-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, IocaSzXroqFyqsM/nAQmow2LjyVfkdZiiitMreXwdIe7QwORn33WqTJj63wO3iUS G/kM8g/TEwwSrAQoKyPXZA== 0000893928-94-000019.txt : 19940318 0000893928-94-000019.hdr.sgml : 19940318 ACCESSION NUMBER: 0000893928-94-000019 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 16 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940317 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ENTERGY CORP/DE CENTRAL INDEX KEY: 0000893928 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 721229752 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-11299 FILM NUMBER: 94516483 BUSINESS ADDRESS: STREET 1: P O BOX 61000 CITY: NEW ORLEANS STATE: LA ZIP: 70161 BUSINESS PHONE: 5045295262 FORMER COMPANY: FORMER CONFORMED NAME: ENTERGY GSU HOLDINGS INC DATE OF NAME CHANGE: 19931115 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ARKANSAS POWER & LIGHT CO CENTRAL INDEX KEY: 0000007323 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 710005900 STATE OF INCORPORATION: AR FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 000-00375 FILM NUMBER: 94516484 BUSINESS ADDRESS: STREET 1: PO BOX 551 STREET 2: 40TH FLOOR CITY: LITTLE ROCK STATE: AR ZIP: 72203 BUSINESS PHONE: 5013774000 MAIL ADDRESS: STREET 1: P O BOX 551 CITY: LITTLE ROCK STATE: AR ZIP: 72203 FILER: COMPANY DATA: COMPANY CONFORMED NAME: GULF STATES UTILITIES CO CENTRAL INDEX KEY: 0000044570 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 740662730 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 000-20371 FILM NUMBER: 94516513 BUSINESS ADDRESS: STREET 1: 350 PINE ST CITY: BEAUMONT STATE: TX ZIP: 77701 BUSINESS PHONE: 4098386631 MAIL ADDRESS: STREET 1: 350 PINE ST CITY: BEAUMONT STATE: TX ZIP: 77701 FILER: COMPANY DATA: COMPANY CONFORMED NAME: LOUISIANA POWER & LIGHT CO /LA/ CENTRAL INDEX KEY: 0000060527 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 720245590 STATE OF INCORPORATION: LA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-08474 FILM NUMBER: 94516485 BUSINESS ADDRESS: STREET 1: PO BOX 61000 CITY: NEW ORLEANS STATE: LA ZIP: 70161 BUSINESS PHONE: 5045953100 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MISSISSIPPI POWER & LIGHT CO CENTRAL INDEX KEY: 0000066901 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 640205830 STATE OF INCORPORATION: MS FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 000-00320 FILM NUMBER: 94516486 BUSINESS ADDRESS: STREET 1: PO BOX 1640 CITY: JACKSON STATE: MS ZIP: 39215-1640 BUSINESS PHONE: 6019692311 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NEW ORLEANS PUBLIC SERVICE INC CENTRAL INDEX KEY: 0000071508 STANDARD INDUSTRIAL CLASSIFICATION: 4931 IRS NUMBER: 720273040 STATE OF INCORPORATION: LA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 000-05807 FILM NUMBER: 94516487 BUSINESS ADDRESS: STREET 1: PO BOX 61000 CITY: NEW ORLEANS STATE: LA ZIP: 70161 BUSINESS PHONE: 5045953100 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SYSTEM ENERGY RESOURCES INC CENTRAL INDEX KEY: 0000202584 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 720752777 STATE OF INCORPORATION: AR FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-09067 FILM NUMBER: 94516488 BUSINESS ADDRESS: STREET 1: ECHELON ONE STREET 2: 1340 ECHELON PKWY CITY: JACKSON STATE: MS ZIP: 39213 BUSINESS PHONE: 6019849000 MAIL ADDRESS: STREET 1: PO BOX 31995 CITY: JACKSON STATE: MS ZIP: 39286-1995 FORMER COMPANY: FORMER CONFORMED NAME: MIDDLE SOUTH ENERGY INC DATE OF NAME CHANGE: 19860803 10-K 1 FORM 10-K 12/31/93 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the Fiscal Year Ended December 31, 1993 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from ____________ to ____________ Commission Registrant, State of Incorporation, IRS Employer File Number Address and Telephone Number Identification No. - ----------- ----------------------------------- ------------------- 1-11299 ENTERGY CORPORATION 13-5550175 (a Delaware corporation) 225 Baronne Street New Orleans, Louisiana 70112 Telephone (504) 529-5262 1-10764 ARKANSAS POWER & LIGHT COMPANY 71-0005900 (an Arkansas corporation) 425 West Capitol Avenue, 40th Floor Little Rock, Arkansas 72201 Telephone (501) 377-4000 1-2703 GULF STATES UTILITIES COMPANY 74-0662730 (a Texas corporation) 350 Pine Street Beaumont, Texas 77701 Telephone (409) 838-6631 1-8474 LOUISIANA POWER & LIGHT COMPANY 72-0245590 (a Louisiana corporation) 639 Loyola Avenue New Orleans, Louisiana 70113 Telephone (504) 569-4000 0-320 MISSISSIPPI POWER & LIGHT COMPANY 64-0205830 (a Mississippi corporation) 308 East Pearl Street Jackson, Mississippi 39201 Telephone (601) 969-2311 0-5807 NEW ORLEANS PUBLIC SERVICE INC. 72-0273040 (a Louisiana corporation) 639 Loyola Avenue New Orleans, Louisiana 70113 Telephone (504) 569-4000 1-9067 SYSTEM ENERGY RESOURCES, INC. 72-0752777 (an Arkansas corporation) Echelon One 1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 984-9000 Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange Registrant Title of Class on Which Registered Entergy Corporation Common Stock, $0.01 Par Value New York Stock - 230,310,494 Exchange, Inc. Shares outstanding at Midwest Stock February 28, 1994 Exchange Incorporated Pacific Stock Exchange Incorporated Arkansas Power & $2.40 Preferred Stock, New York Stock Light Company Cumulative, $0.01 Par Value Exchange, Inc. ($25 Involuntary Liquidation Value) Gulf States Utilities Preferred Stock, Cumulative, Company $100 Par Value: $4.40 Dividend Series New York Stock Exchange, Inc. $4.52 Dividend Series New York Stock Exchange, Inc. $5.08 Dividend Series New York Stock Exchange, Inc. $8.80 Dividend Series New York Stock Exchange, Inc. Adjustable Rate Series B (Depositary Receipts) New York Stock Exchange, Inc. Preference Stock, Cumulative, New York Stock without Par Value Exchange, Inc. $1.75 Dividend Series Louisiana Power & 9.68% Preferred Stock, New York Stock Light Company Cumulative, $25 Par Value Exchange, Inc. 12.64% Preferred Stock, New York Stock Cumulative, $25 Par Value Exchange, Inc. Securities registered pursuant to Section 12(g) of the Act: Registrant Title of Class Arkansas Power & Preferred Stock, Cumulative, Light Company $100 Par Value Preferred Stock, Cumulative, $25 Par Value Preferred Stock, Cumulative, $0.01 Par Value Louisiana Power & Preferred Stock, Cumulative, Light Company $100 Par Value Preferred Stock, Cumulative, $25 Par Value Mississippi Power & Preferred Stock, Cumulative, Light Company $100 Par Value New Orleans Public Preferred Stock, Cumulative, Service Inc. $100 Par Value 4 3/4% 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. Yes __X__ 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. [ ] The aggregate market value of Entergy Corporation Common Stock, $0.01 Par Value, held by non-affiliates, was $7.7 billion based on the reported last sale price of such stock on the New York Stock Exchange on February 28, 1994. Entergy Corporation is the sole holder of the common stock of Arkansas Power & Light Company, Gulf States Utilities Company, Louisiana Power & Light Company, Mississippi Power & Light Company, New Orleans Public Service 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 6, 1994, are incorporated by reference into Part III hereof. TABLE OF CONTENTS Page Number ------ Definitions Part I Item 1. Business Item 2. Properties Item 3. Legal Proceedings Item 4. Submission of Matters to a Vote of Security Holders Part II Item 5. Market for Registrants' Common Equity and Related Stockholder Matters Item 6. Selected Financial Data Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation Item 8. Financial Statements and Supplementary Data Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Part III Item 10. Directors and Executive Officers of the Registrants Item 11. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management Item 13. Certain Relationships and Related Transactions Part IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K Experts Signatures Consents of Experts Independent Auditors' Report on Financial Statement Schedules Index to Financial Statement Schedules Exhibit Index This combined Form 10-K is separately filed by Entergy Corporation, Arkansas Power & Light Company, Gulf States Utilities Company, Louisiana Power & Light Company, Mississippi Power & Light Company, New Orleans Public Service 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 no representation as to information relating to the other companies. This report (including the material incorporated herein by reference) must be read in its entirety. No one section of the report deals with all aspects of the subject matter. DEFINITIONS Certain abbreviations or acronyms used in the text and notes are defined below: Abbreviation or Acronym Term ------------ ---- AFUDC Allowance for Funds Used During Construction Algiers 15th Ward of the City of New Orleans, Louisiana ALJ Administrative Law Judge Alliance The Alliance for Affordable Energy, Inc. ANO Arkansas Nuclear One Steam Electric Generating Station (nuclear) ANO 2 Unit No. 2 of ANO AP&L Arkansas Power & Light Company APSC Arkansas Public Service Commission Arkansas District Court United States District Court for the Western District of Arkansas Availability Agreement Agreement, dated as of June 21, 1974, as amended, among System Energy and AP&L, LP&L, MP&L, and NOPSI, and the assignments thereof Cajun Cajun Electric Power Cooperative, Inc. Capital Funds Agreement Agreement, dated as of June 21, 1974, as amended, between System Energy and Entergy Corporation, and the assignments thereof CCLM Customer-Controlled Load Management (a DSM activity utilizing residential time-of-use rates) City of New Orleans or City New Orleans, Louisiana Council Council of the City of New Orleans, Louisiana D.C. Circuit United States Court of Appeals for the District of Columbia Circuit DOE United States Department of Energy DSM Demand-Side Management (Least Cost Plan activities that influence electricity usage by consumers) Eighth Circuit United States Court of Appeals for the Eighth Circuit Energy Act Energy Policy Act of 1992 Entergy or System Entergy Corporation and its various direct and indirect subsidiaries Entergy Corporation Entergy Corporation, a Delaware corporation, successor to Entergy Corporation, a Florida corporation Entergy Enterprises Entergy Enterprises, Inc. (formerly Electec, Inc.) Entergy Operations Entergy Operations, Inc. Entergy Power Entergy Power, Inc. Entergy Services Entergy Services, Inc. EPA Environmental Protection Agency EWG Exempt Wholesale Generator February 4 Resolution The Resolution (including the Determinations and Order referred to therein) adopted by the Council on February 4, 1988, disallowing the recovery by NOPSI of $135 million of previously deferred Grand Gulf 1 related costs FERC Federal Energy Regulatory Commission Grand Gulf Station Grand Gulf Steam Electric Generating Station (nuclear) Grand Gulf 1 Unit No. 1 of the Grand Gulf Station Grand Gulf 2 Unit No. 2 of the Grand Gulf Station GSU Gulf States Utilities Company (including wholly owned subsidiaries - Varibus Corporation, GSG&T, Inc., Prudential Oil & Gas, Inc., and Southern Gulf Railway Company) Holding Company Act Public Utility Holding Company Act of 1935, as amended Independence Station Independence Steam Electric Generating Station (coal) Independence 2 Unit No. 2 of the Independence Station IRS Internal Revenue Service KV Kilovolts KWH Kilowatt-Hour(s) Least Cost Plan Least Cost Integrated Resource Plan (combination of demand- and supply-side resources to be used by Entergy to satisfy electricity demand) LP&L Louisiana Power & Light Company LPSC Louisiana Public Service Commission MCF 1,000 cubic feet of gas Merger The combination transaction, consummated on December 31, 1993, by which GSU became a subsidiary of Entergy Corporation and Entergy Corporation became a Delaware corporation MP&L Mississippi Power & Light Company MPSC Mississippi Public Service Commission MW Megawatt(s) Nelson Unit 6 Unit No. 6 (coal) of the Nelson Steam Electric Generating Station NISCO Nelson Industrial Steam Company 1986 NOPSI Settlement Settlement, effective March 25, 1986, between NOPSI and the Council regarding NOPSI's Grand Gulf- related rate issues. 1991 NOPSI Settlement Settlement, retroactive to October 4, 1991, among NOPSI, the Council, and the Alliance that settled certain Grand Gulf 1 prudence issues and certain litigation related to the February 4 Resolution NOPSI New Orleans Public Service Inc. NRC Nuclear Regulatory Commission PRP Potentially Responsible Party (a person or entity that may be responsible for remediation of environmental contamination) PUCT Public Utility Commission of Texas PURPA Public Utility Regulatory Policies Act REA Rural Electrification Administration Reallocation Agreement 1981 Agreement, superseded in part by a June 13, 1985 decision of FERC, among AP&L, LP&L, MP&L, NOPSI, and System Energy relating to the sale of capacity and energy from the Grand Gulf Station Ritchie 2 Unit No. 2 of the R. E. Ritchie Steam Electric Generating Station (gas/oil) River Bend River Bend Steam Electric Generating Station (nuclear), owned 70% by GSU. SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards, promulgated by the Financial Accounting Standards Board SRG&T Sam Rayburn G&T, Inc. SRMPA Sam Rayburn Municipal Power Agency System Agreement Agreement, effective January 1, 1983, as modified, among the System operating companies relating to the sharing of generating capacity and other power resources System Energy System Energy Resources, Inc. System Fuels System Fuels, Inc. System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively Unit Power Sales Agreement Agreement, dated as of June 10, 1982, as amended and approved by FERC, among AP&L, LP&L, MP&L, NOPSI, and System Energy, relating to the sale of capacity and energy from System Energy's share of Grand Gulf 1 Waterford 3 Unit No. 3 (nuclear) of the Waterford Steam Electric Generating Station PART I Item 1. Business BUSINESS OF ENTERGY General Entergy Corporation was originally incorporated under the laws of the State of Florida on May 27, 1949. On December 31, 1993, in connection with the Merger (see "Entergy Corporation-GSU Merger," below), Entergy Corporation merged with and into Entergy-GSU Holdings, Inc., a Delaware corporation (Holdings), and Holdings was renamed Entergy Corporation. Entergy Corporation is a holding company registered under the Holding Company Act and does not own or operate any physical properties. Entergy Corporation owns all of the outstanding common stock of five retail operating electric utility subsidiaries, AP&L, GSU, LP&L, MP&L, and NOPSI. AP&L was incorporated under the laws of the State of Arkansas in 1926; GSU was incorporated under the laws of the State of Texas in 1925; LP&L and NOPSI were incorporated under the laws of the State of Louisiana in 1974 and 1926, respectively; and MP&L was incorporated under the laws of the State of Mississippi in 1963. As of December 31, 1993, these operating companies provided electric service to approximately 2.3 million customers in the States of Arkansas, Louisiana, Mississippi, Missouri, and Texas. In addition, GSU furnished gas service in the Baton Rouge, Louisiana area, and NOPSI furnished gas service in the City of New Orleans. GSU's steam products department produces and sells, on an unregulated basis, process steam and by- product electricity supplied from its steam electric extraction plant to a large industrial customer. The business of the System is subject to seasonal fluctuations with the peak period occurring during the third quarter. During 1993, the System's (excluding GSU) electricity sales as a percentage of total System energy sales were: residential - 28.1%; commercial - 19.9%; and industrial - 36.9%. Electric revenues from these sectors as a percentage of total System electric revenues were: 36.3% - residential; 24.4% - commercial; and 27.3% - industrial. Sales to governmental and municipal sectors and to nonaffiliated utilities accounted for the balance of energy sales. During 1993, GSU's electric department sales as a percentage of total GSU energy sales were: residential - 25.5%; commercial - 20.3%; and industrial - 50.8%. Electric revenues from these sectors as a percentage of total GSU electric revenues were: 33.5% - residential; 23.8% - commercial; and 37.2% - industrial. Sales to governmental and municipal sectors and to nonaffiliated utilities accounted for the balance of GSU's energy sales. The System's major industrial customers are in the chemical processing, petroleum refining, paper products, and food products industries. Entergy Corporation also owns all of the outstanding common stock of System Energy, Entergy Services, Entergy Operations, Entergy Power, and Entergy Enterprises. System Energy is a nuclear generating company that was incorporated under the laws of the State of Arkansas in 1974. System Energy sells the capacity and energy at wholesale from its 90% interest in Grand Gulf 1 to its only customers, AP&L, LP&L, MP&L, and NOPSI (see "Capital Requirements and Future Financing - - Certain System Financial and Support Agreements - Unit Power Sales Agreement," below). System Energy has approximately a 78.5% ownership interest and an 11.5% leasehold interest in Grand Gulf 1. Entergy Services provides general executive and advisory services, and accounting, engineering, and other technical services to certain of the System companies, generally at cost. Entergy Operations is a nuclear management company that operates ANO, River Bend, Waterford 3, and Grand Gulf 1, subject to the owner oversight of AP&L, GSU, LP&L, and System Energy, respectively. Entergy Power, an independent power producer, owns 809 MW of generating capacity and markets its capacity and energy in the wholesale market outside Arkansas and Missouri and in markets not otherwise presently served by the System. (For further information on regulatory proceedings related to Entergy Power, see "Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters - Entergy Power," below). Entergy Enterprises is a nonutility company that invests in businesses whose products and activities are of benefit to the System's utility business (see "Corporate Development," below). Entergy Enterprises also markets technical expertise developed by the System companies when it is not required in the System's operations. Entergy Enterprises has received SEC approval to provide services to certain nonutility companies in the System. In 1992 and 1993, several new Entergy Corporation subsidiaries were formed to participate in utility projects located outside the System's retail service territory, both domestically and in foreign countries (see "Corporate Development," below). AP&L, LP&L, MP&L, and NOPSI own, in ownership percentages of 35%, 33%, 19%, and 13%, respectively, all of the common stock of System Fuels, a non-profit subsidiary, that implements and/or maintains certain programs to procure, deliver, and store fuel supplies for the System. GSU has four wholly-owned subsidiaries: Varibus Corporation, GSG&T, Inc., Southern Gulf Railway Company, and Prudential Oil & Gas, Inc. Varibus Corporation operates intrastate gas pipelines in Louisiana, which are used primarily to transport fuel to two of GSU's generating stations, and has marketed computer-aided engineering and drafting technologies and related computer equipment and services. GSG&T, Inc. owns the Lewis Creek Station, a 532 MW (as of December 31, 1993) gas-fired generating plant, which is leased and operated by GSU. Southern Gulf Railway Company will own and operate several miles of rail track being constructed in Louisiana for the purpose of transporting coal for use as a boiler fuel at Nelson Unit 6. Prudential Oil & Gas, Inc., which was formerly in the business of exploring, developing, and operating oil and gas properties in Texas and Louisiana, is presently inactive. Entergy Corporation-GSU Merger On December 31, 1993, Entergy Corporation consummated its acquisition of GSU. Entergy Corporation merged with and into Holdings, and Holdings was renamed Entergy Corporation. GSU became a wholly-owned subsidiary of Entergy Corporation and continues to operate as a public utility under the regulation of the PUCT and the LPSC. As consideration to GSU's shareholders, Entergy Corporation paid $250 million in cash and issued 56,667,726 shares of its common stock at a price of $35.8417 per share, in exchange for outstanding shares of GSU common stock. In addition, $33.5 million of transaction costs were capitalized in connection with the Merger. See "Rate Matters and Regulation - Regulation - Other Regulation and Litigation," for, information on requests for rehearing and appeals of certain regulatory approvals of the Merger. The information contained in this Form 10-K is filed on behalf of all the registrants of Entergy, including GSU. Unless otherwise noted, consolidated financial and statistical information contained in this report that is stated as of December 31, 1993 (such as assets, liabilities, and property), includes the associated GSU amounts, and consolidated financial and statistical information for periods ending before January 1, 1994 (such as revenues, sales, and expenses), does not include GSU amounts; those amounts are presented separately for GSU herein. Certain Industry and System Challenges The System's business is affected by various challenges and issues including those that confront the electric utility industry in general. These issues and challenges include: - an increasingly competitive environment (see "Competition," below); - compliance with regulatory requirements with respect to nuclear operations (see "Rate Matters and Regulation - Regulation - Regulation of the Nuclear Power Industry," below) and environmental matters (see "Rate Matters and Regulation - Regulation - Environmental Regulation," below); - adaptation to structural changes in the electric utility industry, including increased emphasis on least cost planning and changes in the regulation of generation and transmission of electricity (see "Competition - General" and "Competition - Least Cost Planning," below); - continued cost management (particularly in the area of operation and maintenance costs at nuclear units) to improve financial results and to delay or to minimize the need for rate increase requests in light of current rate freezes and rate caps at the System operating companies (see "Rate Matters and Regulation - Rate Matters - Retail Rate Matters," below); - integrating GSU into the System's operations and achieving cost savings (see "Entergy Corporation-GSU Merger," above); - achieving enhanced earnings in light of lower returns and slow growth in the domestic utility business (see "Corporate Development," below); and - resolving GSU's major contingencies, including potential write- offs and refunds related to River Bend (see "Rate Matters and Regulation - Rate Matters - Retail Rate Matters - GSU," below) and litigation with Cajun relating to its ownership interest in River Bend (see "Rate Matters and Regulation - Regulation - Other Regulation and Litigation - GSU," below). Corporate Development Entergy continues to consider new opportunities to expand its regulated electric utility business, as well as to expand into utility and utility-related businesses that are not regulated by state and local regulatory authorities (nonregulated businesses). Investments in nonregulated businesses are likely to draw upon the System's skills in power generation and customer service as well as its strengths in the fuels area. Entergy Corporation's investment strategy with respect to nonregulated businesses is to invest in nonregulated business opportunities wherein Entergy Corporation has the potential to earn a greater rate of return compared to its regulated utility operations. Entergy Corporation's nonregulated businesses fall into two broad categories: overseas power development and new electro- technologies. Entergy Corporation has made investments in Argentina's electric energy infrastructure, as described below, and is pursuing additional projects in Central America, South America, South Africa, and Asia. Entergy Corporation will also open offices in Buenos Aires, Argentina and Hong Kong in 1994. In addition, Entergy Corporation is seeking to provide telecommunications services based upon its experience with interactive communications systems that allow customers to control energy usage. Entergy Corporation expects to invest approximately $150 million per year in nonregulated businesses. Current investments in nonregulated businesses include the following: (1) Entergy Corporation's subsidiary, Entergy Power Development Corporation (an EWG under the provisions of the Energy Act), through its subsidiary (which is also an EWG) Entergy Richmond Power Corporation, owns a 50% interest in an independent power plant in Richmond, Virginia. The power plant is jointly-owned and operated by the Enron Power Corporation, a developer of independent power projects. The plant owners have a 25-year contract to sell electricity to Virginia Electric & Power Company. Entergy Corporation's investment in the project totals approximately $12.5 million. (2) Entergy Enterprises has a 9.95% equity interest in First Pacific Networks, Inc. (FPN), a communications company, and a license from FPN in connection with utility applications, being jointly developed by Entergy Enterprises and FPN, for FPN's patented communications technology. Entergy Enterprises' investment in FPN is approximately $20.1 million, of which $9.7 million is equity investment. (3) Entergy Enterprises' subsidiary, Entergy Systems and Service, Inc. (Entergy SASI), holds a 9.95% equity interest in Systems and Service International, Inc. (SASI), a manufacturer of efficient lighting products. This subsidiary also made a loan to SASI, acquired the business and assets of SASI's distribution subsidiary, and entered into an agreement to distribute SASI's products. Entergy Enterprises' initial investment in this business was approximately $11 million (of which $2.3 million is invested in SASI common stock). Entergy Corporation has provided to Entergy SASI $6.0 million in loans, as of December 31, 1993, to fund Entergy SASI's installment sale agreements with its customers. (4) Entergy Corporation's subsidiary, Entergy, S.A., participated in a consortium with other nonaffiliated companies that acquired a 60% interest in Argentina's Costanera steam electric generating facility consisting of seven natural gas- and oil-fired generating units, with a total installed capacity of 1,260 MW. Entergy Corporation's initial investment to acquire its 10% interest in the consortium was approximately $11 million and its maximum financial obligation currently authorized by the SEC in connection with this investment is $22.5 million. (5) In January 1993, Entergy Corporation, through a new subsidiary, Entergy Argentina, S.A., participated in a consortium with other nonaffiliated companies that acquired a 51% interest in a foreign electric distribution company providing service to Buenos Aires, Argentina. Entergy Corporation's initial investment to acquire its 10% interest in the consortium was approximately $58 million and its maximum financial obligation currently authorized by the SEC in connection with this investment is $77.5 million. (6) In July 1993, Entergy Corporation, through a new subsidiary, Entergy Transener, S.A., participated in a consortium with other nonaffiliated companies that acquired a 65% interest in a foreign transmission system providing service in the country of Argentina. Entergy Corporation's initial investment to acquire its 15% interest in the consortium was $18.5 million. In the near term, these investments are likely to have a minimal effect on earnings; but the possibility exists that they could contribute to future earnings growth. However, due to the absence of an allowed rate of return, these investments involve a higher degree of risk. International operations are subject to certain risks that are inherent in conducting business abroad, including possible nationalization or expropriation, price and exchange controls, limitations on foreign participation in local governmental enterprises, and other restrictive actions. Changes in the relative value of currencies take place from time to time and their effects may be favorable or unfavorable on results of operations. In addition, there are exchange control restrictions in certain countries relating to repatriation of earnings. Selected Data Selected customer and sales data for 1993 are summarized in the following tables: 1993 - Selected Customer Data Customers as of December 31, 1993 ------------------ Area Served Electric Gas ----------- -------- --- AP&L Portions of State of Arkansas 590,862 - GSU Portions of the States of Texas 593,975 85,040 and Louisiana LP&L Portions of State of Louisiana 599,991 - MP&L Portions of State of Mississippi 361,692 - NOPSI City of New Orleans, except Algiers, is provided electric service by LP&L 190,613 154,251 --------- ------- System 2,337,133 239,291 ========= ======= 1993 - Selected Electric Energy Sales Data
System System Excluding AP&L LP&L MP&L NOPSI Energy GSU GSU ---- ---- ---- ----- ------ --------- --- Sales to retail customers 15,667 28,115 10,034 5,326 - 59,142 27,493 Sales for resale: - Affiliates 8,002 112 758 90 7,113 - - - Others 5,948 1,213 670 261 - 8,291 666 - Sales to steam products customer - - - - - - 1,597 ------ ------ ------ ------ ----- ------ ------ Total 29,617 29,440 11,462 5,677 7,113 67,433 29,756 ====== ====== ====== ====== ===== ====== ====== Average use per residential customer (KWH) 11,206 13,949 12,903 11,145 - 12,501 13,905 ====== ====== ====== ====== ===== ====== ======
NOPSI sold 17,437,292 MCF of natural gas to retail customers in 1993. Revenues from natural gas operations for each of the three years in the period ended December 31, 1993, were material for NOPSI, but not material for the System (see "Industry Segments," below, for a description of NOPSI's business segments). GSU sold 6,786,794 MCF of natural gas to retail customers in 1993. Revenues from natural gas operations for each of the three years in the period ended December 31, 1993, were not material for GSU. See "Entergy Corporation and Subsidiaries Selected Financial Data - - Five-Year Comparison," "AP&L Selected Financial Data - Five-Year Comparison," "GSU Selected Financial Data - Five-Year Comparison," "LP&L Selected Financial Data - Five-Year Comparison," "MP&L Selected Financial Data - Five-Year Comparison," "NOPSI Selected Financial Data - - Five-Year Comparison," and "System Energy Selected Financial Data - Five-Year Comparison," (which follow each company's notes to financial statements herein) incorporated herein by reference, for further information with respect to operating statistics of the System and of AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy, respectively. Employees As of December 31, 1993, Entergy had 16,679 employees as follows: Full-time: Entergy Corporation 6 AP&L 2,557 GSU (1) 4,765 LP&L 1,727 MP&L 1,236 NOPSI 716 System Energy - Entergy Operations 3,508 Entergy Services (2) 1,986 Other Subsidiaries 24 ------ Total Full-time 16,525 Part-time 154 ------ Total Entergy System 16,679 ====== __________________ (1) As of December 31, 1993, GSU had not been functionally aligned into Entergy. In December 1993, GSU recorded $17 million for an announced early retirement program in connection with the Merger. Of the 503 employees eligible, 369 employees elected to participate in the program. (2) As a result of System realignment of operations along functional lines, certain employees of AP&L, LP&L, MP&L, and NOPSI transferred to Entergy Services during 1993. Competition General. Entergy and the electric utility industry are experiencing increased competitive pressures both in the retail and wholesale markets. The economic, social, and political forces behind these competitive pressures are numerous and complex. They include legislative and regulatory changes, technological advances, consumer demands, greater availability of natural gas, environmental needs, and others. Entergy looks at these competitive pressures both as opportunities to compete for new customers and as risks for loss of customers. On October 24, 1992, Congress passed the Energy Act. The Energy Act addresses a wide range of energy issues and alters the way Entergy and the rest of the electric utility industry will operate in the future. The Energy Act creates exemptions from regulation under the Holding Company Act and creates a class of EWG's consisting of utility affiliates and nonutilities that are owners and operators of facilities for the generation and transmission of power for sales at wholesale. These exemptions offer an incentive for Entergy to participate in the development of wholesale power generation. In addition, the Holding Company Act has been amended to allow utilities to compete on a global scale with foreign entities to own and operate generation, transmission, and distribution facilities. The Energy Act also gives FERC the authority to order investor-owned utilities, including the System operating companies, to transmit power and energy to or for wholesale purchasers and sellers. The law creates the potential for electric utilities and other power producers to gain increased access to the transmission systems of other entities to facilitate wholesale sales. FERC may also require electric utilities to increase their transmission capacity to provide these services. The impact of this provision on the System operating companies should be lessened by their joint filing of open access transmission service tariffs with FERC in 1991 (see "Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters," below). The Energy Act also amends PURPA by requiring states to consider (1) new regulatory standards that would require electric utilities to undertake integrated resource planning, and (2) allowing energy efficiency programs to be at least as profitable as new energy supply options. Entergy is unable to predict the ultimate impact the Energy Act will have on its operations. Wholesale Competition. Entergy has, like other utility systems, generating capacity (most of which is owned by Entergy Power) and energy available for a period of time for sale to other utility systems. The System is in competition with neighboring systems, as well as EWG's, to sell such capacity and energy. Given this competition, the ability of the System to sell this capacity and energy is limited. However, in 1993, the System sold 8,291 million KWH of energy (compared to 7,979 million KWH in 1992) to nonaffiliated utilities. The System also sold 1,234 MW of long-term capacity (compared to 1,048 MW in 1992) to nonaffiliated utilities outside of the System's service area. These capacity sales represent 8% of the System's net capability (excluding GSU) at year-end 1993. Under AP&L's and LP&L's Grand Gulf 1 rate orders, and under GSU's River Bend rate order in Louisiana, a portion of the capacity of Grand Gulf 1 and River Bend represents capacity that is available for sale, subject to regulatory approval, to nonaffiliated parties. In some cases, profits from such sales must be shared between ratepayers and shareholders. As discussed in "Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters - Open Access Transmission," below, Entergy Power and the System operating companies will be permitted by FERC to make wholesale capacity sales in bulk power markets at rates based primarily upon negotiation and market conditions rather than cost of service. In order to receive authorization to make such sales, AP&L, LP&L, MP&L, and NOPSI also filed with FERC open access transmission service tariffs. FERC has approved this filing, subject to certain modifications. Revisions to the tariffs were filed in December 1993 to recognize GSU's inclusion in the Entergy System. When the modified tariffs are made effective, Entergy Power and the System operating companies may engage in sales at market prices. It is anticipated that these tariffs will enable any electric utility (as defined in such tariffs) to use Entergy 's integrated transmission system for the transmission of capacity and energy produced and sold by such electric utility or by third parties. Other similar open access transmission tariffs have also been filed with FERC for several large utility companies or systems and more open access transmission tariffs are anticipated. Concurrently, capacity resources are being developed and used to make wholesale sales from a range of non-traditional sources, including nonutility generators as well as cogenerators and small power producers qualifying under PURPA. These developments simultaneously produce increased marketing opportunities for utility systems such as Entergy and expose the System to loss of load or reduced sales revenues due to displacement of System sales by alternative suppliers with access to the System's primary areas of service. Entergy Power, which owns 809 MW of capacity, was formed to compete with other utilities and independent power producers in the bulk power market. As of December 31, 1993, Entergy Power has accumulated total losses from operations of $52.5 million. Entergy Power has entered into several long-term contracts for the sale of capacity and associated energy from its resources and has also made short-term capacity and energy sales. Entergy Power continues to actively market its capacity and energy in the bulk power market. (See "Corporate Development," above, for information with respect to a wholly-owned subsidiary of Entergy, Entergy Power Development Corporation, organized as an EWG to compete in the wholesale power market.) Retail Competition. Scheduled increases in the price of power sold by the System pursuant to the operation of phase-in plans (see "Rate Matters and Regulation - Rate matters - Retail Rate Matters," below) will affect the competitiveness of certain classes of industrial customers whose costs of production are energy-sensitive. Entergy is constantly working with these customers to address their concerns. It is the practice of the System operating companies to negotiate the renewal of contracts with large industrial customers prior to their expiration. In certain cases (particularly for GSU), contracts or special tariffs that use incentive pricing below total cost have been negotiated with industrial customers to keep these customers on the System. These contracts and tariffs have generally resulted in increased KWH sales at lower margins over incremental cost. While the System operating companies anticipate they will be successful in renegotiating such contracts, they cannot assure that they will be successful or that future revenues will not be lost to other forms of generation. To date, through these efforts, Entergy has been largely successful in retaining its industrial load. This competitive challenge could increase. Cogeneration is generally defined as the combined production of electricity and steam. Cogenerated power may be either sold by its producer to the local utility at its avoided cost under PURPA, or utilized by the cogenerator to displace purchases from the utility. To the extent that cogeneration is used by industrial customers to meet their own power requirements, the System may suffer loss of industrial load. Cogenerated power delivered to the System would be purchased at avoided cost, which for a number of years is expected to be equivalent to avoided energy cost, and as such, the cost of these purchases would not impact earnings. To date, only a few cogeneration facilities have been installed in areas served by the System, excluding GSU. The primary purpose of these facilities is to displace power that was purchased from the System. The economic advantage to the customer is generally due to the customer having waste products that can be used as fuel. Presently, the loss of load to cogeneration and the amount of cogenerated power delivered under PURPA to the System (excluding GSU) is not significant. The System is prepared to participate (subject to regulatory approval) in various phases of the design, construction, procurement, and ownership of cogeneration facilities. The System has entered into several cogeneration deferral agreements with certain of its retail customers, which give the System the right of first refusal to participate in any of such customers' cogeneration activities. Such participation could occur in the event there are individual customers whose long-term interests, along with Entergy's, can best be served by installing cogeneration facilities. No such participation has occurred to date, except by GSU. Existing qualifying facilities in the GSU service territory are estimated to total approximately 2,400 MW's or over 10% of Entergy's total owned and leased generating capability as of December 31, 1993. GSU currently believes that no significant load will be lost to cogeneration projects during the next several years; however, GSU is currently negotiating a contract with a large industrial customer, which is scheduled to expire in 1996. If the contract is not renewed, GSU would lose approximately $40 million in base revenues. Although GSU has competed in the past for various retail and wholesale customers, the System (excluding GSU) generally is not in direct competition with privately-owned or municipally-owned electric utilities for retail sales. However, a few municipalities distribute electricity within their corporate limits and some of these generate all or a portion of their requirements. A number of electric cooperative associations or corporations serve a substantial number of retail customers in or adjacent to areas served by the System . Sales of energy by the System to privately- or municipally-owned utilities amounted to approximately 4.6% of total System energy sales in 1993 (excluding GSU). Legislatures and regulatory commissions in several states have considered, or are considering, retail wheeling, which is the transmission by an electric utility of energy produced by another entity over the utility's transmission and distribution system to a retail customer in the electric utility's service territory. Retail wheeling would permit retail customers to elect to purchase electric capacity and/or energy from the electric utility in whose service area they are located or from any other electric utility or independent power producer. Retail wheeling is not currently required within the Entergy System service area. See "Rate Matters and Regulation - Regulation - Other Regulation and Litigation," below for information on proceedings brought by Cajun seeking transmission access to certain of GSU's industrial customers. Least Cost Planning. The System continues to pursue least cost planning, also known as integrated resource planning, in order to compete more effectively in both retail and wholesale markets. Least cost planning is the development of strategies to add resources to meet future electricity demands reliably and at the lowest possible cost. The least cost planning process includes the study of electric supply- and demand-side options. The resultant plan uses demand-side options, such as changing customer consumption patterns, to limit electricity usage during times of peak demand, thus delaying the need for new capacity resources. Least cost planning offers the potential for the System to minimize customer costs, while providing an opportunity to earn a return. On December 1, 1992, AP&L, LP&L, MP&L, and NOPSI each filed a Least Cost Plan with its respective regulator, and on July 1, 1993, each company filed a near-term revision to such plan. Each Least Cost Plan details the resources that the System intends to use to provide reasonably priced, reliable electric service to its customers over the next 20 years. Such plan includes 925 MW of DSM resources, such as programs for efficient air conditioning and heating, high efficiency lighting, and CCLM. CCLM is the subject of recent Entergy proposals (filed, or to be filed, by AP&L, LP&L, MP&L, and NOPSI with their respective regulators) requesting the CCLM pilot be withdrawn from consideration in the existing Least Cost Plan dockets on the basis of a new proposal by Entergy to undertake the initial pilot development of CCLM at Entergy stockholder expense. To date, the Council and the LPSC are the only regulators that have addressed the proposal. The System expects to spend a total of approximately $800 million for DSM resources over the next 20 years. Such plan also includes significant resource additions, but does not contemplate construction of any generating facilities at new sites. All incremental supply-side resources will come from either delayed retirements or repowering of existing generating units. The System estimates that, over the next 20 years, least cost planning, if implemented in accordance with the terms of each filed Least Cost Plan, will reduce revenue requirements by approximately $2.3 billion ($600 million on a net present value basis), thereby avoiding the need for related rate increase requests. Each Least Cost Plan includes specific actions that the System will undertake pursuant to regulatory approval, including the recovery of costs associated with DSM (for further information, see "Rate Matters and Regulation - Rate Matters - Retail Rate Matters," below). CAPITAL REQUIREMENTS AND FUTURE FINANCING Construction expenditures for the System are estimated to aggregate $586 million, $560 million, and $550 million for the years 1994, 1995, and 1996, respectively. No significant costs are expected in connection with the System's generating facilities. Actual construction costs may vary from these estimates because of a number of factors, including changes in load growth estimates, changes in environmental regulations, modifications to nuclear units to meet regulatory requirements, increasing costs of labor, equipment and materials, and cost of capital. Construction expenditures by company (including immaterial environmental expenditures and AFUDC, but excluding nuclear fuel and the impact of the ice storm that occurred in February 1994) for the period 1994-1996 are estimated as follows: 1994 1995 1996 Total ---- ---- ---- ----- (In Millions) AP&L $181 $172 $175 $528 GSU 134 128 119 381 LP&L 156 143 142 441 MP&L 61 63 63 187 NOPSI 26 26 26 78 System Energy 26 22 23 71 Entergy Power 2 6 2 10 System $586 $560 $550 $1,696 In addition to construction expenditure requirements, the estimated amounts required during 1994-1996 to meet scheduled long- term debt and preferred stock maturities and cash sinking fund requirements are: AP&L - $83 million; GSU - $214 million; LP&L - $158 million; MP&L - $212 million; NOPSI - $80 million; and System Energy - $615 million. A substantial portion of the above capital and refinancing requirements is expected to be satisfied from internally generated funds and cash on hand supplemented by the issuance of debt and preferred stock. Certain System companies may also continue with the acquisition or refinancing of all, or a portion of, certain outstanding series of preferred stock and long-term debt. In early February 1994, an ice storm left more than 221,000 Entergy customers without electric power across the System's four- state service area. The storm was the most severe natural disaster ever to affect the System, causing damage to transmission and distribution lines, equipment, poles, and facilities in certain areas, particularly in Mississippi. A substantial portion of the related costs, which are estimated to be $110 million - $140 million, are expected to be capitalized. The MPSC acknowledged that there is precedent in Mississippi for recovery of certain costs associated with storms and natural disasters and the restoration of service resulting from such events. MP&L plans to immediately file for rate recovery of the costs related to the ice storm (see "Rate Matters and Regulation - Rate Matters - Retail Rate Matters - MP&L," below). Entergy Corporation's current primary capital requirements are to periodically invest in, or make loans to, its subsidiaries. Entergy Corporation has SEC authorization to make additional investments in Entergy Power, Entergy S.A., Entergy Argentina, S.A., Entergy Transener, S.A., Entergy SASI, and FPN. Entergy Corporation expects to meet these requirements in 1994-1996 with internally generated funds and cash on hand. Entergy receives funds through dividend payments from its subsidiaries. Certain restrictions may limit the amount of these distributions. See Entergy Corporation and Subsidiaries' Notes to Consolidated Financial Statements, Note 2, "Rate and Regulatory Matters" and Note 8, "Commitments and Contingencies," incorporated herein by reference, regarding River Bend rate appeals and pending litigation with Cajun. Substantial write- offs or charges resulting from adverse rulings in these matters could adversely affect GSU's ability to continue to pay dividends. Entergy Corporation continues to consider new opportunities to expand its electric energy business, including expansion into related nonregulated businesses. Entergy Corporation expects to invest up to approximately $150 million per year over the next three years in nonregulated business opportunities. Entergy Corporation may finance any such expansion with cash on hand. Further, shareholder and/or regulatory approvals may be required for such acquisitions to take place. Also, Entergy Corporation has SEC authorization to repurchase shares of its outstanding common stock. Market conditions and board authorization determine the amount of repurchases. Entergy Corporation has requested SEC authorization for a $300 million bank line of credit, the proceeds of which are expected to be used for common stock repurchases and other optional activities. (For further information on the capital and refinancing requirements, capital resources, and short-term borrowing arrangements of AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy, respectively, refer in each case to AP&L's, GSU's, LP&L's, MP&L's, NOPSI's, and System Energy's "Management's Financial Discussion and Analysis - Liquidity and Capital Resources," Note 4 of AP&L's, GSU's, LP&L's, MP&L's, NOPSI's, and System Energy's Notes to Financial Statements, "Lines of Credit and Related Borrowings," Note 5 of AP&L's and NOPSI's Notes to Financial Statements, "Preferred Stock", Note 5 of GSU's Notes to Financial Statements, "Preferred, Preference and Common Stock", Note 5 of LP&L's and MP&L's Notes to Financial Statements, "Preferred and Common Stock," Note 6 of AP&L's, GSU's, LP&L's, MP&L's, and NOPSI's and Note 5 of System Energy's Notes to Financial Statements, "Long-Term Debt," and Note 8 of AP&L's, GSU's, LP&L's, MP&L's, and NOPSI's and Note 7 of System Energy's Notes to Financial Statements, "Commitments and Contingencies - Capital Requirements and Financing," each incorporated herein by reference. For further information concerning Entergy Corporation's capital requirements and resources, refer to Entergy Corporation and Subsidiaries' "Management's Financial Discussion and Analysis - Liquidity and Capital Resources," and Note 4 of Entergy Corporation and Subsidiaries' Notes to Consolidated Financial Statements, "Lines of Credit and Related Borrowings," incorporated herein by reference. For further information on the subsequent event, see Note 12 of AP&L's and Note 11 of MP&L's Notes to Financial Statements, "Subsequent Event (Unaudited)," incorporated herein by reference.) Certain System Financial and Support Agreements Unit Power Sales Agreement. The Unit Power Sales Agreement allocates capacity and energy from System Energy's 90% ownership and leasehold interest in Grand Gulf 1 (and the costs related thereto) to AP&L (36%), LP&L (14%), MP&L (33%), and NOPSI (17%). AP&L, LP&L, MP&L, and NOPSI pay rates to System Energy for their respective entitlements 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 revenues. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf 1 and upon the receipt of payments from AP&L, LP&L, MP&L, and NOPSI. (See "Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters - System Energy," below for further information with respect to proceedings relating to the Unit Power Sales Agreement.) Availability Agreement. The Availability Agreement was entered into among System Energy and AP&L, LP&L, MP&L, and NOPSI in 1974 in connection with the financing by System Energy of the Grand Gulf Station. The agreement provided that System Energy would join in the agreement among AP&L, LP&L, MP&L, and NOPSI for the sharing of generating capacity and other capacity and energy resources on or before the date on which Grand Gulf 1 was placed in commercial operation. It also provided that System Energy would make available to AP&L, LP&L, MP&L, and NOPSI all capacity and energy available from System Energy's share of the Grand Gulf Station. System Energy and AP&L, LP&L, MP&L, and NOPSI further agreed that if this agreement were terminated, or if any of the parties thereto withdrew from it, then System Energy would enter into a separate agreement with all of such parties or the withdrawing party, as the case may be, with respect to the purchase of capacity and energy on the same terms as if this agreement were still controlling. AP&L, LP&L, MP&L, and NOPSI also agreed severally to pay System Energy monthly for the right to receive capacity and energy available from the Grand Gulf Station in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement, or otherwise) would be at least equal to System Energy's total operating expenses for the Grand Gulf Station (including depreciation at a specified rate) and interest charges. As amended to date, the Availability Agreement provides that: - the obligation of AP&L, LP&L, MP&L, and NOPSI for payments for Grand Gulf 1 became effective upon commercial operation of Grand Gulf 1 on July 1, 1985; - the sale of capacity and energy generated by the Grand Gulf Station may be governed by a separate power purchase agreement among System Energy and AP&L, LP&L, MP&L, and NOPSI; - the September 1989 write-off of System Energy's investment in Grand Gulf 2, amounting to approximately $900 million, will be amortized for Availability Agreement purposes over 27 years rather than in the month the write-off was recognized on System Energy's books; and - the allocation percentages under the Availability Agreement are fixed as follows: AP&L - 17.1%; LP&L - 26.9%; MP&L - 31.3%; and NOPSI - 24.7%. As noted above, the Unit Power Sales Agreement provides for different allocation percentages for sales of capacity and energy from Grand Gulf 1. However, the allocation percentages under the Availability Agreement remain in effect and would govern payments made thereunder in the event of a shortfall of funds available to System Energy from other sources, including payments by AP&L, LP&L, MP&L, and NOPSI to System Energy under the Unit Power Sales Agreement. System Energy has assigned its rights to payments and advances from AP&L, LP&L, MP&L, and NOPSI under the Availability Agreement as security for its first mortgage bonds and reimbursement obligations to certain banks providing the letters of credit in connection with the equity funding of the sale and leaseback transactions described under "Sale and Leaseback Arrangements - System Energy," below. In these assignments, AP&L, LP&L, MP&L, and NOPSI further agreed that in the event they were prohibited by governmental action from making payments under the Availability Agreement (if, for example, FERC reduced or disallowed such payments as constituting excessive rates; see the second succeeding paragraph), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances. Each of the assignment agreements relating to the Availability Agreement provides that AP&L, LP&L, MP&L, and NOPSI shall make payments directly to System Energy. However, if there is an event of default, AP&L, LP&L, MP&L, and NOPSI shall make those payments directly to the holders of indebtedness secured by such assignment agreements. The payments shall be made pro rata according to the amount of the respective obligations secured. The obligations of AP&L, LP&L, MP&L, and NOPSI to make payments under the Availability Agreement are subject to 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 filing with FERC has been required because sales of capacity and energy from the Grand Gulf Station are being made under the Unit Power Sales Agreement. Other aspects of the Availability Agreement, including the obligations of AP&L, LP&L, MP&L, and NOPSI to make subordinated advances, are subject to the jurisdiction of the SEC under the Holding Company Act, which approval has been obtained. 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. (Refer to the second preceding paragraph.) Amounts that have been received by System Energy under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Consequently, no payments under the Availability Agreement by AP&L, LP&L, MP&L, and NOPSI have ever been required. If AP&L, LP&L, MP&L, or NOPSI became unable in whole or in part to continue making payments to System Energy under the Unit Power Sales Agreement, and System Energy were unable to procure funds from other sources sufficient to cover any potential shortfall between the amount owing under the Availability Agreement and the amount of continuing payments under the Unit Power Sales Agreement plus other funds then available to System Energy, LP&L and NOPSI 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 for the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments. The amount, if any, which these companies would become liable to pay or advance, over and above amounts they would be paying under the Unit Power Sales Agreement for capacity and energy from Grand Gulf 1, would depend on a variety of factors (especially the degree of any such shortfall and System Energy's access to other funds). It cannot be predicted whether any such claims or demands, if made and upheld, could be satisfied. In NOPSI's case, if any such claims or demands were upheld, the holders of certain of NOPSI's outstanding general and refunding mortgage bonds could require redemption of their bonds at par. The ability of AP&L, LP&L, MP&L, and NOPSI to sustain payments under the Availability Agreement and the assignments thereof in material amounts without substantially equivalent recovery from their customers would be limited by their respective available cash resources and financing capabilities at the time. The ability of AP&L, LP&L, MP&L, and NOPSI to recover from their customers payments made under the Availability Agreement, or under the assignments thereof, would depend upon the outcome of regulatory proceedings before the state and local regulatory authorities having jurisdiction. In view of the controversies that arose over the allocation of capacity and energy from Grand Gulf 1 pursuant to the Unit Power Sales Agreement, opposition to recovery would be likely and the outcome of such proceedings, should they occur, is not predictable. Reallocation Agreement. On November 18, 1981, the SEC authorized LP&L, MP&L, and NOPSI to indemnify AP&L against principally its responsibilities and obligations with respect to the Grand Gulf Station contained in the Availability Agreement and the assignments thereof. The revised percentages of allocated capacity of System Energy's share of Grand Gulf 1 and Grand Gulf 2 were, respectively: LP&L - 38.57% and 26.23%; MP&L - 31.63% and 43.97%; and NOPSI - 29.80% and 29.80%. FERC's decision allocating the capacity and energy of Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI supersedes the Reallocation Agreement insofar as it relates to Grand Gulf 1. However, responsibility for any Grand Gulf 2 amortization amounts (see "Availability Agreement," above) has been allocated to LP&L - 26.23%, MP&L - 43.97%, and NOPSI - 29.80% under the terms of the Reallocation Agreement. The Reallocation Agreement does not affect the obligation of AP&L to System Energy's lenders under the assignments referred to in the fifth preceding paragraph, and AP&L would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual obligations. No payments of any amortization amounts will be required as long as amounts paid to System Energy under the Unit Power Sales Agreement, together with other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future. Capital Funds Agreement. System Energy and Entergy Corporation have entered into the Capital Funds Agreement whereby Entergy Corporation has agreed to supply to System Energy sufficient capital to (1) maintain System Energy's equity capital at an amount equal to a minimum of 35% of its total capitalization (excluding short-term debt), and (2) permit the continuation of commercial operation of Grand Gulf 1 and to pay in full all indebtedness for borrowed money of System Energy when due under any circumstances. Entergy Corporation has entered into various supplements to the Capital Funds Agreement, and System Energy has assigned its rights thereunder 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 under "Sale and Leaseback Arrangements - System Energy," below. Each such supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of the Grand Gulf Station may be secured by System Energy's rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as hereinafter defined). In addition, in the particular supplements to the Capital Funds Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital contributions to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). Except with respect to the Specific Payments, which have been approved by the SEC under the Holding Company Act, the performance by both Entergy Corporation and System Energy of their obligations under the Capital Funds Agreement, as supplemented, is subject to the receipt and continued effectiveness of all governmental authorizations necessary to permit such performance, including approval by the SEC under the Holding Company Act. Each of the supplemental agreements provides that Entergy Corporation shall make its payments directly to System Energy. However, if there is an event of default, Entergy Corporation shall make those payments directly to the holders of indebtedness secured by the supplemental agreements. The payments (other than the Specific Payments) shall be made pro rata according to the amount of the respective obligations secured by the supplemental agreements. Sale and Leaseback Arrangements LP&L. On September 28, 1989, LP&L entered into arrangements for the sale and leaseback of an approximate aggregate 9.3% ownership interest in Waterford 3. LP&L has options to terminate the leases and to repurchase the sold interests in Waterford 3 at certain intervals during the basic terms of the leases. Further, at the end of the terms of the leases, LP&L has options to renew the leases or to repurchase the interests in Waterford 3. If LP&L does not exercise its options to repurchase the interests in Waterford 3 on the fifth anniversary (September 28, 1994) of the closing date of the sale and leaseback transactions, LP&L will be required to provide collateral to the owner participants for the equity portion of certain amounts payable by LP&L under the lease. The required collateral is either a bank letter or letters of credit or the pledging of new series of first mortgage bonds issued by LP&L under its first mortgage bond indenture. (For further information on LP&L's sale and leaseback arrangements, including the required maintenance by LP&L of specified capitalization and fixed charge coverage ratios, see Note 9 of LP&L's Notes to Financial Statements, "Leases - Waterford 3 Lease Obligations," incorporated herein by reference.) System Energy. On December 28, 1988, System Energy entered into arrangements for the sale and leaseback of an 11.5% ownership interest in Grand Gulf 1. System Energy has options to terminate the leases and to repurchase the undivided interest in Grand Gulf 1 at certain intervals during the basic lease term. Further, System Energy has an option at the end of the basic lease term to renew the leases or to repurchase the undivided interest in Grand Gulf 1. In connection with the equity funding of the sale and leaseback arrangements, letters of credit are required to be maintained by System Energy under the leases to secure certain amounts payable for the benefit of the equity investors. The letters of credit currently maintained are effective until January 15, 1997. Under the provisions of a reimbursement agreement, dated December 1, 1988, as amended, entered into by System Energy and various banks in connection with the sale and leaseback arrangements related to the letters of credit, System Energy has agreed to a number of covenants relating to, among other things, the maintenance of certain capitalization and fixed charge ratios. In connection with an audit of System Energy by FERC, if a decision of FERC issued on August 4, 1992 (August 4 Order) is ultimately sustained and implemented, System Energy would need to obtain the consent of certain banks to waive the capitalization and fixed charge coverage covenants for a limited period of time in order to avoid violation of such covenants. System Energy has obtained the consent of the banks to waive these covenants for the twelve-month period beginning with the earlier of the write-off or the first refund, if the August 4 Order is implemented prior to December 31, 1994. Absent a waiver, failure by System Energy to perform these covenants could give rise to a draw under the letters of credit and/or an early termination of the letters of credit, and, if such letters of credit were not replaced in a timely manner, could result in a default under, or other early termination of, System Energy's leases. (For further information on the potential effects of the August 4 Order on System Energy's financial condition, see Note 2 of System Energy's Notes to Financial Statements, "Rate and Regulatory Matters - FERC Audit," incorporated herein by reference, and for a further discussion of the provisions of System Energy's Reimbursement Agreement, see System Energy's Notes to Financial Statements, Note 6, "Dividend Restrictions" and Note 7, "Commitments and Contingencies - Reimbursement Agreement," incorporated herein by reference.) RATE MATTERS AND REGULATION RATE MATTERS The System operating companies' retail rates are regulated by their respective state and/or local regulatory authorities, as described below, and their rates for wholesale sales (including intrasystem sales pursuant to the System Agreement) and interstate transmission of electricity are regulated by FERC. Rates for System Energy's sales of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI pursuant to the Unit Power Sales Agreement are also regulated by FERC. Wholesale Rate Matters GSU. For information, see "Retail Rate Matters - GSU," below and "Regulation - Other Regulation and Litigation - GSU," below. System Energy. As described above under "Certain System Financial and Support Agreements," System Energy recovers costs related to its interest in Grand Gulf 1 through rates charged to AP&L, LP&L, MP&L, and NOPSI for Grand Gulf 1 capacity and energy under the Unit Power Sales Agreement. Several proceedings currently pending or recently concluded at FERC affect these rates. In connection with an audit report covering a review of System Energy's books and records for the years 1986-1988, on August 4, 1992, FERC issued an opinion and order (1) finding that System Energy overstated its Grand Gulf 1 utility plant by approximately $95 million for costs included in utility plant that are related to the System's income tax allocation procedures, and (2) requiring System Energy to make adjusting accounting entries and refunds, with interest, to AP&L, LP&L, MP&L, and NOPSI within 90 days from the date of the order. System Energy requested a rehearing of the order, and on October 5, 1992, FERC issued an order allowing additional time for its consideration of such request and deferring System Energy's refund obligation until 30 days following issuance of FERC's order on rehearing. (For further information on FERC's order and its potential effect