Plan Tables-Retirement Income Plan Table". Ms. Conley, Mr. Jackson, Mr. Wilder, and Mr. Yelverton have 3 years, 29 years, 4 years, and 33 years, respectively, of credited service under this plan.
The amended plan provides that a single employee receives a lifetime annuity and a married employee receives the reduced benefit with a 50% surviving spouse annuity. Other actuarially equivalent options are available to each retiree. SERP benefits are offset by any and all defined benefit plan payments from Entergy. SERP benefits are not subject to Social Security offsets.
Eligibility for and receipt of benefits under any of the executive plans described above are contingent upon several factors. The participant must agree, without the specific consent of the Entergy company for which such participant was last employed, not to take employment after retirement with any entity that is in competition with, or similar in nature to, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy or any affiliate thereof. Eligibility for benefits is forfeitable for various reasons, including violation of an agreement with Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, certain resignations of employment, or certain terminations of employment without Company permission.
Compensation of Directors
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. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy currently have no non-employee directors, and none of the current directors of these companiesare compensated for their responsibilities as director.
Retired non-employee directors of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans with a minimum of five years of service on the respective Boards of Directors are paid $200 a month for a term of years corresponding to the number of years of active service as directors. Retired non-employee directors with over ten years of service receive a lifetime benefit of $200 a month. Years of service as an advisory director are included in calculating this benefit. System Energy has no retired non-employee directors.
Retired non-employee directors of Entergy Gulf States receive retirement benefits under a plan in which all directors who served continuously for a period of years will receive a percentage of their retainer fee in effect at the time of their retirement for life. The retirement benefit is 30 percent of the retainer fee for service of not less than five nor more than nine years, 40 percent for service of not less than ten nor more than fourteen years, and 50 percent for fifteen or more years of service. For those directors who retired prior to the retirement age, their benefits are reduced. The plan also provides disability retirement and optional hospital and medical coverage if the director has served at least five years prior to the disability. The retired director pays one-third of the premium for such optional hospital and medical coverage and Entergy Gulf States pays the remaining two-thirds. Years of service as ana n advisory director are included in calculating this benefit.
Executive Employment Contracts and Retention and Employment Agreements and Change-in-Control Arrangements
Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy
Upon completion of a transaction resulting in a change-in-control of Entergy (a "Merger"), benefits already accrued under Entergy's System Executive Retirement Plan, Post-Retirement Plan, Supplemental Retirement Plan and Pension Equalization Plan, and awards granted under the EOP, will become fully vested if the participant is involuntarily terminated without "cause" or terminates employment for "good reason" (as such terms are defined in such plans).
Retention Agreement with Mr. Leonard - Mr. Leonard's retention agreement provides that if he terminates his employment following his attainment of age 55, with or without "good reason" and except for "cause," he will be entitled to a non-qualified supplemental retirement benefit in lieu of participation in the Company's non-qualified supplemental retirement plans such as the SERP, the SRP, or the PEP. Mr. Leonard will reach age 55 during the 2005 calendar year. If Mr. Leonard's employment is terminated by Entergy for "cause" at any time, before or after his attainment of age 55, he will forfeit his non-qualified supplemental retirement benefit. However, if Mr. Leonard were to leave without "cause" on or after his attainment of age 55, he would be entitled to receive this benefit, plus:
Mr. Leonard's non-qualified supplemental retirement benefit is calculated as a single life annuity equal to 60% of his final monthly compensation (as defined under the SERP), reduced to account for benefits payable to Mr. Leonard under the Company's and a former employer's qualified pension plans. As of December 31, 2004, his final monthly compensation was $191,228 which amount would provide for a single life annuity of approximately $1,376,842 per year as his non-qualified supplemental retirement benefit, subject to the offsets described above. The benefit is payable in a single lump sum, or as periodic payments, at his discretion. If elected, periodic payments will be due for Mr. Leonard's life, and then a reduced benefit of 50% will be due for the life of his spouse.
Upon attainment of 10 years of service with the Company, which will occur in 2008, Mr. Leonard would qualify for retirement under certain Company plans. At this point, he would become eligible to receive additional benefits comparable to those available to other retirees of the Company, such as accelerated vesting of stock options, an extended period to exercise those options, pro-rated payment of annual and long-term incentive awards, and continued health and welfare coverage to the extent available.
The retention agreement with Mr. Leonard further provides that, subject to certain forfeiture provisions, upon a termination of employment while a Merger is pending (a) by Entergy without "cause" or by Mr. Leonard for "good reason", as such terms are defined in the agreement, other than a termination of employment described in the next paragraph, or (b) by reason of Mr. Leonard's death or disability:
If Mr. Leonard's employment is terminated by Entergy for "cause" at any time, or by Mr. Leonard without "good reason" and without Entergy's permission prior to his attainment of age 55, Mr. Leonard will forfeit his supplemental retirement benefit. If Mr. Leonard's employment is terminated by Mr. Leonard without "good reason" with Entergy's permission prior to his attainment of age 55, Mr. Leonard will be entitled to a supplemental retirement benefit, reduced by 6.5% for each year that the termination date precedes his attainment of age 55, payable commencing upon Mr. Leonard's attainment of age 62. If Mr. Leonard's employment is terminated by Mr. Leonard without "good reason" following his attainment of age 55, Mr. Leonard will be entitled to his full supplemental retirement benefit. The amounts payable under the agreement will be funded in a rabbi trust.
Retention agreement with Mr. Hintz - The retention agreement with Mr. Hintz provides that Mr. Hintz will be paid an initial retention payment of approximately $2.8 million on the date on which a Merger is completed and an additional retention payment of approximately $2.3 million on the second anniversary of the completion of a Merger if he remains employed on each of those dates. The agreement also provides that upon termination of employment while a Merger is pending and for two years after completion (a) by Mr. Hintz for "good reason" or by Entergy without "cause", as such terms are definedcertain adjustments in the agreement or (b) by reasoncase of Mr. Hintz's death or disability:
Retention Agreement with Mr. Jackson - The retention agreement with Mr. Jackson provides that upon retirement in accordance with the agreement, Mr. Jackson: (a) will be entitled to a subsidized retirement benefit equal to the applicable nonqualified retirement benefit payable to Mr. Jackson without reduction for early retirement ("Subsidized Retirement Benefit"); and (b) may enter into a consulting arrangement with Entergy through March 31, 2005, under terms and conditions set forth in the agreement.
Pursuant to the agreement, should Mr. Jackson experience a Qualifying Event (as defined in the agreement) after the Successor Placement Date (as defined in the agreement) but before March 31, 2003, he shall not be entitled to benefits under the System Executive Continuity Plan but shall instead be entitled to the following:
Additionally, Mr. Jackson is entitled to certain benefits, as described in the agreement, in the event of a change in control (as defined in the System Executive Continuity Plan) after which Entergy or its successor company fails to honor Mr. Jackson's consulting arrangement.
Retention Agreement with Mr. Wilder - The retention agreement with Mr. Wilder provides that if Mr. Wilder terminates his employment without "good reason" and prior to a termination for "cause," as those terms are defined in his agreement, Entergy will pay to him a lump sum cash severance payment equal to three times the sum of his base salary and target annual award and a "gross-up" payment in respect of any excise taxes he might incur.
The agreement also provides that, as a substitute for the above entitlement, upon termination of employment (a) by Mr. Wilder for "good reason" or by Entergy without "cause", as such terms are defined in the agreement, in each case prior to the termination of a Merger or prior to the second anniversary of the completion of a Merger, (b) by reason of Mr. Wilder's death or disability while a Merger is pending and for two years after completion of a Merger or (c) for any reason following the second anniversary of a Merger:
If Mr. Wilder terminatesEmployment Agreement with Ms. Shanks - The employment without good reason and other than on account of death or disability, on or after the completion of a Merger and before the second anniversary of the completion of a Merger:
During the term of the agreement, Ms. Shanks may resign, or Entergy may terminate her for "cause," as defined in the Fortune Global 500 Indexagreement. In either of those events, Ms. Shanks is due no additional compensation or (c) his employment with any company that hasbenefits under the agreement. If there is a conflict"change in control" before October of interest policy that would prohibit his continued employment with Entergy;
2011, she remains eligible for benefits under the System Executive Continuity Plan. If the change in control occurs while Ms. Shanks is a special project coordinator, and Entergy's obligations under this agreement are breached, she receives:
Retention Agreementagreement with Mr. YelvertonSmith - The retention agreement with Mr. YelvertonSmith provides that heMr. Smith will be paid casha retention paymentspayment of $680,000approximately $525,000 on each of the first three anniversaries of the completion ofdate on which a Merger is completed, if he remains employed on each of those dates. The agreement also provides that upon termination of employment while a Merger is pending and for three years after completion (a) by Mr. YelvertonSmith for "good reason" or by Entergy without "cause", as such terms are defined in the agreement or (b) by reason of Mr. Yelverton'sSmith's death or disability:
System Executive Continuity Plan - Ms. Conley, Mr. Domino, Mr. McDonald, Mr. Packer and Ms. Shanks are participants in Entergy's System Executive Continuity Plan, which provides severance pay and benefits under specified circumstances following a change in control. In the event a participant's employment is involuntarily terminated without cause or if a participant terminates for good reason during the change in control period, the participant will be entitled to:
Participants in the Continuity Plan are subject to post-employment restrictive covenants, including noncompetition provisions, which run for two years for executive officers, but extend to three years if permissible under applicable law.
Personnel Committee Interlocks and Insider Participation
The compensation of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy executive officers was set by the Personnel Committee of Entergy Corporation's Board of Directors, composed solely of Directors of Entergy Corporation.
Item 12.Security Ownership of Certain Beneficial Owners and Management
Entergy Corporation owns 100% of the outstanding common stock of registrants Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy. 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 "Stockholders Who Own at Least Five 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.
As of December 31, 2002,2004, the directors, the Named Executive Officers, and the directors and officers as a group for Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, respectively, beneficially owned directly or indirectly common stock of Entergy Corporation as indicated:
Entergy Corporation | ||||||
Amount of Nature of | ||||||
| Sole Voting |
|
| |||
Entergy Corporation | ||||||
Maureen S. Bateman* | 2,700 | - | 3,200 | |||
W. Frank Blount* | 9,384 | - | 13,600 | |||
Simon D. deBree* | 1,442 | - | 2,400 | |||
Claiborne P. Deming* | 6,700 | - | 1,600 | |||
Leo P. Denault** | 951 | 52,423 | 48,924 | |||
Alexis Herman* | 900 | - | 800 | |||
Donald C. Hintz*** | 4,963 | 630,000 | 87,605 | |||
J. Wayne Leonard*** | 13,433 | 1,376,800 | 150,731 | |||
Robert v.d. Luft* | 24,472 | 285,667 | 9,600 | |||
Kathleen A. Murphy* (e) | 2,700 | 1,000 | 3,200 | |||
Dr. Paul W. Murrill* (d) | 2,915 | - | 14,400 | |||
James R. Nichols* (e) | 8,910 | 3,684 | 14,400 | |||
William A. Percy, II* | 2,950 | - | 3,200 | |||
Dennis H. Reilley* (d) | 600 | - | 4,000 | |||
Mark T. Savoff** | 174 | - | 207 | |||
Robert D. Sloan** | 309 | 4,033 | 217 | |||
Richard J. Smith** | 1,658 | 190,538 | 56,875 | |||
Wm. Clifford Smith* | 12,988 | - | 16,800 | |||
Bismark A. Steinhagen* (e) | 9,424 | 2,623 | 24,000 | |||
C. John Wilder** | - | - | - | |||
Steven V. Wilkinson* | 750 | - | 800 | |||
All directors and executive | ||||||
officers | 118,815 | 2,979,314 | 537,451 |
Entergy Corporation | ||||||
Amount of Nature of | ||||||
| Sole Voting |
|
| |||
Entergy Arkansas | ||||||
Leo P. Denault*** | 951 | 52,423 | 48,924 | |||
Donald C Hintz** | 4,963 | 630,000 | 87,605 | |||
J. Wayne Leonard** | 13,433 | 1,376,800 | 150,731 | |||
Hugh T. McDonald*** | 4,733 | 53,999 | 25,967 | |||
Mark T. Savoff*** | 174 | - | 207 | |||
Richard J. Smith*** | 1,658 | 190,538 | 56,875 | |||
C. John Wilder** | - | - | - | |||
All directors and executive | ||||||
officers | 37,483 | 2,759,540 | 451,418 | |||
Entergy Gulf States | ||||||
E. Renae Conley*** | 1,843 | 107,192 | 40,402 | |||