on System Energy's and Entergy's consolidated financial position, see Note 2 of System Energy's Notes to Financial Statements and Note 2 of Entergy Corporation and Subsidiaries' Notes to Consolidated Financial Statements, "Rate and Regulatory Matters - FERC Audit," incorporated herein by reference.) In a separate proceeding, on August 24, 1992, FERC instituted an investigation of the justness and reasonableness of certain of Entergy's formula wholesale rates, including System Energy's rates under the Unit Power Sales Agreement. Various regulatory authorities intervened in the proceeding. On August 2, 1993, Entergy and the intervenors settled the proceeding and agreed that System Energy's rate of return on equity would be reduced from 13% to 11%, and such rate would remain in effect until at least August 1995. Refunds were payable by System Energy with respect to the period from November 2, 1992, through the effective date of the settlement. FERC approved the settlement on October 25, 1993, and System Energy credited AP&L, LP&L, MP&L, and NOPSI with an aggregate of $29.6 million on their October 1993 bills. This matter is now final. (See Note 2 of System Energy's Notes to Financial Statements, "Rate and Regulatory Matters - FERC Return on Equity Case," incorporated herein by reference.) Entergy Power. In 1990, authorizations were obtained from the SEC, FERC, the APSC, and the Public Service Commission of Missouri for Entergy Power to purchase AP&L's interests in Independence 2 and Ritchie 2, and to begin marketing the capacity and energy from the units in certain wholesale markets. The SEC order approving various aspects of the transaction was appealed by various intervenors in the proceeding to the D.C. Circuit, which reversed a portion of the order and remanded the case to the SEC for consideration of the effect of the transfers on the System's future costs of replacement generating capacity and fuel. In response to a June 24, 1993 SEC order setting a procedural schedule for the filing of further pleadings in the proceeding, in July 1993, the Entergy parties filed a post-effective amendment to their application addressing the issues specified in the SEC order. On September 9, 1993, the City of New Orleans and the LPSC each requested a hearing. However, on January 5, 1994, the City of New Orleans withdrew from the proceeding, as agreed in its settlement with NOPSI of various issues related to the Merger. System Agreement. AP&L, LP&L, MP&L, and NOPSI engage in the coordinated planning, construction, and operation of generation and transmission facilities pursuant to the terms of the System Agreement (described under "Property - Generating Stations," below). GSU became a party to the System Agreement upon consummation of the merger of Entergy's and GSU's electric systems, and GSU now participates in this System-wide coordination. For further information, see Note 2 of GSU's Notes to Financial Statements and Note 2 of Entergy Corporation and Subsidiaries' Notes to Consolidated Financial Statements, "Rate and Regulatory Matters - Merger-Related Rate Agreements." In connection with the Merger, FERC approved certain rate schedule changes to integrate GSU into the System Agreement. Certain commitments were adopted to provide reasonable assurance that the ratepayers of the existing Entergy operating companies will not be allocated higher costs, including, among other things: (1) a tracking mechanism to protect operating companies from certain unexpected increases in fuel costs; (2) excluding GSU from the distribution of profits from power sales contracts entered into prior to the Merger; (3) a methodology to estimate the cost of capital in future FERC proceedings; and (4) a stipulation that the operating companies will be insulated from certain direct effects on capacity equalization payments should GSU, due to a finding of imprudent GSU management prior to the Merger, be required to purchase Cajun's 30% share in River Bend. See "Regulation - Other Regulation and Litigation," for information on requests for rehearing of FERC's approval. On August 20, l990, the City of New Orleans filed a complaint against Entergy Corporation, AP&L, LP&L, MP&L, NOPSI, and System Energy requesting that FERC investigate AP&L's transfer of its interest in Independence 2 and Ritchie 2 to Entergy Power (see "Entergy Power," above) and the effect of the transfer on AP&L, LP&L, MP&L, and NOPSI and their ratepayers. Various parties, including certain of the System's state regulators, intervened in the proceeding. FERC issued an order on March 19, 1991, setting for investigation (l) the question of whether overall billings under the System Agreement will increase as a result of the transfer to Entergy Power, and (2) if so, whether such increased billings reflect prudently incurred costs that may reasonably be charged under the System Agreement. In two separate decisions with respect to these issues, the FERC ALJ assigned to the matter ruled on May 14, l992 and October 30, 1992, respectively, that there was sufficient evidence to show that overall billings would increase as a result of the transfer, but that the transfer was prudent. On December 15, 1993, FERC issued an opinion declining to address the prudence issue until a future time when replacement capacity has been added or planned and finding that, until such time, billings under the System Agreement as affected by the transfer of the two units are reasonable. The Entergy parties and the City of New Orleans each filed a request for rehearing of this order. If FERC's decision were reversed and any refunds were ordered, they would be retroactive to October 19, 1990. Open Access Transmission. On August 2, 1991, Entergy Services, as agent for AP&L, LP&L, MP&L, NOPSI, and Entergy Power, submitted to FERC (1) proposed tariffs that, subject to certain conditions, would provide to electric utilities "open access" to the System's integrated transmission system, and (2) rate schedules providing for sales of wholesale power at market-based rates. Under FERC policy, sales of power at market-based rates would be permitted only if FERC found, among other things, that Entergy did not have market power over transmission. Permitting "open access" to the System's transmission system helps support such a finding. Various parties, including the Council, the APSC, the MPSC, and the LPSC, intervened in the proceeding. On March 3, 1992, FERC approved the filing, with some modifications, and on August 7, l992, FERC denied rehearing of its March 1992 order. On August 24, l992, various parties filed petitions with the D.C. Circuit for review of FERC's 1992 orders, and these petitions have been consolidated. The revised tariffs, submitted by Entergy Services in response to FERC's 1992 orders, were accepted for filing and made effective, subject to further modifications, by order dated April 5, l993. Entergy Services made a further compliance filing on May 5, l993, reflecting these modifications and requesting reconsideration of certain limited matters, which is subject to approval by FERC. On December 31, 1993, Entergy Services filed revisions to the transmission service tariff to recognize GSU's inclusion in the Entergy System. These matters are pending. Retail Rate Matters General. AP&L, LP&L, MP&L, and NOPSI currently have retail rate structures sufficient to recover their costs, including costs associated with their allocated shares of capacity and energy from Grand Gulf 1 under the Unit Power Sales Agreement, and a return on equity. Certain costs related to Grand Gulf 1 (and in LP&L's case, Waterford 3 are being phased-into retail rates over a period of time, in order to avoid the "rate shock" associated with increasing rates to reflect all of such costs at once. The deferral period in which costs are incurred but not currently recovered has expired for all of these programs, and AP&L, LP&L, MP&L, and NOPSI are now recovering those costs that were previously deferred. Also, AP&L and LP&L have retained a portion of their shares of Grand Gulf 1 capacity and GSU is operating under a deregulated asset plan for a portion of its share of River Bend. GSU is involved in several rate proceedings involving recovery, among other things, of costs associated with River Bend. Some rate relief has been received, but GSU has been unable to obtain recognition in rates for a substantial portion of its River Bend investment. Recovery of certain costs has been disallowed, while other costs are being deferred for future recovery, held in abeyance pending further regulatory action, or treated as investments in deregulated assets. There are ongoing rate proceedings and appeals relating to these issues (see "GSU," below). The System is committed to taking actions that will stabilize retail rates and avoid the need for future rate increases. In the short-term, this involves containing costs to the greatest degree practicable, thereby avoiding erosion of earnings and delaying for as long as possible the need for general rate increases. In accordance with this retail rate policy, the System operating companies have agreed to retail rate caps and/or rate freezes for specified periods of time. In the longer term, as discussed in "Business of Entergy - Competition - Least Cost Planning" above, and also as discussed specifically for each applicable company below, the System is pursuing implementation of least cost planning to minimize the cost of future sources of energy. Effective January 1, 1993, the System adopted SFAS No. 106 (SFAS 106), an accounting standard that requires accrual of the costs of postretirement benefits other than pensions prior to the time these costs are actually incurred. In 1992, the System operating companies requested from their retail rate regulators authorization to recognize in rates the costs associated with implementation of SFAS 106. For further information, see Note 10 of Entergy Corporation and Subsidiaries', Note 9 of MP&L's and NOPSI's, and Note 10 of AP&L's, GSU's, and LP&L's Notes to Financial Statements, "Postretirement and Postemployment Benefits," incorporated herein by reference. AP&L Rate Freeze. In connection with the settlement of various issues related to the Merger, AP&L agreed that it will not request any general retail rate increase that would take effect before November 3, 1998, except, among other things, for increases associated with the Least Cost Plan (discussed below); recovery of certain Grand Gulf 1- related costs, excess capacity costs, and costs related to the adoption of SFAS 106 that were previously deferred; recovery of certain taxes; fuel adjustment recoveries; recovery of nuclear decommissioning costs; and force majeure (defined to include, among other things, war, natural catastrophes, and high inflation). Recovery of Grand Gulf 1 Costs. Under the settlement agreement entered into with the APSC in 1985 and amended in 1988, AP&L agreed to retain a portion of its Grand Gulf l-related costs, recover a portion of such costs currently, and defer a portion of such costs for future recovery. In 1994 and subsequent years, AP&L will retain 7.92% of such costs (stated as a percentage of System Energy's 90% share of the unit) and will recover 28.08% currently. Deferrals ceased in l990, and AP&L is recovering a portion of the previously deferred costs each year through l998. As of December 31, l993, the balance of deferred uncollected costs was $568.0 million. AP&L is permitted to recover on a current basis the incremental costs of financing the unrecovered deferrals. AP&L has the right to sell capacity and energy from its retained share of Grand Gulf 1 to third parties and to sell such energy to its retail customers at a price equal to AP&L's avoided energy cost. Proceeds of sales to third parties of AP&L's retained share of Grand Gulf l capacity and energy generally accrue to the benefit of AP&L's stockholder; however, half of the proceeds of such sales to third parties prior to January 1, 1996, are used to reduce the balance of uncollected deferrals and thus accrue to the benefit of retail ratepayers. If AP&L makes sales to third parties prior to that date in excess of the retained share, the proceeds of such excess are also split between the stockholder and the ratepayers, except that the portion of the sale that accrues to the stockholder's benefit cannot exceed the retained share. Least Cost Planning. On December 1, 1992 and July 1, 1993, AP&L filed with the APSC the Least Cost Plan described in "Business of Entergy - Competition - Least Cost Planning," above. AP&L also requested authorization to recover development and implementation costs and costs and incentives related to the DSM aspects of the plan. On October 13, 1993, the APSC found AP&L's plan to be complete and directed the APSC staff to conduct a series of public forums in late 1993, including focus groups, town meetings, and collaborative workshops, before it would establish a procedural schedule that would include evidentiary hearings and the issuance of a Least Cost Plan order. Several of these meetings were delayed into 1994, but are expected to be completed by March 1994. At or before that time, AP&L expects the APSC to issue a procedural schedule that will allow the APSC to issue an order before the end of 1994. On January 19, 1994, AP&L filed a request with the APSC for permission to withdraw the CCLM portion of the filing and to continue such programs on a pilot basis at shareholder expense. The APSC has not yet ruled on AP&L's request. Fuel Adjustment Clause. AP&L's retail rate schedules have a fuel adjustment clause that provides for recovery of the excess cost of fuel and purchased power incurred in the second preceding month. The fuel adjustment clause also contains a nuclear reserve fund designed to cover the cost of replacement energy during scheduled maintenance and refueling outages at ANO, and an incentive provision that permits over- or under-recovery of the excess cost of replacement energy when ANO is operating or down for reasons other than refueling. GSU Rate Cap and Other Merger-Related Rate Agreements. The LPSC and the PUCT approved separate regulatory proposals that include the following elements: (1) a five-year rate cap on GSU's retail electric base rates in the respective states, except for force majeure (defined to include, among other things, war, natural catastrophes, and high inflation); (2) a provision for passing through to retail customers in the respective states the jurisdictional portion of the fuel savings created by the Merger; and (3) a mechanism for tracking nonfuel operation and maintenance savings created by the Merger. The LPSC regulatory plan provides that such nonfuel savings will be shared 60% by the shareholder and 40% by ratepayers during the eight years following the Merger. The LPSC plan requires regulatory filings each year by the end of May through 2001. The PUCT regulatory plan provides that such savings will be shared equally by the shareholder and ratepayers, except that the shareholder's portion will be reduced by $2.6 million per year on a total company basis in years four through eight. The PUCT plan also requires a series of regulatory filings, currently anticipated to be in June 1994, and February 1996, 1998, and 2001, to ensure that the ratepayers' share of such savings be reflected in rates on a timely basis and requires Entergy Corporation to hold GSU's Texas retail customers harmless from the effects of the removal by FERC of a 40% cap on the amount of fuel savings GSU may be required to transfer to other Entergy operating companies under the FERC tracking mechanism (see "Rate Matters - Wholesale Rate Matters - System Agreement," above). On January 14, 1994, Entergy Corporation filed a request for rehearing of FERC's December 15, 1993 order approving the Merger, requesting that FERC restore the 40% cap provision in the fuel cost protection mechanism (see "Regulation - Other Litigation and Regulation," below). The matter is pending. Recovery of River Bend Costs. GSU deferred approximately $369 million of River Bend operating costs, purchased power costs, and accrued carrying charges pursuant to a 1986 PUCT accounting order. Approximately $182 million of these costs are being amortized over a 20-year period, and the remaining $187 million are not being amortized pending the ultimate outcome of the Rate Appeal (see "Texas Jurisdiction - River Bend," below). As of December 31, 1993, the unamortized balance of these costs was $330.3 million. Further, GSU deferred approximately $400.4 million of similar costs pursuant to a 1986 LPSC accounting order. These costs, of which approximately $160.4 million are unamortized as of December 31, 1993, are being amortized over a 10-year period. In accordance with a phase-in plan approved by the LPSC, GSU deferred $324.7 million of its River Bend costs related to the period December 1987 through February 1991. GSU has amortized $86.6 million through December 31, 1993, and the remainder of $238.1 million will be recovered over approximately 3.8 years. Texas Jurisdiction - River Bend. In May 1988, the PUCT granted GSU a permanent increase in annual revenues of $59.9 million resulting from the inclusion in rate base of approximately $1.6 billion of company-wide River Bend plant investment and approximately $182 million of related Texas retail jurisdiction deferred River Bend costs (Allowed Deferrals). In addition, the PUCT disallowed as imprudent $63.5 million of company-wide River Bend plant costs and placed in abeyance, with no finding of prudency, approximately $1.4 billion of company-wide River Bend plant investment and approximately $157 million of Texas retail jurisdiction deferred River Bend operating and carrying costs. The PUCT affirmed that the ultimate rate treatment of such amounts would be subject to future demonstration of the prudency of such costs. GSU and intervening parties appealed this order (Rate Appeal) and GSU filed a separate rate case asking that the abeyed River Bend plant costs be found prudent (Separate Rate Case). Intervening parties filed suit in district court to prohibit the Separate Rate Case. The district court's decision was ultimately appealed to the Texas Supreme Court which ruled in 1990 that the prudence of the purported abeyed costs could not be relitigated in a separate rate proceeding. Further, the Texas Supreme Court's decision stated that all issues relating to the merits of the original order of the PUCT, including the prudence of all River Bend-related costs, should be addressed in the Rate Appeal. In October 1991, the district court in the Rate Appeal issued an order holding that, while it was clear the PUCT made an error in assuming it could set aside $1.4 billion of the total costs of River Bend and consider them in a later proceeding, the PUCT, nevertheless, found that GSU had not met its burden of proof related to the amounts placed in abeyance. The court also ruled that the Allowed Deferrals should not be included in rate base under a 1991 decision regarding El Paso Electric Company's similar deferred costs (El Paso Case). The court further stated that the PUCT erred in reducing GSU's deferred costs by $1.50 for each $1.00 of revenue collected under the interim rate increases authorized in 1987 and 1988. The court remanded the case to the PUCT with instructions as to the proper handling of the Allowed Deferrals. GSU's motion for rehearing was denied, and in December 1991, GSU filed an appeal of the October 1991 district court order. The PUCT also appealed the October 1991 district court order, which served to supersede the district court's judgment, rendering it unenforceable under Texas law. In August 1992, the court of appeals in the El Paso Case handed down its second opinion on rehearing modifying its previous opinion on deferred accounting. The court's second opinion concluded that the PUCT may lawfully defer operating and maintenance costs and subsequently include them in rate base, but that the Public Utility Regulatory Act prohibits such rate base treatment for deferred carrying costs. The court stated, however, its opinion would not preclude the recovery of deferred carrying costs. The August 1992 court of appeals opinion was appealed to the Texas Supreme Court where arguments were heard in September 1993. The matter is still pending. In September 1993, the Texas Third District Court of Appeals (the Third District Court) remanded the October 1991 district court decision to the PUCT "to reexamine the record evidence to whatever extent necessary to render a final order supported by substantial evidence and not inconsistent with our opinion." The Third District Court specifically addressed the PUCT's treatment of certain costs, stating that the PUCT's order was not based on substantial evidence. The Third District Court also applied its most recent ruling in the El Paso Case to the deferred costs associated with River Bend. However, the Third District Court cautioned the PUCT to confine its deliberations to the evidence addressed in the original rate case. Certain parties to the case have indicated their position that, on remand, the PUCT may change its original order only with respect to matters specifically discussed by the Third District Court which, if allowed, would increase GSU's allowed River Bend investment, net of accumulated depreciation and related taxes, by approximately $48 million as of December 31, 1993. GSU believes that under the Third District Court's decision, the PUCT would be free to reconsider any aspect of its order concerning the abeyed $1.4 billion River Bend investment. GSU has filed a motion for rehearing asking the Third District Court to modify its order so as to permit the PUCT to take additional evidence on remand. The PUCT and other parties have also moved for rehearing on various grounds. The Third District Court has not yet ruled on any of these motions. As of December 31, 1993, the River Bend plant costs disallowed for retail ratemaking purposes in Texas, and the River Bend plant costs held in abeyance and the related cost deferrals totaled (net of taxes) approximately $14 million, $300 million (both net of depreciation), and $171 million, respectively. Allowed Deferrals were approximately $95 million, net of taxes and amortization, as of December 31, 1993. GSU estimates it has collected approximately $139 million of revenues as of December 31, 1993, as a result of the originally ordered rate treatment of these deferred costs. However, if the PUCT adopts the most recent decision in the El Paso Case, the possible refunds approximate $28 million as a result of the inclusion of deferred carrying costs in rate base for the period July 1988 through December 1990. However, if the PUCT reverses its decision to reduce GSU's deferred costs by $1.50 for each $1.00 of revenue collected under the interim rate increases authorized in 1987 and 1988, the potential refund of amounts described above could be reduced by an amount ranging from $7 million to $19 million. No assurance can be given as to the timing or outcome of the remands or appeals described above. Pending further developments in these cases, GSU has made no write-offs for the River Bend related costs. Management believes, based on advice from Clark, Thomas & Winters, a Professional Corporation, legal counsel of record in the Rate Appeal, that it is reasonably possible that the case will be remanded to the PUCT, and the PUCT will be allowed to rule on the prudence of the abeyed River Bend plant costs. Rate caps imposed by the PUCT's regulatory approval of the Merger could result in GSU being unable to use the full amount of a favorable decision to immediately increase rates; however, a favorable decision could permit some increases and/or limit or prevent decreases during the period the rate caps are in effect. At this time, management and legal counsel are unable to predict the amount, if any, of the abeyed and previously disallowed River Bend plant costs that ultimately may be disallowed by the PUCT. A net of tax write-off as of December 31, 1993, of up to $314 million could be required based on the PUCT's ultimate ruling. In prior proceedings, the PUCT has held that the original cost of nuclear power plants will be included in rates to the extent those costs were prudently incurred. Based upon the PUCT's prior decisions, management believes that its River Bend construction costs were prudently incurred and that it is reasonably possible that it will recover in rate base, or otherwise through means such as a deregulated asset plan, all or substantially all of the abeyed River Bend plant costs. However, management also recognizes that it is reasonably possible that not all of the abeyed River Bend plant costs may ultimately be recovered. As part of its direct case in the Separate Rate Case, GSU filed a cost reconciliation study prepared by Sandlin Associates, management consultants with expertise in the cost analysis of nuclear power plants, which supports the reasonableness of the River Bend costs held in abeyance by the PUCT. This reconciliation study determined that approximately 82% of the River Bend cost increase above the amount included by the PUCT in rate base was a result of changes in federal nuclear safety requirements and provided other support for the remainder of the abeyed amounts. There have been four other rate proceedings in Texas involving nuclear power plants. Investment in the plants ultimately disallowed ranged from 0% to 15%. Each case was unique, and the disallowances in each were made on a case-by-case basis for different reasons. Appeals of most, if not all, of these PUCT decisions are currently pending. The following factors support management's position that a loss contingency requiring accrual has not occurred, and its belief that all, or substantially all, of the abeyed plant costs will ultimately be recovered: 1. The $1.4 billion of abeyed River Bend plant costs have never been ruled imprudent and disallowed by the PUCT. 2. Sandlin Associates' analysis which supports the prudence of substantially all of the abeyed construction costs. 3. Historical inclusion by the PUCT of prudent construction costs in rate base. 4. The analysis of GSU's internal legal staff, which has considerable experience in Texas rate case litigation. Additionally, management believes, based on advice from Clark, Thomas & Winters, a Professional Corporation, legal counsel of record in the Rate Appeal, that it is probable that the deferred costs will be allowed. However, assuming the August 1992 court of appeals' opinion in the El Paso Case is upheld and applied to GSU and the deferred River Bend costs currently held in abeyance are not allowed to be recovered in rates as allowable costs, a net-of-tax write-off of up to $171 million could be required. In addition, future revenues based upon the deferred costs previously allowed in rate base could also be lost and no assurance can be given as to whether or not refunds (up to $28 million as of December 31, 1993) of revenue received based upon such deferred costs previously recorded will be required. See Note 12 of GSU's Notes to Financial Statements, "Entergy Corporation-GSU Merger," for the accounting treatment of preacquistion contingencies, including a River Bend write-down. Texas Jurisdiction - Fuel Reconciliation. In January 1992, GSU applied with the PUCT for a new fixed fuel factor and requested a final reconciliation of fuel and purchased power costs incurred between December 1, 1986 and September 30, 1991. GSU proposed to recover net underrecoveries and interest (including underrecoveries related to NISCO, discussed below) over a twelve month period. In April 1993, the presiding PUCT ALJ issued a report which concluded that GSU incurred approximately $117 million of nonreimbursable fuel costs on a company-wide basis (approximately $50 million on a Texas retail jurisdictional basis) during the reconciliation period. Included in the nonreimbursable fuel costs were payments above GSU's avoided cost rate for power purchased from NISCO. The PUCT ordered in 1986 that the purchased power costs from NISCO in excess of GSU's avoided costs be disallowed. The PUCT disallowance resulted in approximately $12 million to $15 million of unrecovered purchased power costs on an annual basis, which GSU continued to expense as the costs were incurred. In April 1991, the Texas Supreme Court, in the appeal of such order, ordered the PUCT to allow GSU to recover purchased power payments in excess of its avoided cost in future proceedings, if GSU established to the PUCT's satisfaction that the payments were reasonable and necessary expenses. In June 1993, the PUCT, in the fuel reconciliation case, concluded that the purchased power payments made to NISCO in excess of GSU's avoided cost were not reasonably incurred. As a result of the order, GSU recorded additional fuel expenses (including interest) of $2.8 million for non-NISCO related items. The PUCT's order resulted in no additional expenses related to the NISCO issue, or for overcollections related to the fixed fuel factor, as those charges were expensed by GSU as they were incurred. The PUCT concluded that GSU had over-collected its fuel costs in Texas and ordered GSU to refund approximately $33.8 million to its Texas retail customers, including approximately $7.5 million of interest. The PUCT reduced GSU's fixed fuel factor in Texas from about 2.1 cents per KWH to approximately 1.84 cents per KWH. GSU had requested a new fixed fuel factor of about 2.02 cents per KWH. Based on current sales forecasts, adoption of the PUCT's recommended fixed fuel factor would reduce GSU's revenues by approximately $34 million annually. In October 1993, GSU appealed the PUCT's order to the Travis County District Court. No assurance can be given as to the timing or outcome of the appeal. Texas - Cities Rate Settlement. In June 1993, thirteen cities within GSU's Texas service area instituted an investigation to determine whether GSU's current rates were justified. In October 1993, the general counsel of the PUCT instituted an inquiry into the reasonableness of GSU's rates. In November 1993, a settlement agreement was filed with the PUCT which provides for an initial reduction in annual retail base revenues in Texas of approximately $22.5 million effective for electric usage on or after November 1, 1993, and a second reduction of $20 million to be effective September 1994. Further, the settlement provided for GSU to reduce rates with a $20 million one-time bill credit in December 1993, and to refund approximately $3 million to Texas retail customers on bills rendered in December 1993. The cities rate inquiries had been settled earlier on the same terms. In November 1993, in association with the settlement of the above- described rate inquiries, GSU entered into a settlement covering issues related to a March 1991 non-unanimous settlement in another proceeding. Under this settlement, a $30 million rate increase approved by the PUCT in March 1991, became final and the PUCT's treatment of GSU's federal tax expense was settled, eliminating the possibility of refunds associated with amounts collected resulting from the disputed tax calculation. In December 1993, a large industrial customer of GSU announced its intention to oppose the settlement of the PUCT rate inquiry. The customer's opposition does not affect the cities' rate settlement. The customer's opposition requires the PUCT to conduct a hearing concerning GSU's rates charged in areas outside the corporate limits of the cities in its Texas service territory to determine whether the settlement's rates are just and reasonable. A hearing has been set for July 8, 1994. GSU believes that the PUCT will ultimately approve the settlement, but no assurance can be provided in this regard. Louisiana Jurisdiction - River Bend. Previous rate orders of the LPSC have been appealed, and pending resolution of various appellate proceedings, GSU has made no write-off for the disallowance of $30.6 million of deferred revenue requirement that GSU recorded for the period December 16, 1987 through February 18, 1988. In January 1992, the LPSC ordered a deregulated asset plan for $1.4 billion of River Bend plant costs not allowed in rates. The plan allows GSU to sell the generation from the approximately 22% of River Bend to Louisiana customers at 4.6 cents per KWH, or off-system at higher prices. Incremental revenues from off-system sales above 4.6 cents per KWH will be shared 60% by shareholders and 40% by ratepayers (see GSU's "Management's Financial Discussion and Analysis," incorporated herein by reference, for the effects of the plan on GSU's 1993 results of operations). LPSC - Return on Equity Review. In the June 1993 open session, a preliminary report was made comparing the authorized and actual earned rates of return for electric and gas utilities subject to the LPSC's jurisdiction. The preliminary report indicated that several electric utilities, including GSU, may be over-earning based on current estimated costs of equity. The LPSC requested those utilities to file responses indicating whether they agreed with the preliminary report, and to provide their reasons if they did not agree. GSU provided the LPSC with information that GSU believes supports the current rate level. The LPSC decided at its September 7, 1993 open session to defer review of GSU's base rates until the first earnings analysis after the Merger, scheduled for mid-1994. LPSC Fuel Cost Review. In November 1993, the LPSC ordered a review of GSU's fuel costs. The LPSC stated that fuel costs for the period October 1988 through September 1991 would be reviewed based on the number of outages at River Bend and the findings in the June 1993 PUCT fuel reconciliation case. Hearings are scheduled to begin in March 1994. Least Cost Planning. Currently, the PUCT does not have least cost planning rules in place, and GSU has not filed a Least Cost Plan with the PUCT. However, the PUCT staff has begun a rulemaking process for such rules, and GSU is actively participating in this process. GSU has not yet filed a Least Cost Plan with the LPSC. Fuel Recovery. In January 1993, the PUCT adopted a new rule for setting a fixed fuel factor that is intended to recover projected allowable fuel and purchased power costs not covered by base rates. To the extent actual costs vary from the fixed factor, the PUCT may require refunds of overcharges or permit recovery of undercharges. Under the new rule, fuel factors are to be revised every six months, and GSU is on a schedule providing for revision each March and September. The PUCT is required to act within 60 or 90 days, depending on whether or not a hearing is required, and refunds and surcharges will be required based upon a materiality threshold of 4% of Texas retail fuel revenues. Fuel charges will also be subject to reconciliation proceedings every three years, at which time additional adjustments may be required (see "Texas Jurisdiction - Fuel Reconciliation," above). All of GSU's rate schedules in Louisiana include a fuel adjustment clause to recover the cost of fuel and purchased power energy costs. The fuel adjustment reflects the delivered cost of fuel for the second preceding month. LP&L LPSC Jurisdiction. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, LP&L was granted rate relief with respect to costs associated with Waterford 3 and LP&L's share of capacity and energy from Grand Gulf l, subject to certain terms and conditions. With respect to Waterford 3, LP&L was granted an increase aggregating $170.9 million over the period 1985-1988, and LP&L agreed to permanently absorb, and not recover from retail ratepayers, $284 million of its investment in the unit and to defer $266 million of its costs related to the years 1985-1988 to be recovered over approximately 8.6 years beginning in April 1988. As of December 31, 1993, LP&L's unrecovered deferral balance was $82.5 million. With respect to Grand Gulf l, LP&L agreed to absorb, and not recover from retail ratepayers, 18% of its 14% share (approximately 2.52%) of the costs of Grand Gulf l capacity and energy. LP&L is allowed to recover, through the fuel adjustment clause, 4.6 cents per KWH (currently 2.55 cents per KWH through May 1994) for the energy related to the permanently absorbed percentage, with LP&L's permanently absorbed retained percentage to be available for sale to non-affiliated parties, subject to LPSC approval. (See Note 2 of LP&L's Notes to Financial Statements, "Rate and Regulatory Matters - Waterford 3 and Grand Gulf 1," incorporated herein by reference, for further information on LP&L's Grand Gulf 1 and Waterford 3-related rates.) In a subsequent rate proceeding, on March 1, l989, the LPSC issued an order providing that, in effect, LP&L was entitled to an approximately $45.9 million annual retail rate increase, but that, in lieu of a rate increase, LP&L would be permitted to retain $188.6 million of the proceeds of a 1988 settlement of litigation with a gas supplier, and to amortize such proceeds into revenues over a period of approximately 5.3 years. The amortization of the proceeds will expire in mid-1994 and this source of revenue will no longer be available to LP&L. LP&L believes that the amortization has resulted in approximately the same amount of additional net income as an annual rate increase of $45.9 million would have provided over the same period. In connection with this order, LP&L agreed to a five-year base rate freeze scheduled to expire in March 1994 at then current levels subject to certain conditions. (See Note 2 of LP&L's Notes to Financial Statements, "Rate and Regulatory Matters - March 1989 Order," incorporated herein by reference, for further information on the terms of this order.) By letter dated July 27, 1993, the LPSC requested LP&L to explain its "relatively high cost of debt" compared to other electric utilities subject to LPSC jurisdiction. LP&L responded to the request on August 11, 1993. On August 14, 1993, the LPSC's consultants acknowledged LP&L's rationale for its cost of debt and suggested that certain aspects of LP&L's cost of debt could be taken up in rate proceedings after the expiration of LP&L's rate freeze. On October 7, 1993, the LPSC approved a schedule to conduct a review of LP&L's rates and rate structure upon the expiration of the rate freeze in March 1994. Council Jurisdiction. Under the Algiers rate settlement entered into with the Council in l989, LP&L was granted rate relief with respect to its Grand Gulf l and Waterford 3-related costs, subject to certain terms and conditions. LP&L was granted an annual rate increase of $9.5 million that was phased-in over the two-year period beginning in July 1989, and was permitted to retain $4.2 million (the Council's jurisdictional portion) of the proceeds of litigation with a gas supplier and to amortize such proceeds plus interest into revenues over the same two-year period. LP&L agreed to absorb and not recover from Algiers retail ratepayers $17 million of fixed costs associated with Grand Gulf l and Waterford 3 incurred prior to the date of the settlement, $5.9 million of its investment in Waterford 3, and 18% of the Algiers portion of LP&L's Grand Gulf l-related costs incurred after the settlement. However, LP&L is allowed to recover 4.6 cents per KWH or the avoided cost, whichever is higher, for the energy related to the permanently absorbed percentage through the fuel adjustment clause, with the permanently absorbed percentage to be available for sale to non-affiliated parties, subject to the Council's right of first refusal. LP&L also agreed to a rate freeze for Algiers customers until July 6, l994, except in the case of catastrophic events, changes in federal tax laws, or changes in LP&L's Grand Gulf l costs resulting from FERC proceedings. Least Cost Planning. On December l, l992, and July 1, l993, LP&L filed with the LPSC and the Council the Least Cost Plan described under "Business of Entergy - Competition - Least Cost Planning," above. LP&L also requested authorization to recover development and implementation costs and costs and incentives related to the DSM aspects of the plan. Discovery in the LPSC review of LP&L's Least Cost Plan filing is continuing, and the current procedural schedule (which maybe extended) contemplates that, after hearings and briefings, a report of the LPSC special counsel will be issued on June 14, 1994. The LPSC could render a decision on the basis of this report. On January 19, 1994, LP&L filed a motion with the LPSC to dismiss or withdraw without prejudice the CCLM and to proceed with a pilot CCLM at shareholder expense. The LPSC granted LP&L's motion on February 2, 1994, subject to LP&L, among other things, keeping the LPSC timely informed as to LP&L's CCLM activities. (See "NOPSI - Least Cost Planning," below, for further information on LP&L's and NOPSI's proceedings pending before the Council.) Fuel Adjustment Clause. LP&L's rate schedules include a fuel adjustment clause to reflect the delivered cost of fuel in the second preceding month and purchased power energy costs. The fuel adjustment also reflects a surcharge for deferred fuel expense arising from the monthly reconciliation of actual fuel cost incurred with fuel cost revenues billed to customers. LP&L defers on its books fuel costs that will be reflected in customer billings in the future under the fuel adjustment clause. MP&L Rate Freeze. In a stipulation entered into by MP&L in connection with the settlement of various issues related to the Merger, MP&L agreed that (1) for a period of five years beginning on November 9, 1993, retail base rates under the FRP (see "Incentive Rate Plan," below) would not be increased above the level of rates in effect on November 1, 1993, and (2) MP&L would not request any general retail rate increase that would increase retail rates above the level of MP&L's rates in effect as of November l, 1993, and that would become effective in such five-year period except, among other things, for increases associated with the Least Cost Plan (discussed below), recovery of deferred Grand Gulf 1-related costs, recovery under the fuel adjustment clause, adjustments for certain taxes, and force majeure (defined to include, among other things, war, natural catastrophes, and high inflation). Recovery of Grand Gulf 1 Costs. The MPSC's Final Order on Rehearing, issued in 1985, affirmed by the United States Supreme Court in 1988, and subsequently revised in 1988, granted MP&L an annual base rate increase of approximately $326.5 million in connection with its allocated share of Grand Gulf 1 costs. The Final Order on Rehearing also provided for the deferral of a portion of such costs that were incurred each year through 1992, and recovery of these deferrals over a period of six years ending in 1998. As of December 31, 1993, the uncollected balance of MP&L's deferred costs was approximately $601.4 million. MP&L is permitted to recover the carrying charges on all deferred amounts on a current basis. Incentive Rate Plan. In July 1993, the MPSC ordered MP&L to file a formulary incentive rate plan designed to allow for periodic small adjustments in rates based upon a comparison of earned to benchmark returns and upon performance factors incorporated in the plan. Pursuant to this order, on November 1, 1993, MP&L filed a proposed formula rate plan. MPSC was also expected to conduct a general review of MP&L's current rates in the course of approving an incentive rate plan. On January 28, 1994, MP&L and the Mississippi Public Utilities Staff (MPUS) entered into a Joint Stipulation in this proceeding. Under the Joint Stipulation, MP&L and the MPUS agreed on a number of accounting adjustments for the test year ending June 30, 1993, (June 30 Test Year) that resulted in a reduction to MP&L's base rate revenues in the June 30 Test Year of approximately 4.3%, or $28.1 million. This translates into approximately a 3.7% decrease in overall revenues from sales to retail customers, which include revenues related to fuel, taxes, and Grand Gulf. MP&L and the MPUS agreed on a required return on equity of 11% for the June 30 Test Year. MP&L and the MPUS also stipulated to a revised Formula Rate Plan (FRP). The stipulated FRP is essentially the same as the proposed plan filed by MP&L on November 1, 1993. Certain of the accounting changes agreed to by the MPUS and MP&L for the June 30 Test Year are incorporated into the stipulated FRP. Also, the formula in the stipulated FRP for determining required return on equity would have produced a required return on equity for MP&L of 11.07% for the June 30 Test Year. The stipulated return on equity formula will be applied for the first time in the first Evaluation Report under the stipulated FRP. The first Evaluation Report will be filed in March 1995 for the Evaluation Period ending December 31, 1994. On February 10, 1994, MP&L, the Mississippi Industrial Energy Group (MIEG), and the MPUS entered into and filed with the MPUS, a Joint Stipulation (MIEG Joint Stipulation) resolving the issues raised by the MIEG in the docket. On February 16, 1994, MP&L and the Mississippi Attorney General entered into a Joint Stipulation that resolved the issues raised by the Mississippi Attorney General in the docket. Other parties in the case, including two gas utility intervenors, were not parties to the Joint Stipulations. In late February 1994, the MPSC conducted a general review of MP&L's current rates and on March 1, 1994, issued a final order in which the MPSC approved each of the Joint Stipulations. The MPSC ordered MP&L to file rates designed to provide a reduction of $28.1 million in operating revenues for the June 30 Test Year on or before March 18, 1994, to become effective for service rendered on and after March 25, 1994. The FRP also was approved and will be effective on March 25, 1994, with any initial adjustment to base rates, if any, in May 1995. Under the FRP, a formula will be established under which MP&L's earned rate of return will be calculated automatically every 12 months and compared to a benchmark rate of return calculated under a separate formula within the FRP. If MP&L's earned rate of return falls within a bandwidth around the benchmark rate of return, there will be no adjustment in rates. If MP&L's earnings are above the bandwidth, the FRP will automatically reduce MP&L's base rates. Alternatively, if MP&L's earnings are below the bandwidth, the FRP will automatically increase MP&L's base rates (see "Rate Freeze" above for information on a cap on base rates at November 1993 levels for a period of five years). The reduction or increase in base rates will be an amount representing 50% of the difference between the earned rate of return and the nearest limit of the bandwidth. In no event will the annual adjustment in rates exceed the lesser of 2% of MP&L's aggregate annual retail revenues, or $14.5 million. Under the FRP the benchmark rate of return, and consequently the bandwidth, will be adjusted slightly upward or downward based upon MP&L's performance on three performance factors: customer reliability, customer satisfaction, and customer price. In its Final Order, the MPSC also recognized that on February 9 and 10, 1994, a severe ice storm struck northern Mississippi causing extensive and widespread damage to MP&L's transmission and distribution facilities in approximately 15 counties. Although the MPSC made no findings in the final order as to MP&L's costs associated with the ice storm and restoration of service, the MPSC acknowledged that there is precedent in Mississippi for recovery of certain costs associated with storms and natural disasters and restoration of service. The MPSC stated the recovery of MP&L's ice storm costs should be addressed in a separate docket. MP&L plans to immediately file for rate recovery of the costs related to the ice storm. Least Cost Planning. On December 1, 1992 and July 1, 1993, MP&L filed with the MPSC the Least Cost Plan described in "Business of Entergy - Competition - Least Cost Planning," above. MP&L also requested a finding by the MPSC that the plan's cost recovery methodology is reasonable and appropriate. MP&L will request approval of cost recovery mechanisms after the plan has been approved by the MPSC. On October 6, 1993, the MPSC, on its own motion, stayed all proceedings in this docket. The MPSC stay order regarding MP&L's Least Cost Plan filing remains in effect even though MP&L and the MPUS have stipulated to an FRP (see "Incentive Rate Plan," above). Because the stay order remains in effect, MP&L has not yet filed a request that the CCLM portion of the filing be withdrawn and that a pilot CCLM program be implemented. Fuel Adjustment Clause. MP&L's rate schedules include a fuel adjustment clause that permits recovery from customers of changes in the cost of fuel and purchased power. The monthly fuel adjustment rate is based on projected sales and costs for the month, adjusted for differences between actual and estimated costs for the second prior month. NOPSI Electric Retail Rate Reduction. On November 18, 1993, in connection with the settlement of various issues related to the Merger, the Council adopted a resolution requiring NOPSI to reduce its annual electric base rates by $4.8 million on bills rendered on or after November 1, 1993. Recovery of Grand Gulf 1 Costs. Under NOPSI's various Rate Settlements with the Council (which include the 1986 NOPSI Settlement, the February 4 Resolution relating to prudence issues, and the 1991 NOPSI Settlement of the issues raised in the February 4 Resolution), NOPSI agreed to absorb and not recover from ratepayers a total of $186.2 million of its Grand Gulf 1 costs. NOPSI 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, 1993, the uncollected balance of NOPSI's deferred costs was $228.8 million. NOPSI also agreed to a base rate freeze through October 31, 1996, excluding the scheduled increases, certain changes in tax rates, and increases related to catastrophic events. (See Note 2 of NOPSI's Notes to Financial Statements, "Rate and Regulatory Matters - Prudence Settlement and Finalized Phase-In Plan," incorporated herein by reference, for further information.) Gas Rates. In May 1992, NOPSI and the Council settled a pending application for gas rate increases. The settlement provided for annual rate increases of approximately $3.8 million in May 1992 and 1993, and the deferral of an additional $3 million for recovery in the years beginning in May 1993 through May 1996. NOPSI also agreed to a base rate freeze, except for the scheduled increases and certain other exceptions, through October 31, 1996. Least Cost Planning. On December 1, 1992, and July 1, 1993, NOPSI filed with the Council the Least Cost Plan described under "Business of Entergy - Competition - Least Cost Planning," above. NOPSI also requested authorization to recover development and implementation costs and costs and incentives related to DSM aspects of the plan. After hearings and briefings, the Council issued, on November 22, 1993, a resolution that requires NOPSI and LP&L to provide, within certain time frames, additional information, among other things, on how the seven full scale DSM programs approved by the Council in the resolution will be implemented. Such programs are estimated to cost approximately $13 million over the next three years. The Council provided in the resolution certain assurances regarding recovery of costs associated with these programs. Discovery is proceeding and testimony is being filed, with the second round of hearings to begin in February 1994. After the hearings are concluded and briefs have been filed, the Council will address the second round issues in early April 1994. On February 3, 1994, the Council issued a resolution and order granting the motions of NOPSI and LP&L to dismiss without prejudice the CCLM portion of the filing, authorizing NOPSI and LP&L to proceed with a pilot CCLM (other than the construction of a fiber optics/coaxial cable network) in New Orleans at shareholder expense (subject to certain conditions). The Council also opened a new docket to expeditiously address issues related to the CCLM pilot, and directing NOPSI and LP&L to obtain Council authorization in the new docket before constructing such a fiber optics/coaxial cable network. In connection with the settlement of various issues related to the Merger, the Council adopted a resolution on November 18, 1993, that provides that the Council will not disallow the first $3.5 million of costs incurred by NOPSI through October 31, 1993, in connection with the Least Cost Plan. Fuel Adjustment Clause. NOPSI's electric rate schedules include a fuel adjustment clause to reflect the delivered cost of fuel in the second preceding month, adjusted by a surcharge for deferred fuel expense arising from the monthly reconciliation of actual fuel cost incurred with fuel cost revenues billed to customers. The adjustment clause, on a monthly basis, also reflects the difference between nonfuel Grand Gulf 1 costs paid by NOPSI and the estimate of such costs provided in NOPSI's Grand Gulf 1 Rate Settlements. NOPSI's gas rate schedules include a gas cost adjustment to reflect gas costs in excess of those collected in rates, adjusted by a surcharge similar to that included in the electric adjustment clause. NOPSI defers on its books fuel and purchased gas costs to be reflected in billings to customers in the future under the fuel adjustment clause. REGULATION Federal Regulation Holding Company Act. Entergy Corporation is a registered public utility holding company under the Holding Company Act. As such, Entergy Corporation and its various direct and indirect subsidiaries (with the exception of its independent power/EWG subsidiaries) are subject to the broad regulatory provisions of that Act. Except with respect to investments in certain EWG projects and foreign utility company projects (see "Business of Entergy - Competition - General," above for a discussion of the Energy Act), Section 11(b)(1) of the Holding Company Act limits the operations of a registered holding company system to a single, integrated public utility system, plus additional systems and businesses as provided by that section. Federal Power Act. The System operating companies, System Energy, and Entergy Power are subject to the Federal Power Act as administered by FERC and the DOE. The Federal Power Act provides for regulatory jurisdiction over the licensing of certain hydroelectric projects, the business of, and facilities for, the transmission and sale at wholesale of electric energy in interstate commerce and certain other activities of the System operating companies, System Energy, and Entergy Power as interstate electric utilities, including accounting policies and practices. Such regulation includes jurisdiction over the rates charged by System Energy for capacity and energy provided to AP&L, LP&L, MP&L, and NOPSI, or others, from Grand Gulf 1. AP&L holds a license for two hydroelectric projects (70 MW) that was renewed on July 2, 1980. This license, granted by FERC, will expire in February 2003. Regulation of the Nuclear Power Industry General. Under the Atomic Energy Act of 1954 and Energy Reorganization Act of 1974, operation of nuclear plants is intensively regulated by the NRC, which has broad power to impose licensing and safety-related requirements. In the event of non-compliance, the NRC has the 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. AP&L, GSU, LP&L, and System Energy, as owners of all or a portion of ANO, River Bend, Waterford 3, and Grand Gulf 1, respectively, and Entergy Operations, as the operator of these units, are subject to the jurisdiction of the NRC. Revised safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at System nuclear plants and additional such expenditures could be required in the future. The nuclear power industry faces uncertainties with respect to the cost and availability of long-term arrangements for disposal of spent nuclear fuel and other radioactive waste, nuclear plant operational issues, the technological and financial aspects of decommissioning plants at the end of their licensed lives, and the effect of certain requirements relating to nuclear insurance. These matters are briefly discussed below. Spent Fuel and Other High-Level Radioactive Waste. 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. The NRC, pursuant to this Act, also requires operators of nuclear power reactors to enter into spent fuel disposal contracts with the DOE, and the affected System companies have entered into such disposal contracts. However, the DOE has not yet identified a permanent storage repository and, as a result, future expenditures may be required to increase spent fuel storage capacity at the plant sites. (For further information concerning spent fuel disposal contracts with the DOE, schedules for initial shipments of spent nuclear fuel, current on-site storage capacity, and costs of providing additional on-site storage capacity, with respect to AP&L, GSU, LP&L, and System Energy, respectively, see Note 8 of AP&L's, GSU's, and LP&L's, and Note 7 of System Energy's, Notes to Financial Statements, "Commitments and Contingencies - Spent Nuclear Fuel and Decommissioning Costs," incorporated herein by reference.) Low-Level Radioactive Waste. The availability and cost of disposal facilities for low-level radioactive waste resulting from normal operation of nuclear units are subject to a number of uncertainties. Under the Low-Level Radioactive Waste Policy Act of 1980, as amended, each state is responsible for disposal of its own waste, and states may join in regional compacts to jointly fulfill their responsibilities. The States of Arkansas and Louisiana participate in the Central States Compact, and the State of Mississippi participates in the Southeast Compact. Two disposal sites are currently operating in the United States, and one of them, which is located in Washington, is closed to out-of-region generators. The second site, the Barnwell Disposal Facility (Barnwell) located in South Carolina, is operated by the Southeast Compact and the State of Mississippi is expected to have access to this site through December 1995. Barnwell had been open to out-of-region generators (including generators in Arkansas and Louisiana) in the past; however, on April 14, 1993, the Southeast Compact voted to deny access to Barnwell to members of the Central States Compact. Such access was reinstated for the period from October 1993 through June 1994, at which time legislative action by the State of South Carolina would be required to permit further access to out-of-region generators. Beginning in July 1994, low-level radioactive waste generators in the Central States Compact, including AP&L, GSU, and LP&L, will be required to store such waste on-site until a Central States Compact facility becomes operational or another site becomes accessible. Both the Central States Compact and the Southeast Compact are working to establish additional disposal sites. The System, along with other waste generators, funds the development costs for new disposal facilities. The System's expenditures to date are approximately $30 million; and future levels of expenditures cannot be predicted. Until such facilities are established, the System will continue to seek access to existing facilities, which may be available at costs that are higher than those incurred in the past, or which may be unavailable. If such access is unavailable, the System will store low-level waste on-site at the affected units. ANO has on-site storage that is estimated to be sufficient until 1999. Construction of on-site storage at the other nuclear units is being considered, along with other alternatives. A coordinated design concept that can be utilized at both Waterford 3 and River Bend is being evaluated. Grand Gulf 1 will have continued disposal access through December 1995; therefore, no immediate plans for on-site storage are needed for Grand Gulf 1. The estimated construction costs for storage sufficient for approximately five years at Grand Gulf 1, Waterford 3, and River Bend are in the range of $2.0 million to $5.0 million for each site. As an alternative to on-site storage, Entergy is working with other industry groups to influence the continued operation of the Barnwell disposal facility for out-of-region generators. Decommissioning. AP&L, GSU, LP&L, and System Energy are recovering portions of their estimated decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf 1, respectively. These amounts are being deposited in external trust funds that, together with the earnings thereon, can only be used for future decommissioning costs. Estimated decommissioning costs are regularly reviewed and updated to reflect inflation and changes in regulatory requirements and technology, and applications will be made to appropriate regulatory authorities to recover in rates any projected increase in decommissioning costs above that currently being recovered. (For additional information with respect to decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf 1, respectively, see Note 8 of AP&L's, GSU's, and LP&L's and Note 7 of System Energy's Notes to Financial Statements, "Commitments and Contingencies - Spent Nuclear Fuel and Decommissioning Costs," incorporated herein by reference.) Uranium Enrichment Decontamination and Decommissioning Fees. The Energy Act requires all electric utilities (including AP&L, GSU, LP&L, and System Energy) that have purchased uranium enrichment services from the DOE to contribute up to a total of $150 million annually, adjusted for inflation, up to a total of $2.25 billion over approximately 15 years, for decommissioning and decontamination of enrichment facilities. AP&L's, GSU's, LP&L's, and System Energy's estimated annual contributions to this fund are $3.3 million, $0.6 million, $1.2 million, and $1.3 million, respectively, in 1993 dollars over approximately 15 years. Contributions to this fund are to be recovered through rates in the same manner as other fuel costs. Nuclear Insurance. The Price-Anderson Act provides for a limit of public liability for a single nuclear incident. As of December 31, 1993, the limit of public liability for such type of incident was approximately $9.4 billion. AP&L, GSU, LP&L, and System Energy have protection with respect to this liability through a combination of private insurance and an industry assessment program, and also have insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units. (For a discussion of insurance applicable to nuclear programs of AP&L, GSU, LP&L, and System Energy, see Note 7 of System Energy's and Note 8 of AP&L's, GSU's, and LP&L's Notes to Financial Statements, and Note 8 of Entergy Corporation and Subsidiaries, Notes to Consolidated Financial Statements, "Commitments and Contingencies - Nuclear Insurance," incorporated herein by reference.) Nuclear Operations General. Entergy Operations operates ANO, River Bend, Waterford 3, and Grand Gulf 1, subject to the owner oversight of AP&L, GSU, LP&L, and System Energy, respectively. AP&L, GSU, LP&L, and System Energy, and the other Grand Gulf 1, Waterford 3, and River Bend co- owners, have retained their ownership interests in their respective nuclear generating units. AP&L, GSU, LP&L, and System Energy have also retained their associated capacity and energy entitlements, and pay directly or reimburse Entergy Operations at cost for its operation of the units. On June 24, 1992, the NRC issued a bulletin requiring all utilities using a certain fire barrier material in a nuclear power plant to take certain actions related to the material. This material may have been used in as many as 87 nuclear plants in the United States, including ANO, River Bend, Waterford 3, and Grand Gulf 1 (see "River Bend," below for additional information). ANO. In 1990, in response to a special diagnostic evaluation report by the NRC, AP&L implemented a comprehensive action plan for ANO designed to correct certain management, organizational, and technical problems, and to improve the long-term operational effectiveness and safety of the units. This action plan was largely completed in 1993. Leaks in certain steam generator tubes at ANO 2 were discovered and repaired during an outage in March 1992; and during a refueling outage in September 1992, a comprehensive inspection of all steam generator tubing was conducted and necessary repairs were made. During a mid-cycle outage in May 1993, a scheduled special inspection of certain steam generator tubing was conducted by Entergy Operations and additional repairs were made. Entergy Operations proposes to operate ANO 2 with no further steam generator inspections until the next refueling outage, which is scheduled for the spring of 1994, and the NRC has concurred with this proposal. The operations and power output of the unit have not been adversely affected to date by these repairs. River Bend. The Nuclear Information and Resource Service petitioned the NRC to shut down the River Bend plant in July 1992 because of alleged defects in a fire barrier material. GSU has used this material in its River Bend plant and is in compliance with the requirements of the bulletin. On August 19, 1992, the NRC denied the petitioner's request. In a December 1993 letter, the NRC requested additional technical information on the use of the material in the plant, and requested GSU's plans and schedules for resolving technical issues associated with the use of the material in certain configurations. GSU has provided the information requested in the NRC letter. On January 13, 1993, in connection with the Merger, GSU filed two applications with the NRC to amend the River Bend operating license. The applications sought the NRC's consent to the Merger and to a change in the licensed operator of the facility from GSU to Entergy Operations. On August 6, 1993, Cajun filed a petition to intervene and request for a hearing in the proceedings. On January 27, 1994, the presiding NRC Atomic Safety and Licensing Board (ASLB) issued an order granting Cajun's petition to intervene and ordered a hearing on one of Cajun's contentions. On February 15, 1994, GSU filed an appeal of the ASLB Order with the NRC. On December 16, 1993, prior to this ASLB ruling, the NRC Staff issued the two license amendments for River Bend, making them effective immediately upon consummation of the Merger. On February 16, 1994, Cajun filed with the D.C. Circuit petitions for review of the two license amendments issued by the NRC. These two amendments are in full force and effect, but are subject to the outcome of the two proceedings. A hearing on the proceeding before the ALSB is not expected to begin prior to the fall of 1994. In February 1993, GSU and the other affected utilities were served with a federal grand jury subpoena to produce documents and other information relating to the fire barrier material used in the plant. Nothing in the subpoena indicates that GSU or any employee is a target of the grand jury investigation. GSU is cooperating fully with the government in its investigation. The requested documentation and other information were produced in March 1993, and no additional requests have been received. On October 25, 1993, the NRC staff began an operational safety team inspection at River Bend that was concluded by mid-November 1993. The NRC held the inspection to verify that the plant is being operated safely and in conformance with regulatory requirements. The team's findings were discussed at a public meeting in November 1993, and a written inspection report was issued in January 1994. The inspection team found apparent violations in two categories: (1) procedure adequacy, and (2) concerns with the corrective action program. Due to the nature of these apparent violations, an enforcement conference was not warranted and no fine was proposed. State Regulation General. Each of the System operating companies is subject to regulation by its respective state and/or local regulatory authorities with jurisdiction over the service areas in which each company operates. Such regulation includes authority to set rates for electric and gas service provided at retail. (See "Rate Matters and Regulation - Rate Matters - Retail Rate