Leo P. Denault*** | 951 | 52,423 | 48,924 | |||
Joseph F. Domino*** | 8,125 | 50,809 | 24,377 | |||
Donald C. Hintz** | 4,963 | 630,000 | 87,605 | |||
J. Wayne Leonard** | 13,433 | 1,376,800 | 150,731 | |||
Mark T. Savoff*** | 174 | - | 207 | |||
Richard J. Smith*** | 1,658 | 190,538 | 56,875 | |||
C. John Wilder** | - | - | - | |||
All directors and executive | ||||||
officers | 42,718 | 2,863,542 | 490,230 | |||
Entergy Louisiana | ||||||
E. Renae Conley*** | 1,843 | 107,192 | 40,402 | |||
Leo P. Denault*** | 951 | 52,423 | 48,924 | |||
Donald C. Hintz** | 4,963 | 630,000 | 87,605 | |||
J. Wayne Leonard** | 13,433 | 1,376,800 | 150,731 | |||
Mark T. Savoff*** | 174 | - | 207 | |||
Richard J. Smith*** | 1,658 | 190,538 | 56,875 | |||
C. John Wilder** | - | - | - | |||
All directors and executive | ||||||
officers | 34,593 | 2,812,733 | 465,853 | |||
Entergy Mississippi | ||||||
Leo P. Denault*** | 951 | 52,423 | 48,924 | |||
Donald C. Hintz** | 4,963 | 630,000 | 87,605 | |||
J. Wayne Leonard** | 13,433 | 1,376,800 | 150,731 | |||
Mark T. Savoff*** | 174 | - | 207 | |||
Carolyn C. Shanks*** | 4,999 | 29,333 | 15,698 | |||
Richard J. Smith*** | 1,658 | 190,538 | 56,875 | |||
C. John Wilder** | - | - | - | |||
All directors and executive | ||||||
officers | 37,749 | 2,734,874 | 441,149 |
Entergy Corporation | Entergy Corporation | ||
Name | Sole Voting |
| |
Entergy Corporation | |||
Maureen S. Bateman* | 1,500 | - | 1,600 |
W. Frank Blount* | 8,034 | - | 12,000 |
George W. Davis* | 2,700 | - | 3,200 |
Simon D. deBree* | 568 | - | 800 |
Claiborne P. Deming* | 500 | - | - |
Frank F. Gallaher** | 8,519 | 63,167 | 66,097 |
Alexis Herman* | (f) | - | - |
Donald C. Hintz** | 4,055 | 549,499 | 52,192 |
Jerry D. Jackson** | 22,083 | 181,136 | 47,374 |
J. Wayne Leonard*** | 13,065 | 916,200 | 496 |
Robert v.d. Luft* | 23,272 | 268,998 | 8,000 |
Kathleen A. Murphy* | 1,500 | 1,000 (e) | 1,600 |
Paul W. Murrill* | 2,740 (d) | - | 12,800 |
James R. Nichols* | 10,673 | - | 12,800 |
William A. Percy, II* | 1,750 | - | 1,600 |
Dennis H. Reilley* | 600 (d) | - | 2,400 |
Wm. Clifford Smith* | 11,335 | - | 15,200 |
Bismark A. Steinhagen* | 8,224 | 2,623 (e) | 22,400 |
C. John Wilder** | 798 | 163,524 | 119,673 |
All directors and executive | |||
officers | 137,842 | 2,591,229 | 532,251 |
Entergy Corporation | ||||||
Amount of Nature of | ||||||
| Sole Voting |
|
| |||
Entergy New Orleans | ||||||
Leo P. Denault*** | 951 | 52,423 | 48,924 | |||
Donald C. Hintz** | 4,963 | 630,000 | 87,605 | |||
J. Wayne Leonard** | 13,433 | 1,376,800 | 150,731 | |||
Daniel F. Packer*** | 543 | 40,133 | 5,446 | |||
Mark T. Savoff*** | 174 | - | 207 | |||
Richard J. Smith*** | 1,658 | 190,538 | 56,875 | |||
C. John Wilder** | - | - | - | |||
All directors and executive | ||||||
officers | 33,293 | 2,745,674 | 430,897 | |||
System Energy | ||||||
Leo P. Denault*** | 951 | 52,423 | 48,924 | |||
Donald C. Hintz** | 4,963 | 630,000 | 87,605 | |||
J. Wayne Leonard** | 13,433 | 1,376,800 | 150,731 | |||
Steven C. McNeal* | 5,237 | 19,000 | 3,624 | |||
Mark T. Savoff** | 174 | - | 207 | |||
Richard J. Smith** | 1,658 | 190,538 | 56,875 | |||
Gary J. Taylor*** | 1,198 | 79,200 | 12,094 | |||
C. John Wilder** | - | - | - | |||
All directors and executive | ||||||
officers | 38,307 | 2,727,108 | 429,075 |
Entergy Corporation | Entergy Corporation | ||
Name | Sole Voting |
| |
Entergy Arkansas | |||
Donald C Hintz*** | 4,055 | 549,499 | 52,192 |
Jerry D. Jackson** | 22,083 | 181,136 | 47,374 |
J. Wayne Leonard** | 13,065 | 916,200 | 496 |
Hugh T. McDonald*** | 4,122 | 48,300 | 6,786 |
Richard J. Smith* | 574 | 111,201 | 25,364 |
C. John Wilder*** | 798 | 163,524 | 119,673 |
All directors and executive | |||
officers | 77,397 | 2,376,306 | 440,436 |
Entergy Gulf States | |||
E. Renae Conley*** | 1,444 | 63,899 | 17,100 |
Joseph F. Domino*** | 11,889 | 52,186 | 11,833 |
Donald C. Hintz*** | 4,055 | 549,499 | 52,192 |
Jerry D. Jackson** | 22,083 | 181,136 | 47,374 |
J. Wayne Leonard** | 13,065 | 916,200 | 496 |
Richard J. Smith* | 574 | 111,201 | 25,364 |
C. John Wilder*** | 798 | 163,524 | 119,673 |
All directors and executive | |||
officers | 96,542 | 2,531,339 | 464,678 |
Entergy Louisiana | |||
E. Renae Conley*** | 1,444 | 63,899 | 17,100 |
Donald C. Hintz*** | 4,055 | 549,499 | 52,192 |
Jerry D. Jackson** | 22,083 | 181,136 | 47,374 |
J. Wayne Leonard** | 13,065 | 916,200 | 496 |
Richard J. Smith* | 574 | 111,201 | 25,364 |
C. John Wilder*** | 798 | 163,524 | 119,673 |
All directors and executive | |||
officers | 80,682 | 2,445,020 | 452,571 |
Entergy Mississippi | |||
Donald C. Hintz*** | 4,055 | 549,499 | 52,192 |
Jerry D. Jackson** | 22,083 | 181,136 | 47,374 |
J. Wayne Leonard** | 13,065 | 916,200 | 496 |
Carolyn C. Shanks*** | 4,371 | 23,199 | 3,043 |
Richard J. Smith* | 574 | 111,201 | 25,364 |
C. John Wilder*** | 798 | 163,524 | 119,673 |
All directors and executive | |||
officers | 80,522 | 2,370,341 | 439,263 |
* | Director of the respective Company |
** | Named Executive Officer of the respective Company |
*** | Director and Named Executive Officer of the respective Company |
Entergy Corporation | Entergy Corporation | ||
Name | Sole Voting |
| |
Entergy New Orleans | |||
Donald C. Hintz*** | 4,055 | 549,499 | 52,192 |
Jerry D. Jackson** | 22,083 | 181,136 | 47,374 |
J. Wayne Leonard** | 13,065 | 916,200 | 496 |
Daniel F. Packer*** | 3,691 | 23,199 | 3,884 |
Richard J. Smith* | 574 | 111,201 | 25,364 |
C. John Wilder*** | 798 | 163,524 | 119,673 |
All directors and executive | |||
officers | 71,774 | 2,328,340 | 437,529 |
System Energy | |||
Donald C. Hintz*** | 4,055 | 549,499 | 52,192 |
Jerry D. Jackson** | 22,083 | 181,136 | 47,374 |
J. Wayne Leonard** | 13,065 | 916,200 | 496 |
C. John Wilder*** | 798 | 163,524 | 119,673 |
Jerry W. Yelverton*** | 9,312 | 69,634 | 19,088 |
All directors and executive | |||
officers | 65,438 | 2,025,817 | 283,099 |
(a) | Based on information furnished by the respective individuals. Except as noted, each individual has sole voting and investment power. The number of shares of Entergy Corporation common stock owned by each individual and by all directors and executive officers as a group does not exceed one percent of the outstanding Entergy Corporation common stock. |
(b) | Other Beneficial Ownership includes, for the Named Executive Officers, shares of Entergy Corporation common stock that may be acquired within 60 days after December 31, 2004, in the form of unexercised stock options awarded pursuant to the Equity Ownership Plan. |
(c) | Represents the balances of stock equivalent units each executive holds under the deferral provisions of the Equity Ownership Plan and the Defined Contribution Restoration Plan. These units will be paid out in a combination of Entergy Corporation Common Stock and cash based on the value of Entergy Corporation Common Stock on the date of payout. The deferral period is determined by the individual and is at least two years from the award of the bonus. For directors of Entergy Corporation the stock equivalent units are part of the Service Award for Directors. All non-employee directors are credited with units for each year of service on the Board. |
(d) | Dr. Murrill and Mr. Reilley have deferred receipt of an additional 5,100 shares and 2,100 shares, respectively. |
Includes 1,000 shares in which Ms. Murphy has joint ownership, 2,623 shares for Mr. Steinhagen that are in his wife's name, and 3,684 shares for Mr. Nichols that are owned by a charitable foundation that he controls. |
* Director of the respective Company
** Named Executive Officer of the respective Company
*** Director and Named Executive Officer of the respective Company
Equity Compensation Plan Information
Entergy has two plans that grant stock options, equity awards, and incentive awards to key employees of the Entergy subsidiaries. The Equity Ownership Plan is a shareholder-approved stock-based compensation plan. The Equity Awards Plan is a Board-approved stock-based compensation plan. The following table summarizes information about Entergy's stock options awarded under these plans.plans as of December 31, 2004.
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|
| Number of Securities Remaining Available forFuture Issuance | Number of Securities to be Issued Upon Exercise of Outstanding Options | Weighted Average Exercise Price |
| |||
Equity Ownership Plan | 3,963,349 | $ 34.96 | 8,614,275 | ||||||
Equity Awards Plan | 15,979,765 | 36.07 | 5,671,792 | ||||||
Equity compensation plans |
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Equity compensation plans not |
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| ||||||
Total | 19,943,114 | $ 35.85 | 14,286,067 | 12,310,077 | $41.88 | 5,582,403 |
(a) | Effective upon the May 9, 2003 stockholder re-approval of the Equity Ownership Plan, the Board directed that no further awards be issued under the Equity Awards Plan. As of May 9, 2003, 4,076,628 shares were available for issuance under the Equity Awards Plan. |
Item 13.Certain Relationships and Related Transactions
During 2002,2004, T. Baker Smith & Son, Inc. performed land-surveying services for, and received payments of approximately $287,000$735,856 from Entergy companies. Mr. Wm. Clifford Smith, a director of Entergy Corporation, is Chairman of the Board of T. Baker Smith & Son, Inc. Mr. Smith's children own 100% of the voting stock of T. Baker Smith & Son, Inc.
See Item 10, "Directors and Executive Officers of the Registrants," for information on certain relationships and transactions required to be reported under this item.
Other than as provided under applicable corporate laws, Entergy does not have policies whereby transactions involving Entergy's Code of Business Conduct and Ethics for Employees provides that any waiver of that Code for executive officers, and directors are approvedincluding a waiver of a conflict of interest, can be made only by the Board, or if the Board so chooses, by a majoritycommittee of disinterested directors. However, pursuantindependent directors, and must be promptly disclosed to Entergy's shareholders. Entergy's Code of Business Conduct and Ethics for Members of the Board of Directors provides that any waiver of that Code, including any waiver of a conflict of interest, can be made only by the Board, following a recommendation by the Corporate Governance Committee, and must be promptly disclosed to Entergy's shareholders.
Item 14.Principal Accountant Fees and Services(Entergy Corporation, CodeEntergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
Aggregate fees billed to Entergy Corporation (consolidated), Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy for the years ended December 31, 2004 and 2003 by Deloitte & Touche LLP, the member firms of Conduct, transactions involving an Entergy companyDeloitte Touche Tohmatsu, and its executive officers must have prior approval by the next higher reporting level of that individual, and transactions involving an Entergy company and its directors must be reported to the secretary of the appropriate Entergy company.their respective affiliates (collectively, "Deloitte & Touche"), which includes Deloitte Consulting were as follows:
2004 | 2003 | |||
Entergy Corporation (consolidated) | ||||
Audit Fees | $6,289,500 | $3,244,750 | ||
Audit-Related Fees (a) | 950,900 | 690,665 | ||
Total audit and audit-related fees | 7,240,400 | 3,935,415 | ||
Tax Fees (b) | 62,820 | 119,802 | ||
All Other Fees (c) | - | 5,000 | ||
Total Fees (d) | $7,303,220 | $4,060,217 | ||
Entergy Arkansas | ||||
Audit Fees | $673,875 | $402,200 | ||
Audit-Related Fees (a) | 110,810 | 68,963 | ||
Total audit and audit-related fees | 784,685 | 471,163 | ||
Tax Fees | - | - | ||
All Other Fees (c) | - | - | ||
Total Fees (d) | 784,685 | $471,163 | ||
Entergy Gulf States | ||||
Audit Fees | $1,403,875 | $432,050 | ||
Audit-Related Fees (a) | 110,810 | 79,026 | ||
Total audit and audit-related fees | 1,514,685 | 511,076 | ||
Tax Fees | - | - | ||
All Other Fees | - | - | ||
Total Fees (d) | $1,514,685 | $511,076 | ||
Entergy Louisiana | ||||
Audit Fees | $718,875 | $355,800 | ||
Audit-Related Fees (a) | 110,810 | 69,617 | ||
Total audit and audit-related fees | 829,685 | 425,417 | ||
Tax Fees | - | - | ||
All Other Fees | - | - | ||
Total Fees (d) | $829,685 | $425,417 |
2004 | 2003 | |||
Entergy Mississippi | ||||
Audit Fees | $708,875 | $413,300 | ||
Audit-Related Fees (a) | 110,810 | 53,204 | ||
Total audit and audit-related fees | 819,685 | 466,504 | ||
Tax Fees | - | - | ||
All Other Fees | - | - | ||
Total Fees (d) | $819,685 | $466,504 | ||
Entergy New Orleans | ||||
Audit Fees | $708,875 | $365,800 | ||
Audit-Related Fees (a) | 183,710 | 147,855 | ||
Total audit and audit-related fees | 892,585 | 513,655 | ||
Tax Fees | - | - | ||
All Other Fees (c) | - | - | ||
Total Fees (d) | $892,585 | $513,655 | ||
System Energy | ||||
Audit Fees | $598,750 | $350,200 | ||
Audit-Related Fees (a) | 38,500 | 8,800 | ||
Total audit and audit-related fees | 637,250 | 359,000 | ||
Tax Fees | - | - | ||
All Other Fees | - | - | ||
Total Fees (d) | $637,250 | $359,000 |
(a) | Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services. |
(b) | Includes fees for tax return review and tax compliance assistance. |
(c) | Includes fees for assistance on regulatory matters. During 2003 the fees for other services were approved under the de minimis provision. |
(d) | 100% of fees paid in 2004 and 2003 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:
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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, Risk Management and General Auditor will be responsible for tracking all independent auditor fees and will report quarterly to the Audit Committee. |
PART IV
Item 14. Controls and Procedures
Within the 90-day period prior to the filing of this report, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy Resources (individually "Registrant" and collectively the "Registrants") management, including their respective Chief Executive Officers (CEO) and Chief Financial Officers (CFO). The evaluations assessed the effectiveness of the Registrants' disclosure controls and procedures. Based on the evaluations, each CEO and CFO has concluded that, as to the Registrant or Registrants for which they serve as CEO or CFO, the 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 Securiti es and Exchange Commission rules and forms. Subsequent to the date of the evaluations, there were no significant changes in the Registrants' internal controls or in other factors that could significantly affect the disclosure controls, including any corrective actions with regard to significant deficiencies and material weaknesses.