Matters," above) AP&L is subject to regulation by the APSC and the Tennessee Public Service Commission (TPSC). APSC regulation includes the authority to set rates, determine reasonable and adequate service, fix the value of property used and useful, require proper accounting, control leasing, control the acquisition or sale of any public utility plant or property constituting an operating unit or system, set rates of depreciation, issue certificates of convenience and necessity and certificates of environmental compatibility and public need, and control the issuance and sale of securities. Regulation by the TPSC includes the authority to set standards of service and rates for service to customers in the state, require proper accounting, control the issuance and sale of securities, and issue certificates of convenience and necessity. GSU is subject to the jurisdiction of the municipal authorities of incorporated cities in Texas as to retail rates and services within their boundaries, with appellate jurisdiction over such matters residing in the PUCT. GSU is also subject to regulation by the PUCT as to retail rates and services in rural areas, certification of new generating plants, and extensions of service into new areas. GSU is subject to regulation by the LPSC as to electric and gas service, rates and charges, certification of generating facilities and power or capacity purchase contracts, and other matters. LP&L is subject to the jurisdiction of the LPSC as to rates and charges, standards of service, depreciation, accounting, and other matters, and is subject to the jurisdiction of the Council with respect to such matters within Algiers. MP&L is subject to regulation as to service, service areas, facilities, and retail rates by the MPSC. MP&L is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station. NOPSI is subject to regulation as to electric and gas service, rates and charges, standards of service, depreciation, accounting, issuance of certain securities, and other matters by the Council. Franchises. AP&L holds franchises to provide electric service in 301 incorporated cities and towns in Arkansas, all of which are unlimited in duration and terminable by either party. GSU holds non-exclusive franchises, permits, or certificates of convenience and necessity to provide electric and gas service in 55 incorporated villages, cities, and towns in Louisiana and 64 incorporated cities and towns in Texas. GSU ordinarily holds 50-year franchises in Texas towns and 60-year franchises in Louisiana towns. The present terms of GSU's electric franchises will expire in the years 2007-2036 in Texas and in the years 2015-2046 in Louisiana. The natural gas franchise in the City of Baton Rouge will expire in the year 2015. LP&L holds franchises to provide electric service in 116 incorporated villages, cities, and towns. Most of these franchises have 25-year terms expiring during the period 1995-2015. However, six of these municipalities have granted 60-year franchises, with the last one expiring in the year 2040. Of these franchises, none has expired to date, one is scheduled to expire as early as 1995, and 37 are scheduled to expire by year-end 2000. LP&L also supplies electric service in 353 unincorporated communities, all of which are located in parishes (counties) from which LP&L holds franchises to serve the areas in which the unincorporated communities are located. MP&L has received from the MPSC certificates of public convenience and necessity to provide electric service to the areas of Mississippi that MP&L serves, which include a number of municipalities. MP&L continues to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence. NOPSI provides electric and gas service in the City of New Orleans pursuant to city ordinances, which state, among other things, that the City has a continuing option to purchase NOPSI's electric and gas utility properties. System Energy has no franchises from any municipality or state. Its business is currently limited to wholesale sales of power. Environmental Regulation General. In the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters, the System operating companies, System Energy, Entergy Power, and Entergy Operations are subject to regulation by various federal, state, and local authorities. Each of the Entergy companies considers itself to be in substantial compliance with those environmental regulations currently applicable to its business and operations. Entergy has incurred increased costs of construction and other increased costs in meeting environmental protection standards. Because environmental regulations are continually changing, the ultimate compliance costs to Entergy cannot be precisely estimated at any one time. However, Entergy currently estimates that its potential capital expenditures for environmental control purposes, including those discussed in "Clean Air Legislation," below, will not be material for the System as a whole. Clean Air Legislation. The Clean Air Act Amendments of 1990 (the Act) place limits on emissions of sulfur dioxide and nitrogen oxide from fossil-fueled generating plants. Entergy has evaluated the Act to determine the impact on the System's overall cost of emission control and monitoring equipment. Based upon such evaluation in connection with existing generating facilities, the System has determined that no additional control equipment will be required to control sulfur dioxide. In the area served by GSU, control equipment will be required for nitrogen oxide reductions due to the ozone nonattainment status of the Baton Rouge, Louisiana and Beaumont and Houston, Texas air quality control regions no later than May 1995. The cost of such control equipment is estimated at $16.0 million. The remainder of the System may be required to install nitrogen oxide emission controls on its coal units by the year 2000. The EPA is currently drafting rules that will determine the levels of nitrogen oxide emissions that will be allowed by affected units. Under the latest EPA-proposed regulations on nitrogen oxide, Entergy would not have to install additional controls. It is not possible to determine at this time if the final regulations promulgated by EPA would require the System's coal units to install nitrogen oxide emission controls. Should additional controls be required, the overall cost would vary depending on the eventual emission levels that are set. In addition, the System will be required to install additional continuous emission monitoring equipment at its coal units to comply with final EPA regulations. It is estimated that the continuous emission monitoring systems could cost as much as $1.0 million for all of the coal units. Final EPA regulations established the acceptable continuous monitoring methods, as well as alternative monitoring methods, that make it possible to determine the compliance of the units with respect to emission levels through fuel sampling and other estimation methods. Capital expenditures of approximately $11.0 million are estimated for continuous emission monitoring systems at the other fossil-fueled units. The authority to impose permit fees has been delegated to the states by EPA and, depending on the extent of the state program and the fees imposed by each state regulatory authority, permit fees for the System could range from $1.6 to $5.0 million annually. There are several other areas, such as air toxins and visibility, that will require regulatory study and rule promulgation to determine whether pollution control equipment is necessary. Regarding sulfur dioxide emissions, the Act provides "allowances" to most Entergy units based upon past emission levels and operating characteristics. Each unit of allowance is an entitlement to emit one ton of sulfur dioxide per year. Under the Act, utilities will be required to possess allowances for sulfur dioxide emissions from affected units. Based on Entergy's past operating history, it is considered a "clean" utility and as such will receive more allowances than are currently necessary for normal operations. The System believes that it will be able to operate its units efficiently without installing scrubbers or purchasing allowances from outside sources, and the System may have excess allowances available for sale to other utilities. Entergy currently estimates that total capital costs of approximately $39.4 million could be required to comply with the Act. These estimated costs for each legal entity are as follows: Nitrogen Continuous Company Oxide Emissions Control Monitors Total ---------------------- -------- ---------- ----- (In Thousands) AP&L $ 7,275 $ 3,300 $10,575 GSU 16,000 4,900 20,900 LP&L - 2,300 2,300 MP&L 2,500 1,500 4,000 NOPSI - - - System Energy - - - Entergy Power 1,575 - 1,575 ------- ------- ------- Total Entergy System $27,350 $12,000 $39,350 ======= ======= ======= Other Environmental Matters. The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (Superfund), among other things, authorize the EPA and, indirectly, the states to require the generators and certain transporters of certain hazardous substances released from or at a site, and the owners or operators of such site, to clean up the site or reimburse the costs therefor. This statute has been interpreted to impose joint and several liability on responsible parties. In compliance with applicable laws and regulations at the time, the System operating companies have sent waste materials to various disposal sites over the years. Also, past operating procedures and maintenance practices, which were not subject to regulation at that time, are now regulated by various environmental laws. Some of these sites have been the subject of governmental action, thereby causing one or more of the System operating companies to be involved with site cleanup activities. The System operating companies have participated to various degrees in accordance with their potential liability with these site cleanups and have, therefore, developed experience with cleanup costs. Their experience in these matters, and their judgments related thereto, are utilized by them in evaluating these sites. In addition, the System operating companies have established reserves for environmental clean-up/restoration activities. AP&L. AP&L has received notices from time to time between 1989 and 1993, from the EPA, the Arkansas Department of Pollution Control and Ecology (ADPC&E), and others that it (among numerous others, including various utilities, municipalities and other governmental units, and major corporations) may be a PRP for cleanup costs associated with various sites in Arkansas. Most of these sites are neither owned nor operated by any System company. Contaminants at the sites include principally polychlorinated biphenyls (PCB's), lead, and other hazardous wastes. These sites and others are described below. AP&L received notices from the EPA and ADPC&E in 1990 and 1991, identifying it as one of 30 PRP's (along with LP&L and GSU) at two Saline County sites in Arkansas. Both sites are believed to be contaminated with PCB's and lead. Cleanup costs for both sites are estimated at $6.0 million, with AP&L's total share of the costs being estimated at approximately $2.0 million. AP&L to date has expended approximately $1.0 million for remediation at one of these sites. The total liability cannot be precisely determined until remediation is complete at both sites. AP&L believes its potential liability for these sites will not be material. Reynolds Metals Company (RMC) and AP&L notified the EPA in 1989, of possible PCB contamination at two former RMC plant sites in Arkansas to which AP&L had supplied power. AP&L completed remediation at the substations serving the plant sites at a cost of $1.7 million. Additional PCB contamination was found in a portion of a drainage ditch that flows from the RMC's Patterson facility to the Ouachita River. RMC has demanded that AP&L participate in the remediation efforts with respect to the ditch. AP&L and independent contractors engaged by AP&L conducted an investigation of the ditch contamination and the potential migration of PCB's from the electrical equipment that AP&L maintained at the plant. The investigation concluded that little, if any, of the contamination was caused by AP&L. AP&L's expenditures thus far on the ditch have been approximately $150,000. It is AP&L's understanding that RMC has spent approximately $10.0 million to complete remediation of the ditch contamination. AP&L has not received a notice from the EPA that it may be a PRP with respect to remediation costs for this site. However, RMC is seeking reimbursement of $5.0 million (50% of expenditures) from AP&L. AP&L continues to deny responsibility for any of such remediation costs and believes that its potential liability, if any, for this site will not be material. AP&L entered into a Consent Administrative Order dated February 21, 1991, with the ADPC&E that named AP&L as a PRP for cleanup of contamination associated with the Utilities Services, Inc. state Superfund site located near Rison, Arkansas. Such site was found to have soil contaminated by PCB's and pentachlorophenol (a wood preservative chemical). Also, containers and drums that contained PCB's and other hazardous substances were found at the site. AP&L's share of total remediation costs are estimated to range between $3.0 million and $5.0 million. AP&L is attempting to identify and notify other PRP's. AP&L has received assurances from the ADPC&E that it will use its enforcement authority to allocate remediation expenses among AP&L and any other PRP's that can be identified (approximately 30 - 35 have been identified to date). AP&L has performed the activities necessary to stabilize the site, which to date has cost approximately $114,000. AP&L believes that its potential liability for this site will not be material. AP&L received Notice of Potential Liability and a Demand for Payment in November 1992 from the EPA in conjunction with a contaminated site in Union County, Arkansas. AP&L was identified as one of eleven PRP's, which also include LP&L. The EPA has already completed cleanup of the site. An agreement has been negotiated with the EPA which determined AP&L to be a de minimis party with total liability of approximately $47,000. As a result of an internal investigation, AP&L has discovered soil contamination at two AP&L-owned sites located in Blytheville, Arkansas and Pine Bluff, Arkansas. The contamination appears to be a result of past operating procedures that were performed prior to any applicable environmental regulation. AP&L is still investigating these sites to determine the full extent of the contamination. Until the investigations are complete, AP&L cannot estimate the liabilities associated with these sites. However, AP&L believes its potential liability for both of the sites should not be material. For all of these sites and for certain sites in which remediation has been completed, AP&L has expended approximately $3.2 million for cleanup costs since 1989. GSU. GSU has been notified by the EPA that it has been designated as a PRP for the cleanup of sites on which GSU and others have, or have been alleged to have, disposed of hazardous materials. GSU is currently negotiating with the EPA and various state authorities regarding the cleanup of some of these sites. Several class action and other suits have been filed seeking relief from GSU and others for damages caused by the disposal of hazardous waste and for asbestos-related disease that allegedly occurred from exposure on GSU premises or on premises on which GSU allegedly disposed of materials (see "Other Regulation and Litigation - GSU," below). While the amounts at issue in the cleanup efforts and suits may be very substantial sums, management believes that its financial condition and results of operations will not be materially affected by the outcome of the suits. These environmental liabilities are described below. In 1971, GSU purchased certain property near its Sabine generating station for possible cooling water capability expansion. Although it was not known to GSU at the time of the purchase, the property was utilized by area industries in the 1950's and 1960's as an industrial waste dump. GSU sold the property in 1984. In October 1984 the abandoned waste site on the property was included on the Superfund National Priorities List (NPL) by the EPA. The EPA has indicated that it believes GSU to be a PRP for cleanup of the site based on its past ownership. GSU has advised the EPA that it does not believe that it has such responsibility. GSU has pursued negotiations with the EPA and is a member of a task force made up of other PRP's for the voluntary cleanup of the waste site. A Consent Decree has been signed by all parties. Because additional wastes have been discovered at the site since the original cleanup costs were estimated, the total costs for the voluntary cleanup are unknown. However, it is estimated that cleanup will exceed $15.0 million. GSU has negotiated a responsible share of 2.26% of the estimated cleanup cost. Federal and state agencies are presently examining potential liabilities associated with natural resource damages. This matter is currently under negotiation with the other PRP's and the agencies. Remediation of the site is expected to be completed in 1996. In March 1993, GSU completed its cleanup activities at a site in Houston, Texas, which is included in the NPL. On September 20, 1993, GSU received formal notification from the EPA of its acceptance of the remedial activities conducted at the site. Currently, other parties are conducting cleanup activities at the site. However, these cleanup activities are unrelated to GSU's involvement at the site. Through 1993, GSU incurred cleanup costs of approximately $3.3 million. Pursuant to the Consent Decree, GSU is responsible for oversight costs incurred by the EPA. GSU has not received a reimbursement request for outstanding oversight costs, but anticipates these costs may total between $250,000 and $500,000. GSU is pursuing contribution for the cleanup costs at the site from other parties believed to be potentially responsible. GSU is currently involved in a multi-phased remedial investigation of an abandoned manufactured gas plant (MGP) site located in Lake Charles, Louisiana. The property was the site of an MGP that is believed to have operated during the period from approximately 1916 to 1931. Coal tar, a by-product of the distillation process, was apparently routed to a portion of the property for disposal. Since GSU purchased the property in 1926, the same area has been filled with soil and used as a landfill for miscellaneous items including electrical poles, electrical equipment, and other debris. Under an Order by the Louisiana Department of Environmental Quality (LDEQ), which is currently stayed, GSU was required to investigate and, if necessary, take remedial action at the site. The EPA has notified GSU that it is performing an independent review and ranking of the site to determine whether the site should be listed on the NPL. Another PRP has been identified and is believed to have had a role in the ownership and operation of the MGP. Negotiations with that company for joint participation and any remedial action are expected to continue. GSU currently is awaiting notification from the EPA before initiating additional cleanup negotiations or actions. While studies to determine the location of the coal tar have been conducted, the cleanup costs of the site are unknown. GSU does not presently believe that its ultimate responsibility with respect to this site will be material. GSU has also been advised that it has been named as a PRP, along with a number of other companies (including LP&L), for an abandoned waste oil recycling plant site in Livingston Parish, Louisiana, which is included on the NPL. Although significant remediation has been completed, additional studies are expected to continue in 1994. GSU and LP&L have been named as defendants in a class action lawsuit lodged against a group of PRP's associated with the site. (For information regarding litigation in connection with the Livingston Parish site, see "Other Regulation and Litigation - GSU," below.) GSU does not presently believe that its ultimate responsibility with respect to this site will be material. GSU received notification in 1992 from the EPA of potential liability at a site located in Iota, Louisiana. This site accepted a variety of wastes, including medical and chemical wastes. In addition to GSU, over 200 parties have been named as PRP's. The EPA is continuing its investigation of the site and has notified the PRP's of the possibility of this site being linked to another site. To date, GSU has not received notification of liability with regard to the other site. GSU does not presently believe its ultimate responsibility with respect to this site will be material. GSU has also been notified by the EPA of potential liability at two sites located in Saline County, Arkansas. It is believed that both sites served as a salvaging facility for transformers and batteries. In addition to GSU, 32 other parties (including AP&L and LP&L) have been named as PRP's. At this time, GSU's involvement with the site is unknown. GSU does not presently believe that its ultimate responsibility with respect to this site will be material. In November 1993, GSU received informal notification from the Rhode Island Department of Environmental Management regarding a site at which electrical capacitors had been located. The State traced several of these capacitors to GSU. GSU records indicate these capacitors were returned under warranty to the manufacturer in the 1960's due to defects. GSU does not presently believe it is responsible for any alleged activities occurring at this site. As of December 31, 1993, GSU had expended $7.0 million toward the cleanup of such sites. In 1990, GSU received an order from the LDEQ to reduce emissions of nitrogen oxides and reactive hydrocarbons at its Willow Glen and Louisiana Station plants located near Baton Rouge, Louisiana. GSU has requested an adjudicatory hearing on the matter, which the LDEQ secretary has deemed as staying the order. In the interim, GSU has joined several other Baton Rouge industries to develop and submit to LDEQ a comprehensive set of short- and long-range reduction plans. In 1993, LDEQ adopted regulations requiring permanent reductions in nitrogen oxides emissions at Willow Glen and Louisiana Station and is considering requirements for further reductions. The estimates for actions necessary to comply with these regulations are included in the discussion under "Clean Air Legislation," above. GSU believes these regulations implement the intent of the 1990 order, and actions beyond those required by the regulations will not be required. LP&L and NOPSI. LP&L and NOPSI have received notices from time to time between 1986 and 1993 from the EPA and/or the states of Louisiana and Mississippi that each or either of the companies may be a PRP for cleanup costs associated with disposal sites that are currently in various stages of remediation in Arkansas, Illinois, Louisiana, Mississippi, and Missouri that are neither owned nor operated by any System company. As to one Missouri site, LP&L's and NOPSI's aggregate liability is currently estimated not to exceed $558,000, and because of the type and the large number of PRP's (over 700, including many large utilities and national and international corporations), LP&L and NOPSI do not expect liabilities in excess of this amount. For the other Missouri site, LP&L and the other 64 PRP's (including several large, creditworthy utility companies) have received an EPA demand to pay approximately $1.2 million expended by the EPA. In June of 1993, LP&L paid $12,392 in full payment of its share of the cleanup costs. LP&L considers cleanup at this site to be complete. As to the two Saline County, Arkansas sites (involving AP&L, GSU, and LP&L), LP&L has been advised that current estimates for total cleanup are approximately $6.0 million. LP&L believes that, because of the number and nature of the PRP's, its exposure for these sites will not be material. Initial indications are that LP&L was involved in the Saline sites, but LP&L believes that because of the limited scope of its involvement and the number and nature of PRP's, its exposure for these sites will not be material. LP&L received notice from the EPA in November 1992, that it (along with AP&L) was involved in the Union County, Arkansas site. An agreement has been negotiated with the EPA that determined LP&L to be a de minimis party with a total liability of approximately $47,000 (see "AP&L," above.) As to the Mississippi site, LP&L (along with System Energy) understands that EPA has expended approximately $740,000 for this site (three separate locations being treated administratively as one). The State of Mississippi has indicated it intends to have PRP's conduct a cleanup of the site but has not yet taken formal action. LP&L has expended $22,300 to settle with the EPA for its costs for this site and, because there are 44 PRP's for this site (including a number of major oil companies), does not expect its share of future costs to be material. For a Livingston Parish, Louisiana site (involving at least 70 PRP's, including GSU and many other large and creditworthy corporations), LP&L has found in its records no evidence of its involvement. (For information regarding litigation in connection with the Livingston Parish site, see "Other Regulation and Litigation - LP&L," below.) At a second Louisiana site (also included on the NPL and involving 57 PRP's, including a number of major corporations), NOPSI believes it has no liability for the site because the material it sent to the site was not a hazardous substance. For the Illinois site, NOPSI, upon its review of the site documentation and of its own records, has asserted to the EPA that it has no involvement in this site. However, NOPSI is participating with other PRP's (including many large and creditworthy corporations) as a prudent means of resolving potential liability, if any. For all these sites, LP&L has expended approximately $349,000 and NOPSI has expended approximately $172,000 for cleanup costs (commencing in 1986) to date. During 1993, LP&L performed preliminary site assessments at the locations of two retired power plants previously owned and operated by two Louisiana municipalities. LP&L had purchased the power plants by agreement (as part of the municipal electric systems) after operating them for the last few years of their useful lives. The assessments indicated some subsurface contamination from fuel oil. LP&L and the LDEQ are now reviewing site remediation procedures that LP&L estimates will not exceed $650,000 in the aggregate. During 1993, the LDEQ issued new rules for solid waste regulation, including waste water impoundments. LP&L has determined that certain of its power plant waste water impoundments are affected by these regulations and has chosen to close them rather than retrofit and permit them. The aggregate cost of the impoundment closures, to be completed by 1996, is estimated to be $7.3 million. System Energy. In February 1990, System Energy received an EPA notice that it (among numerous other companies) may be a PRP for cleanup costs associated with the same site in Mississippi in which LP&L is involved. Potential liability is based on the alleged shipment of waste oil to the site from 1981 to 1985. System Energy does not expect its share of the total expenditures to be material because there are 44 PRP's for this site, including a number of major oil companies. Other Regulation and Litigation Entergy Corporation and GSU. In July and August 1992, Entergy Corporation and GSU filed applications with FERC, the LPSC, and the PUCT, and Entergy Corporation, Entergy Operations, and Entergy Services filed an application with the SEC under the Holding Company Act, seeking authorization of various aspects of the Merger. In January 1993, GSU filed two applications with the NRC seeking approval of the change in ownership of GSU and an amendment to the operating license for River Bend to reflect its operation by Entergy Operations. All regulatory approvals were obtained in 1993 and the Merger was consummated on December 31, 1993 (see "Business of Entergy - Entergy Corporation-GSU Merger," above, for further information). Requests for rehearing of certain aspects of the FERC order were filed on January 14, 1994, by 14 parties, including Entergy Corporation, the APSC, the Mississippi Attorney General, the LPSC, the MPSC, the Texas Office of Public Utility Counsel, and the PUCT. Entergy Corporation, the LPSC, the Texas Office of Public Utility Counsel, and the PUCT are requesting FERC to restore a 40% cap on the amount of fuel savings GSU may be required to transfer to other Entergy operating companies under a tracking mechanism designed to protect the other companies from certain unexpected increases in fuel costs. The other parties are seeking to overturn FERC's decision on various grounds. Requests for rehearing of the SEC order were filed with the SEC by Houston Industries Incorporated and Houston Lighting & Power Company on December 28, 1993, and petitions for review seeking to set aside the SEC order were filed with the D.C. Circuit by these parties on February 15, 1994 and by Cajun on February 14, 1994. See "Nuclear Operations - River Bend," above for information on challenges to the NRC's approval of GSU's applications. Appeals seeking to set aside the LPSC order related to the Merger were filed in the 19th Judicial District Court for the Parish of East Baton Rouge, Louisiana, by Houston Lighting & Power Company on August 13, 1993, and by the Alliance for Affordable Energy, Inc. on August 20, 1993. Subsequently, on February 9, 1994, Houston Lighting & Power Company filed a motion voluntarily dismissing its appeal. AP&L. Three lawsuits (which have been consolidated) were filed in the Arkansas District Court by numerous plaintiffs against AP&L and Entergy Services in connection with the operation of two dams during a period of heavy rainfall and flooding in May 1990. The consolidated lawsuits sought approximately $14.4 million in property losses and other compensatory damages, and $500 million in punitive damages. In their responses to these complaints, AP&L and Entergy Services asserted, among other things, that AP&L owns flowage easements giving it the permanent right to inundate the lands owned or occupied by the plaintiffs in connection with the operation of the dams. In June 1991, the Arkansas District Court granted summary judgment to AP&L with respect to the enforceability of its flowage easements. In November 1991, the Arkansas District Court ruled that Entergy Services was entitled to the benefit of AP&L's flowage easements, in effect, removing from consideration damages in the approximate amount of $13.5 million alleged to have occurred within the areas covered by the easements. As a result, over 300 plaintiffs claiming damage within the easements were dismissed from the consolidated case in December 1991. Certain plaintiffs appealed these orders to the Eighth Circuit, which appeal was denied in March 1992. Following the Eighth Circuit's denial of their interlocutory appeal from the Arkansas District Court's orders, certain of the plaintiffs, without prejudice to their right to refile, voluntarily dismissed their claims which had not been disposed of in the Arkansas District Court's orders, thus making the orders a final adjudication, and appealed these orders to the Eighth Circuit. The remaining plaintiffs obtained a stay and an administrative termination of their claims, pending the outcome of the appeal. In December 1993, a three-judge panel of the Eighth Circuit filed its opinion affirming the judgment of the Arkansas District Court and entered judgment accordingly. The plaintiffs appealing the Arkansas District Court's orders filed petitions with the Eighth Circuit for a rehearing by the entire Court sitting en banc, which petitions were denied. The plaintiffs may petition the U.S. Supreme Court to issue a writ of certiorari to permit its review of the Eighth Circuit's decisions. Neither AP&L nor Entergy Services can predict whether the U.S. Supreme Court will grant such a petition, if one is filed. GSU. Between 1986 and 1993, GSU and approximately 70 other defendants, including many national and international corporations, including LP&L, have been sued in 17 suits in the Livingston Parish, Louisiana District Court (State District Court) by a number of plaintiffs who allegedly suffered damage or injury, or are survivors of persons who allegedly died, as a result of exposure to "hazardous toxic waste" that emanated from a site in Livingston Parish. The plaintiffs alleged that the defendants generated, transported, or participated in the storage of such wastes at the facility, which was previously operated as a waste oil recycling facility. These State District Court suits, which seek damages in total amounts ranging from $1.0 million to $10.0 billion and are now consolidated in a class action, and three federal suits in three states other than Louisiana involving issues arising from the same facility, have been removed and transferred, respectively, to the U.S. District Court for the Middle District of Louisiana (Federal District Court). Motions to remand the class action to the State District Court have been filed, and procedural issues regarding the federal suits are being considered as well. It is not known what effect any action taken on these motions and issues, whenever taken by the Federal District Court, would have on the April 11, 1994 State District Court trial date that was established before the suits were removed to Federal District Court; but it is unlikely such trial date will be met. The matter is pending. In October 1989, an amended lawsuit petition was filed on behalf of 985 plaintiffs in the District Court of Jefferson County, Texas, 60th Judicial District in Beaumont, Texas, naming 55 defendants including GSU. In February 1990, another amended lawsuit petition was filed in a different state District Court in Jefferson County, Texas, on behalf of over 200 plaintiffs (subsequently amended to include a total of 660) naming 127 defendants including GSU. Possibly 300 to 400 or more of the plaintiffs in Texas may have worked at GSU's premises. At least five other individual suits have been filed in Beaumont against GSU and others, seeking damages for alleged asbestos exposure. All of the plaintiffs in such suits are also suing GSU and all other defendants on a conspiracy count. There are 25 asbestos- related law suits filed in the 14th Judicial District Court of Calcasieu Parish in Lake Charles, Louisiana, on behalf of an aggregate of 53 plaintiffs naming from 16 to 24 defendants including GSU, and GSU is aware of as many as 61 additional cases that may be filed. The suits allege that each plaintiff contracted an asbestos-related disease from exposure to asbestos insulation products on the premises of such defendants. Management believes that GSU has meritorious defenses, but there can be no assurance as to the outcome of these cases or that additional claims may not be asserted. In asbestos- related suits against the manufacturers, very substantial recoveries have been achieved by large groups of claimants. GSU does not presently believe that the ultimate resolution of these cases will materially adversely affect the financial position of GSU. On February 3, 1984, Dow Chemical Company filed a request with the LPSC for a hearing to consider issues related to the purchase of cogenerated power by GSU. Other industries subsequently filed similar requests and the matters were consolidated. In November 1984, the LPSC completed hearings on rules, policies, and pricing methodologies applicable to cogeneration. Key issues were whether or not (1) GSU should be required to pay the industries for avoided capacity costs, and (2) GSU should be required to wheel power to or from the industrial plants. While the matter is still pending before the LPSC, the LPSC did set interim rates, subject to refund by either Dow or GSU, which exclude capacity costs. GSU has significant business relationships with Cajun, primarily co-ownership of River Bend and Big Cajun 2 Unit 3. GSU and Cajun own 70% and 30% of River Bend, respectively, while Big Cajun 2 Unit 3 is owned 42% and 58% by GSU and Cajun, respectively. GSU operates River Bend and Cajun operates Big Cajun 2 Unit 3. GSU was requested by Cajun and Jefferson Davis Electric Cooperative, Inc., (Jefferson Davis) to provide transmission of power over GSU's system for delivery to the Industrial Road area near Lake Charles, Louisiana. GSU provides electric service to industrial and other customers in such area, and Cajun and Jefferson Davis do not. On October 10, 1989, Cajun filed a complaint at FERC contending that GSU wrongfully refused to provide Cajun certain transmission services so that its member, Jefferson Davis, could provide service to certain industrial customers, and it requested FERC to order GSU to provide the service. On October 26, 1989, FERC summarily dismissed Cajun's complaint, but the D.C. Circuit reversed FERC's summary determination and remanded the case to FERC for a hearing. On June 24, 1992, after a hearing, an ALJ issued an Initial Decision, again dismissing Cajun's complaint. The ALJ found that the parties' contract did not require GSU to provide the service and that Cajun's member, Jefferson Davis, had not sought permission from the LPSC to serve the end-use customers in question. If Jefferson Davis secured permission from the LPSC, the ALJ believed (but did not decide) that FERC would require GSU to provide the requested transmission service. Both Cajun and GSU have filed exceptions to the ALJ's decision, and the matter is pending before FERC. Cajun and Jefferson Davis also brought a related action in federal court in the Western District of Louisiana alleging that GSU breached its obligations under the parties' contract and violated the antitrust laws by refusing to provide the transmission service described above. Cajun and Jefferson Davis seek an injunction requiring GSU to provide the requested service and unspecified treble damages for GSU's refusal to provide the service. On November 9, 1989, the district court judge denied Cajun's and Jefferson Davis' motion for a preliminary injunction. On May 3, 1991, the judge stayed the proceeding pending final resolution of the matters still pending before FERC. GSU and Cajun are parties to FERC proceedings regarding certain long-standing disputes relating to transmission service charges. Cajun asserts that GSU has improperly applied the terms of a rate schedule, Service Schedule CTOC, to its billings to Cajun and it seeks an order from FERC directing GSU to recompute the bills. GSU asserts that Cajun underpaid its bills, and it seeks an order directing Cajun to pay surcharges to make up the underpayments. On April 10, 1992, FERC issued an order affirming in part and reversing in part an ALJ's recommendations. Both GSU and Cajun have requested rehearing, and the requests are still pending. In addition, on August 25, 1993, the United States Court of Appeals for the Fifth Circuit reversed portions of FERC's order previously decided adversely to GSU, and remanded the case to FERC for further proceedings. On January 13, 1994, FERC rejected GSU's proposal to collect an interim surcharge while FERC considers the court's remand. GSU interprets FERC's 1992 order and the Court of Appeals decision to mean that Cajun owes GSU approximately $85 million through December 31, 1993. If GSU also prevails on all of the issues raised in its pending request for rehearing of FERC's earlier orders, then GSU estimates that Cajun would owe GSU approximately $118 million through December 31, 1993. If GSU does not prevail on its rehearing request, and Cajun prevails on its rehearing request, and if FERC rejects the modifications GSU interprets the court of appeals to have directed, then GSU would owe Cajun an estimated $76 million through December 31, 1993. Pending FERC's ruling on the May 1992 motions for rehearing, GSU has continued to bill Cajun utilizing the historical billing methodology and has booked underpaid transmission charges, including interest, in the amount of $140.8 million as of December 31, 1993. This amount is reflected in long-term receivables and in other deferred credits, with no effect on net income. On December 7, 1993, Cajun filed a complaint in the Middle District of Louisiana alleging that GSU failed to provide Cajun an opportunity to construct certain facilities that allegedly would have reduced its rates under Service Schedule CTOC, and Cajun seeks an order compelling the conveyance of certain facilities and unspecified damages. GSU has moved to dismiss the complaint on the basis, among others, that FERC has already addressed the matter in the proceedings described above. In May 1990, GSU received a subpoena from the Office of Inspector General - Investigations, United States Department of Agriculture, seeking production of documents relating to the construction costs of River Bend. Such office is authorized to investigate matters relating to programs of the Department of Agriculture. GSU has been sued by Cajun with respect to its participation in River Bend with funds made available through Department programs administered by the REA. GSU has failed in its efforts to have the REA made a party to the Cajun litigation. GSU does not know the purpose of such Office's investigation, but presently assumes that it relates to the Cajun civil litigation since the production of documents sought by such Office is similar to that sought by Cajun in its action against GSU. However, there can be no assurance given by GSU as to the real purpose of such Office's investigation. Among other areas of responsibility, such office is authorized to investigate possible violations of law. GSU believes the subpoena proceeding has been administratively dismissed without prejudice to the parties. On December 2, 1991, Cajun filed a complaint seeking declaratory and injunctive relief from the U. S. District Court for the Middle District of Louisiana. The complaint concerns GSU's position that Cajun is in default with respect to paying its share of certain expenditures to repair corrosion damage in the service water system, to repair a feedwater nozzle crack, and to repair a turbine rotor. Cajun alleges that it has no obligation to pay its share of such costs and seeks a declaration that it may elect not to participate in the funding of such costs and enjoining GSU from demanding payment therefor or attempting to implement default provisions in the Operating Agreement with respect thereto. Cajun alleges that if it is required to pay its share of such costs it would be forced to default on other obligations and would be forced to seek relief in bankruptcy. GSU believes that Cajun is in default under the provisions of the Operating Agreement. No assurance can be given as to the outcome or timing of this action brought by Cajun. On November 25, 1992, Dixie Electric Membership Corporation and Southwest Louisiana Electric Membership Corporation, both members of Cajun, filed suit in the U.S. District Court for the Western District of Louisiana seeking a declaration that the River Bend Joint Ownership Agreement between GSU and Cajun is void because an allegedly required approval of the LPSC was not obtained. This suit has been transferred from the Western District to the Middle District, and is being processed in conjunction with the suit described in the following paragraph. GSU believes the suit is without merit. In June 1989, Cajun filed a civil action against GSU in the U. S. District Court for the Middle District of Louisiana. Cajun stated in its complaint that the object of the suit is to annul, rescind, terminate, and/or dissolve the Joint Ownership Participation and Operating Agreement entered into on August 28, 1979 (Operating Agreement), related to River Bend. Cajun alleges fraud and error by GSU, breach of its fiduciary duties owed to Cajun, and/or GSU's repudiation, renunciation, abandonment, or dissolution of its core obligations under the Operating Agreement, as well as the lack or failure of cause and/or consideration for Cajun's performance under the Operating Agreement. The suit seeks to recover Cajun's alleged $1.6 billion investment in the unit as damages, plus attorneys' fees, interest, and costs. In March 1992, the district court appointed a mediator to engage in settlement discussions and to schedule settlement conferences between the parties. Discussions with the mediator began in July 1992, however, GSU cannot predict what effect, if any, such discussions will have on the timing or outcome of the case. A trial without a jury is set for April 12, 1994, on the portion of the suit by Cajun to rescind the Operating Agreement. GSU believes the suits are without merit and is contesting them vigorously. No assurance can be given as to the outcome of this litigation. If GSU were ultimately unsuccessful in this litigation and were required to make substantial payments, GSU would probably be unable to make such payments and would probably have to seek relief from its creditors under the Bankruptcy Code. See Note 12 of GSU's Notes to Financial Statements, "Entergy Corporation-GSU Merger," for the accounting treatment of preacquisition contingencies, including a charge resulting from an adverse resolution of the litigation with Cajun related to River Bend. In July 1992, Cajun notified GSU that it would fund a limited amount of costs related to the fourth refueling outage at River Bend, completed in September 1992. Cajun has also not funded its share of the costs associated with certain additional repairs and improvements at River Bend completed during the refueling outage. GSU has paid the costs associated with such repairs and improvements without waiving any rights against Cajun. GSU believes that Cajun is obligated to pay its share of such costs under the terms of the applicable contract. Cajun has filed a suit seeking a declaration that it does not owe such funds and seeking injunctive relief against GSU. GSU is contesting such suit and is reviewing its available legal remedies. In September 1992, GSU received a letter from Cajun alleging that the operating and maintenance costs for River Bend are "far in excess of industry averages" and that "it would be imprudent for Cajun to fund these excessive costs." Cajun further stated that until it is satisfied it would fund a maximum of $700,000 per week under protest for the remainder of 1992. In a December 1992 letter, Cajun stated that it would also withhold costs associated with certain additional repairs, of which the majority will be incurred during the next refueling outage, currently scheduled for April 1994. GSU believes that Cajun's allegations are without merit and is considering its legal and other remedies available with respect to the underpayments by Cajun. The total resulting from Cajun's failure to fund repair projects, Cajun's funding limitation on the fourth refueling outage, and the weekly funding limitation by Cajun was $33.3 million as of December 31, 1993, compared with a $28.4 million unfunded balance as of December 31, 1992. During 1994, and for the next several years, it is expected that Cajun's share of River Bend-related costs will be in the range of $60 million to $70 million per year. Cajun's weak financial condition could have a material adverse effect on GSU, including a possible NRC action with respect to the operation of River Bend and a need to bear additional costs associated with the co-owned facilities. If GSU were required to fund Cajun's share of costs, there can be no assurance that such payments could be recovered. Cajun's weak financial condition could also affect the ultimate collectibility of amounts owed to GSU. Since 1986, GSU had been in litigation with the Southern Company regarding unit power and long-term power purchase contracts with the Southern Company. GSU entered into a settlement agreement dated December 21, 1990, which was consummated on November 7, 1991, and the settlement obligations were fully satisfied in 1993. In 1986, the PUCT and the LPSC disallowed the pass-through by GSU in its retail rates of the costs of the capacity purchases from the Southern Company, which were being incurred by GSU. GSU appealed the actions of the PUCT and the LPSC disallowing pass-through of Southern Company capacity charges to the appropriate state courts. The appeal from the LPSC is pending. As part of a settlement of a retail rate case in Texas during the fourth quarter of 1993, GSU has discontinued its appeal of the PUCT disallowance. Following the announcement of the execution of the Reorganization Agreement, a purported class action complaint was filed on June 9, 1992, in the District Court 60th Judicial District in Jefferson County, Texas (District Court) against GSU and its directors relating to the then proposed business combination with Entergy Corporation. On June 11, 1992, two additional purported class action complaints were filed against such defendants in the District Court. All three of the complaints (the Shareholder Actions) were filed by persons alleged to be shareholders of GSU and seeking declaration of a class action on behalf of all persons owning common stock of GSU. GSU has executed a Memorandum of Understanding with counsel for the plaintiffs in these suits agreeing in principle to settle such actions subject to execution of an appropriate stipulation of settlement, approval by the court, and certain other conditions. In the Memorandum, the defendants have denied any actionable acts or omissions and state that they have entered into the Memorandum solely to eliminate the burden and expense of further litigation and to facilitate the consummation of the business combination. The Memorandum memorialized certain agreements by GSU and Entergy Corporation for the benefit of shareholders principally in the event the business combination were not consummated, including a covenant to consider reinstitution of dividends on the common stock of GSU in such event. The business combination was consummated on December 31, 1993. Incident to the settlement, the defendants agreed not to oppose an application for attorneys' fees by plaintiffs' counsel that do not exceed $500,000 or for an award of expenses not to exceed $50,000. The individual directors named as defendants in these complaints are entitled to indemnification pursuant to GSU's Restated Articles of Incorporation, By-laws, and individual indemnity agreements, provided that the terms and conditions of the indemnities are satisfied. LP&L. For information regarding litigation in connection with an abandoned waste oil recycling plant site in Livingston Parish, Louisiana, in which LP&L and GSU are defendants, see "GSU," above. LP&L does not believe that it was a generator of any material delivered to this facility and is defending vigorously against the claims in these suits. Since the mid-1980's, LP&L and the tax authorities of St. Charles Parish, Louisiana (Parish), in which Parish Waterford 3 is located, have disputed use taxes paid on nuclear fuel ($4.9 million through 1989) under protest by LP&L. LP&L has been successful in a lawsuit in the Parish with regard to recovering these taxes, plus interest, and also with regard to Parish lease tax issues pertaining to fuel financing arrangements. On the grounds of the previous favorable court decisions, LP&L continues to challenge in the courts additional use tax assessments that it has paid to the Parish and to seek additional interest that LP&L claims it is due. Also, in early procedural stages are (1) suits by LP&L with regard to the state use tax on nuclear fuel, and (2) LP&L's defense (and indemnification, if necessary) of nuclear fuel lessors under LP&L's fuel financing arrangements in the suits filed by the Parish use tax authorities claiming approximately $64.0 million in lease and use taxes. These matters are pending. System Energy. In connection with an IRS audit of Entergy's 1988, 1989, and 1990 consolidated federal income tax returns, the IRS is proposing that adjustments be made to the Grand Gulf 2 abandonment loss deduction claimed on Entergy's 1989 consolidated federal income tax return. If any such adjustments are necessary, the effect on System Energy's net income should be immaterial. Entergy intends to contest the proposed adjustments if finalized by the IRS. The outcome of such proceedings cannot be predicted at this time. EARNINGS RATIOS OF SYSTEM OPERATING COMPANIES AND SYSTEM ENERGY The System operating companies and System Energy have calculated ratios of earnings to fixed charges and ratios of earnings to fixed charges and preferred dividends pursuant to Item 503 of Regulation S-K of the SEC as follows:
Years Ended December 31, --------------------------------------------- 1989 1990 1991 1992 1993 ---- ---- ---- ---- ---- Ratios of Earnings to Fixed Charges(a) AP&L 2.31 2.16 2.25 2.28 3.11(h) GSU 1.16 .80(i) 1.56 1.72 1.54 LP&L 1.79 2.32 2.40 2.79 3.06 MP&L 1.04(e) 2.42 2.36 2.37 3.79(h) NOPSI 1.89 2.73 5.66(g) 2.66 4.68(h) System Energy -(f) 2.10 1.74 2.04 1.87
Years Ended December 31, --------------------------------------------- 1989 1990 1991 1992 1993 ---- ---- ---- ---- ---- Ratios of Earnings to Fixed Charges and Preferred Dividends(a)(b)(c) AP&L 1.88 1.81 1.87 1.86 2.54(h) GSU(d) .66(i) .59(i) 1.19 1.37 1.21 LP&L 1.39 1.87 1.95 2.18 2.39 MP&L 1.00(e) 1.93 1.94 1.97 3.08(h) NOPSI 1.62 2.36 4.97(g) 2.36 4.12(h)
____________________ (a) "Earnings" as defined by SEC Regulation S-K represent the aggregate of (1) net income, (2) taxes based on income, (3) investment tax credit adjustments-net, and (4) fixed charges. "Fixed Charges" include interest (whether expensed or capitalized), related amortization, and interest applicable to rentals charged to operating expenses. (b) "Preferred Dividends" as defined by SEC Regulation S-K are computed by dividing the preferred dividend requirement by one hundred percent (100%) minus the income tax rate. (c) System Energy's Amended and Restated Articles of Incorporation do not currently provide for the issuance of preferred stock. (d) "Preferred Dividends" in the case of GSU also include dividends on preference stock. (e) Earnings for the year ended December 31, 1989, include the impact of the write-off of $60 million of deferred Grand Gulf 1-related costs pursuant to an agreement between MP&L and the MPSC. (f) Earnings for the year ended December 31, 1989, were inadequate to cover fixed charges due to System Energy's cancellation and write- off of its investment in Grand Gulf 2 in September 1989. The amount of the coverage deficiency for fixed charges was $745.2 million. (g) Earnings for the year ended December 31, 1991, include the $90 million effect of the 1991 NOPSI Settlement. (h) Earnings for the year ended December 31, 1993, include approximately $81 million, $52 million, and $18 million for AP&L, MP&L, and NOPSI, respectively, related to the change in accounting principle to provide for the accrual of estimated unbilled revenues. (i) Earnings for the year ended December 31, 1990, for GSU were not adequate to cover fixed charges by $60.6 million. Earnings for the years ended December 31, 1990 and 1989, were not adequate to cover fixed charges and preferred dividends by $165.1 million and $190.8 million, respectively. Earnings in 1990 include a $205 million charge for the settlement of a purchased power dispute. INDUSTRY SEGMENTS NOPSI Narrative Description of NOPSI Industry Segments Electric Service. NOPSI supplied electric service to 190,613 customers as of December 31, 1993. During 1993, 36% of electric operating revenues was derived from residential sales, 40% from commercial sales, 6% from industrial sales, 15% from sales to governmental and municipal customers, and 3% from sales to public utilities and other sources. Natural Gas Service. NOPSI supplied natural gas service to 154,251 customers as of December 31, 1993. During 1993, 56% of gas operating revenues was derived from residential sales, 18% from commercial sales, 9% from industrial sales, and 17% from sales to governmental and municipal customers. (See "Fuel Supply - Natural Gas Purchased for Resale," incorporated herein by reference.) Selected Financial Information Relating to Industry Segments For selected financial information relating to NOPSI's industry segments, see NOPSI's financial statements and Note 11 of NOPSI's Notes to Financial Statements, "Business Segment Information," incorporated herein by reference. Employees by Segment NOPSI's full-time employees by industry segment as of December 31, 1993, were as follows: Electric 568 Natural Gas 148 --- Total 716 (For further information with respect to NOPSI's segments, see "Property.") GSU For the year ended December 31, 1993, 96% of GSU's operating revenues were derived from the electric utility business. The remainder of operating revenues were derived 2% from the steam business and 2% from the natural gas business. Segment information for GSU is not provided. PROPERTY Generating Stations The total capability of Entergy 's owned and leased generating stations as of December 31, 1993, by company, is indicated below:
Owned and Leased Capability MW(1) Gas Turbine andl Fossil Internal Company Total Fuel Nuclear Combustion Hydro ------- ----- ---- ------- ---------- ----- AP&L 4,367 (2) 2,373 1,694 230 (8) 70 GSU 6,420 (2) 5,693 652 (5) 75 - LP&L 5,535 (2) 4,441 1,075 (6) 19 - MP&L 3,046 (2) 3,035 (4) - 11 - NOPSI 927 (2) 912 - 15 - System Energy 1,028 - 1,028 (7) - - Total System 21,323 (3) 16,454 (3)(4) 4,449 350 70
_______________________ (1) "Owned and Leased Capability" is the dependable load carrying capability of the stations, as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. (2) Excludes the capacity of fossil-fueled generating stations placed on extended reserve as follows: AP&L - 506 MW; GSU - 405 MW; LP&L - 19 MW; MP&L - 73 MW; and NOPSI - 143 MW. Generating stations that are not expected to be utilized in the near-term to meet load requirements are placed in extended reserve shutdown in order to minimize operating expenses. (3) Excludes net capability of Entergy Power, which owns 809 MW of fossil-fueled capacity (see "Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters - Entergy Power," above). (4) Independence 2, a coal unit operated by AP&L and jointly owned 25% by MP&L (210 MW), 31.5% by Entergy Power (265 MW), and the balance by various municipalities and a cooperative. The unit was out of service, due to an explosion from August 11, 1993 to February 18, 1994. (5) GSU's nuclear capability represents its 70% ownership interest in River Bend; Cajun owns the remaining 30% undivided interest. (6) LP&L's nuclear capability represents its 90.7% ownership interest and 9.3% leasehold interest in Waterford 3. (7) System Energy's capability represents its 90% interest in Grand Gulf 1 (78.5% ownership interest and 11.5% leasehold interest). South Mississippi Electric Power Association has the remaining 10% undivided ownership interest in Grand Gulf 1. Entitlement to System Energy's capacity has been allocated to AP&L, LP&L, MP&L, and NOPSI pursuant to the Unit Power Sales Agreement. (8) Includes 188 MW of capacity leased by AP&L through 1999. Representatives of the System regularly review load and capacity projections in order to coordinate and recommend the location and time of installation of additional generating capacity and of interconnections in light of the availability of power, the location of new loads, and maximum economy to the System. Based on load and capability projections, the System has no need to install additional generating capacity until 1999. To delay the need for new capacity, the System is engaging in conservation and DSM programs, as discussed in "Business of Entergy - Competition - Least Cost Planning," above. When new generation resources are needed, the System plans to meet this need with a variety of sources other than construction of new base load generating capacity. In the meantime, the System will meet capacity needs by, among other things, removing generating stations from extended reserve shutdown. Generating stations brought out of extended reserve shutdown during 1993 added 248 MW to meet operating requirements. Under the terms of the System Agreement, some of the generating capacity and other power resources are shared among the System operating companies. Among other things, the System Agreement provides that parties having generating capacity greater than their load requirements sell such capacity to those parties having deficiencies in generating capacity and that the purchasers pay to the sellers a charge sufficient to cover certain of the sellers' ownership costs, 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 sellers' steam electric generating units fueled by oil or gas. In addition, for all energy to be exchanged among the System operating companies under the System Agreement, the purchasers are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs (see "Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters - System Agreement," above, for a discussion of FERC proceedings relating to the System Agreement). The System's business is subject to seasonal fluctuations with the peak period occurring in the summer months. Excluding GSU, Entergy 's 1993 peak demand of 12,858 MW occurred on August 19, 1993. The net System capability at the time of peak was 14,029 MW, which reflects a reduction of the System's total 14,765 MW of owned and leased capability by net off-system firm sales of 736 MW. The capacity margin at the time of the peak was approximately 8.4%, not including units placed on extended reserve and capacity owned by Entergy Power. GSU's 1993 peak demand of 5,612 MW occurred on August 18, 1993. The net GSU capability at the time of peak was 6,704 MW, which reflects an increase of GSU's total 6,420 MW of owned and leased capability by net off-system purchases of 284 MW. The capacity margin at the time of the peak was approximately 18.2%, not including units placed on extended reserve. Interconnections The electric power supply facilities of Entergy consist principally of steam-electric production facilities strategically located with reference to availability of fuel, protection of local loads, and other controlling economic factors. These are interconnected by a transmission system operating at various voltages up to 500 KV. Generally, with the exception of Grand Gulf 1, Entergy Power's capacity and a small portion of MP&L's capacity, operating facilities or interests therein are owned by the System operating company serving the area in which the facilities are located. However, all of the System's generating facilities are centrally dispatched and operated with a view to realizing the greatest economy. This operation seeks, among other things, the lowest cost sources of energy from hour to hour. The minimum of investment and the most efficient use of plant are sought to be achieved, in part, through the coordinated scheduling of maintenance, inspection, and overhaul. The System operating companies have direct interconnections with neighboring utilities including, in individual cases, Mississippi Power Company, Southwestern Electric Power Company, Southwest Power Administration, Central Louisiana Electric Company, Inc., Oklahoma Gas and Electric Company, The Empire District Electric Company, Union Electric Company, Arkansas Electric Cooperative Corporation, Tennessee Valley Authority, Cajun, Sam Rayburn Dam Electric Cooperative, Inc., SRG&T, SRMPA, Associated Electric Cooperative, Inc., Municipal Energy Agency of Mississippi, Louisiana Energy and Power Authority, Farmers Electric Cooperative, South Mississippi Electric Power Authority, and the cities of Lafayette, Plaquemine, and New Roads, Louisiana. GSU also has an interconnection agreement with Houston Lighting and Power Company providing a minor amount of emergency service only. The System operating companies also have interchange agreements with Alabama Electric Cooperative, Big Rivers Electric Cooperative, Northeast Texas Electric Cooperative, Inc., Sam Rayburn G&T Electric Cooperative, Inc., Florida Power Corporation, Florida Power & Light Company, Jacksonville Electric Authority, Oglethorpe Power Cooperative, the City of Lafayette, Louisiana, the City of Springfield, Missouri, and East Kentucky Electric Cooperative. The System operating companies are members of the Southwest Power Pool, the primary purpose of which is to ensure the reliability and adequacy of the electric bulk power supply in the southwest region of the United States. The Southwest Power Pool is a member of the North American Electric Reliability Council. AP&L, LP&L, MP&L, and NOPSI are also members of the Western Systems Power Pool. Gas Property As of December 31, 1993, NOPSI distributed and transported natural gas for distribution solely within the limits of the City of New Orleans through a total of 1,422 miles of gas distribution mains and 32 miles of gas transmission lines. NOPSI receives deliveries of natural gas for distribution purposes at 14 separate locations, including deliveries from United Gas Pipe Line Company (United) at six of these locations. Of the remaining delivery points, two are principally served by interstate suppliers and the remaining are served by intrastate suppliers. As of December 31, 1993, the gas property of GSU was not material to GSU. Titles The System's generating stations are generally located on lands owned in fee simple. The greater portion of the transmission and distribution lines of the System operating companies has been constructed over lands of private owners pursuant to easements or on public highways and streets pursuant to appropriate permits. The rights of each company in the realty on which its properties are located are considered by it to be adequate for its use in the conduct of its business. Minor defects and irregularities customarily found in properties of like size and character exist, but such defects and irregularities do not materially impair the use of the properties affected thereby. The System operating companies generally have the right of eminent domain whereby they may, if necessary, perfect or secure titles to, or easements or servitudes on, privately-held lands used or to be used in their utility operations. Substantially all the physical properties owned by each System operating company and System Energy are subject to the lien of the mortgage and deed of trust securing the first mortgage bonds of such company. The Lewis Creek generating station is owned by GSG&T, Inc., and is not subject to the lien of the GSU mortgage securing the first mortgage bonds of GSU, but is leased and operated by GSU. In the case of LP&L, certain properties are subject to the liens of second mortgages securing other obligations of LP&L. In the case of MP&L and NOPSI, substantially all of their properties and assets are subject to the second mortgage lien of their respective general and refunding mortgage bond indentures. FUEL SUPPLY The following tabulation shows the percentages of natural gas, fuel oil, nuclear fuel, and coal used in generation, excluding that of Entergy Power, during the past three years. It also shows the average fuel cost per KWH generated by each type of fuel during that period. The balance of generation, which was immaterial, was provided by hydroelectric power. ENTERGY EXCLUDING GSU
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 - ---- --- ----- --- ----- --- ----- --- ----- 1993 27 2.70 7 2.10 51 .58 15 1.91 1992 32 1.99 - - 49 .67 18 1.90 1991 31 1.64 - - 50 .79 18 1.76
GSU
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 - ---- --- ----- --- ----- --- ----- --- ----- 1993 69 2.44 - - 14 1.19 17 1.77 1992 76 2.01 - - 8 1.64 16 1.68 1991 66 1.79 - - 19 1.24 15 2.08
The following tabulation shows the percentages of generation by fuel type used in generation, excluding that of Entergy Power, for 1993 (actual) and 1994 (projected).