Item 15.Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)1. | Financial Statements and Independent Auditors' Reports for Entergy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are listed in the Table of Contents. |
(a)2. | Financial Statement Schedules |
(a)3. | Exhibits |
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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 |
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/ Nathan E. Langston | Senior Vice President and Chief Accounting Officer | March |
J. Wayne Leonard (Chief Executive Officer and Director; Principal Executive Officer); Robert v.d. Luft (Chairman of the Board and Director); C. John WilderLeo P. Denault (Executive Vice President and Chief Financial Officer; Principal Financial Officer); Maureen S. Bateman, W. Frank Blount, George W. Davis, Simon deBee, Claiborne P. Deming, NormanAlexis M. Herman, Donald C. Francis,Hintz, Kathleen A. Murphy, Paul W. Murrill, James R. Nichols, William A. Percy, II, Dennis H. Reilley, Wm. Clifford Smith, and Bismark A. Steinhagen, and Steven V. Wilkinson (Directors).
By: | March |
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. |
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/ Nathan E. Langston | Senior Vice President and Chief Accounting Officer | March 9, 2005 |
Hugh T. McDonald (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Jay A. Lewis (Vice President, Chief Financial Officer - - Utility Operations Group; Principal Financial Officer); Leo P. Denault, Mark T. Savoff, and Richard J. Smith (Directors).
By: /s/ Nathan E. Langston | March 9, 2005 |
ENTERGY GULF STATES, 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 GULF STATES, INC. |
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/ Nathan E. Langston | Senior Vice President and Chief Accounting Officer | March |
Hugh T. McDonaldJoseph F. Domino (Chairman of the Board, President, Chief Executive Officer,Officer-Texas, and Director; Principal Executive Officer); Theodore H. Bunting, Jr.E. Renae Conley (President, Chief Executive Officer-Louisiana, and Director; Principal Executive Officer); Jay A. Lewis (Vice President, and Chief Financial Officer;Officer - - Utility Operations Group; Principal Financial Officer); Donald C. Hintz,Leo P. Denault, Mark T. Savoff, and Richard J. Smith and C. John Wilder (Directors).
By: | March |
ENTERGY GULF STATES,LOUISIANA, 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 |
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/ Nathan E. Langston | Senior Vice President and Chief Accounting Officer | March |
Joseph F. DominoE. Renae Conley (Chairman of the Board, President, Chief Executive Officer-Texas,Officer, and Director; Principal Executive Officer); E. Renae Conley (President, Chief Executive Officer-Louisiana, and Director; Principal Executive Officer); Theodore H. Bunting, Jr.Jay A. Lewis (Vice President, and Chief Financial Officer;Officer - - Utility Operations Group; Principal Financial Officer); Donald C. Hintz,Leo P. Denault, Mark T. Savoff, and Richard J. Smith and C. John Wilder (Directors).
By: | March |
ENTERGY LOUISIANA,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 |
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/ Nathan E. Langston | Senior Vice President and Chief Accounting Officer | March |
E. Renae Conley (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Theodore H. Bunting, Jr. (Vice President and Chief Financial Officer; Principal Financial Officer); Donald C. Hintz, Richard J. Smith, and C. John Wilder (Directors).
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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.
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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.
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Carolyn C. Shanks (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Theodore H. Bunting, Jr.Jay A. Lewis (Vice President, and Chief Financial Officer;Officer - - Utility Operations Group; Principal Financial Officer); Donald C. Hintz,Leo P. Denault, Mark T. Savoff, and Richard J. Smith and C. John Wilder (Directors).
By: | March |
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. |
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/ Nathan E. Langston | Senior Vice President and Chief Accounting Officer | March |
Daniel F. Packer (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Theodore H. Bunting, Jr.Jay A. Lewis (Vice President, and Chief Financial Officer;Officer - - Utility Operations Group; Principal Financial Officer); Donald C. Hintz,Leo P. Denault, Mark T. Savoff, and Richard J. Smith and C. John Wilder (Directors).
By: | March |
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. |
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/ Nathan E. Langston | Senior Vice President and Chief Accounting Officer | March |
Jerry W. YelvertonGary J. Taylor (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); C. John Wilder (Executive ViceTheodore H. Bunting, Jr. (Vice President, Chief Financial Officer and Director;- Nuclear Operations; Principal Financial Officer); DonaldLeo P. Denault and Steven C. Hintz (Director)McNeal (Directors).
By: | March |
CERTIFICATIONS
I, J. Wayne Leonard, certify that:
1. I have reviewed this annual report on Form 10-K of Entergy Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
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Date: March 17, 2003
CERTIFICATIONS
I, C. John Wilder, certify that:
1. I have reviewed these annual reports on Form 10-K of Entergy Corporation and System Energy Resources, Inc.;
2. Based on my knowledge, these annual reports do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by these annual reports;
3. Based on my knowledge, the financial statements, and other financial information included in these annual reports, fairly present in all material respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in these annual reports;
4. The registrants' other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrants, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrants' disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrants' other certifying officers and I have disclosed, based on our most recent evaluation, to the registrants' auditors and the audit committee of registrants' board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants' ability to record, process, summarize and report financial data and have identified for the registrants' auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal controls; and
6. The registrants' other certifying officers and I have indicated in these annual reports whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
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Date: March 17, 2003
CERTIFICATIONS
I, Hugh T. McDonald, certify that:
1. I have reviewed this annual report on Form 10-K of Entergy Arkansas, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
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Date: March 17, 2003
CERTIFICATIONS
I, Joseph F. Domino, certify that:
1. I have reviewed this annual report on Form 10-K of Entergy Gulf States, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
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Date: March 17, 2003
CERTIFICATIONS
I, E. Renae Conley, certify that:
1. I have reviewed these annual reports on Form 10-K of Entergy Gulf States, Inc. and Entergy Louisiana, Inc.;
2. Based on my knowledge, these annual reports do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by these annual reports;
3. Based on my knowledge, the financial statements, and other financial information included in these annual reports, fairly present in all material respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in these annual reports;
4. The registrants' other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrants, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrants' disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrants' other certifying officers and I have disclosed, based on our most recent evaluation, to the registrants' auditors and the audit committee of registrants' board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants' ability to record, process, summarize and report financial data and have identified for the registrants' auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal controls; and
6. The registrants' other certifying officers and I have indicated in these annual reports whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
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Date: March 17, 2003
CERTIFICATIONS
I, Carolyn C. Shanks, certify that:
1. I have reviewed this annual report on Form 10-K of Entergy Mississippi, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
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Date: March 17, 2003
CERTIFICATIONS
I, Daniel F. Packer, certify that:
1. I have reviewed this annual report on Form 10-K of Entergy New Orleans, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
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Date: March 17, 2003
CERTIFICATIONS
I, Jerry W. Yelverton, certify that:
1. I have reviewed this annual report on Form 10-K of System Energy Resources, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
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Date: March 17, 2003
CERTIFICATIONS
I, Theodore H. Bunting, Jr., certify that:
1. I have reviewed these annual reports on Form 10-K of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc.;
2. Based on my knowledge, these annual reports do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by these annual reports;
3. Based on my knowledge, the financial statements, and other financial information included in these annual reports, fairly present in all material respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in these annual reports;
4. The registrants' other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrants, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrants' disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrants' other certifying officers and I have disclosed, based on our most recent evaluation, to the registrants' auditors and the audit committee of registrants' board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants' ability to record, process, summarize and report financial data and have identified for the registrants' auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal controls; and
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Date: March 17, 2003
EXHIBIT 23(a)
CONSENTS OF INDEPENDENT AUDITORS' CONSENTSREGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Post-Effective Amendments No. 3 and 5A on Form S-8 and their related prospectuses to Registration Statement No. 33-54298 of Entergy Corporation on Form S-4, Registration Statements No. 333-02503 and 333-22007 of Entergy Corporation on Form S-3 and Registration Statements No. 333-98179,333-55692, 333-68950, 333-75097, 333-90914, 333-75097, 333-55692, and 333-68950333-98179 of Entergy Corporation on Form S-8 of our reports dated March 8, 2005, relating to the financial statements (which report dated February 21, 2003, which reportexpresses an unqualified opinion and includes an explanatory paragraph regarding Entergy Corporation's change in 2003 in the Corporation'smethod of accounting for asset retirement obligations and for consolidation of variable interest entities and the change in 2002 in the method of accounting for goodwill and intangible assetsassets), financial statement schedules, and to management's report on the change in 2001 in the methodeffectiveness of accounting for derivative instruments,internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Corporation for the year ended December 31, 2002.2004.
We consent to the incorporation by reference in Registration Statements No. 33-50289, 333-00103, 333-05045, and 333-39018333-109453 of Entergy Arkansas, Inc. on Form S-3 of our reports dated March 8, 2005, relating to the financial statements of Entergy Arkansas, Inc. (which report dated February 21,includes an explanatory paragraph regarding Entergy Arkansas, Inc.'s change in 2003 in the method of accounting for asset retirement obligations and for consolidation of variable interest entities), financial statement schedules, and to management's report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Arkansas, Inc. for the year ended December 31, 2002.2004.
We consent to the incorporation by reference in Registration Statements No. 33-49739, 33-51181, 333-60957, and 333-60957333-109923 of Entergy Gulf States, Inc. on Form S-3 and Registration Statement No. 333-17911 on Form S-2 of our reports dated March 8, 2005, relating to the financial statements of Entergy Gulf States, Inc. (which report dated February 21,includes an explanatory paragraph regarding Entergy Gulf States, Inc.'s change in 2003 in the method of accounting for asset retirement obligations and for consolidation of variable interest entities), financial statement schedules, and to management's report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Gulf States, Inc. for the year ended December 31, 2002.2004.
We consent to the incorporation by reference in Registration Statements No. 33-46085, 33-39221, 33-50937, 333-00105, 333-01329, 333-03567, and 333-93683333-114174 of Entergy Louisiana, Inc. on Form S-3 of our reports dated March 8, 2005, relating to the financial statements of Entergy Louisiana, Inc. (which report dated February 21,includes an explanatory paragraph regarding Entergy Louisiana, Inc.'s change in 2003 in the method of accounting for asset retirement obligations and for consolidation of variable interest entities), financial statement schedules, and to management's report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Louisiana, Inc. for the year ended December 31, 2002.2004.
We consent to the incorporation by reference in Registration StatementsStatement No. 33-53004, 33-55826, 33-50507, 333-64023 and 333-53554333-110675 of Entergy Mississippi, Inc. on Form S-3 of our reports dated March 8, 2005, relating to the financial statements of Entergy Mississippi, Inc., financial statement schedules, and to management's report dated February 21, 2003,on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Mississippi, Inc. for the year ended December 31, 2002.2004.
We consent to the incorporation by reference in Registration StatementsStatement No. 33-57926, 333-00255 and 333-95599333-113586 of Entergy New Orleans, Inc. on Form S-3 of our reports dated March 8, 2005, relating to the financial statements of Entergy New Orleans, Inc., financial statement schedules, and to management's report dated February 21, 2003,on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy New Orleans, Inc. for the year ended December 31, 2002.2004.
We consent to the incorporation by reference in Registration Statements No. 33-47662, 33-61189, and 333-06717 of System Energy Resources, Inc. on Form S-3 of our reports dated March 8, 2005, relating to the financial statements of System Energy Resources, Inc. (which report dated February 21,includes an explanatory paragraph regarding System Energy Resources, Inc.'s change in 2003 in the method of accounting for asset retirement obligations) and to management's report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of System Energy Resources, Inc. for the year ended December 31, 2002.
2004.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 18, 200310, 2005
REPORT OF INDEPENDENT AUDITORS' REPORT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Entergy Corporation:
We have audited the consolidated financial statements of Entergy Corporation (the "Corporation") and we have also audited the financial statements of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc. (collectively the "Companies"), as of December 31, 20022004 and 2001,2003, and for each of the three years in the period ended December 31, 2002,2004, management's assessment of the effectiveness of the Corporation's and the respective Companies' internal control over financial reporting as of December 31, 2004, and the effectiveness of the Corporation's and the respective Companies' internal control over financial reporting as of December 31, 2004, and have issued our reports thereon dated February 21, 2003, ourMarch 8, 2005. Our report on the consolidated financial statements of the Corporation expresses an unqualified opinion and includes an explanatory paragraph regarding its change in 2003 in the Corporation'smethod of accounting for a sset retirement obligations and for consolidation of variable interest entities, and its change in 2002 in the method of accounting for goodwill and intangible assetsassets. Our reports on the financial statements of Entergy Arkansas, Inc., Entergy Gulf States, Inc., and theEntergy Louisiana, Inc., each express an unqualified opinion and include an explanatory paragraph regarding their change in 20012003 in the method of accounting for derivative instruments; suchasset retirement obligations and for consolidation of variable interest entities. The financial statements described above, and our respective reports thereon are included elsewhere in your 2002this 2004 Annual Report to Shareholders and are included herein.Shareholders. Our audits also included the consolidated financial statement schedules of Entergy Corporation and the financial statement schedules of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc., listed in Item 15. These financial statement schedules are the responsibility of the Corporation's management.Corporation' s and the respective Companies' managements. Our responsibility is to express an opinion based on our audits. (We did not audit the financial statements of Entergy-Koch, LP, the Corporation's investment in which is accounted for by use of the equity method. The Corporation's equity in earnings of unconsolidated equity affiliates for the year ended December 31, 2003 includes $180,110,000 for Entergy-Koch, LP, which earnings were audited by other auditors whose report, which as to 2003 included an explanatory paragraph concerning a change in accounting for inventory held for trading purposes and energy trading contracts not qualifying as derivatives, has been furnished to us, and our opinion, insofar as it relates to the amount audited by other auditors included for such company, is based solely on the report of such other auditors.) 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 informationi nformation set forth therein.
DELOITTE & TOUCHE LLP
New Orleans, LouisianaFebruary 21, 2003March 8, 2005
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule | Page | |
I | Financial Statements of Entergy Corporation: | |
Statements of Income - For the Years Ended December 31, | S-2 | |
Statements of Cash Flows - For the Years Ended December 31, | S-3 | |
Balance Sheets, December 31, | S-4 | |
Statements of Retained Earnings, Comprehensive Income, and Paid-In Capital for the | S-5 | |
II | Valuation and Qualifying Accounts | |
Entergy Corporation and Subsidiaries | S-6 | |
Entergy Arkansas, Inc. | S-7 | |
Entergy Gulf States, Inc. | S-8 | |
Entergy Louisiana, Inc. | S-9 | |
Entergy Mississippi, Inc. | S-10 | |
Entergy New Orleans, Inc. | S-11 |
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 SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION STATEMENTS OF INCOME For the Years Ended December 31, 2002 2001 2000 (In Thousands) Income: Equity in income of subsidiaries $629,367 $801,155 $698,243 Interest on temporary investments 46,964 18,889 12,273 -------- -------- -------- Total 676,331 820,044 710,516 -------- -------- -------- Expenses and Other Deductions: Administrative and general expenses 41,126 45,525 25,146 Income taxes (credit) 6,948 9,787 (15,212) Taxes other than income 588 825 661 Interest 28,309 37,711 20,627 -------- -------- -------- Total 76,971 93,848 31,222 -------- -------- -------- Net Income $599,360 $726,196 $679,294 ======== ======== ======== See Entergy Corporation and Subsidiaries Notes to Financial Statements in Part II, Item 8.
ENTERGY CORPORATION SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION STATEMENTS OF CASH FLOWS Year to Date December 31, 2002 2001 2000 (In Thousands) Operating Activities: Net income $599,360 $726,196 $679,294 Noncash items included in net income: Equity in earnings of subsidiaries (629,367) (801,155) (698,243) Deferred income taxes (4,803) 11,005 (9,014) Depreciation 912 1,391 962 Changes in working capital: Receivables 1,430 (1,804) 2,013 Payables 4,898 1,140 (13,822) Other working capital accounts (480,711) 489,997 98,489 Common stock dividends received from subsidiaries 618,400 440,300 314,300 Other 68,981 (19,418) (11,694) -------- -------- -------- Net cash flow provided by operating activities 179,100 847,652 362,285 -------- -------- -------- Investing Activities: Investment in subsidiaries (256,212) (239,180) 194,665 Capital expenditures (768) (103) (360) Changes in other temporary investments 4,782 (4,782) - Other 103 897 (1,000) -------- -------- -------- Net cash flow provided by (used in) investing activities (252,095) (243,168) 193,305 -------- -------- -------- Financing Activities: Changes in credit line borrowings 245,000 (36,999) 267,000 Advances to subsidiaries (6,460) 27,067 (32,833) Common stock dividends paid (298,991) (269,122) (271,019) Repurchase of common stock (118,499) (36,895) (550,206) Notes receivable to/from associated companies (146,380) (368,992) - Issuance of common stock 130,061 64,345 41,908 Issuance of long-term debt 265,330 - - -------- -------- -------- Net cash flow used in financing activities 70,061 (620,596) (545,150) -------- -------- -------- Net increase (decrease) in cash and cash equivalents (2,934) (16,112) 10,440 Cash and cash equivalents at beginning of period 10,821 26,933 16,493 -------- -------- -------- Cash and cash equivalents at end of period $7,887 $10,821 $26,933 ======== ======== ======== See Entergy Corporation and Subsidiaries Notes to Financial Statements in Part II, Item 8.
ENTERGY CORPORATION SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION BALANCE SHEETS December 31, 2002 2001 ASSETS (In Thousands) Current Assets: Cash and cash equivalents: Temporary cash investments - at cost, which approximates market $7,887 $10,821 ---------- ---------- Total cash and cash equivalents 7,887 10,821 ---------- ---------- Other temporary investments - 4,782 Notes receivable - associated companies 515,373 368,992 Accounts receivable - associated companies 9,989 4,915 Other 46,383 2,517 ---------- ---------- Total 579,632 392,027 ---------- ---------- Investment in Wholly-owned Subsidiaries 7,819,408 7,486,010 ---------- ---------- Deferred Debits and Other Assets 475,797 472,587 ---------- ---------- Total $8,874,837 $8,350,624 ========== ========== LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Notes payable $ - $350,001 Accounts payable: Associated companies 2,937 13,618 Other 10,003 5,105 Taxes accrued - 215,368 Other current liabilities 8,725 7,861 ---------- ---------- Total 21,665 591,953 ---------- ---------- Deferred Credits and Noncurrent Liabilities 152,935 302,651 ---------- ---------- Long-term debt 862,000 - Shareholders' Equity: Common stock, $.01 par value, authorized 500,000,000 shares; issued 248,174,087 shares in 2002 and in 2001 2,482 2,482 Paid-in capital 4,666,753 4,662,704 Retained earnings 3,938,693 3,638,448 Accumulated other comprehensive loss (22,360) (88,794) Less cost of treasury stock (25,752,410 shares in 2002 and 27,441,384 shares in 2001) 747,331 758,820 ---------- ---------- Total common shareholders' equity 7,838,237 7,456,020 ---------- ---------- Total $8,874,837 $8,350,624 ========== ========== See Entergy Corporation and Subsidiaries Notes to Financial Statements in Part II, Item 8.
ENTERGY CORPORATION CONSOLIDATED STATEMENTS OF RETAINED EARNINGS, COMPREHENSIVE INCOME, AND PAID-IN CAPITAL For the Years Ended December 31, 2002 2001 2000 (In Thousands) RETAINED EARNINGS Retained Earnings - Beginning of period $3,638,448 $3,190,639 $2,786,467 Add: Earnings applicable to common stock 599,360 $599,360 726,196 $726,196 679,294 $679,294 Deduct: Dividends declared on common stock 299,031 278,342 275,929 Capital stock and other expenses 84 45 (807) ---------- ---------- ---------- Total 299,115 278,387 275,122 ---------- ---------- ---------- Retained Earnings - End of period $3,938,693 $3,638,448 $3,190,639 ========== ========== ========== ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Net of taxes): Balance at beginning of period: Accumulated derivative instrument fair value changes ($17,973) $- $- Other accumulated comprehensive (loss) items (70,821) (75,033) (73,805) ---------- ---------- ---------- Total (88,794) (75,033) (73,805) ---------- ---------- ---------- Cumulative effect to January 1, 2001 of accounting change regarding fair value of derivative instruments - (18,021) - Net derivative instrument fair value changes arising during the period 35,286 35,286 48 48 - - Foreign currency translation adjustments 65,948 (15,487) 4,615 4,615 (5,216) (5,216) Minimum pension liability adjustment (10,489) (10,489) - - - - Net unrealized investment gains (losses) (24,311) (24,311) (403) (403) 3,988 3,988 ---------- ---------- ---------- Balance at end of period: Accumulated derivative instrument fair value changes 17,313 (17,973) - Other accumulated comprehensive (loss) items (39,673) (70,821) (75,033) ---------- ---------- ---------- Total ($22,360) ($88,794) ($75,033) ========== -------- ========== -------- ========== -------- Comprehensive Income $584,359 $730,456 $678,066 ======== ======== ======== PAID-IN CAPITAL Paid-in Capital - Beginning of period $4,662,704 $4,660,483 $4,636,163 Add: Common stock issuances related to stock plans 4,049 2,221 24,320 ---------- ---------- ---------- Paid-in Capital - End of period $4,666,753 $4,662,704 $4,660,483 ========== ========== ========== See Entergy Corporation and Subsidiaries Notes to Financial Statements in Part II, Item 8.
ENTERGY CORPORATION SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 2002, 2001, and 2000 (In Thousands) Column A Column B Column C Column D Column E Other Additions Changes Deductions Balance at from Balance Beginning Charged to Provisions at End Description of Period Income (Note 1) of Period Year ended December 31, 2002 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $28,355 $13,024 $14,094 $27,285 ========= ======== ======== ========= Accumulated Provisions Not Deducted from Assets: Property insurance $(203,537) $211,210 $101,614 $(93,941) Injuries and damages (Note 2) 29,385 26,667 25,423 30,629 Environmental 34,802 39,368 47,682 26,488 --------- -------- -------- --------- Total $(139,350) $277,245 $174,719 $(36,824) ========= ======== ======== ========= Year ended December 31, 2001 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $17,782 $16,393 $5,820 $28,355 ========= ======== ======== ========= Accumulated Provisions Not Deducted from Assets: Property insurance $(108,351) $45,714 $140,900 $(203,537) Injuries and damages (Note 2) 35,135 20,334 26,084 29,385 Environmental 37,183 7,442 9,823 34,802 --------- -------- -------- --------- Total $(36,033) $73,490 $176,807 $(139,350) ========= ======== ======== ========= Year ended December 31, 2000 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $9,507 $25,436 $17,161 $17,782 ========= ======== ======== ========= Accumulated Provisions Not Deducted from Assets: Property insurance $(33,267) $66,866 $141,950 $(108,351) Injuries and damages (Note 2) 34,309 16,785 15,959 35,135 Environmental 37,793 9,084 9,694 37,183 --------- -------- -------- --------- Total $38,835 $92,735 $167,603 $(36,033) ========= ======== ======== ========= ___________ Notes: (1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. (2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages.
ENTERGY ARKANSAS, INC. SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 2002, 2001, and 2000 (In Thousands) Column A Column B Column C Column D Column E Other Additions Changes Deductions Balance at from Balance Beginning Charged to Provisions at End Description of Period Income (Note 1) of Period Year ended December 31, 2002 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $5,837 $2,194 $- $8,031 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets: Property insurance $(178,715) $183,438 $18,512 $(13,789) Injuries and damages (Note 2) 2,890 3,129 3,319 2,700 Environmental 6,910 1,999 7,285 1,624 --------- -------- -------- -------- Total $(168,915) $188,566 $29,116 $(9,465) ========= ======== ======== ======== Year ended December 31, 2001 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $4,196 $1,758 $117 $5,837 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets: Property insurance $(80,297) $16,155 $114,573 $(178,715) Injuries and damages (Note 2) 3,152 2,367 2,629 2,890 Environmental 7,136 2,181 2,407 6,910 --------- -------- -------- -------- Total $(70,009) $20,703 $119,609 $(168,915) ========= ======== ======== ======== Year ended December 31, 2000 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $1,768 $6,369 $3,941 $4,196 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets: Property insurance $858 $35,521 $116,676 $(80,297) Injuries and damages (Note 2) 3,253 1,322 1,423 3,152 Environmental 4,934 4,082 1,880 7,136 --------- -------- -------- -------- Total $9,045 $40,925 $119,979 $(70,009) ========= ======== ======== ======== ___________ Notes: (1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. (2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages.
ENTERGY GULF STATES, INC. SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 2002, 2001, and 2000 (In Thousands) Column A Column B Column C Column D Column E Other Additions Changes Deductions Balance at from Balance Beginning Charged to Provisions at End Description of Period Income (Note 1) of Period Year ended December 31, 2002 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $3,696 $3,961 $1,764 $5,893 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets-- Property insurance $(8,721) $4,486 $41,052 $(45,287) Injuries and damages (Note 2) 6,773 7,684 6,173 8,284 Environmental 18,716 34,296 37,595 15,417 --------- -------- -------- -------- Total $16,768 $46,466 $84,820 ($21,586) ========= ======== ======== ======== Year ended December 31, 2001 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $4,810 $940 $2,054 $3,696 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets-- Property insurance $(5,698) $4,485 $7,508 $(8,721) Injuries and damages (Note 2) 9,406 5,266 7,899 6,773 Environmental 20,671 2,306 4,261 18,716 --------- -------- -------- -------- Total $24,379 $12,057 $19,668 $16,768 ========= ======== ======== ======== Year ended December 31, 2000 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $1,828 $7,487 $4,505 $4,810 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets-- Property insurance $(3,452) $4,486 $6,732 $(5,698) Injuries and damages (Note 2) 8,684 6,538 5,816 9,406 Environmental 24,445 1,844 5,618 20,671 --------- -------- -------- -------- Total $29,677 $12,868 $18,166 $24,379 ========= ======== ======== ======== ___________ Notes: (1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. (2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages.
ENTERGY LOUISIANA, INC. SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 2002, 2001, and 2000 (In Thousands) Column A Column B Column C Column D Column E Other Additions Changes Deductions Balance at from Balance Beginning Charged to Provisions at End Description of Period Income (Note 1) of Period Year ended December 31, 2002 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $2,909 $1,181 $- $4,090 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets: Property insurance $(26,575) $14,064 $26,537 $(39,048) Injuries and damages (Note 2) 9,829 4,750 5,465 9,114 Environmental 8,127 1,843 1,813 8,157 --------- -------- -------- -------- Total $(8,619) $20,657 $33,815 $(21,777) ========= ======== ======== ======== Year ended December 31, 2001 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $2,552 $385 $28 $2,909 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets: Property insurance $(27,040) $11,900 $11,435 $(26,575) Injuries and damages (Note 2) 11,583 3,674 5,428 9,829 Environmental 7,793 2,051 1,717 8,127 --------- -------- -------- -------- Total $(7,664) $17,625 $18,580 $(8,619) ========= ======== ======== ======== Year ended December 31, 2000 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $1,615 $5,384 $4,447 $2,552 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets: Property insurance $(24,089) $11,900 $14,851 $(27,040) Injuries and damages (Note 2) 12,452 3,889 4,758 11,583 Environmental 7,022 2,132 1,361 7,793 --------- -------- -------- -------- Total $(4,615) $17,921 $20,970 $(7,664) ========= ======== ======== ======== ___________ Notes: (1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. (2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages.
ENTERGY MISSISSIPPI, INC. SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 2002, 2001, and 2000 (In Thousands) Column A Column B Column C Column D Column E Other Additions Changes Deductions Balance at from Balance Beginning Charged to Provisions at End Description of Period Income (Note 1) of Period Year ended December 31, 2002 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $1,232 $1,063 $662 $1,633 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets: Property insurance $1,279 $8,882 $13,098 $(2,937) Injuries and damages (Note 2) 6,306 5,526 3,904 7,928 Environmental 487 886 706 667 --------- -------- -------- -------- Total $8,072 $15,294 $17,708 $5,658 ========= ======== ======== ======== Year ended December 31, 2001 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $1,197 $45 $10 $1,232 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets: Property insurance $(4,765) $13,124 $7,080 $1,279 Injuries and damages (Note 2) 6,694 8,196 8,584 6,306 Environmental 511 581 605 487 --------- -------- -------- -------- Total $2,440 $21,901 $16,269 $8,072 ========= ======== ======== ======== Year ended December 31, 2000 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $886 $2,788 $2,477 $1,197 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets: Property insurance $(16,356) $14,956 $3,365 $(4,765) Injuries and damages (Note 2) 6,849 1,579 1,734 6,694 Environmental 594 418 501 511 --------- -------- -------- -------- Total $(8,913) $16,953 $5,600 $2,440 ========= ======== ======== ======== ___________ Notes: (1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. (2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages.