Natural Gas Fuel Oil Nuclear Coal ---------------- ---------------- ---------------- ---------------- 1993 1994 1993 1994 1993 1994 1993 1994 ---- ---- ---- ---- ---- ---- ---- ---- System(a) 27% 36% 7% 3% 51% 38% 15% 23% AP&L 7 1 - - 60 48 33 51 GSU 69 59 - - 14 21 17 20 LP&L 52 62 1 - 47 38 - - MP&L 24 39 52 27 - - 24 34 NOPSI 92 100 8 - - - - - System Energy - - - - 100(b) 100(b) - -
_______________________ (a) The System's 1993 actual generation by fuel type excludes GSU; 1994 estimated generation by fuel type includes GSU. (b) Capacity and energy from System Energy's interest in Grand Gulf 1 is allocated as follows: AP&L - 36%; LP&L - 14%; MP&L - 33%; and NOPSI - 17%. Natural Gas The System operating companies have various long-term gas contracts that will satisfy a significant percentage of each operating company's needs; however, such contracts typically require the operating companies to purchase less than half of their annual gas requirements under such contracts. Additional gas requirements are satisfied under less expensive short-term contracts and spot-market purchases. In November 1992, GSU entered into a transportation service agreement with a gas supplier that obligates such supplier to provide GSU with flexible natural gas swing service to certain generating stations by using such supplier's pipeline and salt dome gas storage facility. Many factors influence the availability and price of natural gas supplies for power plants including wellhead deliverability, storage and pipeline capacity, and the demand requirements of the end users. This demand is closely tied to the severity of the weather conditions in the region. Furthermore, pricing relative to other energy sources (i.e. fuel oil, coal, purchased power, etc.) will affect the demand for natural gas for power plants. Supplies of natural gas are expected to be adequate in 1994. Pursuant to FERC and state regulations, gas supplies may be interrupted to power plants during periods of shortage. To the extent natural gas supplies may be disrupted, the System operating companies will use alternate sources of energy such as fuel oil. Coal AP&L has long-term contracts for the supply of low-sulfur coal for the White Bluff Steam Electric Generating Station and the Independence Steam Electric Station (which is owned 25% by MP&L). Coal for the White Bluff Station is supplied under a contract from a mine in the State of Wyoming. The coal contract provides for the delivery of sufficient coal to operate the White Bluff Station through approximately 2002. Coal for the Independence Station is also supplied under a contract from a mine in the State of Wyoming. Coal supplied under this contract is expected to meet the requirements of the Independence Station through at least 2014. GSU has a contract for a supply of low-sulfur Wyoming coal for Nelson Unit 6, which should be sufficient to satisfy the fuel requirements at Nelson Unit 6 through 2004. Cajun has advised GSU that it has contracts that should provide an adequate supply of coal until 1997 for the operation of Big Cajun 2, Unit 3 (which is operated by Cajun and of which GSU owns 42%). Nuclear Fuel Generally, the supply of fuel for nuclear generating units involves the mining and milling of uranium ore to produce a concentrate, the conversion of uranium concentrate to uranium hexafluoride gas, enrichment of that gas, fabrication of the nuclear fuel assemblies, and disposal of the spent fuel. System Fuels is responsible for contracts to acquire nuclear fuel to be used in AP&L's, LP&L's, and System Energy's nuclear units and for maintaining inventories of such materials during the various stages of processing. Each of these companies is currently responsible for contracting for the fabrication of its own nuclear fuel and for purchasing the required enriched uranium hexafluoride from System Fuels. Currently, the requirements for GSU's River Bend plant are covered by contracts made by GSU. On October 3, 1989, System Fuels entered into a revolving credit agreement with banks permitting it to borrow up to $45 million to finance its nuclear materials and services inventory. AP&L, LP&L, and System Energy agreed to purchase from System Fuels the nuclear materials and services financed under the agreement if System Fuels should default in its obligations thereunder. Such purchases would be allocated based on percentages agreed upon among the parties. In the absence of such agreement, AP&L, LP&L, and System Energy would each be obligated to purchase one-third of the nuclear materials and services. Based upon the planned fuel cycles for the System's nuclear units, the following tabulation shows the years through which existing contracts and inventory will provide materials and services: Acquisition of or Conversion Spent Uranium to Uranium Enrich- Fabri- Fuel Concentrate Hexafluoride ment(3) cation Disposal ----------- ------------ ------- ------ -------- ANO 1 (1) (1) 1995 1997 (4) ANO 2 (1) (1) 1995 1994 (4) River Bend (2) (2) 2000 1995 (4) Waterford 3 (1) (1) 1995 1999 (4) Grand Gulf 1 (1) (1) 1995 1995 (4) __________________________ (1) Current contracts will provide these materials and services through termination dates ranging from 1994-1997. Additional materials and services required beyond these dates are estimated to be available for the foreseeable future. (2) Current GSU contracts will provide a significant percentage of these materials and services for River Bend through 1995. (3) Enrichment services for ANO 1, ANO 2, Waterford 3, and Grand Gulf 1 are provided by a System Fuels contract with the United States Enrichment Corporation (USEC). The contract has been terminated after 1995 to permit flexibility on future pricing and terms that could be obtained. Enrichment services for River Bend are provided by a GSU contract with USEC that may be partially terminated after 1998 and fully terminated after 2000. (See "Rate Matters and Regulation - Regulation - Regulation of the Nuclear Power Industry - Decommissioning," above for information on annual contributions to a federal decontamination and decommissioning fund required by the Energy Act to be made by AP&L, GSU, LP&L, and System Energy as a result of their enrichment contracts with DOE.) (4) The Nuclear Waste Policy Act of 1982 provides for the disposal of spent nuclear fuel or high level waste by the DOE. Under this Act, the DOE was to begin accepting spent fuel in 1998 and to continue until the disposal of all spent fuel from reactor sites has been accomplished. In November 1989, the DOE indicated that the repository program will be delayed. Current on-site spent fuel storage capacity at ANO, River Bend, Waterford 3, and Grand Gulf 1 is estimated to be sufficient to store fuel from normal operations until 1995, 2003, 2000, and 2004, respectively. It is expected that any additional storage capacity required, due to delay of the DOE repository program, will have to be provided by the affected companies (see "Rate Matters and Regulation - Regulation - Regulation of the Nuclear Power Industry - Spent Fuel and Other High-Level Radioactive Waste," above). The System will require additional arrangements for segments of the nuclear fuel cycle beyond the dates shown above. Except as noted above, Entergy cannot predict the ultimate availability or cost of such arrangements at this time. AP&L, GSU, LP&L, and System Energy currently have nuclear fuel leasing arrangements that provide that AP&L, GSU, LP&L, and System Energy may lease up to $125 million, $105 million, $95 million, and $105 million of nuclear fuel, respectively. As of December 31, 1993, the unrecovered cost base of AP&L's, GSU's, LP&L's, and System Energy's nuclear fuel leases amounted to approximately $93.6 million, $96.5 million, $61.3 million, and $79.7 million, respectively. Each lessor finances its acquisition and ownership of nuclear fuel under a credit agreement and through the issuance of intermediate-term notes. The credit agreements, which were entered into by AP&L in 1988, by LP&L and System Energy in 1989, and GSU in 1993, had initial terms of five years, with the exception of GSU, which has an initial term of three years. These agreements are subject to annual renewal with, in LP&L's and GSU's case, the consent of the lenders. The credit agreements for AP&L, LP&L, and System Energy have all been extended and now have termination dates of December 1996, January 1997, and February 1997, respectively. The credit agreement for GSU was entered into in December 1993 and has a termination date of December 1996. The intermediate-term notes have varying maturities through January 31, 1999. It is expected that the credit agreements will be extended, or alternative financing will be secured by each lessor, based on the particular lessee's nuclear fuel requirements. If extensions or alternative financing cannot be arranged, the particular lessee must purchase sufficient nuclear fuel to allow the lessor to retire such borrowings. Natural Gas Purchased for Resale NOPSI has several suppliers of natural gas for resale. Its system is interconnected with three interstate and three intrastate pipelines. Presently, NOPSI's primary suppliers of natural gas for resale are United, an interstate pipeline, and Bridgeline and Pontchartrain, intrastate pipelines. NOPSI has a firm gas purchase contract with United and receives this service subject to FERC- approved rates pursuant to a certificate granted by FERC. NOPSI also has firm contracts with its two intrastate suppliers and also makes interruptible spot market purchases when economically attractive. In recent years, natural gas deliveries have been subject primarily to weather-related curtailments. However, NOPSI has experienced no such curtailments. In April 1992, FERC issued Order No. 636, which mandated interstate pipeline restructuring. The order requires interstate pipelines to cease selling gas to local distribution customers at the city-gate interconnection although transportation service can be provided in lieu of the former sale. As a result, in the future, NOPSI must substitute sources upstream of the United system for its current gas supply from United. NOPSI is considering purchases from independent intrastate or interstate supply aggregators and/or from intrastate pipeline sources in a manner consistent with its economic and supply reliability objectives. Prior to the effectiveness of Order No. 636, discussed above, in the event of a natural gas shortage on the United system, NOPSI would have received a portion of the available gas supply from United and its other suppliers. After Order No. 636 mandated restructuring (October 31, 1993), curtailments of supply could occur if NOPSI's suppliers failed to perform their obligations to deliver gas under their supply agreements with NOPSI. United 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, NOPSI does not anticipate that there will be any interruptions in natural gas deliveries to its customers. GSU purchases natural gas for resale from a single interstate supplier. Abandonment of service by the present supplier would be subject to abandonment proceedings by FERC. Research AP&L, GSU, LP&L, MP&L, and NOPSI are members 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 its needs and available resources. During 1991, 1992, and 1993, the System, including GSU, contributed approximately $12 million, $16 million, and $17 million, respectively, for the various research programs in which Entergy was involved. Item 2. Properties Refer to Item 1. "Business - Property," incorporated herein by reference, for information regarding the properties of the registrants. Item 3. Legal Proceedings Refer to Item 1. "Business - Rate Matters and Regulation," incorporated herein by reference, for details of the registrants' material rate proceedings and other regulatory proceedings and litigation that are pending or that terminated in the fourth quarter of 1993. Item 4. Submission of Matters to a Vote of Security Holders A consent in lieu of a special meeting of common stockholders of Entergy-GSU Holdings, Inc. (Holdings) was executed on December 30, 1993, pursuant to a Delaware statute that permits such a procedure. The consent was signed on behalf of Entergy Corporation and GSU, which at that time owned all of the outstanding common stock of Holdings. The common stockholders acted to: (1) increase the number of directors from 2 to 18 upon the occurrence of the combination of Entergy Corporation and GSU, such expanded board to consist of Edwin Lupberger and Joseph Donnelly, who continued as directors, and the following new directors: W. Frank Blount; John A. Cooper, Jr.; Brooke H. Duncan; Lucie J. Fjeldstad; Kaneaster Hodges, Jr.; Robert v.d. Luft; Adm. Kinnaird R. McKee; Paul W. Murrill; James R. Nichols; Eugene H. Owen; John N. Palmer, Sr.; Robert D. Pugh; H. Duke Shackelford; Wm. Clifford Smith; Bismark A. Steinhagen; and Dr. Walter Washington; (2) approve the terms and provisions of certain agreements related to such combination; (3) approve the actions of the officers in connection with those agreements and the transactions contemplated thereby; (4) approve the assumption and adoption by Holdings of certain benefit plans of Entergy Corporation; and (5) approve the taking of actions to issue stock with respect to such plans, including the listing of Holdings' common stock on the New York, Pacific, and Midwest Stock Exchanges and the filing of registration statements with the Securities and Exchange Commission. After the consummation of the transactions involved in the combination, the name of Holdings was changed to Entergy Corporation. On January 22, 1994, Mr. Donnelly resigned from the position of director of Entergy Corporation. 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, Midwest, and Pacific Stock Exchanges. The high and low prices for each quarterly period in 1993 and 1992, were as follows: 1993 1992 --------------- ---------------- High Low High Low ------ ------ ------ ------ (In Dollars) First 36 1/2 32 1/2 29 5/8 27 1/8 Second 38 1/4 33 1/4 28 1/2 26 1/8 Third 39 7/8 36 1/4 31 7/8 28 1/4 Fourth 39 1/4 35 1/8 33 5/8 30 1/2 Four consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in each of 1993 and 1992. In 1993, dividends of 40 cents per share were paid in each of the first three quarters and dividends of 45 cents per share were paid in the last quarter. Dividends of 35 cents per share were paid in each of the first three quarters of 1992, and dividends of 40 cents per share were paid in the last quarter of 1992. As of February 24, 1994, there were 63,779 stockholders of record of Entergy Corporation. For information with respect to Entergy Corporation's future ability to pay dividends, refer to Note 7 of Entergy Corporation and Subsidiaries' Notes to Consolidated Financial Statements, "Dividend Restrictions," incorporated herein by reference. In addition to the restrictions described in Note 7, the Holding Company Act 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. AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy. There is no market for the common stock of System Energy and the System operating companies, all of which is owned by Entergy Corporation. Prior to December 31, 1993, GSU's common stock was publicly held. Effective with the Merger, all shares of GSU common stock were acquired by Entergy Corporation. No cash dividends on common stock were paid by GSU to its stockholders in 1992-1993. Cash dividends on common stock paid by AP&L, LP&L, MP&L, NOPSI, and System Energy to Entergy Corporation during 1993 and 1992, were as follows: 1993 1992 ------ ------ (In Millions) AP&L $156.3 $ 75.0 LP&L 167.6 174.6 MP&L 85.8 68.4 NOPSI 43.9 32.2 System Energy 233.1 137.7 For information with respect to restrictions that limit the ability of System Energy and the System operating companies to pay dividends, and for information with respect to dividends paid to Entergy Corporation by its subsidiaries subsequent to December 31, 1993, refer respectively, to Note 6 of System Energy's and Note 7 of AP&L's, GSU's, LP&L's, MP&L's, and NOPSI's Notes to Financial Statements, "Dividend Restrictions," incorporated herein by reference. Item 6. Selected Financial Data Entergy Corporation. Refer to information under the heading "Entergy Corporation and Subsidiaries Selected Financial Data - Five- Year Comparison," which information is incorporated herein by reference. AP&L. Refer to information under the heading "Arkansas Power & Light Company Selected Financial Data - Five-Year Comparison," which information is incorporated herein by reference. GSU. Refer to information under the heading "Gulf States Utilities Company Selected Financial Data - Five-Year Comparison," which information is incorporated herein by reference. LP&L. Refer to information under the heading "Louisiana Power & Light Company Selected Financial Data - Five-Year Comparison," which information is incorporated herein by reference. MP&L. Refer to information under the heading "Mississippi Power & Light Company Selected Financial Data - Five-Year Comparison," which information is incorporated herein by reference. NOPSI. Refer to information under the heading "New Orleans Public Service Inc. Selected Financial Data - Five-Year Comparison," which information is incorporated herein by reference. System Energy. Refer to information under the heading "System Energy Resources, Inc. Selected Financial Data - Five-Year Comparison," which information is incorporated herein by reference. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Entergy Corporation. Refer to information under the heading "ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference. AP&L. Refer to information under the heading "ARKANSAS POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference. GSU. Refer to information under the heading "GULF STATES UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference. LP&L. Refer to information under the heading "LOUISIANA POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference. MP&L. Refer to information under the heading "MISSISSIPPI POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference. NOPSI. Refer to information under the heading "NEW ORLEANS PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference. System Energy. Refer to information under the heading "SYSTEM ENERGY RESOURCES, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference. Item 8. Financial Statements and Supplementary Data.
INDEX TO FINANCIAL STATEMENTS Entergy Corporation and Subsidiaries: Definitions Report of Management Audit Committee Chairman's Letter Independent Auditors' Report Consolidated Balance Sheets, December 31, 1993 and 1992 Statements of Consolidated Cash Flows For the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis Statements of Consolidated Income For the Years Ended December 31, 1993, 1992 and 1991 Statements of Consolidated Retained Earnings and Paid-In Capital for the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis (continued) Notes to Consolidated Financial Statements Selected Financial Data - Five-Year Comparison AP&L: Definitions Report of Management Audit Committee Chairman's Letter Independent Auditors' Report Balance Sheets, December 31, 1993 and 1992 Statements of Cash Flows For the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis Statements of Income For the Years Ended December 31, 1993, 1992 and 1991 Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis (continued) Notes to Financial Statements Selected Financial Data - Five-Year Comparison GSU: Definitions Report of Management Audit Committee Chairman's Letter Independent Auditors' Report Balance Sheets, December 31, 1993 and 1992 Statements of Cash Flows For the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis Statements of Income For the Years Ended December 31, 1993, 1992 and 1991 Statements of Retained Earnings and Paid-In Capital for the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis (continued) Notes to Financial Statements Selected Financial Data - Five-Year Comparison LP&L: Definitions Report of Management Audit Committee Chairman's Letter Independent Auditors' Report Balance Sheets, December 31, 1993 and 1992 Statements of Cash Flows For the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis Statements of Income For the Years Ended December 31, 1993, 1992 and 1991 Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis (continued) Notes to Financial Statements Selected Financial Data - Five-Year Comparison MP&L: Definitions Report of Management Audit Committee Chairman's Letter Independent Auditors' Report Balance Sheets, December 31, 1993 and 1992 Statements of Cash Flows For the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis Statements of Income For the Years Ended December 31, 1993, 1992 and 1991 Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis (continued) Notes to Financial Statements Selected Financial Data - Five-Year Comparison NOPSI: Definitions Report of Management Audit Committee Chairman's Letter Independent Auditors' Report Balance Sheets, December 31, 1993 and 1992 Statements of Cash Flows For the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis Statements of Income For the Years Ended December 31, 1993, 1992 and 1991 Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis (continued) Notes to Financial Statements Selected Financial Data - Five-Year Comparison System Energy: Definitions Report of Management Audit Committee Chairman's Letter Independent Auditors' Report Balance Sheets, December 31, 1993 and 1992 Statements of Cash Flows For the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis Statements of Income For the Years Ended December 31, 1993, 1992 and 1991 Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 Management's Financial Discussion and Analysis (continued) Notes to Financial Statements Selected Financial Data - Five-Year Comparison
Entergy Corporation and Subsidiaries 1993 Financial Statements ENTERGY CORPORATION AND SUBSIDIARIES DEFINITIONS Certain abbreviations or acronyms used in the Financial Statements, Notes to Financial Statements, and Management's Financial Discussion and Analysis are defined below: Abbreviation or Acronym Term AFUDC Allowance for Funds Used During Construction ANO Arkansas Nuclear One Steam Electric Generating Station ANO 2 Unit No. 2 of ANO AP&L Arkansas Power & Light Company APSC Arkansas Public Service Commission Council Council of the City of New Orleans, Louisiana Entergy or System Entergy Corporation and its various direct and indirect subsidiaries Entergy Enterprises Entergy Enterprises, Inc. (formerly Electec, Inc.) Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy Corporation that has operating responsibility for Grand Gulf 1, Waterford 3, ANO, and River Bend Entergy Power Entergy Power, Inc., a subsidiary of Entergy Corporation that markets capacity and energy for resale from certain generating facilities to other parties, principally non-affiliates FERC Federal Energy Regulatory Commission G&R Bonds General and Refunding Mortgage Bonds issued and issuable by MP&L and NOPSI Grand Gulf 1 Unit No. 1 of the Grand Gulf Steam Electric Generating Station Grand Gulf 2 Unit No. 2 of the Grand Gulf Steam Electric Generating Station GSU Gulf States Utilities Company (including wholly owned subsidiaries - Varibus Corporation, GSG&T, Inc., Prudential Oil and Gas, Inc., and Southern Gulf Railway Company) KWH Kilowatt-Hour(s) LP&L Louisiana Power & Light Company LPSC Louisiana Public Service Commission Merger The combination transaction, consummated on December 31, 1993, by which GSU became a subsidiary of Entergy Corporation and Entergy Corporation became a Delaware corporation MP&L Mississippi Power & Light Company MPSC Mississippi Public Service Commission 1991 NOPSI Settlement Agreement, retroactive to October 4, 1991, among NOPSI, the Council, the Alliance for Affordable Energy, Inc., and others that settled certain Grand Gulf 1 prudence issues and pending litigation related to the resolution (including the Determinations and Order referred to therein) adopted by the Council on February 4, 1988, disallowing NOPSI's recovery of $135 million of previously deferred Grand Gulf 1-related costs NOPSI New Orleans Public Service Inc. PUCT Public Utility Commission of Texas Rate Cap The level of GSU's retail electric base rates in effect at December 31, 1993, for the Louisiana retail jurisdiction, and the level in effect prior to the Texas Cities Rate Settlement for the Texas retail jurisdiction, that may not be exceeded for the five years following December 31, 1993 River Bend River Bend Steam Electric Generating Station (nuclear), owned 70% by GSU SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the Financial Accounting Standards Board SFAS 106 SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS No. 109, "Accounting for Income Taxes" System Agreement Agreement, effective January 1, 1983, as amended, among the System operating companies relating to the sharing of generating capacity and other power resources System Energy System Energy Resources, Inc. System Fuels System Fuels, Inc. System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively System or Entergy Entergy Corporation and its various direct and indirect subsidiaries Waterford 3 Unit No. 3 of the Waterford Steam Electric Generating Station ENTERGY CORPORATION AND SUBSIDIARIES REPORT OF MANAGEMENT The management of Entergy Corporation has prepared and is responsible for the financial statements and related financial information included herein. The financial statements are based on generally accepted accounting principles. Financial information included elsewhere in this report is consistent with the financial statements. To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls that is designed to provide reasonable assurance, on a cost-effective basis, as to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. This system includes communication through written policies and procedures, an employee Code of Conduct, 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. The independent public accountants provide an objective assessment of the degree to which 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 these policies and procedures provide reasonable assurance that its operations are carried out with a high standard of business conduct. /S/ EDWIN LUPBERGER /S/ GERALD D. MCINVALE EDWIN LUPBERGER GERALD D. MCINVALE Chairman and Chief Executive Officer Senior Vice President and Chief Financial Officer ENTERGY CORPORATION AND SUBSIDIARIES AUDIT COMMITTEE CHAIRMAN'S LETTER The Entergy Corporation Board of Directors' Audit Committee is comprised of five directors, who are not officers of Entergy Corporation: H. Duke Shackelford (Chairman), Brooke H. Duncan, Kaneaster Hodges, Jr., John N. Palmer, Sr., and Bismark A. Steinhagen (as of December 31, 1993). The committee held four meetings during 1993. The Audit Committee oversees Entergy Corporation's financial reporting process on behalf of Entergy Corporation's Board of Directors. In fulfilling its responsibility, the committee recommended to the board, subject to stockholder approval, the selection of Entergy Corporation's independent public accountants (Deloitte & Touche). Also, the committee oversees and coordinates the activities and policies of the subsidiary companies' audit committees. The Audit Committee discussed with Entergy's internal auditors and the independent public accountants the overall scope and specific plans for their respective audits, as well as Entergy Corporation's consolidated financial statements and the adequacy of Entergy Corporation's internal controls. The committee met, together and separately, with Entergy's internal auditors and independent public accountants, without management present, to discuss the results of their audits, their evaluation of Entergy Corporation's internal controls, and the overall quality of Entergy Corporation's financial reporting. The meetings also were designed to facilitate and encourage any private communication between the committee and the internal auditors or independent public accountants. /S/ H. DUKE SHACKELFORD H. DUKE SHACKELFORD Chairman, Audit Committee INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directors of Entergy Corporation We have audited the accompanying consolidated balance sheets of Entergy Corporation and subsidiaries as of December 31, 1993 and 1992, and the related statements of consolidated income, retained earnings and paid-in capital, and cash flows for each of the three years in the period ended December 31, 1993. 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 Gulf States Utilities Company (a consolidated subsidiary acquired on December 31, 1993), which statements reflect total assets constituting 31% of consolidated total assets at December 31, 1993. Those statements were audited by other auditors whose report (which included explanatory paragraphs regarding the uncertainties discussed in the fourth and fifth paragraphs below) has been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulf States Utilities Company, is based solely on the report of such other auditors. We conducted our audits in accordance with generally accepted auditing standards. 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 the other auditors provide a reasonable basis for our opinion. In our opinion, based on our audits and the report of the other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and subsidiaries at December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. The Corporation acquired a 70% interest in River Bend Unit I Nuclear Generating Plant (River Bend) through its acquisition of Gulf States Utilities Company on December 31, 1993. As discussed in Note 2 to the consolidated financial statements, the net amount of capitalized costs for River Bend exceed those costs currently being recovered through rates. At December 31, 1993, approximately $747 million is not currently being recovered through rates. If current regulatory and court orders are not modified, a write-off of all or a portion of such costs may be required. Additionally, as discussed in Note 2 to the consolidated financial statements, other rate-related contingencies exist which may result in a refund of revenues previously collected. The extent of such write-off of capitalized River Bend costs or refund of revenues previously collected, if any, will not be determined until appropriate rate proceedings and court appeals have been concluded. Accordingly, the accompanying consolidated financial statements do not include any adjustments that might result from the outcome of these uncertainties. As discussed in Note 8 to the consolidated financial statements, civil actions have been initiated against Gulf States Utilities Company to, among other things, recover the co-owner's investment in River Bend and to annul the related joint ownership participation and operating agreement. The ultimate outcome of these proceedings, including their impact on Gulf States Utilities Company, cannot presently be determined. Accordingly, the accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. As discussed in Note 1 to the consolidated financial statements, certain of the Corporation's subsidiaries changed their method of accounting for revenues in 1993 and, as discussed in Notes 3 and 10 to the consolidated financial statements, in 1993 the Corporation changed its methods of accounting for income taxes and postretirement benefits other than pensions, respectively. /S/ DELOITTE & TOUCHE DELOITTE & TOUCHE New Orleans, Louisiana February 11, 1994 ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS
December 31, ----------------------------- 1993 1992 ----------- ----------- (In Thousands) Utility Plant (Note 1): Electric $20,848,844 $13,765,029 Plant acquisition adjustment - GSU (Note 11) 380,117 - Electric plant under leases (Note 9) 663,024 662,400 Property under capital leases - electric 175,276 100,945 Natural gas 156,452 110,399 Steam products 75,689 - Construction work in progress 533,112 309,552 Nuclear fuel under capital leases (Note 9) 329,433 233,616 Nuclear fuel 17,760 20,683 ----------- ----------- Total 23,179,707 15,202,624 Less - accumulated depreciation and amortization 7,157,981 4,462,693 ----------- ----------- Utility plant - net 16,021,726 10,739,931 ----------- ----------- Other Property and Investments: Decommissioning trust funds 172,960 127,323 Other 183,597 76,558 ----------- ----------- Total 356,557 203,881 ----------- ----------- Current Assets: Cash and cash equivalents (Note 1): Cash 27,345 6,975 Temporary cash investments - at cost, which approximates market 536,404 372,817 ----------- ----------- Total cash and cash equivalents 563,749 379,792 Other temporary investments - at cost, which approximates market - 17,012 Special deposits 36,612 18,739 Notes receivable 17,710 19,778 Accounts receivable: Customer (less allowance for doubtful accounts of $8.8 million in 1993 and $6.2 million in 1992) 315,796 194,980 Other 81,931 43,006 Accrued unbilled revenues (Note 1) 257,321 57,716 Fuel inventory - at average cost and LIFO 110,204 85,595 Materials and supplies - at average cost 360,353 287,407 Rate deferrals (Note 2) 333,311 186,391 Prepayments and other 98,144 74,168 ----------- ----------- Total 2,175,131 1,364,584 ----------- ----------- Deferred Debits and Other Assets: Rate deferrals (Note 2) 1,876,051 1,485,598 SFAS 109 regulatory asset - net (Note 3) 1,385,824 - Long-term receivables 228,030 15,739 Unamortized loss on reacquired debt 210,698 91,825 Other 622,680 337,979 ----------- ----------- Total 4,323,283 1,931,141 ----------- ----------- TOTAL $22,876,697 $14,239,537 =========== =========== See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES
December 31, ---------------------------- 1993 1992 ---------- ----------- (In Thousands) Capitalization: Common stock, $.01 par value in 1993 and $5 par value in 1992: authorized 500,000,000 shares; issued and outstanding 231,219,737 shares in 1993; issued 175,137,392 shares in 1992 (Note 5) $2,312 $875,687 Paid-in capital 4,223,682 1,327,589 Retained earnings (Note 7) 2,310,082 2,062,188 Less - treasury stock (1,943 shares in 1992) (Note 5) - 54 ----------- ----------- Total common shareholders' equity 6,536,076 4,265,410 Subsidiary's preference stock (Note 5) 150,000 - Subsidiaries' preferred stock (Note 5): Without sinking fund 550,955 414,511 With sinking fund 349,053 304,049 Long-term debt (Notes 6 and 9) 7,355,962 5,149,344 ----------- ----------- Total 14,942,046 10,133,314 ----------- ----------- Other Noncurrent Liabilities: Obligations under capital leases (Note 9) 322,867 177,112 Other (Note 8) 270,318 140,292 ----------- ----------- Total 593,185 317,404 ----------- ----------- Current Liabilities: Currently maturing long-term debt (Note 6) 322,010 133,805 Notes payable (Note 4) 43,667 667 Accounts payable 413,727 313,054 Customer deposits 127,524 100,496 Taxes accrued 118,267 128,172 Accumulated deferred income taxes (Note 3) 44,637 43,265 Interest accrued 210,894 152,136 Dividends declared 13,404 15,172 Gas contract settlements - liability to customers - 55,998 Deferred revenue - gas supplier judgment proceeds 14,632 42,256 Deferred fuel cost 4,528 16,128 Obligations under capital leases (Note 9) 194,015 157,448 Other 240,471 90,149 ----------- ----------- Total 1,747,776 1,248,746 ----------- ----------- Deferred Credits: Accumulated deferred income taxes (Note 3) 3,858,337 1,612,947 Accumulated deferred investment tax credits (Note 3) 793,375 553,506 Deferred revenue - gas supplier judgment proceeds - 14,846 Other 941,978 358,774 ----------- ----------- Total 5,593,690 2,540,073 ----------- ----------- Commitments and Contingencies (Notes 2, 8, and 9) TOTAL $22,876,697 $14,239,537 =========== =========== See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS
For the Years Ended December 31, -------------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Operating Activities: Net income $551,930 $437,637 $482,032 Noncash items included in net income: Cumulative effect of a change in accounting principle (93,841) - - Change in rate deferrals/excess capacity - net 200,532 109,153 (7,342) Depreciation and decommissioning 443,550 424,958 398,864 Deferred income taxes and investment tax credits 17,669 118,562 194,830 Allowance for equity funds used during construction (8,049) (7,355) (7,921) Amortization of deferred revenues (42,470) (38,646) (36,310) Provision for estimated losses and reserves 20,832 (24,911) 21,576 Gain on sale of property - net - (19,612) - Changes in working capital: Receivables (40,682) (19,150) 5,655 Fuel inventory (1,161) 20,008 (37,917) Accounts payable (9,167) (54,559) 1,302 Taxes accrued (32,761) 28,561 41,085 Interest accrued (758) (10,845) (19,830) Other working capital accounts 51,100 (12,428) 18,821 Refunds to customers - gas contract settlement (56,027) (56,066) (56,098) Decommissioning trust contributions (20,402) (20,896) (23,193) Other 94,092 (43,185) (13,619) ---------- -------- -------- Net cash flow provided by operating activities 1,074,387 831,226 961,935 ---------- -------- -------- Investing Activities: Merger with GSU - cash paid (250,000) - - Merger with GSU - cash acquired 261,349 - - Construction/capital expenditures (512,235) (438,845) (439,087) Allowance for equity funds used during construction 8,049 7,355 7,921 Proceeds received from sale of property - 67,985 - Nuclear fuel purchases (118,216) (60,359) (66,068) Proceeds from sale/leaseback of nuclear fuel 121,526 62,332 47,452 Investment in nonregulated/nonutility properties (76,870) (35,189) (10,878) Decrease in other temporary investments 17,012 114,651 150,580 ---------- -------- -------- Net cash flow used in investing activities (549,385) (282,070) (310,080) ---------- -------- -------- Financing Activities: Proceeds from the issuance of: First mortgage bonds 605,000 637,114 - General and refunding mortgage bonds 350,000 65,000 - Preferred stock - 120,999 133,175 Bank notes and other long-term debt 106,070 48,067 68,514 Retirement of: First mortgage bonds (911,692) (1,009,320) (665,384) General and refunding mortgage bonds (99,400) - - Bank notes and other long-term debt (69,982) (17,412) (7,442) Common stock (20,558) (105,673) (161,640) Redemption of preferred stock (56,000) (109,369) (85,500) Common stock dividends paid (287,483) (256,117) (228,816) Changes in short-term borrowings 43,000 - - ---------- -------- -------- Net cash flow used in financing activities (341,045) (626,711) (947,093) ---------- -------- -------- Net increase (decrease) in cash and cash equivalents 183,957 (77,555) (295,238) Cash and cash equivalents at beginning of period 379,792 457,347 752,585 ---------- -------- -------- Cash and cash equivalents at end of period $563,749 $379,792 $457,347 ========== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $485,876 $570,199 $646,872 Income taxes $159,659 $125,079 $68,278 Noncash investing and financing activities: Capital lease obligations incurred $126,812 $75,040 $46,073 Merger with GSU - common stock issued $2,031,101 - - See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES Liquidity is important to Entergy due to the capital intensive nature of our business, which requires large investments in long-lived assets. However, large capital expenditures for the construction of new generating capacity are not currently planned. The System requires significant capital resources for the periodic maturity of certain series of debt and preferred stock. Net cash flow from operations totaled $1,074 million, $831 million, and $962 million in 1993, 1992, and 1991, respectively. In recent years, this cash flow, supplemented by cash on hand, has been sufficient to meet substantially all investing and financing requirements, including capital expenditures, dividends, and debt/preferred stock maturities. Entergy's ability to fund these capital requirements with cash from operations results, in part, from our continued efforts to streamline operations and reduce costs as well as collections under our Grand Gulf 1 rate phase-in plans, which exceed the current cash requirements for Grand Gulf 1-related costs. (In the income statement, these revenue collections are offset by the amortization of previously deferred costs, therefore, there is no effect on net income.) Further, Entergy Corporation's subsidiaries have the ability to meet future capital requirements through future debt or preferred stock issuances, as discussed below. See Note 8, incorporated herein by reference, for additional information on the System's capital and refinancing requirements in 1994 - 1996. Also, in order to take advantage of lower interest and dividend rates, Entergy Corporation's subsidiaries may continue to refinance high-cost debt and preferred stock prior to maturity. Productive investment of excess funds is necessary to enhance the long-term value of our common stock. In 1993, Entergy Corporation made approximately $77 million in investments in an electric distribution company and a high-voltage transmission system in Argentina. In 1992, Entergy Corporation invested $11 million in a generating facility in Argentina, $12.5 million in an independent power plant in Virginia, $5.5 million in a lighting efficiency services company, and $6.2 million in a company that develops energy management and other technology applications. Entergy Corporation expects to invest approximately $150 million per year in nonregulated and nonutility businesses. See "Significant Factors and Known Trends - Nonregulated Investments" for additional information. Certain agreements and restrictions limit the amount of mortgage bonds and preferred stock that can be issued by the System operating companies and System Energy. Based on the most restrictive applicable tests as of December 31, 1993 (which in certain instances, are impacted by the inclusion of the cumulative effect of the change in accounting principle for accruing unbilled revenues discussed in Note 1), and an assumed annual interest or dividend rate of 8%, the System operating companies could have issued bonds or preferred stock in the following amounts, respectively: AP&L - $226 million and $1,075 million; GSU - $425 million and $0 million; LP&L - $92 million and $686 million; MP&L - $219 million and $548 million; and NOPSI - $40 million and $306 million. System Energy could also have issued $290 million of bonds, but its charter does not presently provide for the issuance of preferred stock. In addition, the System operating companies and System Energy have the conditional ability to issue bonds against the retirement of bonds, in some cases without meeting an earnings coverage test. AP&L may also issue preferred stock to refund outstanding preferred stock without meeting an earnings coverage test. GSU has no limitations on the issuance of preference stock. See Note 4, incorporated herein by reference, for information on the System's short-term borrowings. Entergy Corporation's current primary capital requirements are to periodically invest in, or make loans to, its subsidiaries. Entergy Corporation expects to meet these requirements in 1994 - 1996 with internally generated funds and cash on hand. Further, Entergy Corporation paid $287.5 million of dividends on its common stock in 1993. Entergy Corporation receives funds through dividend payments from its subsidiaries. During 1993, these common stock dividend payments totaled $686.7 million. Certain restrictions may limit the amount of these distributions. See Note 7, incorporated herein by reference, for additional information. See Notes 2 and 8, incorporated herein by reference, regarding River Bend rate appeals and pending litigation with Cajun Electric Power Cooperative, Inc. (Cajun). Substantial write-offs or charges resulting from adverse rulings in these matters could adversely affect GSU's ability to continue to pay dividends. Entergy Corporation has SEC authorization to repurchase shares of its outstanding common stock. Market conditions and board authorization determine the amount of repurchases. Entergy Corporation has requested SEC authorization for a $300 million bank line of credit, the proceeds of which are expected to be used for common stock repurchases and other optional activities. See Notes 4 and 5, incorporated herein by reference, for additional information. ENTERGY CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME
For the Years Ended December 31, ----------------------------------------- 1993 1992 1991 ---------- ---------- ---------- (In Thousands, Except Share Data) Operating Revenues: Electric $4,394,346 $4,043,555 $3,974,478 Natural gas 90,991 72,944 76,951 ---------- ---------- ---------- Total 4,485,337 4,116,499 4,051,429 ---------- ---------- ---------- Operating Expenses: Operation: Fuel for electric generation and fuel-related expenses 859,641 759,470 735,986 Purchased power 278,070 228,679 205,131 Gas purchased for resale 52,592 43,212 49,986 Other 813,555 806,943 823,817 Maintenance 306,666 301,836 282,821 Depreciation and decommissioning 443,550 424,958 398,864 Taxes other than income taxes 199,151 197,895 184,247 Income taxes (Note 3) 251,163 210,081 243,760 Rate deferrals (Note 2): Rate deferrals (1,651) (24,176) (56,681) Amortization of rate deferrals 289,259 209,015 206,468 Deferral of previously incurred Grand Gulf 1-related costs - - (90,000) ---------- ---------- ---------- Total 3,491,996 3,157,913 2,984,399 ---------- ---------- ---------- Operating Income 993,341 958,586 1,067,030 ---------- ---------- ---------- Other Income: Allowance for equity funds used during construction 8,049 7,355 7,921 Miscellaneous - net 60,068 135,475 122,697 Income taxes (Note 3) (33,640) (46,382) (33,391) ---------- ---------- ---------- Total 34,477 96,448 97,227 ---------- ---------- ---------- Interest and Other Charges: Interest on long-term debt 488,799 529,668 599,797 Other interest - net 29,849 29,686 27,245 Allowance for borrowed funds used during construction (5,478) (5,094) (7,392) Preferred dividend requirements of subsidiaries 56,559 63,137 62,575 ---------- ---------- ---------- Total 569,729 617,397 682,225 ---------- ---------- ---------- Income before Cumulative Effect of a Change in Accounting Principle 458,089 437,637 482,032 Cumulative Effect to January 1, 1993, of Accruing Unbilled Revenues (net of income taxes of $57,188) (Note 1) 93,841 - - ---------- ---------- ---------- Net Income $551,930 $437,637 $482,032 ========== ========== ========== Earnings per average common share before cumulative effect of a change in accounting principle $2.62 $2.48 $2.64 Earnings per average common share $3.16 $2.48 $2.64 Dividends declared per common share (Note 7) $1.65 $1.45 $1.25 Average number of common shares outstanding (Note 5) 174,887,556 176,573,778 182,665,303 See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED RETAINED EARNINGS AND PAID-IN CAPITAL
For the Years Ended December 31, -------------------------------------- 1993 1992 1991 ---------- ---------- ---------- (In Thousands) Retained Earnings, January 1 $2,062,188 $1,943,298 $1,775,000 Add - Net income 551,930 437,637 482,032 ---------- ---------- ---------- Total 2,614,118 2,380,935 2,257,032 ---------- ---------- ---------- Deduct: Dividends declared on common stock 288,342 255,479 228,555 Common stock retirements (Note 5) 13,906 59,187 80,009 Capital stock and other expenses 1,788 4,081 5,170 ---------- ---------- ---------- Total 304,036 318,747 313,734 ---------- ---------- ---------- Retained Earnings, December 31 (Note 7) $2,310,082 $2,062,188 $1,943,298 ========== ========== ========== Paid-in Capital, January 1 $1,327,589 $1,357,883 $1,408,640 Add: Gain (loss) on reacquisition of subsidiaries' preferred stock (20) (1,323) 35 Issuance of 56,667,726 shares of common stock in the merger with GSU (Note 11) 2,027,325 - - Issuance of 174,552,011 shares of common stock at $.01 par value net of the retirement of 174,552,011 shares of common stock at $5.00 par value (Note 5) 871,015 - - ---------- ---------- ---------- Total 4,225,909 1,356,560 1,408,675 ---------- ---------- ---------- Deduct: Common stock retirements (Note 5) 4,389 28,127 49,391 Capital stock discounts and other expenses (2,162) 844 1,401 ---------- ---------- ---------- Total 2,227 28,971 50,792 ---------- ---------- ---------- Paid-in Capital, December 31 $4,223,682 $1,327,589 $1,357,883 ========== ========== ========== See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Consolidated net income increased in 1993 due primarily to the one-time recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1, incorporated herein by reference) and its ongoing effects. Effective January 1, 1993, AP&L, MP&L, and NOPSI began accruing as revenues the charges for energy delivered to customers but not yet billed. Electric and gas revenues were previously recorded on a cycle-billing basis. This increase was partially offset by the effects of implementing SFAS 109 and SFAS 106 (see Notes 3 and 10, respectively, incorporated herein by reference), and the impact in March 1992 of an after-tax gain from the sale of AP&L's Missouri properties. Excluding these items, net income for 1993 would have been $475.9 million and net income for 1992 would have been $418.0 million. This $57.9 million increase is due to increased retail energy sales, improved gas revenues, and decreased interest expense, partially offset by decreased miscellaneous income and by the impact of an August 1993 rate settlement involving System Energy's return on equity (see Note 2, incorporated herein by reference). Consolidated net income decreased in 1992 due primarily to reduced retail energy sales resulting from mild summer and winter temperatures. This decrease was partially offset by lower nonfuel operation and maintenance expenses (excluding nuclear refueling outage expenses of $87.9 million in 1992 and $61.8 million in 1991) and lower interest expense. In addition, 1992 net income includes $19.6 million from the gain on the sale of AP&L's retail properties in Missouri. Significant factors affecting the results of operations and causing variances between the years 1993 and 1992, and 1992 and 1991, are discussed under "Revenues and Sales," "Expenses," and "Other" below. Revenues and Sales See "Selected Financial Data - Five-Year Comparison," incorporated herein by reference, following the notes, for information on electric operating revenues by source and KWH sales. Electric operating revenues were higher in 1993 due primarily to increased residential and commercial energy sales resulting from a return to more normal weather as compared to milder weather in 1992, increased industrial sales primarily in the petrochemical, lumber, and plywood industries, and increased fuel adjustment revenues and collections of previously deferred Grand Gulf 1- related costs, neither of which affects net income. These increases were partially offset by the impact of a System Energy rate settlement. Electric operating revenues were higher in 1992 due primarily to an increase in fuel adjustment revenues and collections of previously deferred Grand Gulf 1 costs, neither of which affects net income. The increase in fuel adjustment revenues was due to increased gas generation resulting from scheduled nuclear refueling outages. Partially offsetting these higher revenues were decreased retail sales resulting from mild temperatures. Gas operating revenues increased in 1993 due primarily to an increase in gas rates and increased fuel adjustment revenues resulting from higher average per unit cost for gas purchased for resale. Expenses Fuel for electric generation and fuel-related expenses increased in 1993 due primarily to an increase in generation requirements resulting from increased energy sales as discussed in "Revenues and Sales" above and higher per unit costs for gas used for generation. Purchased power increased in 1993 due primarily to increased power purchased from nonassociated utilities due to changes in generation requirements for AP&L, LP&L, MP&L, and NOPSI, resulting primarily from changes in fuel-related costs and increased energy sales. Fuel expense and purchased power increased in 1992 as a result of the nuclear refueling outages. In addition to the increased fossil generation discussed in "Revenues and Sales" above, additional power was purchased from outside utilities in 1992. Gas purchased for resale increased in 1993 due to a higher average per unit cost for gas purchased while it declined in 1992 due primarily to a lower average per unit cost. Rate deferrals decreased in 1993 and 1992 due to the fact that as of October 1992, Grand Gulf 1-related costs are no longer being deferred. The amortization of rate deferrals increased in 1993 due primarily to the collection of more Grand Gulf 1-related costs from customers in 1993 as compared to 1992. Total income taxes increased in 1993 due primarily to higher pretax income, an increase in the federal income tax rate as a result of the Omnibus Budget Reconciliation Act of 1993, and the implementation of SFAS 109, partially offset by the impact of the March 1992 sale of AP&L's Missouri properties. Other Miscellaneous other income - net decreased in 1993 and increased in 1992 due primarily to the 1992 pretax gain of approximately $33.7 million from the sale of AP&L's retail properties in Missouri. Additionally, decreased interest income contributed to the 1993 decrease. Interest on long-term debt decreased in 1993 and 1992 due primarily to the continued refinancing of high-cost debt and debt reduction activities. ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Entergy Corporation-GSU Merger On December 31, 1993, Entergy completed the Merger and became one of the nation's largest electric utilities. With GSU as its fifth retail operating company, Entergy gains size, expanded market area, economies of scale, an additional nuclear unit (River Bend), and a more price-competitive fuel mix. Entergy estimates $850 million in fuel cost savings and $670 million in operation and maintenance expense savings over the next decade. It is possible that common shareholders may experience some dilution in earnings in the short term as a result of the Merger. However, Entergy Corporation believes that the Merger will be beneficial to common shareholders over the longer term, both in terms of the strategic benefits and the economies and efficiencies expected to be produced. For further information, see Notes 2 and 11, incorporated herein by reference. Competition Entergy welcomes competition in the electric energy business and believes that a more competitive environment should benefit our shareholders, customers, and employees. We also recognize that competition presents us with many challenges, and we have identified the following as our major competitive challenges. Retail and Wholesale Rate Issues Increasing competition in the utility industry brings an increased need to stabilize or reduce retail rates. The retail regulatory environment is shifting from traditional rate-base regulation to incentive rate regulation. Incentive rate and performance-based plans encourage efficiencies and productivity while permitting utilities to share in the results. The MPSC has approved a formula rate plan for MP&L, and GSU is implementing shared-savings plans as part of the Merger. In February 1994, the MPSC conducted a general review of MP&L's current rates and in March 1994, the MPSC issued a final order adopting a formula rate plan for MP&L that will allow for periodic small adjustments in rates based on a comparison of earned to benchmark returns and upon certain performance factors. The order also adopted previously agreed-upon stipulations of 1) a required return on equity of 11% and 2) certain accounting adjustments that result in a 4.3% ($28.1 million) reduction in MP&L's June 30, 1993, test-year operating revenues. The MPSC's order requires MP&L to file rates designed to provide for this reduction in operating revenues for the test year on or before March 18, 1994, to become effective for service rendered on or after March 25, 1994. See Note 2, incorporated herein by reference, for further information. In connection with the Merger, AP&L and MP&L agreed with their respective regulators not to request any general retail rate increases that would take effect before November 1998, with certain exceptions. NOPSI agreed with the Council to reduce its annual electric base rates by $4.8 million effective for bills rendered on or after November 1, 1993, and is operating under electric and gas base rate freezes through October 31, 1996. GSU agreed with the LPSC and PUCT to a five-year Rate Cap on retail electric rates, and to pass through to retail customers the fuel savings and a certain percentage of the nonfuel savings created by the Merger. See Note 2, incorporated herein by reference, for further information on Merger-related agreements. GSU's base rates will be reviewed by the LPSC during the first post-Merger earnings analysis, scheduled for mid-1994, for reasonableness of its return on equity. The PUCT will also review GSU's base rates in accordance with its Merger approval plan in mid-1994. Further, LP&L is scheduled for a review of its rates and rate structure by the LPSC upon expiration of LP&L's current rate freeze in March 1994. Under the same LPSC order, an approximate $46 million per year increase in LP&L's retail rates will also expire in March 1994. See Note 2, incorporated herein by reference, for additional information. Retail wheeling, a major industry issue which may require utilities to "wheel" or move power from third parties to their own retail customers, is evolving gradually. As a result, the retail market could become more competitive. In the wholesale rate area, FERC approved in 1992, with certain modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power to sell wholesale power at market-based rates and to provide to electric utilities "open access" to the System's transmission system (subject to certain requirements). GSU was later added to this filing. Various intervenors in the proceeding filed petitions for review with the United States Court of Appeals for the District of Columbia Circuit. FERC's order, once it takes effect, will increase marketing opportunities for the System, but will also expose the System to the risk of loss of load or reduced revenues due to competition with alternative suppliers. In light of the rate issues discussed above, Entergy is aggressively reducing costs to avoid potential earnings erosions that might result as well as to successfully compete by becoming a low-cost producer. To help minimize future costs, Entergy remains committed to least cost planning. In December 1992, AP&L, LP&L, MP&L, and NOPSI each filed a Least Cost Integrated Resource Plan (Least Cost Plan) with their respective retail regulators, and GSU is currently working with the PUCT regarding integrated resource planning. Integrated resource or least cost planning includes demand-side measures such as customer energy conservation and supply-side measures such as more efficient power plants. These measures are designed to delay the building of new power plants for the next 20 years. The System operating companies plan to periodically file Least Cost Plans. The Energy Policy Act of 1992 The Energy Policy Act of 1992 (Energy Act) is changing the transmission and distribution of electricity. This act encourages competition and affords us the opportunities, and the risks, associated with an open and more competitive market environment. The Energy Act increases competition in the wholesale energy market through the creation of exempt wholesale generators (EWGs). We are competing in this market through our independent power subsidiary, Entergy Power Development Corporation. The Energy Act also gives FERC the authority to order investor-owned utilities to provide transmission access to or for other utilities, including EWGs. In addition, the Energy Act allows utilities to own and operate foreign generation, transmission, and distribution facilities. See "Nonregulated Investments" below for further information. Litigation and Regulatory Proceedings See Note 2, incorporated herein by reference, for information on the possibility of material adverse effects on GSU's financial condition as a result of substantial write-offs and/or refunds in connection with outstanding appeals and remands regarding approximately $1.4 billion of abeyed company-wide River Bend plant costs and approximately $187 million of Texas retail jurisdiction deferred River Bend operating and carrying costs. See Note 2, incorporated herein by reference, for information with respect to possible write-offs and refunds by System Energy which may result from a decision issued by FERC. See Note 8, incorporated herein by reference, for information on pending litigation with Cajun concerning Cajun's ownership interest in River Bend and the possible material adverse effects on GSU's financial condition in the event that GSU is ultimately unsuccessful in this litigation. Nonregulated Investments Entergy continues to seek new opportunities to expand its electric energy business, including expansion into related nonutility businesses. These opportunities include new domestic ventures such as our subsidiary, Entergy Systems and Service, Inc. (Entergy SASI), the region's only full-service provider of energy-efficient lighting and related services; established ventures in Argentina; and planned investments in South America and China. These nonregulated businesses reduced consolidated net income by approximately $24 million in 1993. Entergy Corporation expects to invest approximately $150 million per year in nonregulated business opportunities. Entergy may finance any such expansion with cash on hand. Further, shareholder and/or regulatory approvals may be required for such acquisitions to take place. For information on Entergy Corporation's investments in Argentina, see "Management's Financial Discussion and Analysis - Liquidity and Capital Resources," incorporated herein by reference. ANO Matters Leaks in certain steam generator tubes at ANO 2 were discovered and repaired during outages in March and September 1992. During a mid-cycle outage in May 1993, a scheduled special inspection of certain steam generator tubing was conducted by Entergy Operations and additional repairs were made. The operations and power output of ANO 2 have not been adversely affected by these repairs and AP&L's budgeted maintenance expenditures were adequate to cover the cost of such repairs. Entergy Operations is taking steps at ANO 2 to reduce the number and severity of future tube cracks. Entergy Operations met with the Nuclear Regulatory Commission (NRC) in August 1993 to discuss such steps along with recent inspection findings and intervals between future inspections. The NRC concurred with Entergy Operations' proposal to operate ANO 2 with no further steam generator inspections until the next refueling outage, which is scheduled for the spring of 1994. 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: AP&L, GSU, LP&L, MP&L, NOPSI, System Energy, Entergy Operations, Entergy Power, Entergy Power Development Corporation, Entergy Richmond Power Corporation, Entergy Services, Inc., System Fuels, Entergy Enterprises, Entergy SASI, Entergy S.A., Entergy Argentina S.A., and Entergy Transener S.A. Because the acquisition of GSU was consummated on December 31, 1993, under the purchase method of accounting, GSU is included only in the December 31, 1993, consolidated balance sheet amounts. All references made to Entergy or System as of, and subsequent to, the Merger closing date include amounts and information pertaining to GSU as an Entergy company. All significant intercompany transactions have been eliminated. Entergy Corporation's utility subsidiaries maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications. Revenues and Fuel Costs The System operating companies accrue estimated revenues for energy delivered since the latest billings. However, prior to January 1, 1993, AP&L, GSU, MP&L, and NOPSI recognized electric and gas revenues when billed. To provide a better matching of revenues and expenses, effective January 1, 1993, AP&L, GSU, MP&L, and NOPSI adopted a change in accounting principle to provide for accrual of estimated unbilled revenues. The cumulative effect of this accounting change as of January 1, 1993 (excluding GSU), increased net income by $93.8 million, or $0.54 per share. Had this new accounting method been in effect during prior years, net income before the cumulative effect would not have been materially different from that shown in the accompanying financial statements. In accordance with an LPSC rate order, GSU recorded a deferred credit for $16.6 million for the January 1, 1993, amount of unbilled revenues. The System operating companies' rate schedules (except GSU's Texas rate schedules) include fuel adjustment clauses that allow either current recovery or deferrals of fuel costs until such costs are reflected in the related revenues. GSU's Texas retail rate schedules include a fixed fuel factor approved by the PUCT, which remains the same until changed as part of a general rate case or fuel reconciliation, or until the PUCT orders a reconciliation for any over or under collections of fuel cost. Utility Plant Utility plant is stated at original cost. The original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the utility plant is subject to liens of the subsidiaries' mortgage bond indentures. 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 utility plant and increases earnings, it is only realized in cash through depreciation provisions included in rates. The System operating companies' effective composite rates for AFUDC were 10.6% for 1993 and 10.8% for 1992 and 1991. Utility plant includes the portions of Grand Gulf 1 and Waterford 3 that were sold and are currently under lease. For financial reporting purposes, these sale and leaseback transactions are reflected as financing transactions. Depreciation is computed on the straight-line basis at rates based on the estimated service lives and costs of removal of the various classes of property. Depreciation provisions on average depreciable property approximated 3.0% in 1993, 1992, and 1991. Jointly-Owned Generating Stations Certain Entergy Corporation subsidiaries own undivided interests in several jointly-owned electric generating facilities and record the investments and expenses associated with these stations to the extent of their respective ownership percentages. As of December 31, 1993, the System's investment and accumulated depreciation in each of these generating stations were as follows:
Total Megawatt Accumulated Generating Stations Fuel Type Capability Ownership Investment Depreciation ------------------- --------- ---------- --------- ---------- ------------ (In Thousands) Grand Gulf Nuclear 1,143 90.00%* $3,449,068 $669,666 River Bend Unit 1 Nuclear 931 70.00% $3,056,464 $545,740 Independence Units 1 and 2 Coal 1,680 56.50% $ 543,659 $156,645 White Bluff Units 1 and 2 Coal 1,660 57.00% $ 398,644 $140,731 Roy S. Nelson Unit 6 Coal 550 70.00% $ 389,915 $134,877 Big Cajun 2 Unit 3 Coal 540 42.00% $ 219,911 $ 68,150
* Includes System Energy's ownership and leasehold interests in Grand Gulf 1 Income Taxes Entergy Corporation and its subsidiaries file a consolidated federal income tax return (excluding GSU prior to 1994). Income taxes are allocated to the System companies in proportion to their contribution to consolidated taxable income. SEC regulations require that no System company pay more taxes than it would have had a separate income tax return been filed. Deferred taxes are recorded for all temporary differences between book and taxable income. Investment tax credits are deferred and amortized based upon the average useful life of the related property in accordance with rate treatment. As discussed in Note 3, effective January 1, 1993, Entergy changed its accounting for income taxes to conform with SFAS 109. Reacquired Debt The premiums and costs associated with reacquired debt are being amortized over the life of the related new issuances, in accordance with ratemaking treatment. Cash and Cash Equivalents Entergy considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. SFAS 101 SFAS 101 specifies how an enterprise that ceases to meet the criteria for application of SFAS No. 71, "Accounting for Certain Types of Regulation," to all or part of its operations should report that event in its financial statements. GSU discontinued regulatory accounting principles for the wholesale jurisdiction and steam department, and the Louisiana deregulated portion of River Bend, during 1989 and 1991, respectively. Fair Value Disclosures The estimated fair value amounts of financial instruments have been determined by Entergy, using available market information and appropriate valuation methodologies. However, considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. In addition, gains or losses realized on financial instruments may be reflected in future rates and not accrue to the benefit of stockholders. Entergy considers the carrying amounts of 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. In addition, Entergy does not presently expect that performance of its obligations will be required in connection with certain off-balance sheet commitments and guarantees considered financial instruments. Due to this factor, and because of the related party nature of these commitments and guarantees, determination of fair value is not considered practicable. See Notes 5, 6, and 8 for additional fair value disclosure. NOTE 2. RATE AND REGULATORY MATTERS River Bend In May 1988, the PUCT granted GSU a permanent increase in annual revenues of $59.9 million resulting from the inclusion in rate base of approximately $1.6 billion of company-wide River Bend plant investment and approximately $182 million of related Texas retail jurisdiction deferred River Bend costs (Allowed Deferrals). In addition, the PUCT disallowed as imprudent $63.5 million of company-wide River Bend plant costs and placed in abeyance, with no finding of prudency, approximately $1.4 billion of company-wide River Bend plant investment and approximately $157 million of Texas retail jurisdiction deferred River Bend operating and carrying costs. The PUCT affirmed that the ultimate rate treatment of such amounts would be subject to future demonstration of the prudency of such costs. GSU and intervening parties appealed this order (Rate Appeal) and GSU filed a separate rate case asking that the abeyed River Bend plant costs be found prudent (Separate Rate Case). Intervening parties filed suit in district court to prohibit the Separate Rate Case. The district court's decision was ultimately appealed to the Texas Supreme Court which ruled in 1990 that the prudence of the purported abeyed costs could not be relitigated in a separate rate proceeding. Further, the Texas Supreme Court's decision stated that all issues relating to the merits of the original order of the PUCT, including the prudence of all River Bend-related costs, should be addressed in the Rate Appeal. In October 1991, the district court in the Rate Appeal issued an order holding that, while it was clear the PUCT made an error in assuming it could set aside $1.4 billion of the total costs of River Bend and consider them in a later proceeding, the PUCT, nevertheless, found that GSU had not met its burden of proof related to the amounts placed in abeyance. The court also ruled the Allowed Deferrals should not be included in rate base under a 1991 decision regarding El Paso Electric Company's similar deferred costs (El Paso Case). The court further stated that the PUCT erred in reducing GSU's deferred costs by $1.50 for each $1.00 of revenue collected under the interim rate increases authorized in 1987 and 1988. The court remanded the case to the PUCT with instructions as to the proper handling of the Allowed Deferrals. GSU's motion for rehearing was denied, and in December 1991, GSU filed an appeal of the October 1991 district court order. The PUCT also appealed the October 1991 district court order, which served to supersede the district court's judgment, rendering it unenforceable under Texas law. In August 1992, the court of appeals in the El Paso Case handed down its second opinion on rehearing modifying its previous opinion on deferred accounting. The court's second opinion concluded that the PUCT may lawfully defer operating and maintenance costs and subsequently include them in rate base, but that the Public Utility Regulatory Act prohibits such rate base treatment for deferred carrying costs. The court stated, however, its opinion would not preclude the recovery of deferred carrying costs. The August 1992 court of appeals opinion was appealed to the Texas Supreme Court where arguments were heard in September 1993. The matter is pending. In September 1993, the Texas Third District Court of Appeals (the Third District Court) remanded the October 1991 district court decision to the PUCT "to reexamine the record evidence to whatever extent necessary to render a final order supported by substantial evidence and not inconsistent with our opinion." The Third District Court specifically addressed the PUCT's treatment of certain costs, stating that the PUCT's order was not based on substantial evidence. The Third District Court also applied its most recent ruling in the El Paso Case to the deferred costs associated with River Bend. However, the Third District Court cautioned the PUCT to confine its deliberations to the evidence addressed in the original rate case. Certain parties to the case have indicated their position that, on remand, the PUCT may change its original order only with respect to matters specifically discussed by the Third District Court which, if allowed, would increase GSU's allowed River Bend investment, net of accumulated depreciation and related taxes, by approximately $48 million as of December 31, 1993. GSU believes that under the Third District Court's decision, the PUCT would be free to reconsider any aspect of its order concerning the abeyed $1.4 billion River Bend investment. GSU has filed a motion for rehearing asking the Third District Court to modify its order so as to permit the PUCT to take additional evidence on remand. The PUCT and other parties have also moved for rehearing on various grounds. The Third District Court has not yet ruled on any of these motions. As of December 31, 1993, the River Bend plant costs disallowed for retail ratemaking purposes in Texas, and the River Bend plant costs held in abeyance and the related cost deferrals totaled (net of taxes) approximately $14 million, $300 million (both net of depreciation), and $171 million, respectively. Allowed Deferrals were approximately $95 million, net of taxes and amortization, as of December 31, 1993. GSU estimates it has collected approximately $139 million of revenues as of December 31, 1993, as a result of the originally ordered rate treatment of these deferred costs. However, if the PUCT adopts the most recent decision in the El Paso Case, the possible refunds approximate $28 million as a result of the inclusion of deferred carrying costs in rate base for the period July 1988 through December 1990. However, if the PUCT reverses its decision to reduce GSU's deferred costs by $1.50 for each $1.00 of revenue collected under the interim rate increases authorized in 1987 and 1988, the potential refund of amounts described above could be reduced by an amount ranging from $7 million to $19 million. No assurance can be given as to the timing or outcome of the remands or appeals described above. Pending further developments in these cases, GSU has made no write-offs for the River Bend-related costs. Management believes, based on advice from Clark, Thomas & Winters, a Professional Corporation, legal counsel of record in the Rate Appeal, that it is reasonably possible that the case will be remanded to the PUCT, and the PUCT will be allowed to rule on the prudence of the abeyed River Bend plant costs. Rate Caps imposed by the PUCT's regulatory approval of the Merger could result in GSU being unable to use the full amount of a favorable decision to immediately increase rates; however, a favorable decision could permit some increases and/or limit or prevent decreases during the period the Rate Caps are in effect. At this time, management and legal counsel are unable to predict the amount, if any, of the abeyed and previously disallowed River Bend plant costs that ultimately may be disallowed by the PUCT. A net of tax write-off as of December 31, 1993, of up to $314 million could be required based on the PUCT's ultimate ruling. In prior proceedings, the PUCT has held that the original cost of nuclear power plants will be included in rates to the extent those costs were prudently incurred. Based upon the PUCT's prior decisions, management believes that its River Bend construction costs were prudently incurred and that it is reasonably possible that it will recover in rate base, or otherwise through means such as a deregulated asset plan, all or substantially all of the abeyed River Bend plant costs. However, management also recognizes that it is reasonably possible that not all of the abeyed River Bend plant costs may ultimately be recovered. As part of its direct case in the Separate Rate Case, GSU filed a cost reconciliation study prepared by Sandlin Associates, management consultants with expertise in the cost analysis of nuclear power plants, which supports the reasonableness of the River Bend costs held in abeyance by the PUCT. This reconciliation study determined that approximately 82% of the River Bend cost increase above the amount included by the PUCT in rate base was a result of changes in federal nuclear safety requirements and provided other support for the remainder of the abeyed amounts. There have been four other rate proceedings in Texas involving nuclear power plants. Investment in the plants ultimately disallowed ranged from 0% to 15%. Each case was unique, and the disallowances in each were made on a case-by-case basis for different reasons. Appeals of most, if not all, of these PUCT decisions are currently pending. The following factors support management's position that a loss contingency requiring accrual has not occurred, and its belief that all, or substantially all, of the abeyed plant costs will ultimately be recovered: 1. The $1.4 billion of abeyed River Bend plant costs have never been ruled imprudent and disallowed by the PUCT. 2. Sandlin Associates' analysis which supports the prudence of substantially all of the abeyed construction costs. 3. Historical inclusion by the PUCT of prudent construction costs in rate base. 4. The analysis of GSU's internal legal staff, which has considerable experience in Texas rate case litigation. Additionally, management believes, based on advice from Clark, Thomas & Winters, a Professional Corporation, legal counsel of record in the Rate Appeal, that it is probable that the deferred costs will be allowed. However, assuming the August 1992 court of appeals' opinion in the El Paso Case is upheld and applied to GSU and the deferred River Bend costs currently held in abeyance are not allowed to be recovered in rates as allowable costs, a net of tax write-off of up to $171 million could be required. In addition, future revenues based upon the deferred costs previously allowed in rate base could also be lost and no assurance can be given as to whether or not refunds (up to $28 million as of December 31, 1993) of revenue received based upon such deferred costs previously recorded will be required. See Note 11 for the accounting treatment of preacquisition contingencies, including a River Bend write-down. Merger-Related Rate Agreements In November 1993, Entergy Corporation, AP&L, MP&L, and NOPSI entered into separate settlement agreements whereby the APSC, MPSC, and Council agreed to withdraw from the SEC proceeding related to the Merger. In return, among other things, AP&L, MP&L, and NOPSI agreed that their retail ratepayers would be protected from (1) increases in the cost of capital resulting from risks associated with the Merger, (2) recovery of any portion of the acquisition premium or transactional costs associated with the Merger, (3) certain direct allocations of costs associated with GSU's River Bend nuclear unit, and (4) any losses of GSU resulting from resolution of litigation in connection with its ownership of River Bend. AP&L and MP&L agreed not to request any general retail rate increase that would take effect before November 1998, except, among other things, for increases associated with the Least Cost Plan, recovery of certain Grand Gulf 1-related costs, recovery of certain taxes, and force majeure (defined to include, among other things, war, natural catastrophes, and high inflation), and in the case of AP&L, excess capacity costs and costs related to the adoption of SFAS 106 that were previously deferred. MP&L also agreed that retail base rates under its proposed formula rate plan would not be increased above November 1, 1993, levels for a period of five years beginning November 9, 1993, (described below). NOPSI was required to reduce its annual electric base rates by $4.8 million effective for bills rendered on or after November 1, 1993, and to expense its SFAS 106 costs. Further, NOPSI's SFAS 106 expenses through October 31, 1996, will be allowed by the Council for purposes of evaluating the appropriateness of NOPSI's rates. The Council also agreed not to seek to disallow the first $3.5 million of costs incurred through October 31, 1993, in connection with the Least Cost Plan. The LPSC and the PUCT approved separate regulatory proposals that include the following elements: (1) a five-year Rate Cap on GSU's retail electric base rates in the respective states, except for force majeure (defined to include, among other things, war, natural catastrophes, and high inflation); (2) a provision for passing through to retail customers in the respective states the jurisdictional portion of the fuel savings created by the Merger; and (3) a mechanism for tracking nonfuel operation and maintenance savings created by the Merger. The LPSC regulatory plan provides that such nonfuel savings will be shared 60% by the shareholder and 40% by ratepayers during the eight years following the Merger. The LPSC plan requires regulatory filings each year by the end of May through 2001. The PUCT regulatory plan provides that such savings will be shared equally by the shareholder and ratepayers, except that the shareholder's portion will be reduced by $2.6 million per year on a total company basis in years four through eight. The PUCT plan also requires a series of regulatory filings, currently anticipated to be in June 1994, and February 1996, 1998, and 2001, to ensure that ratepayers' share of such savings be reflected in rates on a timely basis and requires Entergy Corporation to hold GSU's Texas retail customers harmless from the effects of the removal by FERC of a 40% cap on the amount of fuel savings GSU may be required to transfer to other Entergy operating companies under the FERC tracking mechanism (see below). On January 14, 1994, Entergy Corporation filed a request for rehearing of FERC's December 15, 1993, order approving the Merger requesting that FERC restore the 40% cap provision in the fuel cost protection mechanism. The matter is pending. FERC approved certain rate schedule changes to integrate GSU into the System Agreement. Certain commitments were adopted to provide reasonable assurance that the ratepayers of AP&L, LP&L, MP&L, and NOPSI will not be allocated higher costs, including, among other things, (1) a tracking mechanism to protect AP&L, LP&L, MP&L, and NOPSI from certain unexpected increases in fuel costs, (2) the distribution of profits from power sales contracts entered into prior to the Merger, (3) a methodology to estimate the cost of capital in future FERC proceedings, and (4) a stipulation that AP&L, LP&L, MP&L, and NOPSI will be insulated from certain direct effects on capacity equalization payments should GSU, due to a finding of imprudent GSU management prior to the Merger, be required to purchase Cajun's 30% share in River Bend (see Note 8). Incentive Rate Plan In July 1993, the MPSC ordered MP&L to file a formulary incentive rate plan designed to allow for periodic small adjustments in rates based upon a comparison of earned to benchmark returns and upon performance factors incorporated in the plan. In November 1993, MP&L filed a formula rate plan (Proposed Plan) with the MPSC to become effective on March 1, 1994, with any initial adjustment to base rates in June 1994. Under the Proposed Plan, a formula would be established under which MP&L's earned rate of return would be calculated automatically every 12 months and compared to a benchmark rate of return, which would be calculated under a separate formula within the Proposed Plan. If MP&L's earned rate of return falls within a bandwidth around the benchmark rate of return, there would be no adjustment in rates. If MP&L's earnings are above the bandwidth, the Proposed Plan would automatically reduce MP&L's base rates. Alternatively, if MP&L's earnings are below the bandwidth, the Proposed Plan would automatically increase MP&L's base rates (subject to the five-year cap described above under "Merger-Related Rate Agreements"). The reduction or increase in base rates would be an amount representing 50% of the difference between the earned rate of return and the nearest limit of the bandwidth. In no event would the annual adjustment in rates exceed the lesser of 2% of MP&L's aggregate retail revenues, or $14.5 million. Under the Proposed Plan, the benchmark rate of return, and consequently the bandwidth, would be adjusted slightly upward or downward based upon MP&L's performance on three performance factors: customer reliability, customer satisfaction, and customer price. Subsequently, the MPSC conducted a general review of MP&L's current rates and later issued a final order adopting the Proposed Plan and previously agreed- upon stipulations of 1) a required return on equity of 11% and 2) certain accounting adjustments that result in a 4.3% ($28.1 million) reduction in MP&L's June 30, 1993, test-year base revenues. The MPSC's order requires MP&L to file rates designed to provide for this reduction in operating revenues for the test year on or before March 18, 1994, to become effective for service rendered on or after March 25, 1994. LPSC Investigation In response to a preliminary report of the LPSC indicating that the rates of return on equity of several electric utilities subject to the LPSC's jurisdiction may be too high, GSU provided the LPSC with information GSU believes supports the current rate level. In September 1993, the LPSC deferred review of GSU's base rates until the first post-Merger earnings analysis is filed in accordance with the LPSC Merger approval (scheduled for mid-1994). Recognizing that LP&L is subject to a rate freeze until March 1994, the LPSC requested LP&L to explain its "relatively high cost of debt" compared to other electric utilities subject to LPSC jurisdiction. LP&L responded to this request, and in an August 1993 report to the LPSC, the LPSC's legal consultants acknowledged LP&L's rationale for its cost of debt in comparison to two other utilities subject to the LPSC's jurisdiction. Further, the legal consultants suggested that certain aspects of the LP&L cost of debt could be taken up in any rate proceeding after the expiration of LP&L's rate freeze in March 1994. In October 1993, the LPSC approved a schedule to conduct a review of LP&L's rates and rate structure upon the expiration of LP&L's current rate freeze. FERC Audit In December 1990, FERC Division of Audits issued a report for System Energy for the years 1986 through 1988. The report recommended that System Energy (1) write off, and not recover in rates, approximately $95 million of Grand Gulf 1 costs included in utility plant related to certain System income tax allocation procedures alleged to be inconsistent with FERC's accounting requirements, and (2) compute refunds for the years 1987 to date to correct for resulting overcollections from AP&L, LP&L, MP&L, and NOPSI. In August 1992, FERC issued an opinion and order (August 4 Order) which found that System Energy overstated its Grand Gulf 1 utility plant account by approximately $95 million as indicated in FERC's report. The order required System Energy to make adjusting accounting entries and refunds, with interest, to AP&L, LP&L, MP&L, and NOPSI within 90 days from the date of the order. System Energy filed a request for rehearing, and in October 1992, FERC issued an order allowing additional time for its consideration of the request. In addition, it deferred System Energy's refund obligation until 30 days after FERC issues an order on rehearing. Assuming AP&L, LP&L, MP&L, and NOPSI are required to refund or credit to their customers all of the System Energy refund (except for those portions attributable to AP&L's and LP&L's retained share of Grand Gulf 1 costs), implementation of the August 4 Order would result in a reduction in Entergy's consolidated net income of approximately $146.4 million as of December 31, 1993. However, this reduction could be partially offset by: (1) the write-off by AP&L, LP&L, MP&L, and NOPSI of unamortized balances of corresponding deferred credits (approximately $66.7 million as of December 31, 1993), and (2) any recovery from ratepayers of deferred credits that have been previously amortized and passed on to ratepayers (approximately $24.4 million as of December 31, 1993). The amount of such recovery would depend on the associated retail rate treatment. System Energy believes that its consolidated income tax accounting procedures and related rate treatment are in compliance with SEC and FERC requirements and is vigorously contesting this issue. The ultimate resolution of this matter cannot be predicted. If the August 4 Order is implemented, System Energy needs the consent of certain banks to temporarily waive the fixed charge coverage and equity ratio covenants in the letters of credit and reimbursement agreement related to the Grand Gulf 1 sale and leaseback transaction (see Notes 6 and 9). System Energy has obtained the consent of the banks to waive these covenants, for the 12-month period beginning with the earlier of the write-off or the first refund, if the August 4 Order is implemented prior to December 31, 1994. The waiver is conditioned upon System Energy not paying any common stock dividends to Entergy Corporation until the equity ratio covenant is once again met. Absent a waiver, System Energy's failure to perform these covenants could cause a draw under the letters of credit and/or early termination of the letters of credit. If the letters of credit were not replaced in a timely manner, a default or early termination of System Energy's leases could result. Texas Cities Rate Settlement In June 1993, 13 cities within GSU's Texas service area instituted an investigation to determine whether GSU's current rates were justified. In October 1993, the general counsel of the PUCT instituted an inquiry into the reasonableness of GSU's rates. In November 1993, a settlement agreement was filed with the PUCT which provides for an initial reduction in GSU's annual retail base revenues in Texas of approximately $22.5 million effective for electric usage on or after November 1, 1993, and a second reduction of $20 million to be effective September 1994. Further, the settlement provided for GSU to reduce rates with a $20 million one-time bill credit in December 1993, and to refund approximately $3 million to Texas retail customers on bills rendered in December 1993. The cities' rate inquiries had been settled earlier on the same terms. In November 1993, in association with the settlement of the above-described rates inquiries, GSU entered into a settlement covering issues related to a March 1991 non-unanimous settlement in another proceeding. Under this settlement, a $30 million rate increase approved by the PUCT in March 1991 became final, and the PUCT's treatment of GSU's federal tax expense was settled, eliminating the possibility of refunds associated with amounts collected resulting from the disputed tax calculation. In December 1993, a large industrial customer of GSU announced its intention to oppose the settlement of the PUCT rate inquiry. The customer's opposition does not affect the cities' rate settlement. The customer's opposition requires the PUCT to conduct a hearing concerning GSU's rates charged in areas outside the corporate limits of the cities in its Texas service territory to determine whether the settlement's rates are just and reasonable. A hearing has been set for July 8, 1994. GSU believes that the PUCT will ultimately approve the settlement, but no assurance can be provided in this regard. Rate Deferrals The System operating companies have various rate moderation or phase-in plans that reduced the immediate effect of Grand Gulf 1, River Bend, and Waterford 3 costs on ratepayers. Under these plans, certain costs are either retained permanently (and not recovered from ratepayers), deferred in early years and collected in later years, or recovered currently from customers. These plans vary in the proportions of costs each company retains, defers, or recovers and in the length of the deferral/recovery periods. Only those costs retained permanently and not recovered through rates or through sales to third parties result in a reduction of net income. The carrying charges associated with unamortized deferrals are either deferred or recovered currently from customers. The 1991 NOPSI Settlement provided for a finalized phase-in plan for the increased recovery of NOPSI's Grand Gulf 1-related costs over a 10-year period and for a five-year base rate freeze (subject to certain exceptions) with respect to non-Grand Gulf 1 electric rates. In 1991, NOPSI recorded on its balance sheet a $90 million deferred asset of previously incurred but unrecovered Grand Gulf 1-related costs, with a corresponding pretax gain on the income statement. This gain increased 1991 consolidated net income by $48.6 million after taxes. GSU deferred approximately $369 million of River Bend operating costs, purchased power costs, and accrued carrying charges pursuant to a 1986 PUCT accounting order. Approximately $182 million of these costs are being amortized over a 20-year period and the remaining $187 million are not being amortized pending the ultimate outcome of the Rate Appeal. As of December 31, 1993, the unamortized balance of these costs was $330.3 million. Further, GSU deferred approximately $400 million of similar costs pursuant to a 1986 LPSC accounting order. These costs, of which approximately $160.4 million are unamortized as of December 31, 1993, are being amortized over a 10-year period. Previous rate orders of the LPSC have been appealed, and pending resolution of various appellate proceedings, GSU has made no write-off for the disallowance of $30.6 million of deferred revenue requirement, related to GSU's Louisiana phase-in plan, recorded for the period December 1987 through February 1988. AP&L's permanently retained share of Grand Gulf 1 costs (stated as a percentage of System Energy's 90% owned and leased share of Grand Gulf 1) ranges from 5.67% in 1989 to 7.92% in 1994 and all succeeding years of the unit's commercial operation. In the event AP&L 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 energy cost, which is currently less than AP&L's cost of such energy. LP&L permanently absorbs 18% of its 14% (approximately 2.52%) FERC-allocated share of Grand Gulf 1-related costs. LP&L is able to recover through the fuel adjustment clause 4.6 cents per KWH (currently 2.55 cents per KWH through May 1994) for the energy related to its retained portion of these costs. Alternatively, LP&L may sell such energy to nonaffiliated parties at prices above the fuel adjustment clause recovery amount, subject to LPSC approval. For the year ended December 31, 1993, System Energy's billings for Grand Gulf 1-related costs totaled approximately $650 million. A deregulated asset plan representing an unregulated portion (approximately 22%) of River Bend (plant costs, generation, revenues, and expenses) was established pursuant to a January 1992 LPSC order. The plan allows GSU to sell such generation to Louisiana retail customers at 4.6 cents per KWH or off-system at higher prices with certain sharing provisions for such incremental revenue. FERC Settlements In September 1991, FERC approved a settlement among AP&L, LP&L, MP&L, and NOPSI and various state and local regulatory authorities which (1) required credits from System Energy to AP&L, LP&L, MP&L, and NOPSI of approximately $48 million, (2) increased System Energy's decommissioning collections, and (3) reduced the allowed rate of return on common equity under the System Agreement and for System Energy from 14% to 13%. As a result of the settlement, 1991 consolidated net income was reduced by approximately $30 million. Pursuant to a subsequent settlement in another proceeding, the allowed rate of return was further reduced to 11% effective November 3, 1992. Refunds from this settlement reduced 1993 consolidated revenues and net income by approximately $27.2 million and $16.8 million, respectively. NOTE 3. INCOME TAXES Effective January 1, 1993, the System adopted SFAS 109 (excluding GSU which recorded the adoption effective January 1, 1990). This new standard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that deferred tax balances be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 requires that regulated enterprises recognize adjustments resulting from implementation as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. A substantial majority of the adjustments required by SFAS 109 was recorded to deferred tax balance sheet accounts with offsetting adjustments to regulatory assets and liabilities. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. As a result of the adoption of SFAS 109, 1993 net income and earnings per share were decreased by $13.2 million and $0.08 per share, respectively, and assets and liabilities were increased by $822.7 million and $835.9 million, respectively. Income tax expense consisted of the following:
For the Years Ended December 31, -------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Current: Federal $236,513 $ 99,898 $ 64,111 State 30,618 23,596 13,158 -------- -------- -------- Total 267,131 123,494 77,269 -------- -------- -------- Deferred - net: Reclassification due to net operating (17,131) 35,969 (22,516) loss carryforward Rate deferrals - net (88,651) (54,079) (3,248) Gas contract settlement 9,513 15,180 15,342 Liberalized depreciation 116,513 107,976 116,266 Unbilled revenue 56,315 (18,902) 6,633 Alternative minimum tax (10,270) 6,577 16,019 Bond reacquisition cost 17,958 11,496 (1,256) Nuclear refueling and maintenance (7,929) 9,740 484 Decontamination and decommissioning 27,303 - - fund Other 15,035 (1,595) (6,465) -------- -------- -------- Total 118,656 112,362 121,259 -------- -------- -------- Investment tax credit adjustments - net (43,796) 20,607 78,623 -------- -------- -------- Recorded income tax expense $341,991 $256,463 $277,151 ======== ======== ======== Charged to operations $251,163 $210,081 $243,760 Charged to other income 33,640 46,382 33,391 Charged to cumulative effect 57,188 - - -------- -------- -------- Recorded income tax expense 341,991 256,463 277,151 Income taxes applied against the debt - 696 886 component of AFUDC -------- -------- -------- Total income taxes $341,991 $257,159 $278,037 ======== ======== ========
Total income taxes differ from the amounts computed by applying the statutory federal income tax rate to income before taxes. The reasons for the differences were:
For the Years Ended December 31 ------------------------------------------------------ 1993 1992 1991 --------------- ------------------ --------------- % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income -------- ------ -------- ------- -------- ------- (Dollars in Thousands) Computed at statutory rate $332,555 35.0 $257,461 34.0 $279,395 34.0 Increases (reductions) in tax resulting from: Amortization of excess deferred income taxes (7,063) (0.7) (6,537) (0.9) (7,318) (0.9) State income taxes net of federal income tax effect 30,160 3.2 26,057 3.5 23,741 2.9 Amortization of investment tax credits (25,911) (2.7) (26,885) (3.6) (22,470) (2.7) Depreciation 5,925 0.6 4,527 0.6 5,693 0.7 SFAS 109 adjustment 9,547 1.0 - - - - Other - net (3,222) (0.4) 1,840 0.3 (1,890) (0.2) -------- ----- -------- ----- -------- ----- Recorded income tax expense 341,991 36.0 256,463 33.9 277,151 33.8 Income taxes applied against debt component of AFUDC - - 696 0.1 886 0.1 -------- ----- -------- ----- -------- ----- Total income taxes $341,991 36.0 $257,159 34.0 $278,037 33.9 ======== ===== ======== ===== ======== =====
Significant components of net deferred tax liabilities as of December 31, 1993, were (in thousands): Deferred tax liabilities: Net regulatory assets $(1,676,161) Plant related basis differences (2,945,933) Rate deferrals (767,124) Other (167,478) ----------- Total $(5,556,696) =========== Deferred tax assets: Sale and leaseback $ 241,391 Accumulated deferred investment tax credit 330,852 Alternative minimum tax credit 138,063 Removal cost 92,618 Standard coal plant 30,165 NOL carryforwards 307,737 Pension related items 24,879 Unbilled revenues 23,587 Investment tax credit carryforwards 314,862 Other 149,568 ----------- Total $ 1,653,722 =========== Net deferred tax liabilities $(3,902,974) =========== As of December 31, 1993, Entergy had federal net operating loss (NOL) carryforwards of $790.3 million and state NOL carryforwards of $561.4 million related to GSU operations. Investment tax credit (ITC) and other credit carryforwards as of December 31, 1993, amounted to $357.4 million. The ITC carryforwards include the 35% reduction required by the Tax Reform Act of 1986 and may be applied against federal income tax liabilities and, if not utilized, will expire in 1995 through 2005. It is currently anticipated that approximately $15.2 million will expire unutilized. A valuation allowance has been provided for that amount. Entergy's consolidated tax allocation reflects ITC carryforwards as of December 31, 1993. The allocation does not reflect any NOL carryforwards for the System. However, due to the current method of allocating taxes between subsidiaries, some companies have the tax effect of NOL carryforwards recorded on their separate company books. The alternative minimum tax (AMT) credit carryforwards as of December 31, 1993, were $138.1 million. This AMT credit can be carried forward indefinitely and will reduce the System's federal income tax liability in the future. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized AP&L, LP&L, MP&L, NOPSI, and System Energy to effect short-term borrowings up to an aggregate of $518 million, subject to increase to as much as $865 million (subject to individual authorizations for each company) after further SEC approval. These authorizations are effective through November 30, 1994. Short-term borrowings by MP&L and NOPSI are also limited by the terms of their respective G&R Bond indentures to amounts not exceeding the greater of 10% of capitalization or 50% of Grand Gulf 1 rate deferrals available to support the issuance of G&R Bonds. As of December 31, 1993, AP&L, GSU, LP&L, and MP&L had unused lines of credit for short-term borrowings of $197.6 million from banks within their service territories. Included in this amount for GSU was a $100 million bank credit agreement which expired on March 2, 1994. In addition, AP&L, LP&L, MP&L, NOPSI, System Energy, Entergy Operations, Entergy Services, Inc., and System Fuels can borrow from each other and from Entergy Corporation through the System money pool, an intra-System borrowing arrangement designed to reduce the System's dependence on external short-term borrowings (Money Pool). A filing was made with the SEC on January 4, 1994, requesting authorization for GSU to participate in the Money Pool and enter into new bank lines of credit and commercial paper arrangements. The filing requested a borrowing authorization of $125 million, subject to increase to a maximum amount of $455 million after further SEC approval. Entergy Corporation has a short-term line of credit, expiring September 17, 1994, for $43 million (all of which was outstanding as of December 31, 1993). Entergy Corporation has requested SEC approval for a $300 million three-year bank line of credit. System Fuels has financing agreements totaling $65 million (none of which was outstanding as of December 31, 1993). These are restricted as to use, and are secured by fuel inventories and certain accounts receivable from the sales of these inventories. NOTE 5. PREFERRED, PREFERENCE, AND COMMON STOCK The number of shares and dollar value of the System operating companies' (excluding GSU in 1992) preferred and preference stock was:
As of December 31, -------------------------------------------- Shares Call Price Per Authorized and Total Share as of Outstanding Dollar Value December 31, 1993 1992 1993 1992 1993 --------- -------- -------- -------- --------------- (Dollars in Thousands) Preferred Stock Without sinking fund: Cumulative, $100 par value 4.16% - 5.56% Series 1,201,715 1,070,106 $120,172 $107,011 $102.50 to $108.00 6.08% - 8.56% Series 2,262,829 1,380,000 226,283 138,000 $101.80 to $103.78 9.16% - 11.48% Series 425,000 75,000 42,500 7,500 $104.06 to $104.64 Cumulative, $25 par value 8.00% - 9.68% Series 3,880,000 3,880,000 97,000 97,000 $26.56 Cumulative, $0.01 par value $2.40 Series (1)(2) 2,000,000 2,000,000 50,000 50,000 - $1.96 Series (1)(2) 600,000 600,000 15,000 15,000 - ---------- ---------- -------- -------- Total without sinking fund 10,369,544 9,005,106 $550,955 $414,511 ========== ========== ======== ======== With sinking fund: Cumulative, $100 par value 7.00% - 9.76% Series 2,126,539 1,835,000 $212,654 $183,500 $100.00 to $106.75 10.60% - 12.92% Series 67,700 137,700 6,770 13,770 $104.09 to $106.00 15.44% - 16.16% Series 49,495 79,495 4,950 7,950 $107.72 Adjustable, 7.10% - 7.15% as of December 31, 1993 553,500 - 55,350 - $100.00 to $103.00 Cumulative, $25 par value 9.92% - 12.64% Series 2,311,666 2,931,666 57,791 73,291 $26.34 to $27.37 13.12% - 15.20% Series 461,537 1,021,537 11,538 25,538 $26.64 to $28.22 ---------- ---------- -------- -------- Total with sinking fund 5,570,437 6,005,398 $349,053 $304,049 ========== ========== ======== ======== Preference Stock Cumulative, without par value 7% Series (1)(2) 6,000,000 - $150,000 $ - - ========== ========== ======== ========
(1) The total dollar value represents the involuntary liquidation value of $25 per share. (2) These series are not redeemable as of December 31, 1993. The fair value of the System operating companies' (excluding GSU in 1992) preferred and preference stock with sinking fund was estimated to be approximately $526.2 million and $333.6 million as of December 31, 1993 and 1992, respectively. The fair value was determined using quoted market prices or estimates from nationally recognized investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. As of December 31, 1993, the System operating companies had 8,292,023, 13,798,915, and 12,400,000 shares of cumulative, $100, $25, and $0.01 par value preferred stock, respectively, and 14,000,000 shares of preference stock without par value, that were authorized but unissued. On February 4, 1994, MP&L amended its charter to authorize 1,500,000 additional shares of $100 par value preferred stock. Changes in the preferred stock of AP&L, LP&L, MP&L, and NOPSI, with and without sinking fund, during the last three years were: Number of Shares -------------------------------------- 1993 1992 1991 ----------- ---------- ------------ Preferred Stock Issuances: $100 par value - 700,000 350,000 $25 par value - 1,480,000 2,000,000 $0.01 par value - 600,000 2,000,000 Preferred Stock Retirements: $100 par value (265,000) (589,940) (530,060) $25 par value (1,180,000) (1,895,160) (1,300,000) Cash sinking fund requirements for the next five years for preferred stock outstanding as of December 31, 1993, are (in millions): 1994 - $37.6, 1995 - $36.1, 1996 - $28.1, 1997 - $25.9, and 1998 - $15.6. On December 31, 1993, Entergy Corporation issued 56,667,726 shares of common stock in connection with the Merger. In addition, Entergy Corporation redeemed 174,552,011 shares of $5.00 par value common stock and reissued 174,552,011 shares of $0.01 par value common stock resulting in an increase in paid-in capital of $871 million. Entergy Corporation has SEC authorization to repurchase, through December 31, 1994, up to 27.1 million shares of its outstanding common stock, either on the open market or through negotiated purchases or tender offers. Stock repurchases are made from time to time depending upon market conditions and authorization of the Entergy Corporation board. Under this program, Entergy Corporation repurchased and retired (returned to authorized but unissued status) 3,671,900 shares and 6,447,900 shares, at a cost of $161.6 million and $105.7 million during 1992 and 1991, respectively. In addition, 1,943 shares of treasury stock were purchased during 1992 at a cost of $54,263. During 1993, 627,000 shares of treasury stock were purchased at a cost of $20.6 million. A portion of these treasury shares were subsequently reissued and in connection with the Merger on December 31, 1993, all of the existing balance of 579,274 shares of treasury shares was canceled. Entergy Corporation has SEC authorization to acquire, through December 31, 1994, up to 3,000,000 shares of its common stock to be held as treasury shares, and to be reissued to meet the requirements of the Stock Plan for Outside Directors (Directors Plan), the Equity Ownership Plan of Entergy Corporation and Subsidiaries (Equity Plan), and certain other stock benefit plans. The Directors Plan awards nonemployee directors a portion of their compensation in the form of a fixed number of shares of Entergy Corporation common stock. Shares awarded under the Directors Plan were 12,550, 14,904, and 7,000 during 1993, 1992, and 1991, respectively. The Equity Plan grants stock options, restricted shares, and equity awards to key employees of the System companies. The costs of awards are charged to income over the period of the grant or restricted period, as appropriate. Amounts charged to compensation expense in 1993 were immaterial. Stock options, which comprise 50% of the shares targeted for distribution under the Equity Plan, are granted at exercise prices not less than market value on the date of grant. The options are generally exercisable no less than six months or more than 10 years after the date of grant. Nonstatutory stock options transactions are summarized as follows: Option Price Number of Options ------------ ----------------- Options granted during 1992 29.625 50,000 Options exercised during 1992 29.625 (5,000) Options granted during 1993 34.75 62,500 39.75* 6,107 Options exercised during 1993 29.625 (8,198) ------- Options remaining as of December 31, 1993 105,409 ======= * Options are not currently exercisable at December 31, 1993. During 1993, Entergy Corporation received SEC approval for the Employee Stock Investment Plan (ESIP) which will become effective in March 1994. Entergy Corporation received SEC authorization to issue new shares or acquire, through March 31, 1997, up to 2,000,000 shares of its common stock to be held as treasury shares, and to be reissued to meet the requirements of the ESIP. Under the ESIP, employees may be granted the opportunity to purchase (up to 10% of regular pay) common stock at 85% of the market value on the first or last business day of the plan year, whichever is lower. The 1994 plan year will run from April 1, 1994, to March 31, 1995. NOTE 6. LONG -TERM DEBT The long-term debt of Entergy Corporation's subsidiaries (excluding GSU in 1992) as of December 31, 1993 and 1992, was:
Maturities Interest Rates From To From To 1993 1992 ---- ---- ----- ---- ---------- ---------- (In Thousands) First Mortgage Bonds 1993 1998 4-5/8% 14%* $1,354,810 $ 990,410 1999 2003 6% 11% 1,143,520 861,220 2004 2008 6.65% 10% 635,000 282,767 2014 2018 9-5/8% 11-3/8% 90,319 160,319 2019 2024 7% 10-3/8% 1,083,818 588,550 G&R Bonds 1993 1998 5.95% 14.95%** 284,200 383,600 1999 2023 6-5/8% 8.65% 350,000 - Governmental Obligations *** 1992 2008 6.125% 10% 139,009 115,383 2009 2023 5.95% 12.5% 1,481,678 963,382 Debentures - Due 1998, 9.72% 200,000 - Long-Term DOE Obligation (Note 8) 101,029 97,959 Waterford 3 Lease Obligation, 8.76% (Note 9) 353,600 353,600 Grand Gulf Lease Obligation, 7.02% (Note 9) 500,000 500,000 Other Long-Term Debt 6,879 21,737 Unamortized Premium and Discount - Net (45,890) (35,778) ---------- ---------- Total Long-Term Debt 7,677,972 5,283,149 Less Amount Due Within One Year 322,010 133,805 ---------- ---------- Long-Term Debt Excluding Amount Due Within One Year $7,355,962 $5,149,344 ========== ==========
* The 14% series of $200 million is due 11/15/94. All other series are at interest rates within the range of 4-5/8% - 11.375%. ** The 14.95% series of $20 million is due 2/1/95. All other series are at interest rates within the range of 5.95% - 11.2%. *** Consists of pollution control bonds and municipal revenue bonds, certain series of which are secured by non-interest bearing first mortgage bonds. The fair value of Entergy Corporation's long-term debt (excluding GSU in 1992), excluding lease obligations and long-term DOE obligations, as of December 31, 1993 and 1992, was estimated to be $7,207.3 million and $4,662.3 million, respectively. The fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. For the years 1994, 1995, 1996, 1997, and 1998, Entergy Corporation's subsidiaries have long-term debt maturities (excluding lease obligations) and cash sinking fund requirements in the aggregate of (in millions) $321.4, $378.4, $558.4, $361.9, and $315.9, respectively. In addition, other sinking fund requirements will be satisfied by cash or by certification of property additions at the rate of 167% of such requirements. The amounts associated with this provision total approximately $11.2 million for each of the years 1994 through 1998. NOTE 7. DIVIDEND RESTRICTIONS Various agreements relating to the long-term debt and preferred stock of Entergy Corporation's subsidiaries restrict the payment of cash dividends or other distributions on their common stock. In addition to these restrictions, the Public Utility Holding Company Act of 1935 prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. As of December 31, 1993, Entergy Corporation's subsidiaries had restricted common equity of approximately $5,165.4 million, including $1,167.8 million of restricted retained earnings, which were unavailable for distribution to Entergy Corporation. In February 1994, Entergy Corporation received common stock dividend payments totaling $198.2 million, including $100 million from GSU. Prior to this, GSU had not paid a common stock dividend since June 1986. NOTE 8. COMMITMENTS AND CONTINGENCIES Cajun - River Bend GSU has significant business relationships with Cajun, primarily co- ownership of River Bend and Big Cajun 2 Unit 3. GSU and Cajun own 70% and 30% of River Bend, respectively, while Big Cajun 2 Unit 3 is owned 42% and 58% by GSU and Cajun, respectively. GSU operates River Bend and Cajun operates Big Cajun 2 Unit 3. In June 1989, Cajun filed a civil action against GSU in the U. S. District Court for the Middle District of Louisiana. Cajun stated in its complaint that the object of the suit is to annul, rescind, terminate, and/or dissolve the Joint Ownership Participation and Operating Agreement entered into on August 28, 1979 (Operating Agreement), related to River Bend. Cajun alleges fraud and error by GSU, breach of its fiduciary duties owed to Cajun, and/or GSU's repudiation, renunciation, abandonment, or dissolution of its core obligations under the Operating Agreement, as well as the lack or failure of cause and/or consideration for Cajun's performance under the Operating Agreement. The suit seeks to recover Cajun's alleged $1.6 billion investment in the unit as damages, plus attorneys' fees, interest, and costs. In March 1992, the district court appointed a mediator to engage in settlement discussions and to schedule settlement conferences between the parties. Discussions with the mediator began in July 1992, however, GSU cannot predict what effect, if any, such discussions will have on the timing or outcome of the case. A trial without a jury is set for April 12, 1994, on the portion of the suit by Cajun to rescind the Operating Agreement. Two member cooperatives of Cajun have brought an independent action to declare the River Bend Operating Agreement void, based upon failure to get prior LPSC approval alleged to be necessary. GSU believes the suits are without merit and is contesting them vigorously. No assurance can be given as to the outcome of this litigation. If GSU were ultimately unsuccessful in this litigation and were required to make substantial payments, GSU would probably be unable to make such payments and would probably have to seek relief from its creditors under the Bankruptcy Code. See Note 11 for the accounting treatment of preacquisition contingencies, including a charge resulting from an adverse resolution in the Cajun - River Bend litigation. In July 1992, Cajun notified GSU that it would fund a limited amount of costs related to the fourth refueling outage at River Bend, completed in September 1992. Cajun has also not funded its share of the costs associated with certain additional repairs and improvements at River Bend completed during the refueling outage. GSU has paid the costs associated with such repairs and improvements without waiving any rights against Cajun. GSU believes that Cajun is obligated to pay its share of such costs under the terms of the applicable contract. Cajun has filed a suit seeking a declaration that it does not owe such funds and seeking injunctive relief against GSU. GSU is contesting such suit and is reviewing its available legal remedies. In September 1992, GSU received a letter from Cajun alleging that the operating and maintenance costs for River Bend are "far in excess of industry averages" and that "it would be imprudent for Cajun to fund these excessive costs." Cajun further stated that until it is satisfied it would fund a maximum of $700,000 per week under protest for the remainder of 1992. In a December 1992 letter, Cajun stated that it would also withhold costs associated with certain additional repairs, of which the majority will be incurred during the next refueling outage, currently scheduled for April 1994. GSU believes that Cajun's allegations are without merit and is considering its legal and other remedies available with respect to the underpayments by Cajun. The total resulting from Cajun's failure to fund repair projects, Cajun's funding limitation on the fourth refueling outage, and the weekly funding limitation by Cajun was $33.3 million as of December 31, 1993, compared with a $28.4 million unfunded balance as of December 31, 1992. These amounts are reflected in long- term receivables. During 1994, and for the next several years, it is expected that Cajun's share of River Bend-related costs will be in the range of $60 million to $70 million per year. Cajun's weak financial condition could have a material adverse effect on GSU, including a possible NRC action with respect to the operation of River Bend and a need to bear additional costs associated with the co-owned facilities. If GSU were required to fund Cajun's share of costs, there can be no assurance that such payments could be recovered. Cajun's weak financial condition could also affect the ultimate collectibility of amounts owed to GSU. Cajun - Transmission Service GSU and Cajun are parties to FERC proceedings related to transmission service charge disputes. In April 1992, FERC issued a final order and in May 1992 GSU and Cajun filed motions for rehearings which are pending consideration by FERC. In June 1992, GSU filed a petition for review in the United States Court of Appeals regarding certain of the issues decided by FERC. In August 1993, the United States Court of Appeals rendered an opinion reversing the FERC order regarding the portion of such disputes relating to the calculations of certain credits and equalization charges under GSU's service schedules with Cajun. The opinion remanded the issues to FERC for further proceedings consistent with its opinion. In January 1994, FERC denied GSU's request to collect a surcharge while FERC considers the court's remand. GSU interprets the FERC order and the court of appeals' decision to mean that Cajun would owe GSU approximately $85 million as of December 31, 1993. GSU further estimates that if it prevails in its May 1992 motion for rehearing, Cajun would owe GSU approximately $118 million as of December 31, 1993. If Cajun were to prevail in its May 1992 motion for rehearing to FERC, and if GSU were not to prevail in its May 1992 motion for rehearing to FERC, and if FERC does not implement the court's remand as GSU contends is required, GSU estimates it would owe Cajun approximately $76 million as of December 31, 1993. The above amounts are exclusive of a $7.3 million payment by Cajun on December 31, 1990, which the parties agreed to apply to the disputed transmission service charges. GSU and Cajun further agreed that their positions at FERC would remain unaffected by the $7.3 million. Pending FERC's ruling on the May 1992 motions for rehearing, GSU has continued to bill Cajun utilizing the historical billing methodology and has booked underpaid transmission charges, including interest, in the amount of $140.8 million as of December 31, 1993. This amount is reflected in long-term receivables and in other deferred credits, with no effect on net income. Capital Requirements and Financing Construction expenditures (excluding nuclear fuel) for the years 1994, 1995, and 1996 are estimated to total $586 million, $560 million, and $550 million, respectively. The System will also require $1,362 million during the period 1994-1996 to meet long-term debt and preferred stock maturities and cash sinking fund requirements. The System plans to meet the above requirements primarily with internally generated funds and cash on hand, supplemented by the issuance of debt and preferred stock. Certain System companies may also continue with the acquisition or refinancing of all or a portion of certain outstanding series of preferred stock and long-term debt. See Note 12 for information on additional capital requirements related to a February 1994 ice storm. Capital Funds and Availability Agreements Entergy Corporation has agreed to arrange for or supply to System Energy sufficient amounts of capital to (1) maintain System Energy's equity capital at not less than 35% of System Energy's total capitalization (excluding short-term debt), and (2) continue commercial operation of Grand Gulf 1 and enable System Energy to pay its borrowings. In addition, under supplements to the Capital Funds Agreement assigning System Energy's rights as security for specific debt of System Energy, Entergy Corporation has agreed to make cash capital contributions to enable System Energy to make payments on such debt when due. System Energy has entered into various agreements with AP&L, LP&L, MP&L, and NOPSI, whereby AP&L, LP&L, MP&L, and NOPSI are obligated to purchase their respective entitlements of capacity and energy from System Energy's 90% ownership and leasehold 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 AP&L, LP&L, MP&L, and NOPSI under these agreements. Long-Term Contracts The System has several long-term contracts to purchase natural gas and low-sulfur coal for use at its generating units. LP&L has a long-term agreement through the year 2031 to purchase energy generated by a hydroelectric facility. If the maximum percentage (94%) of the energy is made available to LP&L, current production projections would require estimated payments of approximately $47 million per year through 1996, $54 million in 1997, and a total of $3.5 billion for the years 1998 through 2031. LP&L recovers the cost of purchased energy through its fuel adjustment clause. In 1988, GSU entered into a joint venture with a primary term of 20 years with Conoco, Inc., Citgo Petroleum Corporation, and Vista Chemical Company (Industrial Participants) whereby GSU's Nelson Units 1 and 2 were sold to a partnership (NISCO) consisting of the Industrial Participants and GSU. The Industrial Participants are supplying the fuel for the units, while GSU operates the units at the discretion of the Industrial Participants and purchases the electricity produced by the units. GSU is continuing to sell electricity to the Industrial Participants. For the years ended December 31, 1993, 1992, and 1991, the purchases of electricity from the joint venture totaled $62.6 million, $37.8 million, and $61.3 million, respectively. Nuclear Insurance The Price-Anderson Act limits public liability for a single nuclear incident to approximately $9.4 billion as of December 31, 1993. The System has protection for this liability through a combination of private insurance (currently $200 million) and an industry assessment program. Under the assessment program, the maximum amount the System would be required to pay for each nuclear incident would be $79.28 million per reactor, payable at a rate of $10 million per licensed reactor per incident per year. As a co-licensee of Grand Gulf 1 with System Energy, South Mississippi Electric Power Association (SMEPA) would share 10% of this obligation. With respect to River Bend, any assessments pertaining to this program are subject to the 70/30% ownership interest between GSU and Cajun. The System has five licensed reactors. In addition, the System participates in a private insurance program which provides coverage for worker tort claims filed for bodily injury caused by radiation exposure. The program provides for a maximum assessment of approximately $15.5 million for the System's five nuclear units, in the event losses exceed accumulated reserve funds. AP&L, GSU, LP&L, and System Energy are also members of certain insurance programs that provide coverage for property damage, including decontamination and premature decommissioning expense, to members' nuclear generating plants. As of December 31, 1993, AP&L, GSU, LP&L, and System Energy each were insured against such losses up to $2.7 billion, with $250 million of this amount designated to cover any shortfall in the NRC required decommissioning trust funding. In addition, AP&L, GSU, LP&L, MP&L, and NOPSI are members of an insurance program that covers certain replacement power and business interruption costs incurred due to prolonged nuclear unit outages. Under the property damage and replacement power/business interruption insurance programs, these System companies could be subject to assessments if losses exceed the accumulated funds available to the insurers. As of December 31, 1993, the maximum amounts of such possible assessments were: AP&L - $28.14 million; GSU - $15.9 million; LP&L - $24.34 million; MP&L - $0.63 million; NOPSI - $0.34 million, and System Energy - $21.89 million. Under its agreement with System Energy, SMEPA would share in System Energy's obligation. Cajun shares approximately $4.02 million of GSU's obligation. The amount of property insurance carried by the System exceeds the NRC's minimum requirement for nuclear power plant licensees of $1.06 billion per site. NRC regulations provide that the proceeds of this insurance must be used, first, to place and maintain the reactor in a safe and stable condition 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. Spent Nuclear Fuel and Decommissioning Costs AP&L, GSU, LP&L, and System Energy provide for estimated future disposal costs for spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected System companies entered into contracts with the Department of Energy (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. AP&L, the only System company that generated electricity with nuclear fuel prior to that date, elected to pay the one-time fee, plus accrued interest, no earlier than 1998, and has recorded a liability as of December 31, 1993, of approximately $101.0 million. The fees payable to the DOE may be adjusted in the future to assure full recovery. The System considers all costs incurred or to be incurred, except accrued interest, for the disposal of spent nuclear fuel to be proper components of nuclear fuel expense, and provisions to recover such costs have been or will be made in applications to regulatory authorities. Due to delays of the DOE repository program for the acceptance of spent nuclear fuel, it is uncertain when shipments of spent fuel from the System's nuclear units will commence. In the meantime, the affected companies are responsible for spent fuel storage. Current on-site spent fuel storage capacity at ANO, River Bend, Waterford 3, and Grand Gulf 1 is estimated to be sufficient until 1995, 2003, 2000, and 2004, respectively. Thereafter, the affected companies will provide additional storage. The initial cost of providing the additional on-site spent fuel storage capability required at ANO, River Bend, Waterford 3, and Grand Gulf 1 is approximately $5 million to $10 million per unit. In addition, approximately $3 million to $5 million per unit will be required every two to three years subsequent to 1995 for ANO and every four to five years subsequent to 2003, 2000, and 2004 for River Bend, Waterford 3, and Grand Gulf 1, respectively, until the DOE's repository begins accepting such units' spent fuel. Decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf 1 were estimated to be approximately $606.8 million (based on a 1992 update to the original cost study), $141.0 million (based on a 1985 cost study), $203.0 million (based on a 1988 update to the original cost study), and $248.7 million (based on a 1989 cost study), respectively. AP&L and GSU are authorized to recover through rates amounts that, when added to estimated investment income, should be sufficient to meet the above estimated decommissioning costs for ANO and River Bend. However, GSU did a 1991 update to the cost study which indicated decommissioning costs for River Bend may be approximately $279.8 million. The results of the 1991 update have not yet been added into GSU's rates and used as a basis for funding. During the first quarter of 1994, AP&L expects to prepare and file with the APSC an interim update of the ANO cost study, which will likely reflect significant increases in costs of low-level radioactive waste disposal. The LPSC authorized LP&L to recover $4.0 million annually through 1993, based on the 1988 study update. LP&L will begin funding $4.8 million in 1994 in anticipation of a 1994 study update and a related LPSC review and determination of appropriate funding levels. System Energy is currently recovering in rates amounts sufficient to fund $198.0 million (in 1989 dollars) of its decommissioning costs, and an updated cost study is scheduled to be completed by mid-1994. AP&L, GSU, LP&L, and System Energy regularly review and update estimated decommissioning costs, and applications will be made to the appropriate regulatory authorities to reflect in rates any future change in projected decommissioning costs. The amounts recovered in rates are deposited in external trust funds which have a market value of $193.1 million and $138.5 million (excluding GSU in 1992) as of December 31, 1993 and 1992, respectively. The accumulated decommissioning liability has been recorded in accumulated depreciation for AP&L, GSU, and LP&L, and in other deferred credits for System Energy, in the amounts of $119.2 million, $18.1 million, $22.1 million, and $24.8 million, respectively, as of December 31, 1993. Decommissioning expense amounting to $19.9 million was recorded in 1993. The actual decommissioning costs may vary from the above estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment, and management believes that actual decommissioning costs are likely to be higher than the amounts presented above. The Energy Act has a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning of the DOE's past uranium enrichment operations. The decontamination and decommissioning assessments will be used to set up a fund into which contributions from utilities and the federal government will be placed. AP&L's, GSU's, LP&L's, and System Energy's annual assessments, which will be adjusted annually for inflation, are approximately $3.3 million, $0.6 million, $1.2 million, and $1.3 million (in 1993 dollars), respectively, for approximately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortized. The cumulative liability of $87.4 million as of December 31, 1993, is recorded in other current liabilities and other noncurrent liabilities and is offset in the consolidated financial statements by a regulatory asset, recorded as a deferred debit. NOTE 9. LEASES General As of December 31, 1993, the System had capital leases and noncancelable operating leases (excluding nuclear fuel leases and the sale and leaseback transactions discussed below) with minimum lease payments as follows: Capital Operating Year Leases Leases ---- -------- --------- (In Thousands) 1994 $ 33,780 $ 43,337 1995 33,880 42,527 1996 29,490 39,235 1997 24,654 20,820 1998 24,654 22,532 Years thereafter 160,903 180,651 -------- -------- Minimum lease payments 307,361 $349,102 Less: Amount representing interest 121,708 ======== -------- Present value of net minimum lease payments $185,653 ======== Rental expense for capital and operating leases (excluding nuclear fuel leases and the sale and leaseback transactions) amounted to approximately $62.7 million, $75.5 million, and $73.8 million in 1993, 1992, and 1991, respectively. Nuclear Fuel Leases AP&L, GSU, LP&L, and System Energy have arrangements to lease nuclear fuel in an aggregate amount up to $455 million as of December 31, 1993. The lessors finance their acquisitions of nuclear fuel through credit agreements and the issuance of notes. If a lessor cannot arrange financing upon maturity of its borrowings, the lessee must purchase nuclear fuel in an amount sufficient to enable the lessor to retire such borrowings. Lease payments are based on nuclear fuel use. Nuclear fuel lease expense for AP&L, LP&L, and System Energy of $145.8 million, $158.4 million, and $185.6 million (including interest of $20.5 million, $25.6 million, and $32.7 million) was charged to operations in 1993, 1992, and 1991, respectively. Sale and Leaseback Transactions In 1988 and 1989, System Energy and LP&L, respectively, sold and leased back portions of their ownership interests in Grand Gulf 1 and Waterford 3, for 26- and 28-year lease terms, respectively. Both companies have options to terminate the leases, to repurchase the sold interests, or to renew the leases at the end of their terms. Under System Energy's sale and leaseback arrangements, letters of credit are required to be maintained to secure certain amounts payable, for the benefit of equity investors, by System Energy under the leases. The letters of credit currently maintained are effective until January 1997. It is expected that the letters of credit will either be renewed, extended, or replaced prior to expiration. On January 11, 1994, System Energy refinanced the debt portion of the sale and leaseback arrangements. The new secured lease obligation bonds of $356 million, 7.43% series due 2011 and $79 million, 8.2% series due 2014 will be indirectly secured by liens on, and a security interest in, certain ownership interests and the respective leases relating to Grand Gulf 1. If LP&L does not exercise its option to repurchase the lease interests in Waterford 3 in September 1994, LP&L will be required to provide collateral to secure the equity portion of certain of its obligations under the lease. This collateral would be either a letter of credit or a new series of first mortgage bonds issued by LP&L. As of December 31, 1993, System Energy and LP&L had future minimum lease payments (reflecting implicit rates of 7.02% after the above refinancing and 8.76%, respectively) as follows: System Energy LP&L ---------- -------- (In Thousands) 1994 $ 17,423* $ 32,568 1995 42,464 32,569 1996 42,753 35,165 1997 42,753 39,805 1998 42,753 41,447 Years thereafter 845,573 726,744 ---------- -------- Total $1,033,719 $908,298 ========== ======== * An additional $24 million payment was made in January 1994 prior to the refinancing of the debt portion of the sale/leaseback arrangements. NOTE 10. POSTRETIREMENT BENEFITS Pension Plans The System companies have various postretirement benefit plans covering substantially all of their employees. The pension plans are noncontributory and provide pension benefits that are based on employees' credited service and compensation during the final years before retirement. 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. Total 1993, 1992, and 1991 pension cost of Entergy Corporation and its subsidiaries, including amounts capitalized, included the following components:
Service cost - benefits earned during the period $ 21,760 $ 18,784 $ 16,393 Interest cost on projected benefit obligation 53,371 50,225 44,367 Actual return on plan assets (81,708) (43,772) (120,705) Net amortization and deferral 27,261 (8,243) 70,760 Other - - 2,888 -------- -------- --------- Net pension cost $ 20,684 $ 16,994 $ 13,703 ======== ======== =========
The funded status of Entergy's various pension plans as of December 31, 1993 and 1992 (excluding GSU in 1992), was:
1993 1992 ---------- -------- (In Thousands) Actuarial present value of accumulated pension plan obligation: Vested $ 821,292 $552,437 Nonvested 17,867 2,999 ---------- -------- Accumulated benefit obligation $ 839,159 $555,436 ========== ======== Plan assets at fair value $1,059,715 $647,120 Projected benefit obligation 1,041,104 666,626 ---------- -------- Plan assets in excess of (less than) projected benefit obligation 18,611 (19,506) Unrecognized prior service cost 20,288 21,723 Unrecognized transition asset (61,561) (68,914) Unrecognized net loss (gain) 32,634 (13,473) ---------- -------- Accrued pension asset (liability) $ 9,972 $(80,170) ========== ========
The significant actuarial assumptions used in computing the information above for 1993, 1992, and 1991 (only 1993 with respect to GSU's plan), were as follows: weighted average discount rate, 7.5% for 1993 and 8.25% for 1992 and 1991 (7.5% for GSU); weighted average rate of increase in future compensation levels, 5.6% (5.0% for GSU); and expected long-term rate of return on plan assets, 8.5% (8.5% for GSU). Transition assets of the System are being amortized over the greater of the remaining service period of active participants or 15 years. Other Postretirement Benefits The System companies also provide certain 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 the System companies. The cost of providing these benefits, recorded on a cash basis, to retirees in 1992 was approximately $13 million. Prior to 1992, the cost of providing these benefits for retirees was not separable from the cost of providing benefits for active employees. Based on the ratio of the number of retired employees to the total number of active and retired employees in 1991, the cost of providing these benefits, recorded on a cash basis, for retirees was approximately $11.8 million. Effective January 1, 1993, Entergy adopted SFAS 106. The new standard requires a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. The System operating companies continue to fund these benefits on a pay-as-you-go basis. 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 and $128.0 million for Entergy and for GSU, respectively. Such obligations are being amortized over a 20-year period beginning in 1993. The System operating companies have sought approval, in their respective regulatory jurisdictions, to implement the appropriate accounting requirements related to SFAS 106 for ratemaking purposes. AP&L has received an order permitting deferral, as a regulatory asset, of these costs. MP&L is expensing its SFAS 106 costs, which will be reflected in rates pursuant to an order from the MPSC in connection with MP&L's formulary incentive rate plan (see Note 2). The LPSC ordered GSU and LP&L to use the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions but the LPSC retains the flexibility to examine individual companies' accounting for postretirement benefits to determine if special exceptions to this order are warranted. NOPSI is expensing its SFAS 106 costs. Pursuant to resolutions adopted in November 1993 by the Council related to the Merger, NOPSI's SFAS 106 expenses through October 31, 1996, will be allowed by the Council for purposes of evaluating the appropriateness of NOPSI's rates. Pursuant to a ruling by the PUCT applicable to all Texas utilities, including GSU, amounts recorded in compliance with SFAS 106 and included in a rate filing test period, will be recoverable in rates (at the time of the next general rate case), and postretirement benefits amounts allowed in rates must then be funded by the utility. The System's net income in 1993 (excluding GSU) was decreased by approximately $9 million as a result of adopting SFAS 106. Total 1993 postretirement benefit cost of Entergy Corporation and its subsidiaries (excluding GSU), including amounts capitalized and deferred, included the following components (in thousands): Service cost - benefits earned during the period $ 7,751 Interest cost on APBO 19,394 Return on plan assets (71) Amortization of transition obligation 12,071 ------- Net periodic postretirement benefit cost $39,145 ======= The funded status of Entergy's postretirement plans as of December 31, 1993, was (in thousands): Accumulated postretirement benefit obligation: Retirees $ 221,562 Other fully eligible participants 68,283 Other active participants 95,854 --------- 385,699 Plan assets at fair value 354 --------- Plan assets less than APBO (385,345) Unrecognized transition obligation 229,346 Unrecognized net loss 28,529 --------- Accrued postretirement benefit liability $(127,470) ========= The assumed health care cost trend rate used in measuring the APBO of the System companies, excluding GSU, was 9.9% for 1994 (10% for GSU), gradually decreasing each successive year until it reaches 5.6% in 2020 (5% for GSU in 2002). A one percentage-point increase in the assumed health care cost trend rate for each year would have increased the APBO of the System companies, excluding GSU, as of December 31, 1993, by 8.9%, (13.6% for GSU) and the sum of the service cost and interest cost by approximately 11.4% (22.7% for GSU). The assumed discount rate and rate of increase in future compensation used in determining the APBO were 7.5% (7.5% for GSU) and 5.5% (5% for GSU), respectively. NOTE 11. ENTERGY CORPORATION-GSU MERGER On December 31, 1993, GSU became a wholly-owned subsidiary of Entergy Corporation and continues to operate as a public utility under the regulation of the PUCT and the LPSC. As consideration to GSU's shareholders, Entergy Corporation paid $250 million and issued 56,667,726 shares of its common stock at a price of $35.8417 per share. In addition, $33.5 million of transaction costs were capitalized in connection with the Merger. The Merger was accounted for under the purchase method of accounting. Various parties have requested rehearings and/or are appealing the approval orders or plans of the SEC, NRC, LPSC, and FERC. The Consolidated Balance Sheet of Entergy Corporation as of December 31, 1993, includes the accounts of GSU and, therefore, is not directly comparable to the Consolidated Balance Sheet presented as of December 31, 1992. Entergy Corporation recorded an acquisition adjustment in utility plant in the amount of $380 million representing the excess of the purchase price over the net assets acquired of GSU. The acquisition adjustment will be amortized on a straight- line basis over a 31-year period, which approximates the remaining average book life of the plant being acquired. The allocation of the purchase price has been based on preliminary estimates which may be revised at a later date. The possibility of an adverse result in the litigation relating to Cajun (see Note 8) and the possibility of a write-off relating to Texas River Bend ratemaking issues (see Note 2) represent preacquisition contingencies. There may be other contingencies associated with GSU which could also constitute preacquisition contingencies but which have not yet been specifically identified as such by Entergy Corporation. During the allocation period (which will not exceed one year after consummation of the transaction), Entergy Corporation will complete its analyses with respect to these contingencies. Upon completion, should Entergy Corporation no longer believe GSU has a reasonable possibility of attaining a favorable ruling in such preacquisition contingencies, any resulting write-offs and/or losses would cause the reduction of the affected noncurrent assets and an increase of an equal amount in the acquisition adjustment in Entergy Corporation's consolidated financial statements, in accordance with the purchase method of accounting for business combinations. In accordance with the purchase method of accounting, the 12-month results of operations for Entergy Corporation reported in its Statements of Consolidated Income, Cash Flows, and Retained Earnings do not reflect GSU's results of operations for any period as a result of the December 31, 1993, closing date of the Merger. The pro forma combined revenues, net income, earnings per common share before extraordinary items and cumulative effect of accounting changes, and earnings per common share of Entergy Corporation presented below give effect to the Merger as if it had occurred at January 1, 1992. This pro forma information is not necessarily indicative of the results of operation that would have occurred had the Merger been consummated for the period for which it is being given effect, nor is it necessarily indicative of future operating results. Year Ended December 31, ----------------------- 1993 1992 ---------- ---------- (In Thousands, Except Per Share Amounts) Revenues $6,286,999 $5,850,973 Net income $ 595,211 $ 521,783 Earnings per average common share before extraordinary items and cumulative effect of accounting $ 2.10 $ 2.26 changes Earnings per average common share $ 2.57 $ 2.24 NOTE 12. SUBSEQUENT EVENT (UNAUDITED) In early February 1994, an ice storm left more than 221,000 Entergy customers without electric power across the System's four-state service area. The storm was the most severe natural disaster ever to affect the System, causing damage to transmission and distribution lines, equipment, poles, and facilities in certain areas, primarily in Mississippi. A substantial portion of the related costs, which are estimated to be $110 million to $140 million, are expected to be capitalized. The MPSC acknowledged that there is precedent in Mississippi for recovery of certain costs associated with storms and natural disasters and the restoration of service resulting from such events. MP&L plans to immediately file for rate recovery of the costs related to the ice storm. Estimated construction expenditures (see Note 8) have not yet been updated to reflect the above amounts. NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED) The business of the System is subject to seasonal fluctuations with the peak period occurring during the third quarter. Consolidated operating results for the four quarters of 1993 and 1992 were: Operating Operating Net Earnings Revenues Income Income per Share ----------- ---------- -------- --------- (In Thousands, Except Per Share Amounts) 1993: First Quarter (1) $ 926,412 $192,743 $151,154 $0.86 Second Quarter $1,070,102 $260,574 $130,860 $0.75 Third Quarter $1,410,951 $359,938 $233,430 $1.34 Fourth Quarter $1,077,872 $180,086 $ 36,486 $0.21 1992: First Quarter (2) $ 916,467 $211,679 $ 95,277 $0.54 Second Quarter $ 958,121 $220,141 $ 82,102 $0.46 Third Quarter $1,237,894 $340,361 $204,578 $1.16 Fourth Quarter $1,004,017 $186,405 $ 55,680 $0.32 (1) The first quarter of 1993 reflects a nonrecurring increase in net income of $93.8 million, net of taxes of $57.2 million, and a $0.54 increase in earnings per share, due to the recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1). Beginning with the second quarter, the remaining quarters are not generally comparable to prior year quarters because of the ongoing effects of the accounting change. (2) The first quarter of 1992 reflects a nonrecurring increase in net income of $19.6 million, net of tax, and a $0.11 increase in earnings per share, due to the AP&L sale of retail properties in Missouri.
ENTERGY CORPORATION AND SUBSIDIARIES SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1993 1992 1991 1990 1989 ----------- ----------- ----------- ----------- ----------- (In Thousands, Except Per Share Amounts) Operating revenues $ 4,485,337 $ 4,116,499 $ 4,051,429 $ 3,982,062 $ 3,724,004 Income (loss) before cumulative effect of a change in accounting principle $ 458,089 $ 437,637 $ 482,032 $ 478,318 $ (472,585) Earnings (loss) per share before cumulative effect of a change in accounting principle $ 2.62 $ 2.48 $ 2.64 $ 2.44 $ (2.31) Dividends declared per share $ 1.65 $ 1.45 $ 1.25 $ 1.05 $ 0.90 Book value per share, year-end (2) $ 28.27 $ 24.35 $ 23.46 $ 22.18 $ 20.62 Total assets (2) $22,876,697 $14,239,537 $14,383,102 $14,831,394 $14,715,241 Long-term obligations (1)(2) $ 8,177,882 $ 5,630,505 $ 5,801,364 $ 6,395,951 $ 6,711,509
(1) Includes long-term debt (excluding currently maturing debt), preferred and preference stock with sinking fund, and noncurrent capital lease obligations. (2) 1993 amounts include the effects of the Merger in accordance with the purchase method of accounting for combinations (see Note 11). See Notes 1, 3, and 10 for the effect of the accounting changes in 1993.
1993 1992 1991 1990 1989 ---------- ---------- ---------- ---------- ---------- (Dollars in Thousands) Electric Operating Revenues: Residential $1,596,480 $1,440,360 $1,463,281 $1,449,768 $1,331,154 Commercial 1,072,583 1,007,420 996,619 988,409 930,345 Industrial 1,199,172 1,097,023 1,068,802 1,051,796 1,021,456 Governmental 136,649 127,753 128,762 124,597 121,912 ---------- ---------- ---------- ---------- ---------- Total retail 4,004,884 3,672,556 3,657,464 3,614,570 3,404,867 Sales for resale 293,894 252,288 220,347 212,504 177,014 Other 95,568 118,711 96,667 67,045 51,756 ---------- ---------- ---------- ---------- ---------- Total $4,394,346 $4,043,555 $3,974,478 $3,894,119 $3,633,637 ========== ========== ========== ========== ========== Billed Electric Energy Sales (Millions of KWH): Residential 18,946 17,549 18,329 18,174 17,245 Commercial 13,420 12,928 13,164 12,977 12,533 Industrial 24,889 23,610 23,466 22,795 22,396 Governmental 1,887 1,839 1,903 1,831 1,833 ---------- ---------- ---------- ---------- ---------- Total retail 59,142 55,926 56,862 55,777 54,007 Sales for resale 8,291 7,979 7,346 6,292 4,857 ---------- ---------- ---------- ---------- ---------- Total 67,433 63,905 64,208 62,069 58,864 ========== ========== ========== ========== ==========
ARKANSAS POWER & LIGHT COMPANY 1993 FINANCIAL STATEMENTS ARKANSAS POWER & LIGHT COMPANY DEFINITIONS Certain abbreviations or acronyms used in AP&L's Financial Statements, Notes to Financial Statements, and Management's Financial Discussion and Analysis are defined below: Abbreviation or Acronym Term AFUDC Allowance for Funds Used During Construction ANO Arkansas Nuclear One Steam Electric Generating Station ANO 1 Unit No. 1 of ANO ANO 2 Unit No. 2 of ANO AP&L Arkansas Power & Light Company APSC Arkansas Public Service Commission DOE United States Department of Energy Entergy or System Entergy Corporation and its various direct and indirect subsidiaries Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy Corporation that has operating responsibility for Grand Gulf 1, Waterford 3, ANO, and River Bend Entergy Power Entergy Power, Inc., a subsidiary of Entergy Corporation that markets capacity and energy for resale from certain generating facilities to other parties, principally non-affiliates FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission Grand Gulf Station Grand Gulf Steam Electric Generating Station Grand Gulf 1 Unit No. 1 of the Grand Gulf Station Grand Gulf 2 Unit No. 2 of the Grand Gulf Station GSU Gulf States Utilities Company (including wholly owned subsidiaries - Varibus Corporation, GSG&T, Inc., Prudential Oil and Gas, Inc., and Southern Gulf Railway Company) Independence Station Independence Steam Electric Generating Station Independence 2 Unit No. 2 of the Independence Station KWH Kilowatt-Hour(s) LP&L Louisiana Power & Light Company Merger The combination transaction, consummated on December 31, 1993, by which GSU became a subsidiary of Entergy Corporation and Entergy Corporation became a Delaware Corporation Money Pool Entergy Money Pool, which allows certain System companies to borrow from, or lend to, certain other System companies MP&L Mississippi Power & Light Company NOPSI New Orleans Public Service Inc. NRC Nuclear Regulatory Commission OBRA Omnibus Budget Reconciliation Act of 1993 Revised Settlement Agreement Arkansas Settlement Agreement, as modified by the APSC order issued October 6, 1988, to bring the Grand Gulf 1-related phase-in plan into compliance with the requirements of SFAS No. 92, "Regulated Enterprises - Accounting for Phase-in Plans" Ritchie 2 Unit No. 2 of the Ritchie Steam Electric Generating Station SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the FASB SFAS 106 SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS No. 109, "Accounting for Income Taxes" System or Entergy Entergy Corporation and its various direct and indirect subsidiaries System Energy System Energy Resources, Inc. System Fuels System Fuels, Inc. System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively Union Electric Union Electric Company of St. Louis, Missouri White Bluff Station White Bluff Steam Electric Generating Station ARKANSAS POWER & LIGHT COMPANY REPORT OF MANAGEMENT The management of Arkansas Power & Light Company has prepared and is responsible for the financial statements and related financial information included herein. The financial statements are based on generally accepted accounting principles. Financial information included elsewhere in this report is consistent with the financial statements. To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls that is designed to provide reasonable assurance, on a cost-effective basis, as to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. This system includes communication through written policies and procedures, an employee Code of Conduct, 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. The independent public accountants provide an objective assessment of the degree to which 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 these policies and procedures provide reasonable assurance that its operations are carried out with a high standard of business conduct. /S/ EDWIN LUPBERGER /S/ GERALD D. MCINVALE EDWIN LUPBERGER GERALD D. MCINVALE Chairman and Chief Executive Officer Senior Vice President and Chief Financial Officer ARKANSAS POWER & LIGHT COMPANY AUDIT COMMITTEE CHAIRMAN'S LETTER The Arkansas Power & Light Company Audit Committee of the Board of Directors is comprised of four directors, who are not officers of AP&L: Kaneaster Hodges, Jr. (Chairman), Richard P. Herget, Jr., Dr. Raymond P. Miller, Sr., and Gus B. Walton, Jr. The committee held four meetings during 1993. The Audit Committee oversees AP&L's financial reporting process on behalf of the Board of Directors and provides reasonable assurance to the Board that sufficient operating, accounting, and financial controls are in existence and are adequately reviewed by programs of internal and external audits. The Audit Committee discussed with Entergy's internal auditors and the independent public accountants (Deloitte & Touche) the overall scope and specific plans for their respective audits, as well as AP&L's financial statements and the adequacy of AP&L' s internal controls. The committee met, together and separately, with Entergy's internal auditors and independent public accountants, without management present, to discuss the results of their audits, their evaluation of AP&L's internal controls, and the overall quality of AP&L's financial reporting. The meetings also were designed to facilitate and encourage any private communication between the committee and the internal auditors or independent public accountants. /S/ KANEASTER HODGES, JR. KANEASTER HODGES, JR. Chairman, Audit Committee INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directors of Arkansas Power & Light Company We have audited the accompanying balance sheets of Arkansas Power & Light Company (AP&L) as of December 31, 1993 and 1992, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of AP&L's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. 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 AP&L at December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. As discussed in Note 1 to the financial statements, AP&L changed its method of accounting for revenues in 1993 and, as discussed in Notes 3 and 10 to the financial statements, in 1993 AP&L changed its methods of accounting for income taxes and postretirement benefits other than pensions, respectively. /S/ DELOITTE & TOUCHE DELOITTE & TOUCHE New Orleans, Louisiana February 11, 1994 ARKANSAS POWER & LIGHT COMPANY BALANCE SHEETS ASSETS
December 31, ----------------------- 1993 1992 ---------- ---------- (In Thousands) Utility Plant (Notes 1 and 2): Electric $4,098,355 $4,002,350 Property under capital leases (Note 9) 62,139 67,840 Construction work in progress 197,005 174,909 Nuclear fuel under capital lease (Note 9) 93,606 102,435 ---------- ---------- Total 4,451,105 4,347,534 Less - accumulated depreciation and amortization 1,604,318 1,512,919 ---------- ---------- Utility plant - net 2,846,787 2,834,615 ---------- ---------- Other Property and Investments: Investment in subsidiary companies - at equity (Note 8) 11,232 11,232 Decommissioning trust fund (Note 8) 108,192 91,075 Other - at cost (less accumulated depreciation) 4,257 3,498 ---------- ---------- Total 123,681 105,805 ---------- ---------- Current Assets: Cash 1,825 - Accounts receivable: Customer (less allowance for doubtful accounts of $2.1 million in 1993 and $1.6 million in 1992) 65,641 75,087 Associated companies (Note 11) 18,312 32,238 Other 20,817 6,881 Accrued unbilled revenues (Note 1) 83,378 - Fuel inventory - at average cost 51,920 52,093 Materials and supplies - at average cost 81,398 91,000 Rate deferrals (Note 2) 92,592 69,536 Deferred excess capacity (Note 2) 9,115 8,395 Prepayments and other 28,303 35,918 ---------- ---------- Total 453,301 371,148 ---------- ---------- Deferred Debits: Rate deferrals (Note 2) 475,387 574,040 Deferred excess capacity (Note 2) 28,465 38,300 SFAS 109 regulatory asset - net (Note 3) 234,015 - Unamortized loss on reaquired debt 60,169 23,262 Other (Note 8) 112,300 91,641 ---------- ---------- Total 910,336 727,243 ---------- ---------- TOTAL $4,334,105 $4,038,811 ========== ========== See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES
December 31, ----------------------- 1993 1992 ---------- ---------- (In Thousands) Capitalization: Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 1993 and 1992 $470 $470 Paid-in capital 590,844 590,838 Retained earnings (Note 7) 448,811 420,691 ---------- ---------- Total common shareholder's equity 1,040,125 1,011,999 Preferred stock (Note 5): Without sinking fund 176,350 176,350 With sinking fund 70,027 85,527 Long-term debt (Note 6) 1,313,315 1,260,947 ---------- ---------- Total 2,599,817 2,534,823 ---------- ---------- Other Noncurrent Liabilities: Obligations under capital leases (Note 9) 94,861 107,114 Other (Note 8) 59,750 86,020 ---------- ---------- Total 154,611 193,134 ---------- ---------- Current Liabilities: Currently maturing long-term debt (Note 6) 3,020 17,900 Notes payable: Associated companies (Note 4) 21,395 4,000 Other 667 667 Accounts payable: Associated companies (Note 11) 45,177 36,757 Other 93,611 81,423 Customer deposits 15,241 14,926 Taxes accrued 43,013 64,996 Accumulated deferred income taxes (Note 3) 32,367 20,904 Interest accrued 31,410 31,209 Dividends declared 5,049 5,534 Nuclear refueling reserve 3,070 3,050 Co-owner advances (Note 1) 39,435 31,005 Deferred fuel cost (Note 1) 16,130 19,553 Obligations under capital leases (Note 9) 60,883 63,162 Other 29,789 25,842 ---------- ---------- Total 440,257 420,928 ---------- ---------- Deferred Credits: Accumulated deferred income taxes (Note 3) 876,618 618,416 Accumulated deferred investment tax credits (Note 3) 154,723 165,296 Other 108,079 106,214 ---------- ---------- Total 1,139,420 889,926 ---------- ---------- Commitments and Contingencies (Notes 2, 8, and 9) TOTAL $4,334,105 $4,038,811 ========== ========== See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS
For the Years Ended December 31, ---------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Operating Activities: Net income $205,297 $130,529 $143,451 Noncash items included in net income: Cumulative effect of a change in accounting principle (50,187) - - Change in rate deferrals/excess capacity - net (Note 2) 84,712 60,344 16,936 Depreciation and decommissioning 135,530 132,459 128,410 Deferred income taxes and investment tax credits (6,965) (820) 9,448 Allowance for equity funds used during construction (3,627) (4,173) (4,508) Provision for estimated losses and reserves 1,963 (21,670) 7,786 Gain on sale of property - net - (19,612) - Changes in working capital: Receivables 7,385 (22,281) 10,948 Fuel inventory 173 17,039 (37,142) Accounts payable 20,608 (5,393) (4,528) Taxes accrued (21,983) (23,492) 2,514 Interest accrued 201 (8,041) (154) Other working capital accounts 26,486 5,249 2,506 Decommissioning trust contributions (11,491) (13,255) (13,765) Other (41,826) (2,736) (284) -------- -------- -------- Net cash flow provided by operating activities 346,276 224,147 261,618 -------- -------- -------- Investing Activities: Construction expenditures (176,540) (179,320) (156,734) Proceeds received from sale of property (Note 2) - 67,985 - Allowance for equity funds used during construction 3,627 4,173 4,508 Nuclear fuel purchases (29,156) (34,238) (32,900) Proceeds from sale/leaseback of nuclear fuel 29,156 34,238 33,058 -------- -------- -------- Net cash flow used in investing activities (172,913) (107,162) (152,068) -------- -------- -------- Financing Activities: Proceeds from issuance of: First mortgage bonds 445,000 148,114 - Preferred stock - 14,222 48,175 Other long-term debt 48,070 3,973 18,607 Retirement of: First mortgage bonds (441,141) (329,019) (35,598) Other long-term debt (47,700) (1,225) (1,140) Redemption of preferred stock (15,500) (34,388) (14,000) Changes in short-term borrowings 17,395 4,000 - Dividends paid: Common stock (156,300) (75,000) (39,900) Preferred stock (21,362) (23,730) (22,071) -------- -------- -------- Net cash flow used in financing activities (171,538) (293,053) (45,927) -------- -------- -------- Net increase (decrease) in cash and cash equivalents 1,825 (176,068) 63,623 Cash and cash equivalents at beginning of period - 176,068 112,445 -------- -------- -------- Cash and cash equivalents at end of period $1,825 - $176,068 ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $103,826 $114,791 $124,220 Income taxes $66,366 $60,987 $36,396 Noncash investing and financing activities: Capital lease obligations incurred $48,513 $37,351 $36,619 See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES Liquidity is important to AP&L due to the capital intensive nature of our business, which requires large investments in long-lived assets. However, large capital expenditures for the construction of new generating capacity are not currently planned. AP&L requires significant capital resources for the periodic maturity of certain series of debt and preferred stock. Net cash flow from operations totaled $346 million, $224 million, and $262 million in 1993, 1992, and 1991, respectively. The increase in AP&L's 1993 cash flow from operations resulted primarily from increased electricity sales and increased collections under the phase-in plan, as discussed below. In recent years, this cash flow, supplemented by issuances of debt and proceeds from the sale of retail properties in Missouri, has been sufficient to meet substantially all investing and financing requirements, including capital expenditures, dividends, and debt/preferred stock maturities. AP&L's ability to fund these capital requirements results, in part, from our continued efforts to streamline operations and reduce costs, as well as collections under our Grand Gulf 1 rate phase-in plan which exceed the current cash requirements for Grand Gulf 1- related costs. (In the income statement, these revenue collections are offset by the amortization of previously deferred costs, therefore, there is no effect on net income.) See Note 2, incorporated herein by reference, for additional information on AP&L's rate phase-in plan. See Note 8, incorporated herein by reference, for additional information on AP&L's capital and refinancing requirements in 1994 - 1996. Further, in order to take advantage of lower interest and dividend rates, AP&L may continue to refinance high-cost debt and preferred stock prior to maturity. Earnings coverage tests (which are impacted by the inclusion of the cumulative effect of the change in accounting principle for accruing unbilled revenues discussed in Note 1) and bondable property additions limit the amount of first mortgage bonds and preferred stock that AP&L can issue. Based on the most restrictive applicable tests as of December 31, 1993, and an assumed annual interest or dividend rate of 8%, AP&L could have issued $226 million of additional first mortgage bonds or $1,075 million of additional preferred stock. AP&L has the conditional ability to issue first mortgage bonds and preferred stock against the retirement of first mortgage bonds and preferred stock, respectively, in some cases, without satisfying an earnings coverage test. See Notes 5 and 6, incorporated herein by reference, for information on AP&L's financing activities and Note 4, incorporated herein by reference, for information on AP&L's short-term borrowings and lines of credit. ARKANSAS POWER & LIGHT COMPANY STATEMENTS OF INCOME
For the Years Ended December 31, ----------------------------------------- 1993 1992 1991 ---------- ---------- ---------- (In Thousands) Operating Revenues (Notes 1, 2, and 11): $1,591,568 $1,521,129 $1,528,270 ---------- ---------- ---------- Operating Expenses: Operation (Note 11): Fuel for electric generation and fuel-related expenses 257,983 242,040 268,699 Purchased power 349,718 417,099 378,069 Other 294,103 285,740 298,584 Maintenance (Note 11) 109,724 118,540 108,398 Depreciation and decommissioning 135,530 132,459 128,410 Taxes other than income taxes 28,626 26,709 23,068 Income taxes (Note 3) 18,746 4,058 22,958 Amortization of rate deferrals (Note 2) 160,916 114,711 80,666 ---------- ---------- ---------- Total 1,355,346 1,341,356 1,308,852 ---------- ---------- ---------- Operating Income 236,222 179,773 219,418 ---------- ---------- ---------- Other Income: Allowance for equity funds used during construction 3,627 4,173 4,508 Miscellaneous - net (Note 2) 64,884 113,842 82,733 Income taxes (Note 3) (32,451) (46,531) (30,908) ---------- ---------- ---------- Total 36,060 71,484 56,333 ---------- ---------- ---------- Interest Charges: Interest on long-term debt 107,771 120,318 133,854 Other interest - net 11,819 3,666 2,415 Allowance for borrowed funds used during construction (2,418) (3,256) (3,969) ---------- ---------- ---------- Total 117,172 120,728 132,300 ---------- ---------- ---------- Income before Cumulative Effect of a Change in Accounting Principle 155,110 130,529 143,451 Cumulative Effect to January 1, 1993, of Accruing Unbilled Revenues (net of income taxes of $31,140) (Note 1) 50,187 - - ---------- ---------- ---------- Net Income 205,297 130,529 143,451 Preferred Stock Dividend Requirements 20,877 23,202 22,870 ---------- ---------- ---------- Earnings Applicable to Common Stock $184,420 $107,327 $120,581 ========== ========== ========== See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, ------------------------------------ 1993 1992 1991 -------- -------- -------- (In Thousands) Retained Earnings, January 1 $420,691 $388,364 $307,683 Add: Net income 205,297 130,529 143,451 -------- -------- -------- Total 625,988 518,893 451,134 -------- -------- -------- Deduct: Dividends declared: Preferred stock 20,877 23,202 22,870 Common stock 156,300 75,000 39,900 -------- -------- -------- Total 177,177 98,202 62,770 -------- -------- -------- Retained Earnings, December 31 (Note 7) $448,811 $420,691 $388,364 ======== ======== ======== See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income increased in 1993 due primarily to the one-time recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1, incorporated herein by reference) and its ongoing effects, partially offset by the effect of implementing SFAS 109 (see Note 3, incorporated herein by reference) and by the impact in March 1992 of an after- tax gain from the sale of AP&L's retail properties in Missouri. Effective January 1, 1993, AP&L began accruing as revenues the charges for energy delivered to customers but not yet billed. Electric revenues were previously recorded on a cycle-billing basis. Excluding the above mentioned items, net income for 1993 would have been $157.7 million and net income for 1992 would have been $110.9 million. This increase of $46.8 million is due primarily to increased retail energy sales. Net income decreased in 1992 due primarily to decreased operating revenues and slight increases in maintenance expense, taxes other than income taxes, depreciation and decommissioning expense, and the retained share of Grand Gulf 1-related costs. These decreases in net income were partially offset by the $19.6 million after-tax gain from the sale of AP&L's retail properties in Missouri in March 1992 and a decrease in interest expense. Significant factors affecting the results of operations and causing variances between the years 1993 and 1992, and 1992 and 1991, are discussed under "Revenues and Sales", "Expenses", and "Other" below. Revenues and Sales See "Selected Financial Data - Five-Year Comparison," incorporated herein by reference, following the notes, for information on operating revenues by source and KWH sales. Electric operating revenues were higher in 1993 due to an increase in residential and commercial energy sales resulting from a return to more normal weather as compared to milder weather in 1992. Industrial sales increased primarily in the lumber/plywood and petroleum/natural gas pipeline industries. Additionally, electric revenues increased as a result of increased collections of previously deferred Grand Gulf 1-related costs, which does not impact net income. Electric operating revenues were lower in 1992 due primarily to decreased retail revenues resulting from milder temperatures and the loss of the Missouri retail customers. This decrease was partially offset by increased revenues from sales for resale due to the addition of Union Electric as a wholesale customer resulting from the Missouri property sale. Total energy sales were lower in 1992 due primarily to decreased retail sales as discussed above and decreased sales for resale to associated companies resulting from changes in generation availability and requirements among AP&L, LP&L, MP&L, and NOPSI. Expenses Fuel for electric generation and fuel-related expenses increased in 1993 due primarily to an increase in generation requirements resulting primarily from increased retail energy sales and increased fuel costs as discussed in "Revenues and Sales" above. Purchased power decreased in 1993 due primarily to energy demands being met by increased nuclear generation. Scheduled refueling outages at both ANO 1 and ANO 2 during 1992, and an unscheduled outage at ANO 2 from March 1992 to May 1992, contributed to the decrease in fuel for electric generation and fuel-related expenses and the corresponding increase in purchased power in 1992. Lower energy sales in 1992 also contributed to decreased fuel expenses. The amortization of rate deferrals increased in 1993 and 1992 due to increased amortization of previously deferred Grand Gulf 1-related costs pursuant to the step-up provisions of AP&L's phase-in plan. Total income taxes increased in 1993 due primarily to higher pretax income, an increase in the federal income tax rate as a result of OBRA, and the effect of implementing SFAS 109. Other Miscellaneous other income - net decreased in 1993 and increased in 1992 due primarily to the impact of the pretax gain on the 1992 sale of AP&L's retail properties in Missouri. Interest on long-term debt decreased in 1993 due primarily to the continued refinancing of high-cost debt. Other interest - net was higher in 1993 as AP&L began recording decommissioning interest expense on its decommissioning trust fund. This expense has no effect on net income, as decommissioning trust fund earnings are recorded in miscellaneous other income - net. ARKANSAS POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Competition AP&L welcomes competition in the electric energy business and believes that a more competitive environment should benefit our customers, employees, and shareholders of Entergy Corporation. We also recognize that competition presents us with many challenges, and we have identified the following as our major competitive challenges: Retail and Wholesale Rate Issues Increasing competition in the utility industry brings an increased need to stabilize or reduce retail rates In connection with the Merger, AP&L agreed with its retail regulator not to request any general rate increases that would take effect before November 1998, with certain exceptions. See Note 2, incorporated herein by reference, for further information. Retail wheeling, a major industry issue which may require utilities to "wheel" or move power from third parties to their own retail customers, is evolving gradually. As a result, the retail market could become more competitive. In the wholesale rate area, FERC approved in 1992, with certain modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power to sell wholesale power at market-based rates and to provide to electric utilities "open access" to the System's transmission system (subject to certain requirements). GSU was later added to this filing. Various intervenors in the proceeding filed petitions for review with the United States Court of Appeals for the District of Columbia Circuit. FERC's order, once it takes effect, will increase marketing opportunities for AP&L, but will also expose AP&L to the risk of loss of load or reduced revenues due to competition with alternative suppliers. In light of the rate issues discussed above, AP&L is aggressively reducing costs to avoid potential earnings erosions that might result as well as to successfully compete by becoming a low-cost producer. To help minimize future costs, AP&L remains committed to least cost planning. In December 1992, AP&L filed a Least Cost Integrated Resource Plan (Least Cost Plan) with its retail regulator. Least cost planning includes demand-side measures such as customer energy conservation and supply-side measures such as more efficient power plants. These measures are designed to delay the building of new power plants for the next 20 years. AP&L plans to periodically file revised Least Cost Plans. The Energy Policy Act of 1992 The Energy Policy Act of 1992 (Energy Act) is changing the transmission and distribution of electricity. This act encourages competition and affords us the opportunities, and the risks, associated with an open and more competitive market environment. The Energy Act increases competition in the wholesale energy market through the creation of exempt wholesale generators (EWGs). The Energy Act also gives FERC the authority to order investor-owned utilities to provide transmission access to or for other utilities, including EWGs. ANO Matters Leaks in certain steam generator tubes at ANO 2 were discovered and repaired during outages in March and September 1992. During a mid-cycle outage in May 1993, a scheduled special inspection of certain steam generator tubing was conducted by Entergy Operations and additional repairs were made. The operations and power output of ANO 2 have not been adversely affected by these repairs and AP&L's budgeted maintenance expenditures were adequate to cover the cost of such repairs. Entergy Operations is taking steps at ANO 2 to reduce the number and severity of future tube cracks. Entergy Operations met with the NRC in August 1993 to discuss such steps along with recent inspection findings and intervals between future inspections. The NRC concurred with Entergy Operations' proposal to operate ANO 2 with no further steam generator inspections until the next refueling outage, which is scheduled for the spring of 1994. ARKANSAS POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AP&L maintains accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications. Revenues and Fuel Costs Prior to January 1, 1993, AP&L recorded revenues when billed to its customers with no accrual for energy delivered but not yet billed. To provide a better matching of revenues and expenses, effective January 1, 1993, AP&L adopted a change in accounting principle to provide for accrual of estimated unbilled revenues. The cumulative effect of this accounting change as of January 1, 1993, increased net income by $50.2 million. Had this new accounting method been in effect during prior years, net income before the cumulative effect would not have been materially different from that shown in the accompanying financial statements. Substantially all of AP&L's rate schedules include fuel adjustment clauses that allow either current recovery or deferrals of fuel costs until such costs are reflected in the related revenues. The fuel adjustment clause provides, as an incentive with respect to ANO, for over or under-recovery of the cost of replacement energy in excess of the cost of equal amounts of nuclear energy when the units are not down for refueling. Utility Plant Utility plant is stated at original cost. The original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of AP&L's utility plant is subject to the lien of its mortgage and deed of trust. 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 utility plant and increases earnings, it is only realized in cash through depreciation provisions included in rates. AP&L's effective composite rates for AFUDC were 10.3%, 10.5%, and 10.7% for 1993, 1992, and 1991, respectively. Depreciation is computed on the straight-line basis at rates based on the estimated service lives and costs of removal of the various classes of property. Depreciation provisions on average depreciable property approximated 3.4% in 1993, 1992, and 1991. Jointly-Owned Generating Stations AP&L is a co-owner in two coal-fueled, two-unit generating stations, the White Bluff Station and the Independence Station. AP&L is the agent for the respective co-owners and operates the stations. AP&L records its investment and expenses associated with these generating stations to the extent of its ownership interests. As of December 31, 1993, AP&L's investment and accumulated depreciation in these generating stations were as follows:
Total Megawatt Accumulated Generating Stations Capability Ownership Investment Depreciation - ------------------- ---------- --------- ---------- ------------ (In Thousands) White Bluff: Units 1 and 2 946 57.00% $398,644 $140,731 Independence: Unit 1 263 31.50% $116,511 $ 35,797 Common Facilities 15.75% $ 29,163 $ 8,043
Income Taxes AP&L, its parent, and affiliates (excluding GSU prior to 1994) file a consolidated federal income tax return. Income taxes are allocated to AP&L in proportion to its contribution to consolidated taxable income. SEC regulations require that no System company pay more taxes than it would have had a separate income tax return been filed. Deferred taxes are recorded for all temporary differences between book and taxable income. Investment tax credits are deferred and amortized based upon the average useful life of the related property in accordance with rate treatment. As discussed in Note 3, effective January 1, 1993, AP&L changed its accounting for income taxes to conform with SFAS 109. Reacquired Debt The premiums and costs associated with reacquired debt are being amortized over the life of the related new issuances, in accordance with ratemaking treatment. Cash and Cash Equivalents AP&L considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Fair Value Disclosure The estimated fair value amounts of financial instruments have been determined by AP&L, using available market information and appropriate valuation methodologies. However, considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that AP&L could realize in a current market exchange. In addition, gains or losses realized on financial instruments may be reflected in future rates and not accrue to the benefit of stockholders. AP&L considers the carrying amounts of 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. In addition, AP&L does not presently expect that performance of its obligations will be required in connection with certain off-balance sheet commitments and guarantees considered financial instruments. Due to this factor, and because of the related party nature of these commitments and guarantees, determination of fair value is not considered practicable. See Notes 5, 6, and 8 for additional fair value disclosure. NOTE 2. RATE AND REGULATORY MATTERS Rate Agreement In November 1993, AP&L and the APSC entered into a settlement agreement whereby the APSC agreed to withdraw its request for hearing and its objections in the SEC proceeding related to the Merger. In return, AP&L agreed, among other things, (a) that it will not request any general retail rate increase that would take effect before November 3, 1998, except, among other things, for increases associated with the Least Cost Plan, recovery of certain Grand Gulf 1- related costs, excess capacity costs and costs related to the adoption of SFAS 106 that were previously deferred, recovery of certain taxes, and force majeure (defined to include, among other things, war, natural catastrophes, and high inflation); and (b) that its retail ratepayers would be protected from (1) increases in its cost of capital resulting from risks associated with the Merger, (2) recovery of any portion of the acquisition premium or transactional costs associated with the Merger, (3) certain direct allocations of costs associated with GSU's River Bend nuclear unit, and (4) any losses of GSU resulting from resolution of litigation in connection with its ownership of River Bend. Arkansas - Revised Settlement Agreement Pursuant to the terms of the Revised Settlement Agreement, AP&L (1) permanently retains a portion of its Grand Gulf 1-related costs (Retained Share), ranging from 5.67% (stated as a percentage of System Energy's share of Grand Gulf 1) in 1989 to 7.92% in 1994 and all succeeding years of commercial operation of the unit; (2) recovers currently a portion of such costs, ranging from 17.86% in 1989 to 28.08% in 1994 and thereafter; and (3) deferred a portion of such costs for future recovery (Deferred Balance). AP&L is permitted to currently recover carrying charges on the unrecovered portion of the Deferred Balance. For the year ended December 31, 1993, $234 million was billed to AP&L by System Energy. AP&L has the right under the Revised Settlement Agreement to sell capacity and energy available from its Retained Share to third parties, which shall not include AP&L's wholesale customers. In the event AP&L is not able to sell such capacity and energy to such third parties, it has the right to sell the energy available from such capacity, and to date a significant portion has been sold, to its retail customers at a price equal to AP&L's avoided energy cost, which is currently less than AP&L's cost of such energy. The Revised Settlement Agreement requires that a portion of the proceeds from sales of Retained Share capacity and energy to third parties through 1995 be applied to reduce the Deferred Balance. Arkansas - Rate Riders In conjunction with the Revised Settlement Agreement, AP&L was permitted to implement annual updates to the Grand Gulf 1 rate rider, increasing Arkansas retail rates by approximately 3.1% and 2.6% for the years 1992 and 1991, respectively. These increases reflect scheduled phase-in plan increases adjusted for any prior year over or under-collection. Beginning in 1993 and continuing for a five year period, rates will remain at the 1992 level, unless adjustments are made for an over or under-collection of Grand Gulf 1-related costs in excess of $10 million. Although it was not required under the terms of the Grand Gulf 1 rate rider, in 1993 AP&L opted to implement a 0.7% rate refund in 1994 for a cumulative over-recovery amount of $7.3 million. Various other rate riders, which modify non-Grand Gulf 1 rates under the Revised Settlement Agreement, have been implemented with respect to tax adjustments, depreciation, decommissioning costs, and deferred return on excess capacity (which is being recovered over a 10-year period ending in 1998). Missouri Retail Operations In March 1992, AP&L sold its retail properties in Missouri for approximately $68 million. AP&L's retail properties in Missouri constituted less than 2% of its total property. The cash received from the sale, which also included Missouri accounts receivable and material and supplies inventory, was approximately $72 million, which was in excess of book value. The gain on the sale, classified as "Other Income-Miscellaneous" in the 1992 Statement of Income, was approximately $33.7 million, which resulted in a $19.6 million increase in net income after taxes. Under the terms of the contract, AP&L's 28,000 Missouri retail customers became Union Electric customers and AP&L's employees in Missouri became Union Electric employees. The proceeds from this sale were used to redeem all or a portion of certain series of AP&L's outstanding first mortgage bonds at special redemption prices, pursuant to the applicable provisions of AP&L's mortgage and deed of trust. In addition, AP&L has agreed to sell to Union Electric 120 megawatts of capacity and associated energy for an initial period of 10 years, and beginning on January 1, 1995, Union Electric shall also purchase 40 megawatts of peaking capacity from AP&L. NOTE 3. INCOME TAXES Effective January 1, 1993, AP&L adopted SFAS 109. This new standard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that deferred tax balances be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 requires that regulated enterprises recognize adjustments resulting from implementation as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. A substantial majority of the adjustments required by SFAS 109 was recorded to deferred tax balance sheet accounts with offsetting adjustments to regulatory assets and liabilities. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. As a result of the adoption of SFAS 109, 1993 net income was reduced by $2.6 million, assets were increased by $168.2 million, and liabilities were increased by $170.8 million. Income tax expense consisted of the following:
For the Years Ended December 31, ---------------------------------- 1993 1992 1991 ------- ------- ------- (In Thousands) Current: Federal $47,326 $45,932 $34,648 State 10,836 11,156 9,770 ------- ------- ------- Total 58,162 57,088 44,418 ------- ------- ------- Deferred - net: Liberalized depreciation 7,074 4,929 5,885 Alternative minimum tax (2,227) 6,577 6,249 Nuclear refueling and maintenance (2,161) 7,751 (5,001) Deferred purchased power costs (35,896) (14,375) (1,868) Deferred excess capacity costs (4,044) (3,190) (1,609) Unbilled revenue 26,847 (2,474) 3,424 Bond reacquisition costs 14,706 5,184 765 Intangible plant 410 1,941 4,514 Decontamination and decommissioning fund 16,429 - - Other 13,610 (2,853) (1,311) ------- ------- ------- Total 34,748 3,490 11,048 ------- ------- ------- Investment tax credit adjustments - net (10,573) (9,989) (1,600) ------- ------- ------- Recorded income tax expense $82,337 $50,589 $53,866 ======= ======= ======= Charged to operations $18,746 $ 4,058 $22,958 Charged to other income 32,451 46,531 30,908 Charged to cumulative effect 31,140 - - ------- ------- ------- Recorded income tax expense 82,337 50,589 53,866 Income taxes applied against the debt - 1 94 component of AFUDC ------- ------- ------- Total income taxes $82,337 $50,590 $53,960 ======= ======= =======
Total income taxes differ from the amounts computed by applying the statutory federal income tax rate to income before taxes. The reasons for the differences were:
For the Years Ended December 31 ----------------------------------------------------------- 1993 1992 1991 ------------------ ----------------- --------------- % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income -------- ------ ------- ------ ------- ------ (Dollars in Thousands) Computed at statutory rate $100,673 35.0 $61,580 34.0 $67,088 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 12,119 4.2 7,963 4.4 7,409 3.7 Amortization of investment tax credits (11,702) (4.1) (13,285) (7.4) (11,064) (5.6) Depreciation (3,156) (1.1) (6,755) (3.7) (6,122) (3.1) Reversal of tax contingency (3,771) (1.3) - - - - Flow-through/permanent differences (7,669) (2.7) (1,407) (0.8) (76) - Other - net (4,157) (1.4) 2,493 1.4 (3,369) (1.7) -------- ----- ------- ----- ------- ----- Recorded income tax expense 82,337 28.6 50,589 27.9 53,866 27.3 Income taxes applied against debt component of AFUDC - - 1 - 94 - -------- ----- ------- ----- ------- ----- Total income taxes $ 82,337 28.6 $50,590 27.9 $53,960 27.3 ======== ===== ======= ===== ======= =====
Significant components of AP&L's net deferred tax liabilities as of December 31, 1993, were (in thousands): Deferred tax liabilities: Net regulatory assets $ (294,713) Plant related basis differences (458,023) Rate deferrals (229,714) Bond reacquisition (23,604) Decontamination and decommissioning fund (16,429) Other (21,414) ----------- Total $(1,043,897) =========== Deferred tax assets: Alternative minimum tax credit $ 34,137 Nuclear refueling and maintenance 12,035 Accumulated deferred investment tax credit 60,698 Standard coal plant 9,552 Other 18,490 ----------- Total $ 134,912 =========== Net deferred tax liabilities $ (908,985) =========== The alternative minimum tax (AMT) credit as of December 31, 1993, was $34.1 million. This AMT credit can be carried forward indefinitely and will reduce AP&L's federal income tax liability in future years. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized AP&L to effect short-term borrowings up to $125 million, subject to increase to as much as $255 million after further SEC approval. These authorizations are effective through November 30, 1994. As of December 31, 1993, AP&L had unused lines of credit for short-term borrowings of $34 million from banks within its service territory. In addition, AP&L can borrow from the Money Pool, subject to its maximum authorized level of short-term borrowings and the availability of funds. AP&L had $21.4 million in outstanding borrowings under the Money Pool arrangement as of December 31, 1993. NOTE 5. PREFERRED STOCK The number of shares and dollar value of AP&L's preferred stock was:
As of December 31, ------------------------------------------- Shares Call Price Per Authorized and Total Share as of Outstanding Dollar Value December 31, 1993 1992 1993 1992 1993 ------ ------- -------- -------- -------------- (Dollars in Thousands) Without sinking fund: Cumulative, $100 par value: 4.32% Series 70,000 70,000 $ 7,000 $ 7,000 $103.647 4.72% Series 93,500 93,500 9,350 9,350 $107.000 4.56% Series 75,000 75,000 7,500 7,500 $102.830 4.56% 1965 Series 75,000 75,000 7,500 7,500 $102.500 6.08% Series 100,000 100,000 10,000 10,000 $102.830 7.32% Series 100,000 100,000 10,000 10,000 $103.170 7.80% Series 150,000 150,000 15,000 15,000 $103.250 7.40% Series 200,000 200,000 20,000 20,000 $102.800 7.88% Series 150,000 150,000 15,000 15,000 $103.000 Cumulative, $25 par value: 8.84% Series 400,000 400,000 10,000 10,000 $26.560 Cumulative, $0.01 par value: $2.40 Series(1)(2) 2,000,000 2,000,000 50,000 50,000 - $1.96 Series(1)(2) 600,000 600,000 15,000 15,000 - --------- --------- -------- -------- Total without sinking fund 4,013,500 4,013,500 $176,350 $176,350 ========= ========= ======== ======== With sinking fund: Cumulative, $100 par value: 10.60% Series 20,000 40,000 $ 2,000 $ 4,000 $104.090 11.04% Series - 40,000 - 4,000 - 8.52% Series 400,000 425,000 40,000 42,500 $106.390 Cumulative, $25 par value: 9.92% Series 721,085 801,085 18,027 20,027 $26.940 13.28% Series 400,000 600,000 10,000 15,000 $28.220 --------- --------- -------- -------- Total with sinking fund 1,541,085 1,906,085 $ 70,027 $ 85,527 ========= ========= ======== ========