ENTERGY NEW ORLEANS, INC. SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 2002, 2001, and 2000 (In Thousands) Column A Column B Column C Column D Column E Other Additions Changes Deductions Balance at from Balance Beginning Charged to Provisions at End Description of Period Income (Note 1) of Period Year ended December 31, 2002 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $4,273 $501 $- $4,774 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets: Property insurance $9,195 $340 $2,415 $7,120 Injuries and damages (Note 2) 3,587 5,578 6,562 2,603 Environmental 562 344 283 623 --------- -------- -------- -------- Total $13,344 $6,262 $9,260 $10,346 ========= ======== ======== ======== Year ended December 31, 2001 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $2,463 $5,422 $3,612 $4,273 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets: Property insurance $9,449 $50 $304 $9,195 Injuries and damages (Note 2) 4,300 831 1,544 3,587 Environmental 1,072 323 833 562 --------- -------- -------- -------- Total $14,821 $1,204 $2,681 $13,344 ========= ======== ======== ======== Year ended December 31, 2000 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $846 $3,408 $1,791 $2,463 ========= ======== ======== ======== Accumulated Provisions Not Deducted from Assets: Property insurance $9,772 $3 $326 $9,449 Injuries and damages (Note 2) 3,071 3,457 2,228 4,300 Environmental 798 608 334 1,072 --------- -------- -------- -------- Total $13,641 $4,068 $2,888 $14,821 ========= ======== ======== ======== ___________ Notes: (1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. (2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages.
ENTERGY CORPORATION | ||||||
SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION | ||||||
STATEMENTS OF INCOME | ||||||
For the Years Ended December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
Income: | ||||||
Equity in income of subsidiaries | $936,961 | $945,514 | $629,367 | |||
Interest on temporary investments | 37,859 | 36,400 | 46,964 | |||
Total | 974,820 | 981,914 | 676,331 | |||
Other Expenses (Income) and Deductions: | ||||||
Administrative and general expenses | 23,643 | 16,844 | 41,126 | |||
Reimbursement on Subsidiary Stock Option Expenses | (49,481) | (14,419) | - - | |||
Income taxes (credit) | 16,544 | (7,916) | 6,948 | |||
Taxes other than income | 1,754 | 753 | 588 | |||
Interest | 72,836 | 59,709 | 28,309 | |||
Total | 65,296 | 54,971 | 76,971 | |||
Net Income | $909,524 | $926,943 | $599,360 | |||
See Entergy Corporation and Subsidiaries Notes to Financial | ||||||
Statements in Part II, Item 8. |
ENTERGY CORPORATION | ||||||
SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION | ||||||
STATEMENTS OF CASH FLOWS | ||||||
Year to Date December 31, | ||||||
2004 | 2003 | 2002 | ||||
(In Thousands) | ||||||
Operating Activities: | ||||||
Net income | $909,524 | $926,943 | $599,360 | |||
Noncash items included in net income: | ||||||
Equity in earnings of subsidiaries | (936,961) | (945,514) | (629,367) | |||
Deferred income taxes | 32,316 | (2,811) | (4,803) | |||
Depreciation | 237 | 591 | 912 | |||
Changes in working capital: | ||||||
Receivables | 38,007 | (878) | 1,430 | |||
Payables | (678) | (9,258) | 4,898 | |||
Other working capital accounts | (237,727) | 145,014 | (480,711) | |||
Common stock dividends received from subsidiaries | 825,022 | 424,993 | 618,400 | |||
Other | 55,811 | 95,388 | 68,981 | |||
Net cash flow provided by operating activities | 685,551 | 634,468 | 179,100 | |||
Investing Activities: | ||||||
Investment in subsidiaries | (99,502) | (254,894) | (256,212) | |||
Capital expenditures | (460) | 874 | (768) | |||
Changes in other temporary investments | 10,328 | (10,328) | 4,782 | |||
Other | 59,719 | (59,719) | 103 | |||
Net cash flow used in investing activities | (29,915) | (324,067) | (252,095) | |||
Financing Activities: | ||||||
Changes in credit line borrowings | 50,000 | (499,975) | 245,000 | |||
Advances to subsidiaries | (13,312) | (7,254) | (6,460) | |||
Common stock dividends paid | (427,901) | (362,814) | (298,991) | |||
Repurchase of common stock | (1,017,996) | (8,135) | (118,499) | |||
Notes receivable to/from associated companies | 510,113 | (111,595) | (146,380) | |||
Issuance of common stock | 170,237 | 217,521 | 130,061 | |||
Issuance of long-term debt | - - | 534,362 | 265,330 | |||
Net cash flow provided by (used in) financing activities | (728,859) | (237,890) | 70,061 | |||
Net increase (decrease) in cash and cash equivalents | (73,223) | 72,511 | (2,934) | |||
Cash and cash equivalents at beginning of period | 80,398 | 7,887 | 10,821 | |||
Cash and cash equivalents at end of period | $7,175 | $80,398 | $7,887 | |||
See Entergy Corporation and Subsidiaries Notes to Financial Statements | ||||||
in Part II, Item 8. | ||||||
ENTERGY CORPORATION | ||||
SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION | ||||
BALANCE SHEETS | ||||
December 31, | ||||
2004 | 2003 | |||
ASSETS | (In Thousands) | |||
Current Assets: | ||||
Cash and cash equivalents: | ||||
Temporary cash investments - at cost, | ||||
which approximates market | $7,175 | $80,398 | ||
Total cash and cash equivalents | 7,175 | 80,398 | ||
Other temporary investments | - | 10,328 | ||
Notes receivable - associated companies | 116,855 | 626,968 | ||
Accounts receivable - associated companies | 8,506 | 44,639 | ||
Other | 62,017 | 53,549 | ||
Total | 194,553 | 815,882 | ||
Investment in Wholly-owned Subsidiaries | 8,734,507 | 8,607,556 | ||
Deferred Debits and Other Assets | 556,643 | 606,760 | ||
Total | $9,485,703 | $10,030,198 | ||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||
Current Liabilities: | ||||
Accounts payable: | ||||
Associated companies | $2,190 | $2,433 | ||
Other | 1,308 | 745 | ||
Other current liabilities | 11,536 | 188,779 | ||
Total | 15,034 | 191,957 | ||
Deferred Credits and Noncurrent Liabilities | 223,982 | 234,558 | ||
Long-term debt | 950,000 | 900,025 | ||
Shareholders' Equity: | ||||
Common stock, $.01 par value, authorized | ||||
500,000,000 shares; issued 248,174,087 shares | ||||
in 2004 and in 2003 | 2,482 | 2,482 | ||
Paid-in capital | 4,835,375 | 4,767,615 | ||
Retained earnings | 4,984,302 | 4,502,508 | ||
Accumulated other comprehensive loss | (93,453) | (7,795) | ||
Less cost of treasury stock (31,345,028 shares in | ||||
2004 and 19,276,445 shares in 2003) | 1,432,019 | 561,152 | ||
Total common shareholders' equity | 8,296,687 | 8,703,658 | ||
Total | $9,485,703 | $10,030,198 | ||
See Entergy Corporation and Subsidiaries Notes to Financial Statements in Part II, Item 8. |
ENTERGY CORPORATION | ||||||||||||||
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS, COMPREHENSIVE INCOME, AND PAID-IN CAPITAL | ||||||||||||||
For the Years Ended December 31, | ||||||||||||||
2004 | 2003 | 2002 | ||||||||||||
(In Thousands) | ||||||||||||||
RETAINED EARNINGS | ||||||||||||||
Retained Earnings - Beginning of period | $4,502,508 | $3,938,693 | $3,638,448 | |||||||||||
Add: Earnings applicable to common stock | 909,524 | $909,524 | 926,943 | $926,943 | 599,360 | $599,360 | ||||||||
Deduct: | ||||||||||||||
Dividends declared on common stock | 427,740 | 362,941 | 299,031 | |||||||||||
Capital stock and other expenses | (10) | 187 | 84 | |||||||||||
Total | 427,730 | 363,128 | 299,115 | |||||||||||
Retained Earnings - End of period | $4,984,302 | $4,502,508 | $3,938,693 | |||||||||||
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Net of taxes): | ||||||||||||||
Balance at beginning of period: | ||||||||||||||
Accumulated derivative instrument fair value changes | ($25,811) | $17,313 | ($17,973) | |||||||||||
Other accumulated comprehensive (loss) items | 18,016 | (39,673) | (70,821) | |||||||||||
Total | (7,795) | (22,360) | (88,794) | |||||||||||
Net derivative instrument fair value changes | ||||||||||||||
arising during the period | (115,600) | (115,600) | (43,124) | (43,124) | 35,286 | 35,286 | ||||||||
Foreign currency translation adjustments | 1,882 | 1,882 | 4,169 | 4,169 | 65,948 | (15,487) | ||||||||
Minimum pension liability adjustment | 2,762 | 2,762 | 1,153 | 1,153 | (10,489) | (10,489) | ||||||||
Net unrealized investment gains (losses) | 25,298 | 25,298 | 52,367 | 52,367 | (24,311) | (24,311) | ||||||||
Balance at end of period: | ||||||||||||||
Accumulated derivative instrument fair value changes | ($141,411) | ($25,811) | 17,313 | |||||||||||
Other accumulated comprehensive (loss) items | 47,958 | 18,016 | (39,673) | |||||||||||
Total | ($93,453) | ($7,795) | ($22,360) | |||||||||||
Comprehensive Income | $823,866 | $941,508 | $584,359 | |||||||||||
PAID-IN CAPITAL | ||||||||||||||
Paid-in Capital - Beginning of period | $4,767,615 | $4,666,753 | $4,662,704 | |||||||||||
Add: | ||||||||||||||
Common stock issuances related to stock plans | 67,760 | 100,862 | 4,049 | |||||||||||
Paid-in Capital - End of period | $4,835,375 | $4,767,615 | $4,666,753 | |||||||||||
See Entergy Corporation and Subsidiaries Notes to Financial | ||||||||||||||
Statements in Part II, Item 8. | ||||||||||||||
ENTERGY CORPORATION | ||||||||
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | ||||||||
Years Ended December 31, 2004, 2003, and 2002 | ||||||||
(In Thousands) | ||||||||
Column A | Column B | Column C | Column D | Column E | ||||
Other | ||||||||
Additions | Changes | |||||||
Deductions | ||||||||
Balance at | from | Balance | ||||||
Beginning | Charged to | Provisions | at End | |||||
Description | of Period | Income | (Note 1) | of Period | ||||
Year ended December 31, 2004 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $25,976 | $5,479 | $7,697 | $23,758 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | ($123,313) | $49,950 | $50,762 | ($124,125) | ||||
Injuries and damages (Note 2) | 34,189 | 667,983 | 88,739 | 613,433 | ||||
Environmental | 26,514 | 26,653 | 35,729 | 17,438 | ||||
Total | ($62,610) | $744,586 | $175,230 | $506,746 | ||||
Year ended December 31, 2003 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $27,285 | $12,598 | $13,907 | $25,976 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | ($93,941) | $108,221 | $137,593 | ($123,313) | ||||
Injuries and damages (Note 2) | 30,629 | 29,255 | 25,695 | 34,189 | ||||
Environmental | 26,488 | 11,621 | 11,595 | 26,514 | ||||
Total | ($36,824) | $149,097 | $174,883 | ($62,610) | ||||
Year ended December 31, 2002 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $28,355 | $13,024 | $14,094 | $27,285 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | ($203,537) | $211,210 | $101,614 | ($93,941) | ||||
Injuries and damages (Note 2) | 29,385 | 26,667 | 25,423 | 30,629 | ||||
Environmental | 34,802 | 39,368 | 47,682 | 26,488 | ||||
Total | ($139,350) | $277,245 | $174,719 | ($36,824) | ||||
___________ | ||||||||
Notes: | ||||||||
(1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. | ||||||||
(2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages. |
ENTERGY ARKANSAS, INC. | ||||||||
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | ||||||||
Years Ended December 31, 2004, 2003, and 2002 | ||||||||
(In Thousands) | ||||||||
Column A | Column B | Column C | Column D | Column E | ||||
Other | ||||||||
Additions | Changes | |||||||
Deductions | ||||||||
Balance at | from | Balance | ||||||
Beginning | Charged to | Provisions | at End | |||||
Description | of Period | Income | (Note 1) | of Period | ||||
Year ended December 31, 2004 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $9,020 | $3,030 | $1,011 | $11,039 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | ($25,283) | $10,476 | $14,220 | ($29,027) | ||||
Injuries and damages (Note 2) | 3,353 | 2,849 | 3,589 | 2,613 | ||||
Environmental | 1,729 | 1,761 | 1,925 | 1,565 | ||||
Total | ($20,201) | $15,086 | $19,734 | ($24,849) | ||||
Year ended December 31, 2003 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $8,031 | $2,626 | $1,637 | $9,020 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | ($13,789) | $31,452 | $42,946 | ($25,283) | ||||
Injuries and damages (Note 2) | 2,700 | 2,950 | 2,297 | 3,353 | ||||
Environmental | 1,624 | 2,280 | 2,175 | 1,729 | ||||
Total | ($9,465) | $36,682 | $47,418 | ($20,201) | ||||
Year ended December 31, 2002 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $5,837 | $2,194 | $- | $8,031 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | ($178,715) | $183,438 | $18,512 | ($13,789) | ||||
Injuries and damages (Note 2) | 2,890 | 3,129 | 3,319 | 2,700 | ||||
Environmental | 6,910 | 1,999 | 7,285 | 1,624 | ||||
Total | ($168,915) | $188,566 | $29,116 | ($9,465) | ||||
___________ | ||||||||
Notes: | ||||||||
(1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. | ||||||||
(2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages. |
ENTERGY GULF STATES, INC. | ||||||||
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | ||||||||
Years Ended December 31, 2004, 2003, and 2002 | ||||||||
(In Thousands) | ||||||||
Column A | Column B | Column C | Column D | Column E | ||||
Other | ||||||||
Additions | Changes | |||||||
Deductions | ||||||||
Balance at | from | Balance | ||||||
Beginning | Charged to | Provisions | at End | |||||
Description | of Period | Income | (Note 1) | of Period | ||||
Year ended December 31, 2004 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $4,856 | $889 | $3,058 | $2,687 | ||||
Accumulated Provisions | ||||||||
Not Deducted from Assets-- | ||||||||
Property insurance | ($57,353) | $7,673 | $7,453 | ($57,133) | ||||
Injuries and damages (Note 2) | 11,554 | 12,288 | 14,872 | 8,970 | ||||
Environmental | 14,711 | 20,201 | 30,430 | 4,482 | ||||
Total | ($31,088) | $40,162 | $52,755 | ($43,681) | ||||
Year ended December 31, 2003 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $5,893 | $4,484 | $5,521 | $4,856 | ||||
Accumulated Provisions | ||||||||
Not Deducted from Assets-- | ||||||||
Property insurance | ($45,287) | $26,988 | $39,054 | ($57,353) | ||||
Injuries and damages (Note 2) | 8,284 | 8,805 | 5,535 | 11,554 | ||||
Environmental | 15,417 | 3,319 | 4,025 | 14,711 | ||||
Total | ($21,586) | $39,112 | $48,614 | ($31,088) | ||||
Year ended December 31, 2002 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $3,696 | $3,961 | $1,764 | $5,893 | ||||
Accumulated Provisions | ||||||||
Not Deducted from Assets-- | ||||||||
Property insurance | ($8,721) | $4,486 | $41,052 | ($45,287) | ||||
Injuries and damages (Note 2) | 6,773 | 7,684 | 6,173 | 8,284 | ||||
Environmental | 18,716 | 34,296 | 37,595 | 15,417 | ||||
Total | $16,768 | $46,466 | $84,820 | ($21,586) | ||||
___________ | ||||||||
Notes: | ||||||||
(1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. | ||||||||
(2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages. |
ENTERGY LOUISIANA, INC. | ||||||||
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | ||||||||
Years Ended December 31, 2004, 2003, and 2002 | ||||||||
(In Thousands) | ||||||||
Column A | Column B | Column C | Column D | Column E | ||||
Other | ||||||||
Additions | Changes | |||||||
Deductions | ||||||||
Balance at | from | Balance | ||||||
Beginning | Charged to | Provisions | at End | |||||
Description | of Period | Income | (Note 1) | of Period | ||||
Year ended December 31, 2004 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $4,487 | $473 | $1,825 | $3,135 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | ($40,878) | $20,146 | $20,973 | ($41,705) | ||||
Injuries and damages (Note 2) | 8,537 | 6,188 | 4,329 | 10,396 | ||||
Environmental | 7,245 | 2,589 | 1,770 | 8,064 | ||||
Total | ($25,096) | $28,923 | $27,072 | ($23,245) | ||||
Year ended December 31, 2003 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $4,090 | $2,152 | $1,755 | $4,487 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | ($39,048) | $36,691 | $38,521 | ($40,878) | ||||
Injuries and damages (Note 2) | 9,114 | 5,256 | 5,833 | 8,537 | ||||
Environmental | 8,157 | 2,441 | 3,353 | 7,245 | ||||
Total | ($21,777) | $44,388 | $47,707 | ($25,096) | ||||
Year ended December 31, 2002 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $2,909 | $1,181 | $- | $4,090 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | ($26,575) | $14,064 | $26,537 | ($39,048) | ||||
Injuries and damages (Note 2) | 9,829 | 4,750 | 5,465 | 9,114 | ||||
Environmental | 8,127 | 1,843 | 1,813 | 8,157 | ||||
Total | ($8,619) | $20,657 | $33,815 | ($21,777) | ||||
___________ | ||||||||
Notes: | ||||||||
(1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. | ||||||||
(2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages. |
ENTERGY MISSISSIPPI, INC. | ||||||||
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | ||||||||
Years Ended December 31, 2004, 2003, and 2002 | ||||||||
(In Thousands) | ||||||||
Column A | Column B | Column C | Column D | Column E | ||||
Other | ||||||||
Additions | Changes | |||||||
Deductions | ||||||||
Balance at | from | Balance | ||||||
Beginning | Charged to | Provisions | at End | |||||
Description | of Period | Income | (Note 1) | of Period | ||||
Year ended December 31, 2004 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $1,375 | $357 | $606 | $1,126 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | ($3,481) | $10,916 | $4,962 | $2,473 | ||||
Injuries and damages (Note 2) | 5,414 | 2,938 | 2,803 | 5,549 | ||||
Environmental | 495 | 1,236 | 841 | 890 | ||||
Total | $2,428 | $15,090 | $8,606 | $8,912 | ||||
Year ended December 31, 2003 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $1,633 | $587 | $845 | $1,375 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | ($2,937) | $12,323 | $12,867 | ($3,481) | ||||
Injuries and damages (Note 2) | 7,928 | 7,410 | 9,924 | 5,414 | ||||
Environmental | 667 | 1,482 | 1,654 | 495 | ||||
Total | $5,658 | $21,215 | $24,445 | $2,428 | ||||
Year ended December 31, 2002 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $1,232 | $1,063 | $662 | $1,633 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | $1,279 | $8,882 | $13,098 | ($2,937) | ||||
Injuries and damages (Note 2) | 6,306 | 5,526 | 3,904 | 7,928 | ||||
Environmental | 487 | 886 | 706 | 667 | ||||
Total | $8,072 | $15,294 | $17,708 | $5,658 | ||||
___________ | ||||||||
Notes: | ||||||||
(1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. | ||||||||
(2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages. |
ENTERGY NEW ORLEANS, INC. | ||||||||
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | ||||||||
Years Ended December 31, 2004, 2003, and 2002 | ||||||||
(In Thousands) | ||||||||
Column A | Column B | Column C | Column D | Column E | ||||
Other | ||||||||
Additions | Changes | |||||||
Deductions | ||||||||
Balance at | from | Balance | ||||||
Beginning | Charged to | Provisions | at End | |||||
Description | of Period | Income | (Note 1) | of Period | ||||
Year ended December 31, 2004 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $3,104 | $612 | $224 | $3,492 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | $3,682 | $739 | $3,154 | $1,267 | ||||
Injuries and damages (Note 2) | 4,077 | 3,231 | 2,043 | 5,265 | ||||
Environmental | 663 | 866 | 763 | 766 | ||||
Total | $8,422 | $4,836 | $5,960 | $7,298 | ||||
Year ended December 31, 2003 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $4,774 | $2,479 | $4,149 | $3,104 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | $7,120 | $767 | $4,205 | $3,682 | ||||
Injuries and damages (Note 2) | 2,603 | 2,514 | 1,040 | 4,077 | ||||
Environmental | 623 | 428 | 388 | 663 | ||||
Total | $10,346 | $3,709 | $5,633 | $8,422 | ||||
Year ended December 31, 2002 | ||||||||
Accumulated Provisions | ||||||||
Deducted from Assets-- | ||||||||
Doubtful Accounts | $4,273 | $501 | $- | $4,774 | ||||
Accumulated Provisions Not | ||||||||
Deducted from Assets: | ||||||||
Property insurance | $9,195 | $340 | $2,415 | $7,120 | ||||
Injuries and damages (Note 2) | 3,587 | 5,578 | 6,562 | 2,603 | ||||
Environmental | 562 | 344 | 283 | 623 | ||||
Total | $13,344 | $6,262 | $9,260 | $10,346 | ||||
___________ | ||||||||
Notes: | ||||||||
(1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. | ||||||||
(2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages. |
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, respectively, 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 14 of Form 10-K. Reference is made to a duplicate list of exhibits being filed as a part of this Form 10-K, which list, prepared in accordance with Item 102 of Regulation S-T of the SEC, immediately precedes the exhibits being physically filed with this Form 10-K10-K.
(3) (i) Articles of Incorporation
Entergy Corporation
(a) -- | Certificate of Incorporation of Entergy Corporation dated December 31, 1993 (A-1(a) to Rule 24 Certificate in 70-8059). |
System Energy
(b) -- | 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). |
Entergy Arkansas
(c) -- | Amended and Restated Articles of Incorporation of Entergy Arkansas effective November 12, 1999 (3(i)(c)1 to Form 10-K for the year ended December 31, 1999 in 1-10764). |
Entergy Gulf States
(d) -- | Restated Articles of Incorporation of Entergy Gulf States effective November 17, 1999 (3(i)(d)1 to Form 10-K for the year ended December 31, 1999 in 1-27031). |
Entergy Louisiana
(e) -- | Amended and Restated Articles of Incorporation of Entergy Louisiana effective November 15, 1999 (3(a) to Form S-3 in 333-93683). |
Entergy Mississippi
(f) -- | Amended and Restated Articles of Incorporation of Entergy Mississippi effective November 12, 1999 (3(i)(f)1 to Form 10-K for the year ended December 31, 1999 in 0-320). |
Entergy New Orleans
(g) -- | Amended and Restated Articles of Incorporation of Entergy New Orleans effective November 15, 1999 (3(a) to Form S-3 in 333-95599). |
(3) (ii) By-Laws
(a) -- | By-Laws of Entergy Corporation as amended |
(b) -- | By-Laws of System Energy effective July 6, 1998, and as presently in effect (3(f) to Form 10-Q for the quarter ended June 30, 1998 in 1-9067). |
(c) -- | 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). |
(d) -- | By-Laws of Entergy Gulf States effective November 26, 1999, and as presently in effect (3(ii)(d) to Form 10-K for the year ended December 31, 19991-27031). |
(e) -- | By-Laws of Entergy Louisiana effective November 26, 1999, and as presently in effect (3(b) to Form S-3 in File No. 333-93683). |
(f) -- | By-Laws of Entergy Mississippi effective November 26, 1999, and as presently in effect (3(ii)(f) to Form 10-K for the year ended December 31, 1999 in 0-320). |
(g) -- | By-Laws of Entergy New Orleans effective November 30, 1999, and as presently in effect (3(b) to Form S-3 in File No. 333-95599). |
(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 holders of long-term debt of System Energy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans. |
*(a) 2 -- | Credit Agreement, dated as of May |
*(a) 3 -- | First Amendment dated as of June 6, 2003, to the Credit Agreement dated May 31, 2002. |
(a) 4 -- | Credit Agreement, dated as of November 24, 2003, among Entergy Corporation, as Borrower, Bayerische Hypo-und Vereinsbank AG, New York Branch, as Bank, and Bayerische Hypo-und Vereinsbank AG, New York Branch, as Administrative Agent (4(a)11 to Form 10-K for the year ended December 31, 2003 1-11299). |
(a) 5 -- | Credit Agreement, dated as of May 13, 2004, among Entergy Corporation, the Banks (Citibank, N.A., ABN AMRO Bank N.V., |
(a) |
|
| Indenture, dated as of December 1, 2002, between Entergy Corporation and Deutsche Bank Trust Company Americas, as |
| Officer' Certificate for Entergy |
Officer' Certificate for Entergy Corporation relating to 6.17% Senior Notes due March 15, 2008 (4(c) to Form 10-Q for the quarter ended March 31, 2003 in 1-11299). | |
(a) 10 -- | Officer' Certificate for Entergy Corporation relating to 7.06% Senior Notes due March 15, 2011 (4(d) to Form 10-Q for the quarter ended March 31, 2003 in 1-11299). |
(a) 11 -- | Officer' Certificate for Entergy Corporation relating to 6.58% Senior Notes due May 15, 2010 (4(d) to Form 10-Q for the quarter ended June 30, 2003 in 1-11299). |
(a) 12 -- | Officer' Certificate for Entergy Corporation relating to 6.13% Senior Notes due September 15, 2008 (4(a) to Form 10-Q for the quarter ended September 30, 2003 in 1-11299). |
(a) 13 -- | Officer' Certificate for Entergy Corporation relating to 6.23% Senior Notes due March 15, 2008 (4(a)9 to Form 10-K for the year ended December 31, 2003 in 1-11299). |
(a) 14 -- | Officer' Certificate for Entergy Corporation relating to 6.90% Senior Notes due November 15, 2010 (4(a)10 to Form 10-K for the year ended December 31, 2003 in 1-11299). |
System Energy
(b) 1 -- | Mortgage and Deed of Trust, dated as of June 15, 1977, as amended by twenty-two 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); and A-2(a) to Rule 24 Certificate dated October 4, 2002 in 70-9753 (Twenty-second)). |
(b) 2 -- | Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561) |
(b) 3 -- | Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561) |
Entergy Arkansas
*(c) 1 -- | Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by |
|
|
|
|
|
|
Entergy Gulf States
(d) 1 -- | Indenture of Mortgage, dated September 1, 1926, as amended by certain Supplemental Indentures (B-a-I-1 in Registration No. 2-2449 (Mortgage); 7-A-9 in Registration No. 2-6893 (Seventh); B to Form 8-K dated September 1, 1959 (Eighteenth); B to Form 8-K dated February 1, 1966 (Twenty-second); B to Form 8-K dated March 1, 1967 (Twenty-third); C to Form 8-K dated March 1, 1968 (Twenty-fourth); B to Form 8-K dated November 1, 1968 (Twenty-fifth); B to Form 8-K dated April 1, 1969 (Twenty-sixth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4-2 to Form 10-K for the year ended December 31, 1984 in 1-27031 (Forty-eighth); 4-2 to Form 10-K for the year ended December 31, 1988 in 1-27031 (Fifty-second); 4 to Form 10-K for the year ended December 31, 1991 in 1-27031 (Fifty-third); 4 to Form 8-K dated July 29, 1992 in 1-27031 (Fifth-fourth); 4 to Form 10-K dated December 31, 1992 in 1-27031 (Fifty-fifth); 4 to Form 10-Q for the quarter ended March 31, 1993 in 1-27031 (Fifty-sixth); 4-2 to Amendment No. 9 to Registration No. 2-76551 (Fifty-seventh); 4(b) to Form 10-Q for the quarter ended March 31,1999 in 1-27031 (Fifty-eighth); A-2(a) to Rule 24 Certificate dated June 23, 2000 in 70-8721 (Fifty-ninth); A-2(a) to Rule 24 Certificate dated September 10, 2001 in 70-9751 (Sixtieth); A-2(b) to Rule 24 Certificate dated November 18, 2002 in 70-9751 (Sixty-first); |
(d) 2 -- | Indenture, dated March 21, 1939, accepting resignation of The Chase National Bank of the City of New York as trustee and appointing Central Hanover Bank and Trust Company as successor trustee (B-a-1-6 in Registration No. 2-4076). |
(d) 3 -- | Indenture for Unsecured Subordinated Debt Securities relating to Trust Securities, dated as of January 15, 1997 (A-11(a) to Rule 24 Certificate dated February 6, 1997 in 70-8721). |
(d) 4 -- | Amended and Restated Trust Agreement of Entergy Gulf States Capital I dated January 28, 1997 of Series A Preferred Securities (A-13(a) to Rule 24 Certificate dated February 6, 1997 in 70-8721). |
(d) 5 -- | Guarantee Agreement between Entergy Gulf States, Inc. (as Guarantor) and The Bank of New York (as Trustee) dated as of January 28, 1997 with respect to Entergy Gulf States Capital I's obligation on its 8.75% Cumulative Quarterly Income Preferred Securities, Series A (A-14(a) to Rule 24 Certificate dated February 6, 1997 in 70-8721). |
Entergy Louisiana
(e) 1 -- | Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by |
(e) 2 -- | Facility Lease No. 1, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-1 in Registration No. 33-30660), as supplemented by Lease Supplement No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 1, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 2 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474). |
(e) 3 -- | Facility Lease No. 2, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-2 in Registration No. 33-30660), as supplemented by Lease Supplemental No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 2, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 3 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474). |
(e) 4 -- | Facility Lease No. 3, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-3 in Registration No. 33-30660) |
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Entergy Mississippi
(f) 1 -- | Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by |
Entergy New Orleans
(g) 1 -- | Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by |
(10) Material Contracts
Entergy Corporation
(a) 1 -- | Agreement, dated April 23, 1982, among certain System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
(a) 2 -- | Middle South Utilities (now Entergy Corporation) System Agency Agreement, dated December 11, 1970 (5(a) |
(a) 3 -- | Amendment, dated February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) |
(a) 4 -- | Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) |
(a) 5 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a) |
(a) 6 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a) |
(a) 7 -- | Amendment, dated |
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(a) |
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| Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(a) |
*(a) | Amendment, dated |
(a) | 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) | First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate dated June 24, 1977 in 70-5399). |
(a) | Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate dated July 1, 1981 in 70-6592). |
(a) | 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) | Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate dated June 8, 1989 in 70-5399). |
(a) | Eighteenth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-2 to Rule 24 Certificate dated October 1, 1986 in 70-7272). |
(a) | Nineteenth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-3 to Rule 24 Certificate dated October 1, 1986 in 70-7272). |
(a) | Twenty-sixth Assignment of Availability Agreement, Consent and Agreement, dated as of October 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(c) to Rule 24 Certificate dated November 2, 1992 in 70-7946). |
(a) | Twenty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1993, with United States Trust Company of New York and Gerard F. Ganey as Trustees (B-2(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946). |
(a) | Twenty-ninth Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey as Trustees (B-2(f) to Rule 24 Certificate dated May 6, 1994 in 70-7946). |
(a) | Thirtieth Assignment of Availability Agreement, Consent and Agreement, dated as of August 1, 1996, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans, and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(a) to Rule 24 Certificate dated August 8, 1996 in 70-8511). |
(a) | Thirty-first Assignment of Availability Agreement, Consent and Agreement, dated as of August 1, 1996, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to Rule 24 Certificate dated August 8, 1996 in 70-8511). |
(a) |
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| Thirty-fourth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2002, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, The Bank of New York and Douglas J. MacInnes (B-2(a)(1) to Rule 24 Certificate dated October 4, 2001 in 70-9753). |
(a) | Thirty-fifth Assignment of Availability Agreement, Consent and Agreement, dated as of December 22, 2003, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and Union Bank of California, N.A (10(a)25 to Form 10-K for the year ended December 31, 2003 in 1-11299). |
*(a) 24 -- | First Amendment to Thirty-fifth Assignment of Availability Agreement, Consent and Agreement, dated as of December 17, 2004. |
(a) 25 -- | 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) | 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) | Eighteenth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-2 to Rule 24 Certificate dated October 1, 1986 in 70-7272). |
(a) | Nineteenth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-3 to Rule 24 Certificate dated October 1, 1986 in 70-7272). |
(a) | Twenty-sixth Supplementary Capital Funds Agreement and Assignment, dated as of October 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(c) to Rule 24 Certificate dated November 2, 1992 in 70-7946). |
(a) | Twenty-seventh Supplementary Capital Funds Agreement and Assignment, dated as of April 1, 1993, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946). |
(a) | Twenty-ninth Supplementary Capital Funds Agreement and Assignment, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(f) to Rule 24 Certificate dated May 6, 1994 in 70-7946). |
(a) | Thirtieth Supplementary Capital Funds Agreement and Assignment, dated as of August 1, 1996, among Entergy Corporation, System Energy and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(a) to Rule 24 Certificate dated August 8, 1996 in 70-8511). |
(a) | Thirty-first Supplementary Capital Funds Agreement and Assignment, dated as of August 1, 1996, among Entergy Corporation, System Energy and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(b) to Rule 24 Certificate dated August 8, 1996 in 70-8511). |