(1) The total dollar value represents the involuntary liquidation value of $25 per share. (2) These series are not redeemable as of December 31, 1993. The fair value of AP&L's preferred stock with sinking fund was estimated to be approximately $74.7 million and $89.3 million as of December 31, 1993 and 1992, respectively. The fair value was determined using quoted market prices or estimates from nationally recognized investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. As of December 31, 1993, AP&L had 2,296,500, 7,478,915, and 12,400,000 shares of cumulative, $100, $25, and $0.01 par value preferred stock, respectively, that were authorized but unissued. Changes in the preferred stock, with and without sinking fund, during the last three years were: Number of Shares ---------------------------------- 1993 1992 1991 --------- -------- --------- Preferred stock issuances: $0.01 par value - 600,000 2,000,000 Preferred stock retirements: $100 par value (85,000) (109,940) (70,060) $25 par value (280,000) (880,000) (280,000) Cash sinking fund requirements for the next five years for preferred stock outstanding as of December 31, 1993 are (in millions): 1994 - $8.0; 1995 - $8.0; 1996 - $7.0; 1997 - $7.0; and 1998 - $4.5. AP&L has the annual non-cumulative option to redeem, at par, additional amounts of certain series of its outstanding preferred stock. Additionally, AP&L has SEC authorization for the acquisition, through December 31, 1995, of up to $150 million of preferred stock. NOTE 6. LONG-TERM DEBT The long-term debt of AP&L as of December 31, 1993 and 1992 was: Maturities Interest Rates From To From To 1993 1992 ---- ---- ----- ------ ---------- ---------- (In Thousands) First Mortgage Bonds 1993 1998 4-5/8% 8-3/4% $ 100,560 $ 116,160 1999 2003 6% 9-3/4% 182,000 217,200 2004 2008 6.65% 7-1/2% 215,000 175,000 2019 2023 7% 10-3/8% 448,818 403,550 Governmental Obligations* 1995 2008 6.125% 10% 83,290 81,708 2009 2021 6-1/8% 11% 202,193 202,193 Long-Term DOE Obligation (Note 8) 101,029 97,959 Unamortized Premium and Discount - Net (16,555) (14,923) ---------- ---------- Total Long-Term Debt 1,316,335 1,278,847 Less Amount Due Within One Year 3,020 17,900 ---------- ---------- Long-Term Debt Excluding Amount Due Within $1,313,315 $1,260,947 One Year ========== ========== * Consists of pollution control bonds, certain series of which are secured by non-interest bearing first mortgage bonds. The fair value of AP&L's long-term debt, excluding long-term DOE obligation, as of December 31, 1993 and 1992 was estimated to be $1,250.8 million and $1,286.6 million, respectively. The fair value was determined using quoted market prices or estimates from nationally recognized investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. For the years 1994, 1995, 1996, 1997 and 1998, AP&L has long-term debt maturities and cash sinking fund requirements (in millions) of $2.2, $27.4, $28.2, $33.5, and $19.4, respectively. In addition, other sinking fund requirements of approximately $.9 million annually may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements. AP&L has regulatory authorization for the issuance and sale through December 31, 1995, of up to $600 million of additional first mortgage bonds (of which $270 million remained available as of December 31, 1993). In addition, AP&L has SEC authorization for the acquisition of not more than $350 million of first mortgage bonds (of which $199 million remained available as of December 31, 1993) and $175 million of pollution control revenue bonds and/or solid waste disposal revenue bonds, issued for the benefit of AP&L through December 31, 1995. NOTE 7. DIVIDEND RESTRICTIONS The indenture relating to AP&L's long-term debt and provisions of the Amended and Restated Articles of Incorporation, as amended, relating to AP&L's preferred stock provide for restrictions on the payment of cash dividends or other distributions on common stock. As of December 31, 1993, $291.3 million of AP&L's retained earnings were restricted against the payment of cash dividends or other distributions on common stock. On February 1, 1994, AP&L paid Entergy Corporation a $17.9 million cash dividend on common stock. NOTE 8. COMMITMENTS AND CONTINGENCIES Capital Requirements and Financing Construction expenditures (excluding nuclear fuel) for the years 1994, 1995, and 1996 are estimated to total $181 million, $172 million, and $175 million, respectively. AP&L will also require $83 million during the period 1994-1996 to meet long-term debt and preferred stock maturities and sinking fund requirements. AP&L plans to meet the above requirements with internally generated funds and cash on hand, supplemented by the issuance of debt and preferred stock. See Notes 5 and 6 regarding the possible refunding, redemption, purchase or other acquisition of certain outstanding series of preferred stock and long-term debt. See Note 12 for information on additional capital requirements related to a February 1994 ice storm. Unit Power Sales Agreement System Energy has agreed to sell all of its 90% owned and leased share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this agreement are paid in consideration for AP&L's 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 approved by FERC, most likely upon Grand Gulf 1's retirement from service. AP&L's monthly obligation for payments under the agreement is approximately $19 million. Availability Agreement AP&L, LP&L, MP&L, and NOPSI are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 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. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Payments or advances under the Availability Agreement are only required if funds available to System Energy from all sources are less than the amount required under the Availability Agreement. 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 have ever been required. In 1989, the Availability Agreement was amended to provide that the write-off of $900 million of Grand Gulf 2 costs would be amortized for Availability Agreement purposes over a period of 27 years, in order to avoid the need for payments by AP&L, LP&L, MP&L, and NOPSI. Reallocation Agreement System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation Agreement relating to the sale of capacity and energy from the Grand Gulf Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and obligations with respect to the Grand Gulf Station under the Availability Agreement. FERC's decision allocating a portion of Grand Gulf 1 capacity and energy to AP&L supersedes the Reallocation Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect AP&L's obligation to System Energy's lenders under the assignments referred to in the preceding paragraph. AP&L would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual obligations. No payments of any amortization amounts will be required as 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. System Fuels AP&L has a 35% interest in System Fuels, a jointly owned subsidiary of AP&L, LP&L, MP&L, and NOPSI. The parent companies of System Fuels, including AP&L, agreed to make loans to System Fuels to finance its fuel procurement, delivery, and storage activities. As of December 31, 1993, AP&L had approximately $11 million of loans outstanding to System Fuels which mature in 2008. In addition, System Fuels entered into a revolving credit agreement with a bank that provides $45 million in borrowings to finance System Fuels' nuclear materials and services inventory. Should System Fuels default on its obligations under its credit agreement, AP&L, LP&L, and System Energy have agreed to purchase nuclear materials and services financed under the agreement. On April 30, 1993, AP&L assumed System Fuels' rights and obligations in connection with System Fuels' coal car leases. The other parent companies of System Fuels have been released from their obligations with respect to the coal car leases. Coal AP&L is a party to a contract with a joint venture for supply of coal from a mine in Wyoming which, based on estimated reserves, is expected to provide the projected requirements of the Independence Station through at least 2014. AP&L has also agreed to purchase, over an approximate 20-year period beginning in 1980, 100 million tons of coal for use at the White Bluff Station, of which approximately 60 million have been purchased as of December 31, 1993. Nuclear Insurance The Price-Anderson Act limits public liability for a single nuclear incident to approximately $9.4 billion as of December 31, 1993. AP&L has protection for this liability through a combination of private insurance (currently $200 million) and an industry assessment program. Under the assessment program, the maximum amount that would be required for each nuclear incident would be $79.28 million per reactor, payable at a rate of $10 million per licensed reactor per incident per year. AP&L has two licensed reactors. In addition, the System participates in a private insurance program which provides coverage for worker tort claims filed for bodily injury caused by radiation exposure. AP&L's maximum assessment under the program is an aggregate of approximately $6.2 million in the event losses exceed accumulated reserve funds. AP&L is a member of certain insurance programs that provide coverage for property damage, including decontamination and premature decommissioning expense, to members' nuclear generating plants. As of December 31, 1993, AP&L was insured against such losses up to $2.7 billion, with $250 million of this amount designated to cover any shortfall in the NRC required decommissioning trust funding. In addition, AP&L is a member of an insurance program that covers certain replacement power and business interruption costs incurred due to prolonged nuclear unit outages. Under the property damage and replacement power/business interruption insurance programs, AP&L could be subject to assessments if losses exceed the accumulated funds available to the insurers. As of December 31, 1993, the maximum amount of such possible assessments to AP&L was $28.14 million. The amount of property insurance presently carried by AP&L exceeds the NRC's minimum requirement for nuclear power plant licensees of $1.06 billion per site. NRC regulations provide that the proceeds of this insurance must be used, first, to place and maintain the reactor in a safe and stable condition 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. Spent Nuclear Fuel and Decommissioning Costs AP&L provides for estimated future disposal costs for spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. AP&L entered into a contract 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. AP&L elected to pay the one-time fee, plus accrued interest, and has recorded a liability as of December 31, 1993, of approximately $101 million. The fees payable to the DOE may be adjusted in the future to assure full recovery. AP&L considers all costs incurred or to be incurred, except accrued interest, for the disposal of spent nuclear fuel to be proper components of nuclear fuel expense and provisions to recover such costs have been or will be made in applications to regulatory authorities. Due to delays of the DOE's repository program for the acceptance of spent nuclear fuel, it is uncertain when shipments of spent fuel from AP&L's nuclear units will commence. In the meantime, AP&L is responsible for spent fuel storage. Current on-site spent fuel storage capacity at ANO is estimated to be sufficient until 1995. Thereafter, AP&L will provide additional storage capacity at an estimated initial cost of $5 million to $10 million per unit. In addition, approximately $3 million to $5 million per unit will be required every two to three years subsequent to 1995 until the DOE's repository program begins accepting ANO's spent fuel. AP&L is recovering in rates amounts sufficient to fund decommissioning costs for ANO, based on a 1992 update to the original decommissioning cost study, of approximately $606.8 million (in 1992 dollars). These amounts are deposited in external trust funds which have a market value of approximately $124.3 million and $101.3 million as of December 31, 1993 and 1992, respectively. The accumulated decommissioning liability of $119.2 million as of December 31, 1993, has been recorded in accumulated depreciation.. Decommissioning expense in the amount of $11.0 million was recorded in 1993. During the first quarter of 1994, AP&L expects to file with the APSC an interim update of the ANO cost study which will likely reflect significant increases in costs of low-level radioactive waste disposal. AP&L regularly reviews and updates its estimates for decommissioning costs and applications will be made to the APSC to reflect in rates future changes in projected decommissioning costs. The actual decommissioning costs may vary from the above estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment, and management believes that actual decommissioning costs are likely to be higher than the amounts presented above. The Energy Act has a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning of the DOE's past uranium enrichment operations. The decontamination and decommissioning assessments will be used to set up a fund into which contributions from utilities and the federal government will be placed. AP&L's annual assessment, which will be adjusted annually for inflation, is approximately $3.3 million (in 1993 dollars) for approximately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortized. The liability of $45.7 million as of December 31, 1993 is recorded in other current liabilities and other noncurrent liabilities and is offset in the financial statements by a regulatory asset, recorded as a deferred debit. NOTE 9. LEASES As of December 31, 1993, AP&L had capital leases and noncancelable operating leases (excluding the nuclear fuel lease) with minimum lease payments as follows: Capital Operating Leases Leases -------- --------- (In Thousands) 1994 $ 13,189 $17,284 1995 13,544 17,229 1996 11,127 16,068 1997 8,293 10,548 1998 8,293 10,514 Years thereafter 56,989 21,908 -------- ------- Minimum lease payments 111,435 $93,551 Less: Amount representing interest (47,674) ======= ------- Present value of net minimum lease payments $63,761 ======= Rental expense for capital and operating leases (excluding the nuclear fuel lease) amounted to approximately $23.2 million, $27.4 million, and $26.2 million in 1993, 1992, and 1991, respectively. Nuclear Fuel Lease AP&L has an arrangement to lease nuclear fuel in an amount of up to $125 million.. The lessor finances its acquisition of nuclear fuel through a credit agreement and the issuance of notes. The credit agreement, which was entered into in 1988, has been extended to December 1996 and the notes have varying remaining maturities of up to 4 years. It is expected that these arrangements will be extended or alternative financing will be secured by the lessor upon the maturity of the current arrangements, based on AP&L's nuclear fuel requirements. If the lessor cannot arrange financing upon maturity of its borrowings, AP&L must purchase nuclear fuel in an amount sufficient to enable the lessor to retire such borrowings. Lease payments are based on nuclear fuel use. Nuclear fuel lease expense of $69.7 million, $65.5 million, and $76.9 million (including interest of $10.6 million, $11.6 million, and $14.0 million) was charged to operations in 1993, 1992, and 1991, respectively. NOTE 10. POSTRETIREMENT BENEFITS Pension Plan AP&L has a defined benefit pension plan covering substantially all of its employees. The pension plan is noncontributory and provides pension benefits that are based on employees' credited service and average compensation, during the last ten years of employment. AP&L funds 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 plan consist primarily of common and preferred stocks, fixed income securities, interest in a money market fund, and insurance contracts. Effective June 6, 1990, AP&L's nuclear operations employees became employees of Entergy Operations. However, the employees still remain under AP&L's plan and no transfers of related pension liabilities and assets have been made. AP&L's 1993, 1992, and 1991 pension cost, including amounts capitalized, included the following components:
For the Years Ended December 31, -------------------------------- 1993 1992 1991 ------- ------- ------- (In Thousands) Service cost - benefits earned during the period $ 7,940 $ 6,906 $ 6,210 Interest cost on projected benefit obligation 21,744 20,512 18,505 Actual return on plan assets (31,984) (16,765) (47,707) Net amortization and deferral 10,531 (3,531) 28,377 Other - - 915 ------- ------- ------- Net pension cost $ 8,231 $ 7,122 $ 6,300 ======= ======= =======
The funded status of AP&L's pension plan as of December 31, 1993 and 1992, was:
1993 1992 -------- -------- (In Thousands) Actuarial present value of accumulated pension plan benefits: Vested $255,955 $228,237 Nonvested 1,724 1,231 -------- -------- Accumulated benefit obligation $257,679 $229,468 ======== ======== Plan assets at fair value $288,418 $255,956 Projected benefit obligation 316,255 272,148 -------- -------- Plan assets less than projected benefit obligation (27,837) (16,192) Unrecognized prior service cost 5,841 6,168 Unrecognized transition asset (18,686) (21,022) Unrecognized net loss (gain) 13,242 (5,806) -------- -------- Accrued pension liability $(27,440) $(36,852) ======== ======== The significant actuarial assumptions used in computing the information above for 1993, 1992, and 1991 were as follows: weighted average discount rate, 7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in future compensation levels, 5.6%; and expected long-term rate of return on plan assets, 8.5%. Transition assets are being amortized over 15 years. Other Postretirement Benefits AP&L also provides certain 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 AP&L. The cost of providing these benefits, recorded on a cash basis, to retirees in 1992 was approximately $3.5 million. Prior to 1992, the cost of providing these benefits for retired employees was not separable from the cost of providing benefits for active employees. Based on the ratio of the number of retired employees to the total number of active and retired employees in 1991, the cost of providing these benefits in 1991, recorded on a cash basis, for retirees was approximately $4.1 million. Effective January 1, 1993, AP&L adopted SFAS 106. The new standard requires a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. AP&L continues to fund these benefits on a pay-as-you-go basis. As of January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $80.5 million. This obligation is being amortized over a 20-year period beginning in 1993. AP&L has received an order from the APSC permitting deferral, as a regulatory asset, of the increased annual expense associated with these benefits. AP&L's 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components (in thousands): Service cost - benefits earned during the period $ 2,366 Interest cost on APBO 6,427 Actual return on plan assets (71) Amortization of transition obligation 3,954 ------- Net periodic postretirement benefit cost $12,676 ======= The funded status of AP&L's postretirement plan as of December 31, 1993, was (in thousands): Accumulated postretirement benefit obligation: Retirees $59,906 Other fully eligible participants 8,366 Other active participants 25,038 ------- 93,310 Plan assets at fair value 354 ------- Plan assets less than APBO (92,956) Unrecognized transition obligation 75,114 Unrecognized net loss 8,360 ------- Accrued postretirement benefit liability $(9,482) ======= The assumed health care cost trend rate used in measuring the APBO was 9.9% for 1994, gradually decreasing each successive year until it reaches 5.6% in 2020. A one percentage-point increase in the assumed health care cost trend rate for each year would have increased the APBO as of December 31, 1993, by 8.7 % and the sum of the service cost and interest cost by approximately 11.2%. The assumed discount rate and rate of increase in future compensation used in determining the APBO were 7.5% and 5.5%, respectively. NOTE 11. TRANSACTIONS WITH AFFILIATES AP&L buys electricity from and/or sells electricity to LP&L, MP&L, NOPSI, System Energy, and Entergy Power under rate schedules filed with FERC. In addition, AP&L purchases fuel from System Fuels, receives technical and advisory services from Entergy Services, Inc. and receives management and operating services from Entergy Operations. Operating revenues include revenues from sales to affiliates amounting to $181.8 million in 1993, $211.4 million in 1992, and $212.6 million in 1991. Operating expenses include charges from affiliates for fuel costs, purchased power and related charges, management services, and technical and advisory services totaling $323.2 million in 1993, $573.4 million in 1992, and $510.1 million in 1991. Operating expenses also include $16.8 million in 1993, $47.4 million in 1992, and $33.4 million in 1991 for power purchased from Entergy Power. AP&L pays directly or reimburses Entergy Operations for the costs associated with operating ANO (excluding nuclear fuel), which were approximately $226.3 million in 1993, $292.3 million in 1992, and $248.6 million in 1991. NOTE 12. SUBSEQUENT EVENT (UNAUDITED) In early February 1994, an ice storm left more than 97,000 AP&L customers without electric power in its service area. The storm was the most severe natural disaster ever to affect AP&L, causing damage to transmission and distribution lines, equipment, poles, and facilities in certain areas. A substantial portion of the related costs, which are estimated to be $25 million to $35 million, are expected to be capitalized. Estimated construction expenditures (see Note 8) have not yet been updated to reflect the above amounts. NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED) AP&L's business is subject to seasonal fluctuations with the peak period occurring during the third quarter. Operating results for the four quarters of 1993 and 1992 were: Operating Operating Net Revenues Income Income --------- --------- -------- (In Thousands) 1993: First Quarter (1) $346,740 $ 36,961 $66,081 Second Quarter $383,651 $ 53,332 $34,572 Third Quarter $519,822 $101,484 $81,677 Fourth Quarter $341,355 $ 44,445 $22,967 1992: First Quarter (2) $338,996 $ 39,402 $41,725 Second Quarter $347,224 $ 31,239 $14,052 Third Quarter $465,130 $ 79,006 $62,059 Fourth Quarter $369,779 $ 30,126 $12,693 (1) The first quarter of 1993 reflects a nonrecurring increase in net income of $50.2 million, net of taxes of $31.1 million, due to the recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1). Beginning with the second quarter, the remaining quarters are not generally comparable to prior year quarters because of the ongoing effects of the accounting change. (2) The first quarter of 1992 reflects a nonrecurring increase in net income of $19.6 million, net of tax, due to the sale of retail properties in Missouri (see Note 2). ARKANSAS POWER & LIGHT COMPANY SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1993 1992 1991 1990 1989 ---------- ---------- ---------- ---------- ---------- (In Thousands) Operating revenues $1,591,568 $1,521,129 $1,528,270 $1,481,408 $1,381,871 Income before cumulative effect of a change in accounting principle $ 155,110 $ 130,529 $ 143,451 $ 129,765 $ 131,979 Total assets $4,334,105 $4,038,811 $4,192,020 $4,137,938 $4,059,596 Long-term obligations (1) $1,478,203 $1,453,588 $1,670,678 $1,731,212 $1,584,749
(1) Includes long-term debt (excluding currently maturing debt), preferred stock with sinking fund, and noncurrent capital lease obligations. See Notes 1, 3, and 10 for the effect of accounting changes in 1993.
1993 1992 1991 1990 1989 ---------- ---------- ---------- ---------- ---------- (Dollars in Thousands) Operating Revenues: Residential $ 528,734 $ 476,090 $ 494,375 $ 484,359 $ 425,568 Commercial 306,742 291,367 289,291 283,971 254,636 Industrial 336,856 325,569 324,632 331,929 307,853 Governmental 16,670 17,700 19,731 19,599 20,990 ---------- ---------- ---------- ---------- ---------- Total retail 1,189,002 1,110,726 1,128,029 1,119,858 1,009,047 Sales for resale 379,480 385,028 373,735 339,366 345,377 Other 23,086 25,375 26,506 22,184 27,447 ---------- ---------- ---------- ---------- ---------- Total $1,591,568 $1,521,129 $1,528,270 $1,481,408 $1,381,871 ========== ========== ========== ========== ========== Billed Electric Energy Sales (Millions of KWH): Residential 5,680 5,102 5,564 5,401 5,098 Commercial 4,067 3,841 3,967 3,821 3,644 Industrial 5,690 5,509 5,565 5,532 5,513 Governmental 230 248 290 285 320 ---------- ---------- ---------- ---------- ---------- Total retail 15,667 14,700 15,386 15,039 14,575 Sales for resale 13,950 15,413 16,087 13,618 12,128 ---------- ---------- ---------- ---------- ---------- Total 29,617 30,113 31,473 28,657 26,703 ========== ========== ========== ========== ==========
Gulf States Utilities Company 1993 Financial Statements GULF STATES UTILITIES COMPANY DEFINITIONS Certain abbreviations or acronyms used in GSU's Financial Statements, Notes to Financial Statements, and Management's Financial Discussion and Analysis are defined below: Abbreviation or Acronym Term AFUDC Allowance for Funds Used During Construction AP&L Arkansas Power & Light Company Cajun Cajun Electric Power Cooperative, Inc. DOE United States Department of Energy Entergy or System Entergy Corporation and its various direct and indirect subsidiaries Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy that has operating responsibility for Grand Gulf 1, River Bend, Waterford 3, and Arkansas Nuclear One Steam Electric Generating Station FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission GSU Gulf States Utilities Company (including wholly owned subsidiaries - Varibus Corporation, GSG&T, Inc., Prudential Oil and Gas, Inc., and Southern Gulf Railway Company) KWH Kilowatt-Hour(s) LP&L Louisiana Power & Light Company LPSC Louisiana Public Service Commission Money Pool Entergy Money Pool, which allows certain System companies to borrow from, or lend to, certain other System companies MP&L Mississippi Power & Light Company Merger The combination transaction consummated on December 31, 1993, by which GSU became a subsidiary of Entergy Corporation and Entergy Corporation became a Delaware corporation NOPSI New Orleans Public Service Inc. PUCT Public Utility Commission of Texas Rate Cap The level of retail electric base rates in effect at December 31, 1993, for the Louisiana retail jurisdiction, and the level in effect prior to the Texas Cities Rate Settlement for the Texas retail jurisdiction, that may not be exceeded for the five years following December 31, 1993 River Bend River Bend Steam Electric Generating Station (nuclear), owned 70% by GSU SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the FASB SFAS 106 SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS No. 109, "Accounting for Income Taxes" System or Entergy Entergy Corporation and its various direct and indirect subsidiaries System Agreement Agreement, effective January 1, 1983, as amended among the System operating companies relating to the sharing of generating capacity and other power resources System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively GULF STATES UTILITIES COMPANY REPORT OF MANAGEMENT The management of Gulf States Utilities Company has prepared and is responsible for the financial statements and related financial information included herein. The financial statements are based on generally accepted accounting principles. Financial information included elsewhere in this report is consistent with the financial statements. To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls that is designed to provide reasonable assurance, on a cost-effective basis, as to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. This system includes communication through written policies and procedures, an employee Code of Conduct, 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. The independent public accountants provide an objective assessment of the degree to which 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 these policies and procedures provide reasonable assurance that its operations are carried out with a high standard of business conduct. /S/ EDWIN LUPBERGER /S/ GERALD D. MCINVALE EDWIN LUPBERGER GERALD D. MCINVALE Chairman and Chief Executive Officer Senior Vice President and Chief Financial Officer GULF STATES UTILITIES COMPANY AUDIT COMMITTEE CHAIRMAN'S LETTER The Gulf States Utilities Company Audit Committee of the Board of Directors is comprised of four directors, who are not officers of GSU: Bismark A. Steinhagen (Chairman-effective January 2, 1994), Frank W. Harrison, Jr., M. Bookman Peters, and James E. Taussig, II. The committee held two meetings during 1993. The Audit Committee oversees GSU's financial reporting process on behalf of the Board of Directors and provides reasonable assurance to the Board that sufficient operating, accounting, and financial controls are in existence and are adequately reviewed by programs of internal and external audits. The Audit Committee discussed with GSU's internal auditors and the independent public accountants (Coopers & Lybrand) the overall scope and specific plans for their respective audits, as well as GSU's financial statements and the adequacy of GSU's internal controls. The committee met, together and separately, with GSU's internal auditors and independent public accountants, without management present, to discuss the results of their audits, their evaluation of GSU's internal controls, and the overall quality of GSU's financial reporting. The meetings also were designed to facilitate and encourage any private communication between the committee and the internal auditors or independent public accountants. /S/ BISMARK A. STEINHAGEN BISMARK A. STEINHAGEN Chairman, Audit Committee INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directors of Gulf States Utilities Company We have audited the accompanying balance sheets of Gulf States Utilities Company as of December 31, 1993 and 1992 and the related statements of income, retained earnings and paid in capital and cash flows for each of the three years in the period ended December 31, 1993. 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 generally accepted auditing standards. 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. As discussed in Note 12 to the financial statements, the common stock of the Company was acquired on December 31, 1993. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Gulf States Utilities Company as of December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. As discussed in Note 2 to the financial statements, the net amount of capitalized costs for the Company's River Bend Unit I Nuclear Generating Plant (River Bend) exceed those costs currently being recovered through rates. At December 31, 1993, approximately $747 million is not currently being recovered through rates. If current regulatory and court orders are not modified, a write-off of all or a portion of such costs may be required. Additionally, as discussed in Note 2 to the financial statements, other rate-related contingencies exist which may result in a refund of revenues previously collected. The extent of such write-off of River Bend costs or refund of revenues previously collected, if any, will not be determined until appropriate rate proceedings and court appeals have been concluded. Accordingly, no provision for write-off or refund has been recorded in the accompanying financial statements. As discussed in Note 8 to the financial statements, civil actions have been initiated against the Company to, among other things, recover the co-owner's investment in River Bend and to annul the River Bend Joint Ownership Participation and Operating Agreement. The ultimate outcome of these proceedings cannot presently be determined. Accordingly, no provision for any liability that may result from the ultimate resolution of these proceedings has been recorded in the accompanying financial statements. As discussed in Note 3 to the financial statements, in 1993, the Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes", and elected to restate the 1991 and 1992 financial statements for its effects. As discussed in Note 10 to the financial statements, the Company adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", as of January 1, 1993. As discussed in Note 1 to the financial statements, as of January 1, 1993, the Company began accruing revenues for energy delivered to customers but not yet billed. As discussed in Note 1 to the financial statements, the Company changed its accounting for power plant materials and supplies as of January 1, 1992. /S/ COOPERS & LYBRAND COOPERS & LYBRAND Houston, Texas February 11, 1994
GULF STATES UTILITIES COMPANY BALANCE SHEETS ASSETS December 31, ----------------------------- 1993 1992 ---------- ---------- (In Thousands) Utility Plant (Notes 1 and 2): Electric $6,825,989 $6,770,017 Natural gas 42,786 41,160 Steam products 75,689 72,292 Property under capital leases (Note 9) 86,039 87,214 Construction work in progress 50,080 32,305 Nuclear fuel under capital leases (Note 9) 94,828 106,565 ---------- ---------- Total 7,175,411 7,109,553 Less - accumulated depreciation and amortization 2,323,804 2,172,719 ---------- ---------- Utility plant - net 4,851,607 4,936,834 ---------- ---------- Other Property and Investments: Decommissioning trust fund (Note 8) 17,873 14,102 Other - at cost (less accumulated depreciation) 29,360 36,225 ---------- ---------- Total 47,233 50,327 ---------- ---------- Current Assets: Cash and cash equivalents (Note 1): Cash 3,012 720 Temporary cash investments - at cost, which approximates market 258,337 197,021 ---------- ---------- Total cash and cash equivalents 261,349 197,741 Accounts receivable: Customer (less allowance for doubtful accounts of $2.4 million in 1993 and $3.0 million in 1992) 117,369 124,214 Other 18,371 18,405 Accrued unbilled revenues (Note 1) 32,572 - Deferred fuel costs (Note 1) 5,883 - Fuel inventory (Note 1) 23,448 21,159 Materials and supplies - at average cost 86,831 86,972 Rate deferrals (Note 2) 90,775 85,473 Accumulated deferred income taxes (Note 3) 28,425 91,731 Prepayments and other 48,948 38,314 ---------- ---------- Total 713,971 664,009 ---------- ---------- Deferred Debits and Other Assets: Rate deferrals (Note 2) 638,015 728,790 SFAS 109 regulatory asset - net (Note 3) 432,411 357,253 Long-term receivables 218,079 191,269 Unamortized loss on reacquired debt 70,970 67,074 Other 193,490 168,891 ---------- ---------- Total 1,552,965 1,513,277 ---------- ---------- TOTAL $7,165,776 $7,164,447 ========== ========== See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES
December 31, ----------------------------- 1993 1992 ---------- ----------- (In Thousands) Capitalization: Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 100 shares at December 31, 1993 (Notes 5 and 12) $114,055 $1,200,923 Paid-in capital 1,152,304 67,316 Retained earnings (Notes 3 and 7) 666,401 631,462 ---------- ---------- Total common shareholder's equity 1,932,760 1,899,701 Preference stock (Note 5) 150,000 - Preferred stock (Note 5): Without sinking fund 136,444 136,444 With sinking fund 101,004 269,387 Long-term debt (Note 6) 2,368,639 2,374,458 ---------- ---------- Total 4,688,847 4,679,990 ---------- ---------- Other Noncurrent Liabilities: Obligations under capital leases (Note 9) 152,359 154,923 Other (Note 8) 47,107 18,865 ---------- ---------- Total 199,466 173,788 ---------- ---------- Current Liabilities: Currently maturing long-term debt 425 160,425 Accounts payable: Associated companies (Note 11) 2,745 - Other 109,840 101,513 Customer deposits 21,958 21,152 Taxes accrued 22,856 19,092 Interest accrued 59,516 62,013 Nuclear refueling reserve 22,356 10,083 Deferred fuel cost (Note 1) - 36,954 Obligations under capital leases (Note 9) 41,713 51,688 Other 97,203 66,534 ---------- ---------- Total 378,612 529,454 ---------- ---------- Deferred Credits: Accumulated deferred income taxes (Note 3) 1,252,295 1,192,182 Accumulated deferred investment tax credits (Note 3) 94,455 94,690 Deferred River Bend finance charges 106,765 131,123 Other 445,336 363,220 ---------- ---------- Total 1,898,851 1,781,215 ---------- ---------- Commitments and Contingencies (Notes 2, 8, and 9) TOTAL $7,165,776 $7,164,447 ========== ========== See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY STATEMENTS OF CASH FLOWS
For the Years Ended December 31, ------------------------------------------ 1993 1992 1991 -------- ---------- -------- (In Thousands) Operating Activities: Net income $78,862 $133,848 $112,030 Noncash items included in net income: Extraordinary items 1,259 9,597 361 Cumulative effect of accounting changes (10,660) (4,032) - Change in rate deferrals 61,115 52,946 38,236 Depreciation and decommissioning 190,405 188,393 187,936 Deferred income taxes and investment tax credits 41,302 50,238 43,504 Allowance for equity funds used during construction (726) (1,226) (608) Changes in working capital: Receivables 6,879 4,373 (12,503) Fuel inventory (2,289) (4,152) 10,422 Accounts payable 11,072 (1,171) (6,912) Taxes accrued 3,764 (2,634) 753 Interest accrued (2,497) (15,276) 3,211 Other working capital accounts (9,582) (13,675) 12,602 Decommissioning trust contributions 2,710 5,912 2,315 Purchased power settlement (169,300) (20,797) 12,565 Other 53,121 (34,816) 29,833 -------- ---------- -------- Net cash flow provided by operating activities 255,435 347,528 433,745 -------- ---------- -------- Investing Construction expenditures (115,481) (97,377) (87,470) Proceeds received from sale of property - 12,460 - Allowance for equity funds used during construction 726 1,226 608 Nuclear fuel purchases (2,118) - - Proceeds from sale/leaseback of nuclear fuel 2,118 - - Other property, investments and escrow account 5,921 13,091 10,070 -------- ---------- -------- Net cash flow used in investing activities (108,834) (70,600) (76,792) -------- ---------- -------- Financing Activities: Proceeds from issuance of: First mortgage bonds 338,379 1,185,260 - Preference stock 146,625 - - Other long-term debt 21,440 48,965 200,000 Retirement of: First mortgage bonds (360,199) (1,067,717) (87,320) Other long-term debt (18,398) (127,161) (245,762) Redemption of preferred and preference stock (174,841) (174,226) - Dividends paid: Preferred and preference stock (35,999) (237,369) (127,398) -------- ---------- -------- Net cash flow used in financing activities (82,993) (372,248) (260,480) -------- ---------- -------- Net increase (decrease) in cash and cash equivalents 63,608 (95,320) 96,473 Cash and cash equivalents at beginning of period 197,741 293,061 196,588 -------- ---------- Cash and cash equivalents at end of period $261,349 $197,741 $293,061 ======== ========== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $197,058 $239,607 $227,306 Income taxes $15,600 $8,000 $5,700 Noncash investing and financing activities: Capital lease obligations incurred $17,143 $87,022 $13,958 See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES Liquidity is important to GSU due to the capital intensive nature of our business, which requires large investments in long-lived assets. However, large capital expenditures for the construction of new generating capacity are not currently planned. GSU requires significant capital resources for the periodic maturity of certain series of debt, preferred stock, and preference stock. Net cash flow from operations totaled $255 million, $348 million, and $434 million in 1993, 1992, and 1991, respectively. Cash flow from operations in 1993 includes nonrecurring items related to the payment of $169.3 million as a result of the settlement of a purchased power dispute. In recent years, this cash flow, supplemented by cash on hand, has been sufficient to meet substantially all investing and financing requirements, including capital expenditures, preferred and preference dividends, and debt/preferred stock maturities. GSU's ability to fund these capital requirements with cash from operations, results in part from our continued efforts to reduce costs as well as collections under our River Bend rate phase-in plan of previously deferred amounts. (In the income statement, these revenue collections are offset by the amortization of previously deferred costs, therefore, there is no effect on net income.) See Note 2, incorporated herein by reference, for additional information on GSU's rate phase-in plan. Further, GSU has the ability to meet future capital requirements through future debt and preference stock issuances, as discussed below. See Note 8, incorporated herein by reference, for additional information on GSU's capital and refinancing requirements in 1994 through 1996. Further, in order to take advantage of lower interest and dividend rates, GSU continues to refinance high-cost debt and preferred stock prior to maturity. In February 1994, GSU paid to Entergy Corporation a $100 million cash dividend on common stock. Prior to the February 1994 dividend payment, GSU had not paid a common dividend since June 1986. Earnings coverage tests (which are impacted by the inclusion of the cumulative effect of the change in accounting principle for accruing unbilled revenues discussed in Note 1) and bondable property additions limit the amount of first mortgage bonds and preferred stock that GSU can issue. Based on the most restrictive applicable tests as of December 31, 1993, and an assumed annual interest rate of 8%, GSU could have issued $425 million of additional first mortgage bonds. As of December 31, 1993, GSU was unable to issue any additional preferred stock. There are no limitations on the issuance of preference stock. GSU has the conditional ability to issue first mortgage bonds against the retirement of first mortgage bonds without satisfying an earnings coverage test. See Notes 5 and 6, incorporated herein by reference, for information on GSU's financing activities and Note 4, incorporated herein by reference, for information on GSU's short-term borrowings and lines of credit. See Notes 2 and 8 regarding River Bend rate appeals and litigation with Cajun. Substantial write-offs or charges resulting from adverse rulings in these matters could adversely affect GSU's ability to continue to pay dividends and obtain financing, which could in turn affect GSU's liquidity. GULF STATES UTILITIES COMPANY STATEMENTS OF INCOME
For the Years Ended December 31, ----------------------------------------- 1993 1992 1991 ---------- ---------- ---------- (In Thousands) Operating Revenues (Notes 1 and 2): Electric $1,747,961 $1,694,536 $1,623,959 Natural gas 32,466 28,523 31,858 Steam products 47,193 50,315 46,418 ---------- ---------- ---------- Total 1,827,620 1,773,374 1,702,235 ---------- ---------- ---------- Operating Expenses: Operation: Fuel for electric generation and fuel-related expenses 538,887 471,873 446,543 Purchased power 134,936 136,716 161,374 Gas purchased for resale 20,529 16,563 19,290 Other 324,617 277,385 248,302 Maintenance 144,766 161,080 142,098 Depreciation and decommissioning 190,405 188,393 187,936 Taxes other than income taxes 95,742 91,740 88,402 Income taxes (Note 3) 46,007 38,058 35,084 Amortization of rate deferrals (Note 2) 61,115 52,946 38,236 ---------- ---------- ---------- Total 1,557,004 1,434,754 1,367,265 ---------- ---------- ---------- Operating Income 270,616 338,620 334,970 ---------- ---------- ---------- Other Income: Allowance for equity funds used during construction 726 1,226 608 Miscellaneous - net 19,996 64,837 49,947 Income taxes (Note 3) (12,009) (17,801) (13,166) ---------- ---------- ---------- Total 8,713 48,262 37,389 Interest Charges: Interest on long-term debt 202,235 239,341 234,418 Other interest - net 8,364 9,075 26,038 Allowance for borrowed funds used during construction (731) (947) (488) ---------- ---------- ---------- Total 209,868 247,469 259,968 ---------- ---------- ---------- Income before Extraordinary Items and the Cumulative Effect of Accounting Changes 69,461 139,413 112,391 Extraordinary Items (net of income taxes) (Note 1) (1,259) (9,597) (361) Cumulative Effect of Accounting Changes (net of income taxes) (Note 1) 10,660 4,032 - ---------- ---------- ---------- Net Income 78,862 133,848 112,030 Preferred and Preference Stock Dividend Requirements 35,581 49,702 63,070 ---------- ---------- ---------- Earnings Applicable to Common Stock $43,281 $84,146 $48,960 ========== ========== ========== See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL
For the Years Ended December 31, ---------------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Retained Earnings, January 1 (Note 3) $631,462 $667,893 $622,026 Add - Net income 78,862 133,848 112,030 Total 710,324 801,741 734,056 Deduct: Dividends declared: Preferred and preference stock 35,581 158,547 66,163 Common stock - - - Preferred and preference stock redemption 8,342 11,732 - -------- -------- -------- Total 43,923 170,279 66,163 -------- -------- -------- Retained Earnings, December 31 (Note 7) $666,401 $631,462 $667,893 ======== ======== ======== Paid-in Capital, January 1 $67,316 $73,993 $22,237 Issuance of 100 shares of no par common stock with a stated value of $114,055 net of the retirement of 114,055,065 shares of no par common stock (Notes 5 and 12) 1,086,868 - - Issuance of 6,000,000 shares of common stock in the settlement of purchased power dispute - - 51,775 Loss on reacquisition of preferred and preference stock (1,880) (6,677) (19) ---------- -------- -------- Paid-in Capital, December 31 $1,152,304 $67,316 $73,993 ========== ======== ======== See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income decreased in 1993 due primarily to Merger-related charges recorded at year-end. Also contributing to the decrease was a rate refund and one-time credit resulting from a November 1993 rate settlement (see Note 2, incorporated herein by reference), the effect of implementing SFAS 106 (see Note 10, incorporated herein by reference), and the impact in 1992 of reducing a purchased power settlement liability. The decrease in net income was partially offset by the one-time recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1, incorporated herein by reference) and its ongoing effects. Effective January 1, 1993, GSU began accruing as revenues the charges for energy delivered to customers but not yet billed. Electric and gas revenues were previously recorded on a cycle-billing basis. Excluding the above mentioned items, net income for 1993 would have been $139.2 million and net income for 1992 would have been $109.6 million. This increase of $29.6 million is due primarily to increased retail energy sales and decreased interest expense. Net income increased in 1992 due primarily to increased revenues, reduced interest charges, and reductions to a previously recorded purchased power settlement liability. Significant factors affecting the results of operations and causing variances between the years 1993 and 1992, and 1992 and 1991 are discussed under "Revenues and Sales," "Expenses," and "Other" below. Revenues and Sales Operating revenues were higher in 1993 due primarily to increased residential and commercial energy sales resulting primarily from a return to more normal weather as compared to milder weather in 1992, and increased fuel adjustment revenues and collections of previously deferred River Bend costs, neither of which affects net income. These increases were partially offset by a refund and one-time credit to Texas retail customers resulting from a rate settlement. Operating revenues were higher in 1992 due primarily to increased fuel adjustment revenues and increased collections of previously deferred River Bend costs and, to a lesser extent, to increased energy sales, primarily industrial. Also contributing to the 1992 increase was the fact that revenues were lower in 1991 due in part to a $24.1 million refund provision ordered by the LPSC. See "Selected Financial Data - Five-Year Comparison," incorporated herein by reference, following the notes, for information on operating revenues by source and KWH sales. Expenses Fuel for electric generation and fuel-related expenses increased in 1993 due primarily to a higher average per unit cost for gas resulting from increased gas prices in 1993 and increased generation, primarily River Bend. Fuel expense in 1992 increased due to higher average fuel cost, offset partially by reduced generation resulting from a scheduled refueling outage at River Bend in the first half of 1992. Purchased power expense decreased in 1992, despite increased purchases, due to the conclusion in June 1991 of capacity costs associated with the buyback of a portion of Cajun's share of River Bend generation. Other operating expenses increased in 1993 due primarily to $52.3 million of Merger-related charges for financial investment advisor fees and early retirement and other severance plan provisions. Charges for other postemployment benefits increased resulting from the adoption of SFAS 106. Other operating and maintenance expenses increased in 1992 due to costs in excess of the normal eighteen month outage accrual resulting from an extended refueling outage at River Bend from March to September. Further, amortization of rate deferrals increased in 1993 and 1992 due to increased amortization of amounts in accordance with the River Bend phase-in plan. Other Other miscellaneous income decreased in 1993 and increased in 1992 due primarily to the 1992 effect of reducing a liability relating to a purchased power settlement. In accordance with the settlement, the liability was based upon the price of GSU common stock as of the November 1991 settlement and was subsequently reduced as the price of GSU common stock increased. Interest expense declined in 1993 and 1992 as a result of the continued refinancing of high-cost debt during 1993, 1992, and 1991. GULF STATES UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Entergy Corporation-GSU Merger On December 31, 1993, Entergy Corporation completed the Merger with GSU. For further information, see Note 12, incorporated herein by reference. Competition GSU welcomes competition in the electric energy business and believes that a more competitive environment should benefit our customers, employees, and shareholders of Entergy Corporation. We also recognize that competition presents us with many challenges, and we have identified the following as our major competitive challenges: Retail and Wholesale Rate Issues Increasing competition in the utility industry brings an increased need to stabilize or reduce rates. In connection with the Merger, GSU agreed with the LPSC and PUCT to a five-year Rate Cap on retail electric rates, and to pass through to retail customers the fuel savings and a certain percentage of the nonfuel savings created by the Merger. GSU's base rates will be reviewed by the LPSC during the first post-Merger earnings analysis, scheduled for mid-1994, for reasonableness of its return on equity. The PUCT will review GSU's base rates in accordance with its Merger approval plan in mid-1994 also. For further information on Merger-related rate agreements, see Note 2, incorporated herein by reference. Cogeneration projects developed or considered by certain industrial customers over the last several years have resulted in GSU developing and securing approval of rates lower than the rates previously approved by the PUCT and LPSC for such industrial customers. Such rates are designed to retain such customers, and to compete for and develop new loads, and do not presently recover GSU's full cost of service. The pricing agreements at non-full cost of service based rates fully recover all related costs but provide only a minimal return. Substantially all of such pricing agreements expire no later than 1997. During 1993, KWH sales to industrial customers at less than full cost of service, which make up approximately 26% of the total industrial class, increased 8%. Sales to the remaining industrial customers decreased 3%. Retail wheeling, a major industry issue which may require utilities to "wheel" or move power from third parties to their own retail customers, is evolving gradually. As a result, the retail market could become more competitive. In the wholesale rate area, FERC approved in 1992, with certain modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power, Inc. to sell wholesale power at market-based rates and to provide to electric utilities "open access" to the System's transmission system (subject to certain requirements). GSU was later added to this filing. Various intervenors in the proceeding filed petitions for review with the United States Court of Appeals for the District of Columbia Circuit. FERC's order, once it takes effect, will increase marketing opportunities for GSU, but will also expose GSU to the risk of loss of load or reduced revenues due to competition with alternative suppliers. In light of these rate issues, GSU is aggressively reducing costs to avoid potential earnings erosions that might result as well as to successfully compete by becoming a low-cost producer. To minimize future costs, GSU is currently working with the PUCT regarding integrated resource planning. Integrated resource planning, or least cost planning, includes demand-side measures such as customer energy conservation and supply-side measures such as more efficient power plants. These measures are designed to delay the building of new power plants for the next 20 years. The Energy Policy Act of 1992 The Energy Policy Act of 1992 (Energy Act) is changing the transmission and distribution of electricity. This act encourages competition and affords us the opportunities, and the risks, associated with an open and more competitive market environment. The Energy Act increases competition in the wholesale energy market through the creation of exempt wholesale generators (EWGs). The Energy Act also gives FERC the authority to order investor-owned utilities to provide transmission access to or for other utilities, including EWGs. Deregulated Portion of River Bend As of December 31, 1993, GSU has not recovered a significant amount of its investment or received any return associated with the portion of River Bend included in the deregulated asset plan in Louisiana and the portion of River Bend placed in abeyance as part of the Texas rate order which went into effect in July 1988. See Note 2, incorporated herein by reference, for further information. Future earnings will continue to be limited as long as the limited recovery of the investment and lack of return continues. For the year ended December 31, 1993, GSU recorded revenues resulting from the sale of electricity from the deregulated asset plan of approximately $35.3 million. Operations and maintenance expenses, including fuel, were approximately $33.3 million, and depreciation expense associated with the deregulated asset plan investment was approximately $16.8 million for the year ended December 31, 1993. For the year ended December 31, 1993, GSU recorded nonfuel revenue of $31.5 million (included in the $35.3 million of total deregulated asset plan revenue discussed above) which, absent the deregulated asset plan, would not have been realized. The operations and maintenance expenses and depreciation expense allocated to the deregulated asset plan as detailed above, however, would have been incurred at River Bend with or without the deregulated asset plan. Future impact of the deregulated asset plan on GSU's results of operations and financial position will depend on River Bend's future operating costs, the unit's efficiency and availability, and the future market for energy over the remaining life of the unit. GSU anticipates based on current estimates of the factors discussed above, that future revenues from the deregulated asset plan will fully recover all related costs. Litigation and Regulatory Proceedings See Note 2, incorporated herein by reference, for information on the possibility of material adverse effects on GSU's financial condition resulting from substantial write-offs and/or refunds in connection with outstanding appeals and remands regarding approximately $1.4 billion of abeyed River Bend plant costs and approximately $187 million of Texas retail jurisdiction deferred River Bend operating and carrying costs. See Note 8, incorporated herein by reference, for information regarding litigation with Cajun concerning Cajun's ownership interest in River Bend and the possible material adverse effects on GSU's financial condition in the event that GSU is ultimately unsuccessful in this litigation, including a possible filing under the bankruptcy laws. GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES GSU maintains accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications. Revenues and Fuel Costs Prior to January 1, 1993, GSU recognized electric and gas revenues when billed. To provide a better matching of revenues and expenses, effective January 1, 1993, GSU adopted a change in accounting principle to provide for accrual of the nonfuel portion of estimated unbilled revenues. The cumulative effect of this accounting change as of January 1, 1993 for the Texas retail jurisdiction, wholesale jurisdiction, and gas department increased 1993 net income by $10.7 million, net of related income taxes of $6.9 million. Had this new accounting method been in effect during prior years, net income before the cumulative effect would not have been materially different from that shown in the accompanying financial statements. In the Louisiana retail jurisdiction, the LPSC issued a rate order, effective March 1, 1991, which required GSU to defer the initial effect when and if GSU changed its accounting for unbilled revenue. The amount of unbilled revenues in the Louisiana jurisdiction was $16.6 million at January 1, 1993. Because of the LPSC rate order, GSU recorded a deferred credit of $16.6 million. There was no cumulative effect of the change recorded in operations. If the LPSC order were to be revised, the net income effect would be $10.1 million, net of related income taxes of $6.5 million. Changes in unbilled revenues in the Louisiana retail jurisdiction subsequent to January 1, 1993 have been recorded in operations. GSU's wholesale and Louisiana retail rate schedules include fuel adjustment clauses that allow deferral of fuel costs until such costs are reflected in the related revenues. GSU's Texas retail rate schedules include a fixed fuel factor approved by the PUCT, which remains the same until changed as part of a general rate case or fuel reconciliation, or until the PUCT orders a reconciliation for any over or under collections of fuel costs. Reconcilable fuel and purchased power costs in excess of those included in base rates or recovered through fuel adjustment clauses are deferred (or accrued) until such costs are billed (or credited) to customers. Utility Plant Utility plant is stated at original cost. The original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of GSU's utility plant is subject to the lien of its mortgage indenture. 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 utility plant and earnings, only recovery of prudently incurred costs are realized in cash through depreciation provisions included in rates allowed by regulators. GSU's AFUDC rates were as follows: January 1, 1991 - March 31, 1991 11.50% April 1, 1991 - March 31, 1992 11.75% April 1, 1992 - March 31, 1993 10.75% April 1, 1993 - December 31, 1993 10.50% Depreciation is computed on the straight-line basis at rates based on the estimated service lives and cost of removal of the various classes of property. Depreciation provisions on average depreciable property approximated 2.7% in 1993, 1992, and 1991. Jointly-Owned Facilities As of December 31, 1993, GSU owned undivided interests in three jointly- owned electric generating facilities as detailed below:
Total Fuel Megawatt Accumulated Generating Stations Type Capability Ownership Investment Depreciation ------------------- ------ ---------- --------- ---------- ------------ (In Thousands) River Bend Unit 1 Nuclear 931 70% $3,056,464 $545,740 Roy S. Nelson Unit 6 Coal 550 70% $ 389,915 $134,877 Big Cajun 2 Unit 3 Coal 540 42% $ 219,911 $ 68,150