(a) |
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| Thirty-fourth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 2002, among Entergy Corporation, System Energy, The Bank of New York and Douglas J. MacInnes (B-3(a)(1) to Rule 24 Certificate dated October 4, 2002 in 70-9753). |
(a) | Thirty-fifth Supplementary Capital Funds Agreement and Assignment, dated as of December 22, 2003, among Entergy Corporation, System Energy, and Union Bank of California, N.A (10(a)38 to Form 10-K for the year ended December 31, 2003 in 1-11299). |
(a) 36 -- | 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) | 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) | 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) | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
(a) | 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) | Operating Agreement dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337). |
(a) | 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) | 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) | Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337). |
(a) | Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033). |
(a) | 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) | 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) |
(a) | 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) | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
(a) | 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) | 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) | 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) | 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) | 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) | 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) | 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) | 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) | 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) | Loan Agreement between Entergy Power and Entergy Corporation, dated as of August 28, 1990 (A-4(b) to Rule 24 Certificate dated September 6, 1990 in 70-7684). |
(a) | 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) | Executive Financial Counseling Program of Entergy Corporation and Subsidiaries (10(a)64 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) |
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+(a) | Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate dated May 24, 1991 in 70-7831). |
+(a) | Amendment No. 1 to the Equity Ownership Plan of Entergy Corporation and Subsidiaries (10(a)71 to Form 10-K for the year ended December 31, 1992 in 1-3517). |
+(a) |
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+(a) | Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)70 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) | Amendment, effective December 28, 2001, to the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries (10(a)71 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) | Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)72 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) | Amendment, effective December 28, 2001, to the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (10(a)73 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) | 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) | Amended and Restated Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, |
+(a) |
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| Equity Awards Plan of Entergy Corporation and Subsidiaries, effective as of August 31, 2000 (10(a)77 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) | Amendment, effective December 7, 2001, to the Equity Awards Plan of Entergy Corporation and Subsidiaries (10(a)78 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) | Amendment, effective December 10, 2001, to the Equity Awards Plan of Entergy Corporation and Subsidiaries (10(b) to Form 10-Q for the quarter ended March 31, 2002 in 1-11299). |
+(a) | Restatement of System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective as of March |
*+(a) | First Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective December 29, 2004. |
+(a) 77 -- | System Executive Continuity Plan II of Entergy Corporation and Subsidiaries, effective March 8, 2004 (10(e) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299). |
*+(a) 78 -- | First Amendment of the System Executive Continuity Plan II of Entergy Corporation and Subsidiaries, effective December 29, 2004. |
+(a) 79 -- | 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) | 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) | Pension Equalization Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)82 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) | Amendment, effective December 28, 2001, to the Pension Equalization Plan of Entergy Corporation and Subsidiaries (10(a)83 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) | Service Recognition Program for Non-Employee Outside Directors of Entergy Corporation and Subsidiaries, effective January 1, 2000 (10(a)84 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) |
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| 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) | System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 2000 (10(a)87 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) | Amendment, effective December 28, 2001, to the System Executive Retirement Plan of Entergy Corporation and Subsidiaries (10(a)88 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) | Retention Agreement effective October 27, 2000 between J. Wayne Leonard and Entergy Corporation (10(a)81 to Form 10-K for the year ended December 31, 2000 in 1-11299). |
+(a) | Amendment to Retention Agreement effective |
+(a) |
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| Retention Agreement effective January 22, 2001 between Richard J. Smith and Entergy Services, Inc (10(a)87 to Form 10-K for the year ended December 31, 2000 in 1-11299). |
+(a) |
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| Employment Agreement effective August 7, 2001 between Curt L. Hebert and Entergy Corporation (10(a)97 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
+(a) | Agreement of Limited Partnership of Entergy-Koch, LP among EKLP, LLC, EK Holding I, LLC, EK Holding II, LLC and Koch Energy, Inc. dated January 31, 2001 (10(a)94 to Form 10-K/A for the year ended December 31, 2000 in 1-11299). |
+(a) 92 -- | Employment Agreement effective April 15, 2003 between Robert D. Sloan and Entergy Services (10(c) to Form 10-Q for the quarter ended June 30, 2003 in 1-11299). |
+(a) 93 -- | Employment Agreement effective November 24, 2003 between Mark T. Savoff and Entergy Services (10(a)99 to Form 10-K for the year ended December 31, 2003 in 1-11299). |
+(a) 94 -- | 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) 95 -- | 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) 96 -- | 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) 97 -- | Consulting Agreement effective May 4, 2004 between Hintz & Associates, LLC and Entergy Services, Inc. (10(d) to Form 10-Q for the quarter ended June 30, 2004 in 1-11299). |
+(a) 98 -- | Form of Stock Option Grant Agreement Letter, as of December 31, 2004 (99.1 to Form 8-K dated January 26, 2005 in 1-11299). |
+(a) 99 -- | Form of Long Term Incentive Plan Performance Unit Grand Letter, as of December 31, 2004 (99.2 to Form 8-K dated January 26, 2005 in 1-11299). |
*+(a) 100 -- | Summary of Executive Officer and Director Compensation. |
*+(a) 101 -- | Terms of Restricted Stock Grants for Outside Directors. |
System Energy
(b) 1 through | |
(b) 16 through (b) 29 -- See 10(a)25 through 10(a)38 above. | |
(b) | |
| Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
(b) | 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) | Operating Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337). |
(b) | 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) | 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) | Loan Agreement, dated as of May 15, 1999, between System Energy and Mississippi Business Finance Corporation (B-6(c) to Rule 24 Certificate dated June 8, 1999 in 70-8511). |
(b) | 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) |
(b) | 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) |
(b) | Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561). |
(b) | 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) | Collateral Trust Indenture, dated as of |
(b) | Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337). |
(b) | Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033). |
(b) | 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) |
(b) | 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) | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
(b) | 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) | 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) | 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) | 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) | 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) | 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) | 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) | 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) | 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) | 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) | Service Agreement with Entergy Services, dated as of July 16, 1974, as amended (10(b) |
*(b) 57 -- | Amendment, dated January 1, 2004, to Service Agreement with Entergy Services. |
*(b) 58 -- | Amendment, dated |
(b) 59 |
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| 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) | 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) |
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*(b) 62 -- | Amendment to Letter of Credit and Reimbursement Agreement, dated |
*(b) 63 -- | First Amendment and Consent, dated as of May 3, |
(b) 64 -- | 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 |
Entergy Arkansas
(c) 1 -- | Agreement, dated April 23, 1982, among Entergy Arkansas and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
(c) 2 -- | Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)2 in 2-41080). |
(c) 3 -- | Amendment, dated February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) |
(c) 4 -- | Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080). |
(c) 5 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a) |
(c) 6 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a) |
(c) 7 -- | Amendment, dated |
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| Amendment, dated January 1, 2000, to Service Agreement with Entergy |
*(c) | Amendment, dated |
(c) | |
(c) | Agreement, dated August 20, 1954, between Entergy Arkansas and the United States of America (SPA)(13(h) in 2-11467). |
(c) | Amendment, dated April 19, 1955, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d) |
(c) | Amendment, dated January 3, 1964, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d) |
(c) | Amendment, dated September 5, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d) |
(c) | Amendment, dated November 19, 1970, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d) |
(c) | Amendment, dated July 18, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d) |
(c) | Amendment, dated December 27, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d) |
(c) | Amendment, dated January 25, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d) |
(c) | Amendment, dated October 14, 1971, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d) |
(c) | Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d) |
(c) | Agreement, dated May 14, 1971, between Entergy Arkansas and the United States of America (SPA) (5(e) in 2-41080). |
(c) | Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated May 14, 1971 (5(e) |
(c) | 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) |
(c) |
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| 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) | 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) | 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) | Agreement, dated June 29, 1979, between Entergy Arkansas and City of Conway, Arkansas (5(r) |
(c) | Transmission Agreement, dated August 2, 1977, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r) |
(c) | Power Coordination, Interchange and Transmission Service Agreement, dated as of June 27, 1977, between Arkansas Electric Cooperative Corporation and Entergy Arkansas (5(r) |
(c) | 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) |
(c) | 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) | 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) |
(c) | Amendment, dated December 28, 1979, to the Independence Steam Electric Station Ownership Agreement (5(r) |
(c) | 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) | 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) | 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) | 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) |
(c) | Power Coordination, Interchange and Transmission Agreement, dated as of June 29, 1979, between City of Conway, Arkansas and Entergy Arkansas (5(r) |
(c) | Agreement, dated June 21, 1979, between Entergy Arkansas and Reeves E. Ritchie |
(c) | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
(c) | 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) | First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
(c) | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
(c) | 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) |
(c) | 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) | 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) | 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) | 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) | 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) | 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) | 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) | 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) | Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757). |
(c) | Agreement for Purchase and Sale of Independence Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-3(c) to Rule 24 Certificate dated September 6, 1990 in 70-7684). |
(c) | 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) | 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) | 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) | Power Coordination, Interchange and Transmission Service Agreement between Entergy Power and Entergy Arkansas, dated as of August 28, 1990 (10(c) |
(c) | Loan Agreement dated June 15, 1993, between Entergy Arkansas and Independence Country, Arkansas |
(c) | Loan Agreement dated June 15, 1994, between Entergy Arkansas and Jefferson County, Arkansas (B-1(a) to Rule 24 Certificate dated June 30, 1994 in 70-8405). |
(c) | Loan Agreement dated June 15, 1994, between Entergy Arkansas and Pope County, Arkansas (B-1(b) to Rule 24 Certificate in 70-8405). |
(c) | Loan Agreement dated November 15, 1995, between Entergy Arkansas and Pope County, Arkansas (10(c)96 to Form 10-K for the year ended December 31, 1995 in 1-10764). |
(c) |
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| Loan Agreement dated December 1, 1997, between Entergy Arkansas and Jefferson County, Arkansas (10(c)100 to Form 10-K for the year ended December 31, 1997 in 1-10764). |
(c) | Refunding Agreement, dated December 1, 2001, between Entergy Arkansas and Pope Country, Arkansas (10(c)81 to Form 10-K for the year ended December 31, 2001 in 1-10764). |
Entergy Gulf States
(d) 1 |
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| Guaranty Agreement, dated August 1, 1992, between Entergy Gulf States and Hibernia National Bank, relating to Pollution Control Revenue Refunding Bonds of the Industrial Development Board of the Parish of Calcasieu, Inc. (Louisiana) (10-1 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
(d) | Guaranty Agreement, dated January 1, 1993, between Entergy Gulf States and Hancock Bank of Louisiana, relating to Pollution Control Revenue Refunding Bonds of the Parish of Pointe Coupee (Louisiana) (10-2 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
(d) | Deposit Agreement, dated as of December 1, 1983 between Entergy Gulf States, Morgan Guaranty Trust Co. as Depositary and the Holders of Depository Receipts, relating to the Issue of 900,000 Depositary Preferred Shares, each representing 1/2 share of Adjustable Rate Cumulative Preferred Stock, Series E-$100 Par Value (4-17 to Form 10-K for the year ended December 31, 1983 in 1-27031). |
(d) | Agreement effective February 1, 1964, between Sabine River Authority, State of Louisiana, and Sabine River Authority of Texas, and Entergy Gulf States, Central Louisiana Electric Company, Inc., and Louisiana Power & Light Company, as supplemented (B to Form 8-K dated May 6, 1964, A to Form 8-K dated October 5, 1967, A to Form 8-K dated May 5, 1969, and A to Form 8-K dated December 1, 1969 in 1-27031). |
(d) | Joint Ownership Participation and Operating Agreement regarding River Bend Unit 1 Nuclear Plant, dated August 20, 1979, between Entergy Gulf States, 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 and Cajun; and Letter Agreement regarding CEPCO buybacks, dated August 28, 1979, between Entergy Gulf States and Cajun (2, 3, and 4, respectively, to Form 8-K dated September 7, 1979 in 1-27031). |
(d) | Ground Lease, dated August 15, 1980, between Statmont Associates Limited Partnership (Statmont) and Entergy Gulf States, 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). |
(d) | Lease and Sublease Agreement, dated August 15, 1980, between Statmont and Entergy Gulf States, 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). |
(d) | Lease Agreement, dated September 18, 1980, between BLC Corporation and Entergy Gulf States (1 to Form 8-K dated October 6, 1980 in 1-27031). |
(d) | Joint Ownership Participation and Operating Agreement for Big Cajun, between Entergy Gulf States, 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) | Agreement of Joint Ownership Participation between SRMPA, SRG&T and Entergy Gulf States, 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) | Agreements between Southern Company and Entergy Gulf States, dated February 25, 1982, which cover the construction of a 140-mile transmission line to connect the two systems, purchase of power and use of transmission facilities (10-31 to Form 10-K for the year ended December 31, 1981 in 1-27031). |
(d) | Transmission Facilities Agreement between Entergy Gulf States 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) | 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, Central Louisiana Electric Co., Inc., and Louisiana Power and Light Company (10-72 to Form 10-K for the year ended December 31, 1985 in 1-27031). |
+(d) | Deferred Compensation Plan for Directors of Entergy Gulf States and Varibus Corporation, as amended January 8, 1987, and effective January 1, 1987 (10-77 to Form 10-K for the year ended December 31, 1986 in 1-27031). Amendment dated December 4, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551). |
+(d) | Trust Agreement for Deferred Payments to be made by Entergy Gulf States pursuant to the Executive Income Security Plan, by and between Entergy Gulf States 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) | Trust Agreement for Deferred Installments under Entergy Gulf States' Management Incentive Compensation Plan and Administrative Guidelines by and between Entergy Gulf States 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) | Nonqualified Deferred Compensation Plan for Officers, Nonemployee Directors and Designated Key Employees, effective December 1, 1985, as amended, continued and completely restated effective as of March 1, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551). |
+(d) | Trust Agreement for Entergy Gulf States' Nonqualified Directors and Designated Key Employees by and between Entergy Gulf States and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
(d) | Lease Agreement, dated as of June 29, 1987, among GSG&T, Inc., and Entergy Gulf States 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). |
(d) | Nuclear Fuel Lease Agreement between Entergy Gulf States and River Bend Fuel Services, Inc. to lease the fuel for River Bend Unit 1, dated February 7, 1989 (10-64 to Form 10-K for the year ended December 31, 1988 in 1-27031). |
(d) | Trust and Investment Management Agreement between Entergy Gulf States 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, dated March 15, 1989 (10-66 to Form 10-K for the year ended December 31, 1988 in 1-27031). |
(d) | Amendment No. 2 dated November 1, 1995 between Entergy Gulf States and Mellon Bank to Decommissioning Trust Agreement (10(d)31 to Form 10-K for the year ended December 31, 1995 in 1-27031). |
*(d) 23 -- | Amendment No. 3 dated March 5, 1998 between Entergy Gulf States and Mellon Bank to Decommissioning Trust Agreement. |
*(d) 24 -- | Amendment No. 4 dated December 17, 2003 between Entergy Gulf States and Mellon Bank to Decommissioning Trust Agreement. |
(d) 25 -- | Partnership Agreement by and among Conoco Inc., and Entergy Gulf States, CITGO Petroleum Corporation and Vista Chemical Company, dated April 28, 1988 (10-67 to Form 10-K for the year ended December 31, 1988 in 1-27031). |
+(d) | Gulf States Utilities Company Executive Continuity Plan, dated January 18, 1991 (10-6 to Form 10-K for the year ended December 31, 1990 in 1-27031). |
+(d) | Trust Agreement for Entergy Gulf States' Executive Continuity Plan, by and between Entergy Gulf States and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
+(d) | 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). |
(d) | Operating Agreement between Entergy Operations and Entergy Gulf States, dated as of December 31, 1993 (B-2(f) to Rule 24 Certificate in 70-8059). |
(d) | Guarantee Agreement between Entergy Corporation and Entergy Gulf States, dated as of December 31, 1993 (B-5(a) to Rule 24 Certificate in 70-8059). |
(d) | Service Agreement with Entergy Services, dated as of December 31, 1993 (B-6(c) to Rule 24 Certificate in 70-8059). |
| Amendment, dated January 1, 2000, to Service Agreement with Entergy |
*(d) | Amendment, dated |
(d) | 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) | 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) | Agreement as to Expenses and Liabilities between Entergy Gulf States and Entergy Gulf States Capital I, dated as of January 28, 1997 (10(d)52 to Form 10-K for the year ended December 31, 1996 in 1-27031). |
(d) | Refunding Agreement dated as of May 1, 1998 between Entergy Gulf States and Parish of Iberville, State of Louisiana (B-3(a) to Rule 24 Certificate dated May 29, 1998 in 70-8721). |
(d) | Refunding Agreement dated as of May 1, 1998 between Entergy Gulf States and Industrial Development Board of the Parish of Calcasieu, Inc. (B-3(b) to Rule 24 Certificate dated January 29, 1999 in 70-8721). |
(d) | Refunding Agreement (Series 1999-A) dated as of September 1, 1999 between Entergy Gulf States and Parish of West Feliciana, State of Louisiana (B-3(c) to Rule 24 Certificate dated October 8, 1999 in 70-8721). |
(d) | Refunding Agreement (Series 1999-B) dated as of September 1, 1999 between Entergy Gulf States and Parish of West Feliciana, State of Louisiana (B-3(d) to Rule 24 Certificate dated October 8, 1999 in 70-8721). |
Entergy Louisiana
(e) 1 -- | Agreement, dated April 23, 1982, among Entergy Louisiana and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982, in 1-3517). |
(e) 2 -- | Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) |
(e) 3 -- | Amendment, dated as of February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) |
(e) 4 -- | Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080). |
(e) 5 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a) |
(e) 6 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a) |
(e) 7 -- | Amendment, dated as of |
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| Amendment, dated January 1, 2000, to Service Agreement with Entergy |
*(e) | Amendment, dated |
(e) | |
(e) | Fuel Lease, dated as of January 31, 1989, between River Fuel Company #2, Inc., and Entergy Louisiana (B-1(b) to Rule 24 Certificate in 70-7580). |
(e) | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
(e) | Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-8474). |
(e) | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
(e) | First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
(e) | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
(e) | Middle South Utilities, Inc. and Subsidiary Companies Intercompany Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
(e) | First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated January 1, 1990 (D-2 to Form U5S for the year ended December 31, 1989). |
(e) | 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). |
(e) | 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). |
(e) | 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). |
(e) | Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated February 2, 1984, among DOE, System Fuels and Entergy Louisiana (10(d)33 to Form 10-K for the year ended December 31, 1984 in 1-8474). |
(e) | Operating Agreement between Entergy Operations and Entergy Louisiana, dated as of June 6, 1990 (B-2(c) to Rule 24 Certificate dated June 15, 1990 in 70-7679). |
(e) | Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a) |
(e) | Installment Sale Agreement, dated July 20, 1994, between Entergy Louisiana and St. Charles Parish, Louisiana (B-6(e) to Rule 24 Certificate dated August 1, 1994 in 70-7822). |
(e) | Installment Sale Agreement, dated November 1, 1995, between Entergy Louisiana and St. Charles Parish, Louisiana (B-6(a) to Rule 24 Certificate dated December 19, 1995 in 70-8487). |
(e) | Refunding Agreement (Series 1999-A), dated as of June 1, 1999, between Entergy Louisiana and Parish of St. Charles, State of Louisiana (B-6(a) to Rule 24 Certificate dated July 6, 1999 in 70-9141). |
(e) | Refunding Agreement (Series 1999-B), dated as of June 1, 1999, between Entergy Louisiana and Parish of St. Charles, State of Louisiana (B-6(b) to Rule 24 Certificate dated July 6, 1999 in 70-9141). |
(e) | Refunding Agreement (Series 1999-C), dated as of October 1, 1999, between Entergy Louisiana and Parish of St. Charles, State of Louisiana (B-11(a) to Rule 24 Certificate dated October 15, 1999 in 70-9141). |
(e) 48 --
Agreement as to Expenses and Liabilities between Entergy Louisiana, Inc. and Entergy Louisiana Capital I dated July 16, 1996 (4(d) to Form 10-Q for the quarter ended June 30, 1996 in 1-8474).
Entergy Mississippi
(f) 1 -- | Agreement dated April 23, 1982, among Entergy Mississippi and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
(f) 2 -- | Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) |
(f) 3 -- | Amendment, dated February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080). |
(f) 4 -- | Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080). |
(f) 5 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a) |
(f) 6 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (D in 37-63). |
(f) 7 -- | Amendment, dated |
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| Amendment, dated January 1, 2000, to Service Agreement with Entergy |
*(f) | Amendment, dated |
(f) | |
(f) |
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| Refunding Agreement, dated as of May 1, 1999, between Entergy Mississippi and Independence County, Arkansas (B-6(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719). |
(f) | Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B-3(a) in 70-6337). |
(f) | Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c)51 to Form 10-K for the year ended December 31, 1984 in 0-375). |
(f) | Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c)54 to Form 10-K for the year ended December 31, 1984 in 0-375). |
(f) | Owners Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi and other co-owners of the Independence Station (10(c)55 to Form 10-K for the year ended December 31, 1984 in 0-375). |
(f) | Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c)56 to Form 10-K for the year ended December 31, 1984 in 0-375). |
(f) | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
+(f) | Post-Retirement Plan (10(d)24 to Form 10-K for the year ended December 31, 1983 in 0-320). |
(f) | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
(f) | First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
(f) | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
(f) | Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399). |
(f) | Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399). |
(f) | Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399). |
(f) | Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
(f) | First Amendment dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). |
(f) | Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). |
(f) | Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
(f) | Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
+(f) 45 -- | Employment Agreement effective July 24, 2003 between Carolyn C. Shanks and Entergy Mississippi (10(f)48 to Form 10-K for the year ended December 31, 2003 in 1-31508). |
Entergy New Orleans
(g) 1 -- | Agreement, dated April 23, 1982, among Entergy New Orleans and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) |
(g) 2 -- | Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) |
(g) 3 -- | Amendment dated as of February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) |
(g) 4 -- | Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080). |
(g) 5 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a) |
(g) 6 -- | Service Agreement with Entergy Services dated as of April 1, 1963 (5(a) |
(g) 7 |
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| Amendment, dated as of April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517). |
(g) |
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| Amendment, dated January 1, 2000, to Service Agreement with Entergy |
*(g) | Amendment, dated |
(g) | |
(g) | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
(g) | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
(g) | First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
(g) | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
(g) | Transfer Agreement, dated as of June 28, 1983, among the City of New Orleans, Entergy New Orleans and Regional Transit Authority (2(a) to Form 8-K dated June 24, 1983 in 1-1319). |
(g) | Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
(g) | First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). |
(g) | Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). |
(g) | Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
(g) | 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). |
(12) Statement Re Computation of Ratios
*(a) | Entergy |
*(b) | Entergy Gulf States' Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
*(c) | Entergy Louisiana's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
*(d) | Entergy Mississippi's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
*(e) | Entergy New Orleans' Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
*(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
*(a) | The consent of Deloitte & Touche LLP is contained herein at page |
*(b) | Consent of Ernst & Young LLP. |
*(24) Powers of Attorney
(31) Rule 13a-14(a)/15d-14(a) Certifications
*(a) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation. |
*(b) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation. |
*(c) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas. |
*(d) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States. |
*(e) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States and Entergy Louisiana. |
*(f) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi. |
*(g) | Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans. |
*(h) | Rule 13a-14(a)/15d-14(a) Certification for System Energy. |
*(i) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans. |
*(j) | Rule 13a-14(a)/15d-14(a) Certification for System Energy. |
(32) Section 1350 Certifications
*(a) | Section 1350 Certification for Entergy Corporation. |
*(b) | Section 1350 Certification for Entergy Corporation. |
*(c) | Section 1350 Certification for Entergy Arkansas. |
*(d) | Section 1350 Certification for Entergy Gulf States. |
*(e) | Section 1350 Certification for Entergy Gulf States and Entergy Louisiana. |
*(f) | Section 1350 Certification for Entergy Mississippi. |
*(g) | Section 1350 Certification for Entergy New Orleans. |
*(h) | Section 1350 Certification for System Energy. |
*(i) | Section 1350 Certification for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans. |
*(j) | Section 1350 Certification for System Energy. |
(99) Additional Exhibits
*(a) | Entergy-Koch, LP Financial Statements for the years 2004, 2003, and 2002. |
_________________
* Filed herewith.
+ Management contracts or compensatory plans or arrangements.