GSU's share of operations and maintenance expense related to the jointly- owned units is included in operating expenses. See Note 8 for information regarding unpaid amounts by Cajun for their share of River Bend costs. Income Taxes GSU and its subsidiaries file a consolidated federal income tax return. Income taxes are allocated to GSU in proportion to its contribution to the consolidated taxable income subject to the limitations for recognition of net operating loss carryforwards and investment tax credits. Deferred taxes are recorded for all temporary differences between book and taxable income. Investment tax credits are deferred and amortized based upon the average useful life of the related property in accordance with rate treatment. Inventories GSU's fuel inventories are comprised of fuel oil and natural gas, valued at weighted average cost, and coal, valued at last-in, first-out cost. Accounting for Power Plant Materials and Supplies During the first quarter of 1992, accounting procedures were changed to include in inventory, power plant materials and supplies previously expensed or capitalized as plant in service. GSU believed this change provided a better matching of costs with related revenues. The change resulted from recommendations during audits by FERC and the LPSC, in addition to a general change in industry practice. The pro forma effect of retroactive application on any period prior to 1992 was not determinable as, prior to this change, GSU did not perform the physical inventory counts necessary to determine inventory balances in prior periods. The effect of the change was to increase materials and supplies by $76.6 million, of which $41.1 million associated with GSU's Texas and Louisiana retail jurisdictions was deferred, and to decrease amounts previously capitalized, primarily plant in service, by $29 million. Amounts deferred for the Louisiana retail jurisdiction are currently being amortized to income over approximately seven years, through February 1998, while amounts deferred for the Texas retail jurisdiction will be amortized to income in future years. The cumulative effect of this accounting change as of January 1, 1992, which relates to the operations on which GSU has discontinued regulatory accounting principles, amounted to $6.5 million before the related income tax effect of $2.5 million. Reacquired Debt The premiums and costs associated with reacquired debt are amortized over the life of the related new issuances for the portions of the business accounted for in accordance with generally accepted accounting principles for regulated enterprises. During 1992, GSU extinguished over $1 billion of long-term debt through refinancings. A loss of $81.8 million was recorded associated with the extinguished debt of which $67.2 million of the loss was deferred, representing the portion of GSU's operations allocable to the Texas and Louisiana retail jurisdictions, and began to amortize that amount over the life of the new debt sold to retire the existing debt. A loss of $9.6 million, net of related income taxes of $5.0 million, was charged to income in 1992 as an extraordinary item. Further, refinancings of long-term debt during 1993 resulted in an extraordinary loss of $1.3 million, net of $.7 million of related taxes. Cash and Cash Equivalents GSU considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. SFAS 101 SFAS No. 101, "Regulated Enterprises - 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 No. 71, "Accounting for the Effects of Certain Types of Regulation," to all or part of its operations should report that event in its financial statements. GSU discontinued regulatory accounting principles for the wholesale jurisdiction and steam department, and the Louisiana deregulated portion of River Bend, during 1989 and 1991, respectively. Fair Value Disclosure The estimated fair value of GSU's significant financial instruments have been determined using available market information and appropriate valuation methodologies. However, considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that GSU could realize in a current market exchange. In addition, gains or losses realized on financial instruments may be reflected in future rates and not accrue to the benefit of stockholders. GSU considers the carrying amounts of financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. See Notes 5, 6, and 8 for additional fair value disclosure. NOTE 2. RATE AND REGULATORY MATTERS River Bend In May 1988, the PUCT granted GSU a permanent increase in annual revenues of $59.9 million resulting from the inclusion in rate base of approximately $1.6 billion of company-wide River Bend plant investment and approximately $182 million of related Texas retail jurisdiction deferred River Bend costs (Allowed Deferrals). In addition, the PUCT disallowed as imprudent $63.5 million of company-wide River Bend plant costs and placed in abeyance, with no finding of prudency, approximately $1.4 billion of company-wide River Bend plant investment and approximately $157 million of Texas retail jurisdiction deferred River Bend operating and carrying costs. The PUCT affirmed that the ultimate rate treatment of such amounts would be subject to future demonstration of the prudency of such costs. GSU and intervening parties appealed this order (Rate Appeal) and GSU filed a separate rate case asking that the abeyed River Bend plant costs be found prudent (Separate Rate Case). Intervening parties filed suit in district court to prohibit the Separate Rate Case. The district court's decision was ultimately appealed to the Texas Supreme Court which ruled in 1990 that the prudence of the purported abeyed costs could not be relitigated in a separate rate proceeding. Further, the Texas Supreme Court's decision stated that all issues relating to the merits of the original order of the PUCT, including the prudence of all River Bend-related costs, should be addressed in the Rate Appeal. In October 1991, the district court in the Rate Appeal issued an order holding that, while it was clear the PUCT made an error in assuming it could set aside $1.4 billion of the total costs of River Bend and consider them in a later proceeding, the PUCT, nevertheless, found that GSU had not met its burden of proof related to the amounts placed in abeyance. The court also ruled that the Allowed Deferrals should not be included in rate base under a 1991 decision regarding El Paso Electric Company's similar deferred costs (El Paso Case). The court further stated that the PUCT erred in reducing GSU's deferred costs by $1.50 for each $1.00 of revenue collected under the interim rate increases authorized in 1987 and 1988. The court remanded the case to the PUCT with instructions as to the proper handling of the Allowed Deferrals. GSU's motion for rehearing was denied, and in December 1991, GSU filed an appeal of the October 1991 district court order. The PUCT also appealed the October 1991 district court order, which served to supersede the district court's judgment, rendering it unenforceable under Texas law. In August 1992, the court of appeals in the El Paso Case handed down its second opinion on rehearing modifying its previous opinion on deferred accounting. The court's second opinion concluded that the PUCT may lawfully defer operating and maintenance costs and subsequently include them in rate base, but that the Public Utility Regulatory Act prohibits such rate base treatment for deferred carrying costs. The court stated, however, its opinion would not preclude the recovery of deferred carrying costs. The August 1992 court of appeals opinion was appealed to the Texas Supreme Court where arguments were heard in September 1993. The matter is pending. In September 1993, the Texas Third District Court of Appeals (the Third District Court) remanded the October 1991 district court decision to the PUCT "to reexamine the record evidence to whatever extent necessary to render a final order supported by substantial evidence and not inconsistent with our opinion." The Third District Court specifically addressed the PUCT's treatment of certain costs, stating that the PUCT's order was not based on substantial evidence. The Third District Court also applied its most recent ruling in the El Paso Case to the deferred costs associated with River Bend. However, the Third District Court cautioned the PUCT to confine its deliberations to the evidence addressed in the original rate case. Certain parties to the case have indicated their position that, on remand, the PUCT may change its original order only with respect to matters specifically discussed by the Third District Court which, if allowed, would increase GSU's allowed River Bend investment, net of accumulated depreciation and related taxes, by approximately $48 million as of December 31, 1993. GSU believes that under the Third District Court's decision, the PUCT would be free to reconsider any aspect of its order concerning the abeyed $1.4 billion River Bend investment. GSU has filed a motion for rehearing asking the Third District Court to modify its order so as to permit the PUCT to take additional evidence on remand. The PUCT and other parties have also moved for rehearing on various grounds. The Third District Court has not yet ruled on any of these motions. As of December 31, 1993, the River Bend plant costs disallowed for retail ratemaking purposes in Texas, and the River Bend plant costs held in abeyance and the related cost deferrals totaled (net of taxes) approximately $14 million, $300 million (both net of depreciation), and $171 million, respectively. Allowed Deferrals were approximately $95 million, net of taxes and amortization, as of December 31, 1993. GSU estimates it has collected approximately $139 million of revenues as of December 31, 1993, as a result of the originally ordered rate treatment of these deferred costs. However, if the PUCT adopts the most recent decision in the El Paso Case, the possible refunds approximate $28 million as a result of the inclusion of deferred carrying costs in rate base for the period July 1988 through December 1990. However, if the PUCT reverses its decision to reduce GSU's deferred costs by $1.50 for each $1.00 of revenue collected under the interim rate increases authorized in 1987 and 1988, the potential refund of amounts described above could be reduced by an amount ranging from $7 million to $19 million. No assurance can be given as to the timing or outcome of the remands or appeals described above. Pending further developments in these cases, GSU has made no write-offs for the River Bend-related costs. Management believes, based on advice from Clark, Thomas & Winters, a Professional Corporation, legal counsel of record in the Rate Appeal, that it is reasonably possible that the case will be remanded to the PUCT, and the PUCT will be allowed to rule on the prudence of the abeyed River Bend plant costs. Rate Caps imposed by the PUCT's regulatory approval of the Merger could result in GSU being unable to use the full amount of a favorable decision to immediately increase rates; however, a favorable decision could permit some increases and/or limit or prevent decreases during the period the Rate Caps are in effect. At this time, management and legal counsel are unable to predict the amount, if any, of the abeyed and previously disallowed River Bend plant costs that ultimately may be disallowed by the PUCT. A net of tax write-off as of December 31, 1993, of up to $314 million could be required based on the PUCT's ultimate ruling. In prior proceedings, the PUCT has held that the original cost of nuclear power plants will be included in rates to the extent those costs were prudently incurred. Based upon the PUCT's prior decisions, management believes that its River Bend construction costs were prudently incurred and that it is reasonably possible that it will recover in rate base, or otherwise through means such as a deregulated asset plan, all or substantially all of the abeyed River Bend plant costs. However, management also recognizes that it is reasonably possible that not all of the abeyed River Bend plant costs may ultimately be recovered. As part of its direct case in the Separate Rate Case, GSU filed a cost reconciliation study prepared by Sandlin Associates, management consultants with expertise in the cost analysis of nuclear power plants, which supports the reasonableness of the River Bend costs held in abeyance by the PUCT. This reconciliation study determined that approximately 82% of the River Bend cost increase above the amount included by the PUCT in rate base was a result of changes in federal nuclear safety requirements and provided other support for the remainder of the abeyed amounts. There have been four other rate proceedings in Texas involving nuclear power plants. Investment in the plants ultimately disallowed ranged from 0% to 15%. Each case was unique, and the disallowances in each were made on a case-by-case basis for different reasons. Appeals of most, if not all, of these PUCT decisions are currently pending. The following factors support management's position that a loss contingency requiring accrual has not occurred, and its belief that all, or substantially all, of the abeyed plant costs will ultimately be recovered: 1. The $1.4 billion of abeyed River Bend plant costs have never been ruled imprudent and disallowed by the PUCT. 2. Sandlin Associates' analysis which supports the prudence of substantially all of the abeyed construction costs. 3. Historical inclusion by the PUCT of prudent construction costs in rate base. 4. The analysis of GSU's internal legal staff, which has considerable experience in Texas rate case litigation. Additionally, management believes, based on advice from Clark, Thomas & Winters, a Professional Corporation, legal counsel of record in the Rate Appeal, that it is probable that the deferred costs will be allowed. However, assuming the August 1992 court of appeals' opinion in the El Paso Case is upheld and applied to GSU and the deferred River Bend costs currently held in abeyance are not allowed to be recovered in rates as allowable costs, a net of tax write-off of up to $171 million could be required. In addition, future revenues based upon the deferred costs previously allowed in rate base could also be lost and no assurance can be given as to whether or not refunds (up to $28 million as of December 31, 1993) of revenue received based upon such deferred costs previously recorded will be required. See Note 12 for the accounting treatment of preacquisition contingencies, including a River Bend write-down. Merger-Related Rate Agreements The LPSC and the PUCT approved separate regulatory proposals that include the following elements: (1) a five-year Rate Cap on GSU's retail electric base rates in the respective states, except for force majeure (defined to include, among other things, war, natural catastrophes, and high inflation); (2) a provision for passing through to retail customers in the respective states the jurisdictional portion of the fuel savings created by the Merger; and (3) a mechanism for tracking nonfuel operation and maintenance savings created by the Merger. The LPSC regulatory plan provides that such nonfuel savings will be shared 60% by the shareholder and 40% by ratepayers during the eight years following the Merger. The LPSC plan requires regulatory filings each year by the end of May through 2001. The PUCT regulatory plan provides that such savings will be shared equally by the shareholder and ratepayers, except that the shareholder's portion will be reduced by $2.6 million per year on a total company basis in years four through eight. The PUCT plan also requires a series of regulatory filings currently anticipated to be in June 1994, and February 1996, 1998, and 2001, to ensure that ratepayers' share of such savings be reflected in rates on a timely basis and requires Entergy Corporation to hold GSU's Texas retail customers harmless from the effects of the removal by FERC of a 40 % cap on the amount of fuel savings GSU may be required to transfer to other Entergy operating companies under the FERC tracking mechanism (see below). On January 14, 1994, Entergy Corporation filed a request for rehearing of FERC's December 15, 1993, order approving the Merger requesting that FERC restore the 40 % cap provision in the fuel cost protection mechanism. The matter is pending. FERC approved certain rate schedule changes to integrate GSU into the System Agreement. Certain commitments were adopted to provide reasonable assurance that the ratepayers of AP&L, LP&L, MP&L, and NOPSI will not be allocated higher costs, including, among other things: (1) a tracking mechanism to protect AP&L, LP&L, MP&L, and NOPSI from certain unexpected increases in fuel costs; (2) the distribution of profits from power sales contracts entered into prior to the Merger; (3) a methodology to estimate the cost of capital in future FERC proceedings; and (4) a stipulation that AP&L, LP&L, MP&L, and NOPSI will be insulated from certain direct effects on capacity equalization payments should GSU, due to a finding of imprudent GSU management prior to the Merger, be required to purchase Cajun's 30% share in River Bend (see Note 8). Texas - Fuel Reconciliation In January 1992, GSU applied with the PUCT for a new fixed fuel factor and requested a final reconciliation of fuel and purchased power costs incurred between December 1, 1986 and September 30, 1991. GSU proposed to recover net underrecoveries and interest (including underrecoveries related to Nelson Industrial Steam Company (NISCO), discussed below) over a twelve month period. In April 1993, the presiding PUCT administrative law judge (ALJ) issued a report which concluded that GSU incurred approximately $117 million of nonreimbursable fuel costs on a company-wide basis (approximately $50 million on a Texas retail jurisdictional basis) during the reconciliation period. Included in the nonreimbursable fuel costs were payments above GSU's avoided cost rate for power purchased from NISCO. The PUCT ordered in 1986 that the purchased power costs from NISCO in excess of GSU's avoided costs be disal lowed. The PUCT disallowance resulted in approximately $12 million to $15 million of unrecovered purchased power costs on an annual basis, which GSU continued to expense as the costs were incurred. In April 1991, the Texas Supreme Court, in the appeal of such order, ordered the PUCT to allow GSU to recover purchased power payments in excess of its avoided cost in future proceedings, if GSU established to the PUCT's satisfaction that the payments were reasonable and necessary expenses. In June 1993, the PUCT, in the fuel reconciliation case, concluded that the purchased power payments made to NISCO in excess of GSU's avoided cost were not reasonably incurred. As a result of the order, GSU recorded additional fuel expenses (including interest) of $2.8 million for non-NISCO related items. The PUCT's order resulted in no additional expenses related to the NISCO issue, or for overcollections related to the fixed fuel factor, as those charges were expensed by GSU as they were incurred. The PUCT concluded that GSU had over- collected its fuel costs in Texas and ordered GSU to refund approximately $33.8 million to its Texas retail customers, including approximately $7.5 million of interest. The PUCT reduced GSU's fixed fuel factor in Texas from about 2.1 cents per KWH to approximately 1.84 cents per KWH. GSU had requested a new fixed fuel factor of about 2.02 cents per KWH. Based on current sales forecasts, adoption of the PUCT's recommended fixed fuel factor would reduce GSU's revenues by approximately $34 million annually. In October 1993, GSU appealed the PUCT's order to the Travis County District Court. No assurance can be given as to the timing or outcome of the appeal. Texas Cities Rate Settlement In the state of Texas, incorporated cities have original jurisdiction over GSU's rates and services within their boundaries, while the PUCT has appellate jurisdiction over intramunicipal rates and original jurisdiction over unincorporated areas. In June 1993, 13 cities within GSU's Texas service area instituted an investigation to determine whether GSU's current rates were justified. In October 1993, the general counsel of the PUCT instituted an inquiry into the reasonableness of GSU's rates. In November 1993, a settlement agreement was filed with the PUCT which provides for an initial reduction in annual retail base revenues in Texas of approximately $22.5 million effective for electric usage on or after November 1, 1993, and a second reduction of $20 million to be effective September 1994. Further, the settlement provided for GSU to reduce rates with a $20 million one-time bill credit in December 1993, and to refund approximately $3 million to Texas retail customers on bills rendered in December 1993. The cities rate inquiries had been settled earlier on the same terms. In November 1993, in association with the settlement of the above-described rate inquiries, GSU entered into a settlement covering issues related to a March 1991 non-unanimous settlement in another proceeding. Under this settlement, a $30 million rate increase approved by the PUCT in March 1991, became final and the PUCT's treatment of GSU's federal tax expense was settled, eliminating the possibility of refunds associated with amounts collected resulting from the disputed tax calculation. In December 1993, a large industrial customer of GSU announced its intention to oppose the settlement of the PUCT rate inquiry. The customer's opposition does not affect the cities' rate settlement. The customer's opposition requires the PUCT to conduct a hearing concerning GSU's rates charged in areas outside the corporate limits of the cities in its Texas service territory to determine whether the settlement's rates are just and reasonable. A hearing has been set for July 8, 1994. GSU believes that the PUCT will ultimately approve the settlement, but no assurance can be provided in this regard. Louisiana Previous rate orders of the LPSC have been appealed, and pending resolution of various appellate proceedings, GSU has made no write-off for the disallowance of $30.6 million of deferred revenue requirement that GSU recorded for the period December 16, 1987 through February 18, 1988. Deregulated Asset Plan A deregulated asset plan representing an unregulated portion (approximately 22%) of River Bend (plant costs, generation, revenues, and expenses) was established pursuant to a January 1992 LPSC order. The plan allows GSU to sell such generation to Louisiana retail customers at 4.6 cents per KWH or off-system at higher prices with certain sharing provisions for such incremental revenue. LPSC Return on Equity Review In the June 1993 open session, a preliminary report was made comparing the authorized and actual earned rates of return for electric and gas utilities subject to the LPSC's jurisdiction. The preliminary report indicated that several electric utilities, including GSU, may be over-earning based on current estimated costs of equity. The LPSC requested those utilities to file responses indicating whether they agreed with the preliminary report, and to provide their reasons if they did not agree. GSU provided the LPSC with information that GSU believes supports the current rate level. The LPSC decided at its September 7, 1993 open session to defer review of GSU's base rates until the first post- Merger earnings analysis, scheduled for mid-1994. LPSC Fuel Cost Review In November 1993, the LPSC ordered a review of GSU's fuel costs. The LPSC stated that fuel costs for the period October 1988 through September 1991 would be reviewed based on the number of outages at River Bend and the findings in the June 1993 PUCT fuel reconciliation case. Hearings are scheduled to begin in March 1994. River Bend Cost Deferrals GSU deferred approximately $369 million of River Bend operating costs, purchased power costs, and accrued carrying charges pursuant to a 1986 PUCT accounting order. Approximately $182 million of these costs are being amortized over a 20-year period, and the remaining $187 million are not being amortized pending the ultimate outcome of the Rate Appeal. As of December 31, 1993, the unamortized balance of these costs was $330.3 million. Further, GSU deferred approximately $400.4 million of similar costs pursuant to a 1986 LPSC accounting order. These costs, of which approximately $160.4 million are unamortized as of December 31, 1993, are being amortized over a 10-year period. In accordance with a phase-in plan approved by the LPSC, GSU deferred $324.7 million of its River Bend costs related to the period December 1987 through February 1991. GSU has amortized $86.6 million through December 31, 1993, and the remainder of $238.1 million will be recovered over approximately 3.8 years. NOTE 3. INCOME TAXES Effective January 1, 1993, GSU adopted SFAS 109. This new standard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that deferred tax balances be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 requires that regulated enterprises recognize adjustments resulting from its implementation as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. A substantial majority of the adjustments required by SFAS 109 were recorded to deferred tax balance sheet accounts with offsetting adjustments to regulatory assets and liabilities. GSU recorded the adoption of SFAS 109 by restating 1990, 1991, and 1992 financial statements and including a charge of $96.5 million for the cumulative effect of the adoption of SFAS 109 in 1990 primarily for that portion of the operations on which GSU has discontinued regulatory accounting principles. Detailed below are the effects on GSU's 1992 and 1991 results of operations and financial position as of December 31, 1992, resulting from such restatement (in thousands):
1991 As SFAS 1991 Previously No. 109 As Reported Effect Restated ---------- --------- -------- Income before extraordinary items and the cumulative effect of accounting change $122,449 $(10,058) $112,391 Net income $102,283 $ 9,747 $112,030 Income applicable to common stock $ 39,213 $ 9,747 $ 48,960
1992 As SFAS 1992 Previously No. 109 As Reported Effect Restated ---------- ------- -------- Income before extraordinary items and the cumulative effect of accounting change $133,787 $5,626 $139,413 Net income $128,157 $5,691 $133,848 Income applicable to common stock $ 78,455 $5,691 $ 84,146
Balance at Balance at December 31, December 31, 1992 As SFAS 1992 Previously No. 109 As Reported Effect Restated ------------ -------- ------------ Total assets $6,858,494 $305,953 $7,164,447 Total capitalization and liabilities (excluding retained earnings) $6,153,859 $379,126 $6,532,985 Retained earnings $ 704,635 $(73,173) $ 631,462
Income taxes differ from the amounts computed by applying the statutory federal income tax rate to income before taxes. The reasons for these differences were (1992 and 1991 restated for the effects of SFAS 109):
For the Years Ended December 31, ----------------------------------------------------- 1993 1992 1991 ---------------- ---------------- --------------- % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income ------- ------ ------- ------ ------- ------ (Dollars in Thousands) Computed at statutory rate $50,101 35.0 $63,662 34.0 $54,415 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 1,332 0.9 3,573 1.9 3,444 2.2 Rate deferrals - net 6,193 4.3 5,439 2.9 5,481 3.4 Depreciation (11,343) (7.9) (15,479) (8.3) (12,302) (7.7) Impact of change in tax rate 5,179 3.6 - - - - Book expenses not deducted for tax 15,134 10.6 142 0.1 187 0.1 Amortization of investment tax credits (4,435) (3.1) (4,356) (2.3) (4,308) (2.7) Other - net 2,123 1.5 413 0.2 1,098 0.7 ------- ----- ------- ----- ------- ----- Total income taxes $64,284 44.9 $53,394 28.5 $48,015 30.0 ======= ===== ======= ===== ======= =====
Income tax expense (1992 and 1991 restated for the effects of SFAS 109) consisted of the following:
For the Years Ended December 31, -------------------------------- 1993 1992 1991 ------- ------- ------ (In Thousands) Current Federal $16,714 $ 5,621 $4,746 State - - - ------- ------- ------ Total 16,714 5,621 4,746 ------- ------- ------ Deferred - net Liberalized depreciation 37,951 24,287 26,041 Nuclear unit cancellation costs, net of amortization (2,930) (3,107) (2,954) Fuel and purchased power costs (accrued) 7,689 (669) (4,652) Expenses deferred for tax purposes (12,387) 3,449 (5,216) Tax net operating loss carryforward (8,357) 12,349 60,333 Rate deferrals - net (24,458) (21,238) (15,347) Unbilled revenues 4,999 2,889 813 Income deferred for book purposes (2,102) 2,328 (14,614) Louisiana provision for rate refund 3,793 4,416 (8,209) Alternative minimum tax credit (22,183) (8,197) (5,595) Loss on debt extinguishment, net of amortization 1,398 22,314 - State tax refund deferred for financial reporting - - 6,478 Purchased power settlement 66,753 6,562 8,088 Other (3,689) 4,590 2,411 ------- ------- ------- Total 46,477 49,973 47,577 ------- ------- ------- Investment tax credit adjustments - net 1,093 (2,200) (4,308) ------- ------- ------- Recorded income tax expense $64,284 $53,394 $48,015 ======= ======= ======= Charged to operations $46,007 $38,058 $35,084 Charged to other income 12,009 17,801 13,166 Charged to extraordinary items (671) (4,943) (235) Charged to cumulative effect of accounting changes 6,939 2,478 - ------- ------- ------- Total income taxes $64,284 $53,394 $48,015 ======= ======= =======
Significant components of net deferred tax liabilities, as restated for the effects of SFAS 109, as of December 31, 1993 and 1992, were (in thousands):
1993 1992 ------------ ------------ Deferred tax liabilities: Net regulatory assets $ (529,706) $ (453,064) Plant related basis differences (1,023,446) (981,915) Rate deferrals - net (169,689) (194,147) Debt reacquisition loss (24,140) (22,805) Other (25,871) (29,799) ----------- ----------- Total $(1,772,852) $(1,681,730) =========== =========== Deferred tax assets: Net operating loss carryforwards $ 307,737 $ 294,100 Investment tax credit carryforward 176,032 181,560 Valuation allowance-investment tax credit carryforward (15,213) - Unbilled revenue 12,243 17,242 Southern Company settlement - 66,753 Plant related basis differences 25,007 22,868 Alternative minimum tax credit 39,860 17,453 Other 164,135 162,863 ----------- ----------- 709,801 762,839 Investment tax credit carryforwards reserved (160,819) (181,560) ----------- ----------- Total $ 548,982 $ 581,279 =========== =========== Net deferred tax liability $(1,223,870) $(1,100,451) =========== ===========
As of December 31, 1993, for tax purposes, GSU had federal tax loss carryforwards of approximately $790 million, state tax loss carryforwards of approximately $561 million, and investment tax (ITC) and other credit carryforwards of approximately $179 million which will be used to reduce income tax payments in future years and, if not used, will expire through the year 2008. It is currently anticipated that approximately $15.2 million of ITC carryforwards will expire unutilized as a result of limitations arising from the Merger. A valuation allowance has been provided for that amount. The alternative minimum tax credit, which can be carried forward indefinitely to reduce GSU's future federal income tax liability, was $40 million as of December 31, 1993. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS As of December 31, 1993, GSU had agreements with banks and banking institutions which provided for short-term lines of credit totaling $113.4 million. Included in the total short-term lines of credit was a $100 million bank credit agreement which expired on March 2, 1994. GSU had no outstanding borrowings under these arrangements as of December 31, 1993. A filing has been made with the SEC requesting authorization for GSU to participate in the Money Pool, an intra-system borrowing arrangement designed to reduce the System's dependence on external short-term borrowings, and to enter into new bank lines of credit and commercial paper arrangements. The filing requested a borrowing authorization of $125 million with reservation of jurisdiction over additional amounts up to a maximum of $455 million. NOTE 5. PREFERRED, PREFERENCE, AND COMMON STOCK The number of shares and dollar value of GSU's preferred and preference stock was:
Call Price As of December 31 Per Share as Shares Outstanding Total Dollar Value of December 1993 1992 1993 1992 31, 1993 --------- ------- -------- --------- ----------- (Dollars in Thousands) Preference Stock Authorized 20,000,000 shares, without par value, cumulative 7% Series (2) 6,000,000 - $150,000 $ - (1) ========= ======= ======== ======== Preferred Stock Authorized 6,000,000 shares, $100 par value, cumulative 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 350,000 350,000 35,000 35,000 $101.80 8.52% Series 500,000 500,000 50,000 50,000 $102.43 9.96% Series 350,000 350,000 35,000 35,000 $104.64 --------- --------- -------- -------- Total without sinking fund 1,364,438 1,364,438 $136,444 $136,444 ========= ========= ======== ======== With sinking fund: 8.80% Series 237,963 260,275 $23,796 $26,027 $100.00 9.75% Series 22,576 24,598 2,258 2,460 $100.00 8.64% Series 196,000 224,000 19,600 22,400 $103.00 11.48% Series - 340,000 - 34,000 - 12.92% Series - 510,000 - 51,000 - 11.50% Series - 712,500 - 71,250 - Adjustable Rate Series A, 7.10% (3) 216,000 240,000 21,600 24,000 $100.00 Adjustable Rate Series B, 7.15% (3) 337,500 382,500 33,750 38,250 $103.00 --------- --------- -------- -------- Total with sinking fund 1,010,039 2,693,873 $101,004 $269,387 ========= ========= ======== ========
(1) This series is not redeemable as of December 31, 1993. (2) The total dollar value represents the involuntary liquidation value of $25 dollars per share. (3) Rates are as of December 31, 1993. The fair value of GSU's preferred and preference stock with sinking fund was estimated to be approximately $255 million and $279.5 million as of December 31, 1993 and 1992, respectively. The fair value was determined using quoted market prices or estimates from nationally recognized investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. Changes in the common stock, preference stock, and preferred stock during the last three years were:
Number of Shares -------------------------------------- 1993 1992 1991 ------------ ---------- ---------- Common stock issuances 100 - 6,000,000 Common stock retirements with Merger closing (114,055,065) - - Preference stock issuances 6,000,000 - - Preference stock retirements - (4,000,000) - Preferred stock with sinking fund retirements (1,683,834) (559,257) -
Minimum cash sinking fund requirements for preferred stock with sinking funds are $6.1 million for each of the years 1994-1998. Limitations based on the ratio of after-tax earnings to fixed charges and preferred dividends are imposed by the Articles of Incorporation (Articles) upon the issuance of additional preferred stock. Based upon the results of operations for the year ended December 31, 1993, GSU is unable to issue any additional preferred stock. NOTE 6. LONG-TERM DEBT GSU's long-term debt as of December 31, 1993 and 1992, was as follows:
Maturities Interest Rates December 31 From To From To 1993 1992 ---- ---- ---- ---- ---------- ---------- (In Thousands) First Mortgage Bonds 1996 1998 5% 7.35% $ 345,000 $ 345,000 1999 2003 6.41% 8-1/2% 470,000 420,000 2004 2008 6.77% 8-7/8% 420,000 480,000 2022 2024 8.70% 8.94% 450,000 450,000 Governmental and Industrial Development Bonds 2006 2016 5.9% 12% 482,885 483,310 Debentures - Due 1998, 9.72% 200,000 200,000 Notes payable - 160,000 Other long-term debt 6,879 2,718 Unamortized premium and discount - net (5,700) (6,145) ---------- ---------- Total long-term debt 2,369,064 2,534,883 Less amount due within one year 425 160,425 ---------- ---------- Long-term debt excluding amount due within one year $2,368,639 $2,374,458 ========== ==========
The fair value of GSU's long-term debt as of December 31, 1993 and 1992 was estimated to be $2,548.1 million and $2,623 million, respectively. Fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. For the years 1994, 1995, 1996, 1997, and 1998, GSU has long-term debt maturities and cash sinking fund requirements of (in millions) $.4, $50.4, $145.4, $160.9, and $190.9, respectively. In addition, other sinking fund requirements for the years 1994, 1995, 1996, 1997, and 1998 of (in millions) $16.7, $16.7, $15.6, $14.3, and $12.6, respectively, may be satisfied by cash or by certification of property additions at a rate of 167% of such requirements. GSU has three outstanding series of pollution control bonds which are collateralized by irrevocable letters of credit which are scheduled to expire before the scheduled maturity of the bonds. The letter of credit collateralizing the $50 million 10-5/8% series due May 1, 2014, expires in May 1994, the letter of credit collateralizing the $28.4 million variable rate series due December 1, 2015, expires in September 1996 and the letter of credit collateralizing the $20 million variable rate series due April 1, 2016, expires in April 1996. GSU plans to refinance these series or renew the letters of credit. NOTE 7. DIVIDEND RESTRICTIONS Certain limitations on the payment of cash dividends on common stock are contained in the Articles, Mortgage Indenture, loan agreements, and applicable state and federal law. Under existing limitations, as part of the short-term line of credit discussed in Note 4, $560 million of GSU's retained earnings are restricted against the payment of common dividends at December 31, 1993. If such restriction did not exist, the most restrictive limitation as of December 31, 1993, as to the amount of such dividends which might be paid, was contained in the Articles. Under the restrictions contained in the Articles, as of December 31, 1993, $21 million of GSU's retained earnings were restricted against the payment of cash dividends or other distributions on common stock. On February 1, 1994, GSU paid Entergy Corporation a $100 million cash dividend on common stock. Prior to the February 1, 1994, dividend payment, GSU had not paid a common dividend since June 1986. NOTE 8. COMMITMENTS AND CONTINGENCIES Financial Condition Although GSU received partial rate relief relating to River Bend, GSU's financial position was strained from 1986 to 1990 by its inability to earn a return on and fully recover its investment and other costs associated with River Bend. GSU's financial position has continued to improve; however, issues to be finally resolved in PUCT rate proceedings and appeals thereof, as discussed in Note 2, combined with the application of accounting standards, may result in substantial write-offs and charges that could result in substantial net losses being reported in 1994, and subsequent periods, with resulting substantial adverse adjustments to common shareholder's equity. Future earnings will continue to be adversely affected by the lack of full recovery and return on the investment and other costs associated with River Bend. Cajun - River Bend GSU has significant business relationships with Cajun, primarily co-ownership of River Bend and Big Cajun 2 Unit 3. GSU and Cajun own 70% and 30% of River Bend, respectively, while Big Cajun 2 Unit 3 is owned 42% and 58% by GSU and Cajun, respectively. GSU operates River Bend, and Cajun operates Big Cajun 2 Unit 3. In June 1989, Cajun filed a civil action against GSU in the U. S. District Court for the Middle District of Louisiana. Cajun stated in its complaint that the object of the suit is to annul, rescind, terminate, and/or dissolve the Joint Ownership Participation and Operating Agreement entered into on August 28, 1979 (Operating Agreement) related to River Bend. Cajun alleges fraud and error by GSU, breach of its fiduciary duties owed to Cajun, and/or GSU's repudiation, renunciation, abandonment, or dissolution of its core obligations under the Operating Agreement, as well as the lack or failure of cause and/or consideration for Cajun's performance under the Operating Agreement. The suit seeks to recover Cajun's alleged $1.6 billion investment in the unit as damages, plus attorneys' fees, interest, and costs. In March 1992, the district court appointed a mediator to engage in settlement discussions and to schedule settlement conferences between the parties. Discussions with the mediator began in July 1992, however, GSU cannot predict what effect, if any, such discussions will have on the timing or outcome of the case. A trial without a jury is set for April 12, 1994, on the portion of the suit by Cajun to rescind the Operating Agreement. Two member cooperatives of Cajun have brought an independent action to declare the River Bend Operating Agreement void, based upon failure to get prior LPSC approval alleged to be necessary. GSU believes the suits are without merit and is contesting them vigorously. No assurance can be given as to the outcome of this litigation. If GSU were ultimately unsuccessful in this litigation and were required to make substantial payments, GSU would probably be unable to make such payments and would probably have to seek relief from its creditors under the Bankruptcy Code. See Note 12 for the accounting treatment of preacquisition contingencies, including a charge resulting from an adverse resolution in the Cajun - River Bend litigation. In July 1992, Cajun notified GSU that it would fund a limited amount of costs related to the fourth refueling outage at River Bend, completed in September 1992. Cajun has also not funded its share of the costs associated with certain additional repairs and improvements at River Bend completed during the refueling outage. GSU has paid the costs associated with such repairs and improvements without waiving any rights against Cajun. GSU believes that Cajun is obligated to pay its share of such costs under the terms of the applicable contract. Cajun has filed a suit seeking a declaration that it does not owe such funds and seeking injunctive relief against GSU. GSU is contesting such suit and is reviewing its available legal remedies. In September 1992, GSU received a letter from Cajun alleging that the operating and maintenance costs for River Bend are "far in excess of industry averages" and that "it would be imprudent for Cajun to fund these excessive costs." Cajun further stated that until it is satisfied it would fund a maximum of $700,000 per week under protest for the remainder of 1992. In a December 1992 letter, Cajun stated that it would also withhold costs associated with certain additional repairs, of which the majority will be incurred during the next refueling outage, currently scheduled for April 1994. GSU believes that Cajun's allegations are without merit and is considering its legal and other remedies available with respect to the underpayments by Cajun. The total resulting from Cajun's failure to fund repair projects, Cajun's funding limitation on the fourth refueling outage, and the weekly funding limitation by Cajun was $33.3 million as of December 31, 1993, compared with a $28.4 million unfunded balance as of December 31, 1992. These amounts are reflected in long- term receivables. During 1994, and for the next several years, it is expected that Cajun's share of River Bend-related costs will be in the range of $60 million to $70 million per year. Cajun's weak financial condition could have a material adverse effect on GSU, including a possible Nuclear Regulatory Commission (NRC) action with respect to the operation of River Bend and a need to bear additional costs associated with the co-owned facilities. If GSU were required to fund Cajun's share of costs, there can be no assurance that such payments could be recovered. Cajun's weak financial condition could also affect the ultimate collectibility of amounts owed to GSU. Cajun - Transmission Service GSU and Cajun are parties to FERC proceedings related to transmission service charge disputes. In April 1992, FERC issued a final order, and in May 1992, GSU and Cajun filed motions for rehearings which are pending consideration by FERC. In June 1992, GSU filed a petition for review in the United States Court of Appeals regarding certain of the issues decided by FERC. In August 1993, the United States Court of Appeals rendered an opinion reversing the FERC order regarding the portion of such disputes relating to the calculations of certain credits and equalization charges under GSU's service schedules with Cajun. The opinion remanded the issues to FERC for further proceedings consistent with its opinion. In January 1994, FERC denied GSU's request to collect a surcharge while FERC considers the court's remand. GSU interprets the FERC order and the court of appeals' decision to mean that Cajun would owe GSU approximately $85 million as of December 31, 1993. GSU further estimates that if it prevails in its May 1992 motion for rehearing, Cajun would owe GSU approximately $118 million as of December 31, 1993. If Cajun were to prevail in its May 1992 motion for rehearing to FERC, and if GSU were not to prevail in its May 1992 motion for rehearing to FERC, and if FERC does not implement the court's remand as GSU contends is required, GSU estimates it would owe Cajun approximately $76 million as of December 31, 1993. The above amounts are exclusive of a $7.3 million payment by Cajun on December 31, 1990, which the parties agreed to apply to the disputed transmission service charges. GSU and Cajun further agreed that their positions at FERC would remain unaffected by the $7.3 million. Pending FERC's ruling on the May 1992 motions for rehearing, GSU has continued to bill Cajun utilizing the historical billing methodology and has booked underpaid transmission charges, including interest, in the amount of $140.8 million as of December 31, 1993. This amount is reflected in long-term receivables and in other deferred credits, with no effect on net income. Capital Requirements and Financing Construction expenditures (excluding nuclear fuel) for the years 1994, 1995, and 1996 are estimated to total $134 million, $128 million, and $119 million, respectively. GSU will also require $214 million during the period 1994-1996 to meet long-term debt and preferred stock maturities and sinking fund requirements. GSU plans to meet the above requirements with internally generated funds and cash on hand. External financing during the period would be primarily for refinancing of higher cost securities. See Note 5 and Note 6 regarding the possible issuance of first mortgage bonds and preference stock and the possible refunding, redemption, purchase or other acquisition of outstanding securities. Nuclear Insurance The Price-Anderson Act limits public liability for a single nuclear incident to approximately $9.4 billion as of December 31, 1993. GSU has protection for this liability through a combination of private insurance (currently $200 million) and an industry assessment program. Under the assessment program, the maximum amount that would be required for each nuclear incident would be $79.28 million per reactor, payable at a rate of $10 million per licensed reactor per incident per year. GSU has one licensed reactor. Any assessments pertaining to this program are subject to the 70/30 % ownership interest between GSU and Cajun. In addition, GSU participates in a private insurance program which provides coverage for worker tort claims filed for bodily injury caused by radiation exposure. GSU's maximum assessment under the program is an aggregate of approximately $3.1 million in the event losses exceed accumulated reserve funds. GSU and Cajun are members of certain insurance programs that provide coverage for property damage, including decontamination and premature decommissioning expense, to members' nuclear generating plants. As of December 31, 1993, GSU was insured against such losses up to $2.7 billion with $250 million of this amount designated to cover any shortfall in the NRC required decommissioning trust funding. In addition, GSU is a member of an insurance program that covers certain replacement power and business interruption costs incurred due to prolonged nuclear unit outages. Under the property damage and replacement power/business interruption insurance programs, GSU could be subject to assessments if losses exceed the accumulated funds available to the insurers. As of December 31, 1993, the maximum amount of such possible assessments to GSU was $15.9 million. The amount of property insurance presently carried by GSU exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per site. NRC regulations provide that the proceeds of this insurance must be used, first, to place and maintain the reactor in a safe and stable condition 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. Spent Nuclear Fuel and Decommissioning Costs GSU provides for estimated future disposal costs for spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. GSU entered into a contract with the DOE, whereby the DOE will furnish disposal service at a cost of one mill per net KWH generated and sold. The fees payable to the DOE may be adjusted in the future to assure full recovery. GSU considers all costs incurred or to be incurred for the disposal of spent nuclear fuel to be proper components of nuclear fuel expense and provisions to recover such costs have been or will be made in applications to regulatory authorities. Due to delays of the DOE's repository program for the acceptance of spent nuclear fuel, it is uncertain when shipments of spent fuel from GSU will commence. In the meantime, GSU is responsible for spent fuel storage. Current on-site spent fuel storage capacity at River Bend is estimated to be sufficient until 2003. Thereafter, GSU will provide additional storage capacity at an estimated initial cost of $5 million to $10 million. In addition, approximately $3 million to $5 million will be required every four to five years subsequent to 2003 until DOE's repository begins accepting River Bend spent fuel. GSU is recovering in rates amounts sufficient to fund decommissioning costs for River Bend, based on the original 1985 decommissioning cost study of approximately $141 million. The amounts recovered in rates are deposited in external trust funds, with a market value of approximately $18.5 million and $14.5 million at December 31, 1993 and 1992, respectively. The accumulated decommissioning liability of $18.1 million as of December 31, 1993, has been recorded in accumulated depreciation. Decommissioning expense amounting to $3 million was recorded in 1993. A more recent 1991 engineering study, which has not yet been reflected in rates and used as a basis of funding, indicates decommissioning costs may be $279.8 million. GSU feels that recent changes in the laws will tend to allow annual contributions to the trust to remain at current levels of funding and offset or mitigate the increase in decommissioning costs, as indicated in the 1991 engineering study. The actual decommissioning costs may vary from the above estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment, and management believes that actual decommissioning costs are likely to be higher than the amounts presented above. The Energy Act has a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning of the DOE's past uranium enrichment operations. The decontamination and decommissioning assessments will be used to set up a fund into which contributions from utilities and the federal government will be placed. GSU's assessment, which will be adjusted annually for inflation, is $.6 million annually for approximately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortized. The liability of $7.8 million as of December 31, 1993, is recorded in other current liabilities and other noncurrent liabilities and is offset in financial statements by a regulatory asset, recorded as a deferred debit. Long-Term Contracts NISCO Power Purchases. In 1988, GSU entered into a joint venture with a primary term of 20 years with Conoco, Inc., Citgo Petroleum Corporation, and Vista Chemical Company (Industrial Participants) whereby GSU's Nelson Units 1 and 2 were sold to a partnership (NISCO) consisting of the Industrial Participants and GSU. The Industrial Participants are supplying the fuel for the units, while GSU operates the units at the discretion of the Industrial Participants and purchases the electricity produced by the units. GSU is continuing to sell electricity to the Industrial Participants. For the years ended December 31, 1993, 1992, and 1991, the purchases of electricity from the joint venture totaled $62.6 million, $37.8 million, and $61.3 million, respectively. Natural Gas Contracts. GSU has long-term gas contracts which will satisfy approximately 75% of its annual requirements. However, such contracts as a whole only require GSU to purchase in the range of 40% of expected total gas needs. Additional gas requirements are satisfied under less expensive short- term contracts. In November 1992, GSU entered into a transportation service agreement which obligated the gas supplier to provide GSU with flexible natural gas swing service to the Sabine and Lewis Creek generating stations. This service is provided by the supplier's pipeline and salt dome gas storage facility, which has a present capacity of 1.3 billion cubic feet of natural gas. Coal Contracts. GSU has contracted for a long-term supply of low-sulfur Wyoming coal for use at Nelson Unit 6. This contract, which is set to expire in 2004, will provide a supply of 50 million tons over the term of the contract. Cajun has advised GSU that current contracts will provide an adequate supply of coal for Big Cajun 2 Unit 3 until 1997. Environmental Issues GSU has been notified by the U. S. Environmental Protection Agency (EPA) that it has been designated as a potentially responsible party for the cleanup of sites on which GSU and others have or have been alleged to have disposed of mate rial designated as hazardous waste. GSU is currently negotiating with the EPA and state authorities regarding the cleanup of some of these sites. Several class action and other suits have been filed in state and federal courts seeking relief from GSU and others for damages caused by the disposal of hazardous waste and for asbestos-related disease which allegedly occurred from exposure on GSU premises. While the amounts at issue in the cleanup efforts and suits may be very substantial sums, management believes that its results of operations and financial condition will not be materially affected by the outcome of the suits. As of December 31, 1993, GSU has accrued cumulative amounts related to the cleanup of six sites at which GSU has been designated a potentially responsible party, totaling $25.2 million since 1990. Through December 31, 1993, GSU has expensed $7 million cumulatively on the cleanup, resulting in a remaining liability of $18.2 million as of December 31, 1993. GSU is also involved in litigation arising in the normal course of business. While the results of such litigation cannot be predicted with certainty, management believes that the final outcome will not have a material adverse effect on its financial condition or operating results when resolved in a future period. NOTE 9. LEASES General As of December 31, 1993, GSU had capital leases and noncancelable operating leases (excluding nuclear fuel leases) with minimum lease payments as follows: Capital Operating Year Leases Leases ---- ------- --------- (In Thousands) 1994 $ 12,475 $ 19,720 1995 12,475 19,720 1996 12,475 19,720 1997 12,475 9,509 1998 12,475 11,271 Years thereafter 93,855 96,749 -------- -------- Minimum lease payments 156,230 $176,689 Less: Amount representing interest 63,628 ======== -------- Present value of net minimum lease payments $ 92,602 ======== Rental expense for capital and operating leases (excluding nuclear fuel leases) amounted to approximately $31.9 million, $21.9 million, and $14.9 million, in 1993, 1992, and 1991, respectively. GSU is leasing the Lewis Creek generating station from its wholly owned consolidated subsidiary, GSG&T. Nuclear Fuel Lease GSU has arrangements to lease nuclear fuel with a non-affiliated third party which finances its acquisition of nuclear fuel through a credit agreement and the issuance of notes totaling $130 million as of December 31, 1993. On January 31, 1994, $25 million of the notes matured, while $40 million of the notes each will mature on January 31, 1995 and January 31, 1996. It is expected that alternative financing will be secured by the lessor upon the maturity of the notes in 1995 and 1996. If the lessor cannot arrange for alternative financing upon the maturity of its borrowings, GSU must purchase nuclear fuel in an amount sufficient to enable the lessor to retire such borrowings. Lease payments are based on nuclear fuel use. Nuclear fuel expense of $43.6 million, $31.6 million, and $58.1 million (including interest of $10.2 million, $11.5 million and $12.2 million) was charged to operations in 1993, 1992, and 1991, respectively. NOTE 10. POSTRETIREMENT BENEFITS Pension Plan GSU has a defined benefit pension plan covering substantially all of its employees. The pension plan is noncontributory and provides pension benefits that are based on employees' credited service and the highest five consecutive years of employees' compensation during the last ten years before retirement. GSU funds 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 plan consist primarily of common and preferred stocks and fixed income securities. GSU's 1993, 1992, and 1991 pension cost, including amounts capitalized, included the following components:
For the Years Ended December 31, -------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Service cost - benefits earned during the period $ 10,417 $ 12,396 $ 10,306 Interest cost on projected benefit obligation 17,643 16,307 15,355 Actual return on plan assets (43,400) (28,117) (56,898) Net amortization and deferral 14,863 2,926 36,347 -------- -------- -------- Net pension cost $ (477) $ 3,512 $ 5,110 ======== ======== ========
The funded status of GSU's pension plan as of December 31, 1993 and 1992, was:
1993 1992 -------- -------- (In Thousands) Actuarial present value of benefit obligations: Vested $197,386 $186,845 Nonvested 13,667 11,508 -------- -------- Accumulated benefit obligation $211,053 $198,353 ======== ======== Plan assets at fair market value $337,922 $306,660 Projected benefit obligation 259,462 255,573 -------- -------- Plan assets in excess of projected benefit obligation 78,460 51,087 Unrecognized prior service cost 25,977 24,671 Unrecognized transition asset (16,712) (19,099) Unrecognized net gain (92,910) (62,321) -------- -------- Accrued pension liability $ (5,185) $ (5,662) ======== ========
The significant actuarial assumptions used in computing the information above were: 1993 1992 1991 ---- ---- ---- Weighted average discount rate 7.50% 6.50% 7.25% Weighted average increase in future compensation levels 5.00 5.75 6.10 Expected long-term rate of return on plan assets 8.50 8.50 8.50 Transition assets are being amortized over 15 years. In December 1993, GSU recorded a $17 million charge related to the announced early retirement program in connection with the Merger, of which $14.9 million was expensed. Other Postretirement Benefits GSU also provides certain health care and life insurance benefits for retired employees. All of GSU's employees may become eligible for these benefits if they reach retirement age while still working for GSU. The cost of providing these benefits, recorded on a cash basis, was $5.3 million and $5.5 million for the years 1992 and 1991, respectively. Effective January 1, 1993, GSU adopted SFAS 106. The new standard requires a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. GSU continues to fund these benefits on a pay-as-you-go-basis. As of January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $128 million. This obligation is being amortized over a 20-year period beginning in 1993. In March 1993, the PUCT issued a ruling applicable to all Texas utilities that amounts recorded in compliance with SFAS 106 and included in a rate filing test period, will be recoverable in rates (at the time of the next general rate case) and that the postretirement benefit amounts allowed in rates must then be funded by the utility. The PUCT made no specific provision in its order permitting deferral, as a regulatory asset, of these costs. The LPSC ordered GSU to use the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions, but the LPSC retains the flexibility to examine companies' accounting for postretirement benefits to determine if special exceptions to this order are warranted. GSU's net income in 1993 was decreased by approximately $7.9 million as a result of adopting SFAS 106. GSU's 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components (in thousands): Service cost - benefits earned during the period $ 5,467 Interest cost on APBO 9,976 Actual return on plan assets - Amortization of transition obligation 6,402 ------- Net periodic postretirement benefit cost $21,845 ======= The funded status of GSU's postretirement plan as of December 31, 1993, was (in thousands): Accumulated postretirement benefit obligation: Retirees $ 46,270 Other fully eligible participants 38,091 Other active participants 18,359 --------- 102,720 Plan assets at fair value - --------- Plan assets in excess of (less than APBO) (102,720) Unrecognized transition obligation 121,634 Unrecognized net gain (35,534) --------- Accrued postretirement benefit liability $ (16,620) ========= The assumed health care cost trend rate used in measuring the APBO is 10% for 1994, gradually decreasing each successive year until it reaches 5% in 2002. A one percentage-point increase in the assumed health care cost trend rate for each year would increase the APBO as of December 31, 1993, by 13.6% and the sum of the service cost and interest cost by approximately 22.7%. The assumed discount rate and rate of increase in future compensation used in determining the APBO were 7.5%, and 5%, respectively. NOTE 11. TRANSACTIONS WITH AFFILIATES Effective December 31, 1993, GSU purchases electricity from and/or sells electricity to the other System operating companies under rate schedules filed with FERC. Operating revenues include revenues from sales to System operating companies prior to the Merger, totaling $.5 million in 1993, $0 in 1992, and $.5 million in 1991. Operating expenses include charges from System operating companies for purchased power and related charges, prior to the Merger, totaling $25.5 million in 1993, $38.8 million in 1992, and $16.1 million in 1991. NOTE 12. ENTERGY CORPORATION-GSU MERGER On December 31, 1993, Entergy Corporation and GSU consummated their Merger. GSU became a wholly-owned subsidiary of Entergy Corporation and continues to operate as a corporation under the regulation of the PUCT and the LPSC. As consideration to GSU's shareholders, Entergy Corporation paid $250 million and issued 56,667,726 shares of its common stock in exchange for the 114,055,065 outstanding shares of GSU common stock. The Merger was accounted for under the purchase method of accounting. Various parties have requested rehearings and/or are appealing the approval orders or plans of the SEC, NRC, LPSC, and FERC. As a result of the December 31, 1993 Merger closing, GSU recorded expenses totaling $49 million, net of related tax effects, for early retirement and other severance related plans and the payment to financial consultants involved in Merger negotiations on behalf of GSU. See Note 2 for information regarding Merger related rate agreements. Entergy Corporation recorded an acquisition adjustment in utility plant in the amount of $380 million representing the excess of the purchase price over the net assets acquired of GSU. The acquisition adjustment will be amortized on a straight-line basis over a 31-year period, which approximates the remaining average book life of GSU's plant. The allocation of the purchase price has been based on preliminary estimates which may be revised at a later date. The possibility of an adverse result in the litigation relating to Cajun (see Note 8) and the possibility of a write-off relating to Texas River Bend ratemaking issues (see Note 2) represent preacquisition contingencies. There may be other contingencies associated with GSU which could also constitute preacquisition contingencies but which have not yet been specifically identified as such by Entergy Corporation. During the allocation period (which will not exceed one year after consummation of the transaction), Entergy Corporation will complete its analyses with respect to these contingencies. Upon completion, should Entergy Corporation no longer believe GSU has a reasonable possibility of attaining a favorable ruling in such preacquisition contingencies, any resulting write-offs and/or losses would cause the reduction of the affected noncurrent assets and an increase of an equal amount in the acquisition adjustment in Entergy Corporation's consolidated financial statements, in accordance with the purchase method of accounting for business combinations. Any resulting write- offs and/or losses would be charged to operations during the current period on GSU's financial statements. NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED) Operating results for the four quarters of 1993 and 1992 were: Income (Loss) Before Extraordinary Items and the Cumulative Effect Net Operating Operating of Accounting Income Revenues Income Changes (Loss) --------- --------- ------------- ----- (In Thousands) 1993: First Quarter $404,178 $ 69,408 $ 15,007 $ 25,667 Second Quarter $442,223 $ 81,989 $ 31,066 $ 30,781 Third Quarter $574,607 $118,032 $ 70,155 $ 69,181 Fourth Quarter $406,612 $ 1,187 $(46,767) $(46,767) 1992: First Quarter $403,279 $ 71,372 $ 24,187 $ 26,209 Second Quarter $417,365 $ 78,999 $ 32,155 $ 27,889 Third Quarter $517,899 $116,252 $ 66,167 $ 65,648 Fourth Quarter $434,831 $ 71,997 $ 16,904 $ 14,102 GSU's business is subject to seasonal fluctuations with the peak period occurring during the third quarter. See Note 1 for information regarding the change in accounting for unbilled revenues during 1993. See Note 2 for information regarding rate refunds during December 1993, and Note 12 for information regarding Merger-related charges recorded during the fourth quarter of 1993. See Note 1 for information regarding extraordinary items recorded in 1992 due to the extinguishment of debt and for information regarding the cumulative effect of a change in accounting for power plant materials and supplies.
GULF STATES UTILITIES COMPANY SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1993 1992 1991 1990 1989 ---------- ---------- ---------- ---------- ---------- (In Thousands) Operating revenues $1,827,620 $1,773,374 $1,702,235 $1,690,685 $1,607,406 Income (loss) before extraordinary items and the cumulative effect of accounting changes $ 69,461 $ 139,413 $ 112,391 $ (36,399) $ (45,573) Total assets $7,165,776 $7,164,447 $7,183,119 $7,135,399 $6,751,432 Long-term obligations (1) $2,772,002 $2,798,768 $2,816,577 $2,663,249 $2,954,736
(1) Includes long-term debt (excluding currently maturing debt), preferred and preference stock with sinking fund, and noncurrent capital lease obligations. See Notes 1 and 10 for the effect of accounting changes in 1993 and 1992 and Notes 2 and 8 regarding River Bend rate appeals and litigation with Cajun.
1993 1992 1991 1990 1989 ---------- ---------- --------- ---------- ---------- (Dollars in Thousands) Electric Department Operating Revenues: Residential $ 585,799 $ 560,552 $ 547,147 $ 523,911 $ 487,972 Commercial 415,267 400,803 383,883 378,253 357,568 Industrial 650,230 642,298 582,568 578,928 541,019 Governmental 26,118 26,195 24,792 24,101 22,728 ---------- ---------- ---------- ---------- ---------- Total retail 1,677,414 1,629,848 1,538,390 1,505,193 1,409,287 Sales for resale 31,898 24,485 44,136 48,125 51,584 Other 38,649 40,203 41,433 43,317 41,003 ---------- ---------- ---------- ---------- ---------- Total Electric Department $1,747,961 $1,694,536 $1,623,959 $1,596,635 $1,501,874 ========== ========== ========== ========== ========== Billed Electric Energy Sales (Millions of KWH): Electric Department Residential 7,192 6,825 6,925 6,834 6,473 Commercial 5,711 5,474 5,460 5,388 5,198 Industrial 14,294 14,413 13,629 13,347 12,333 Governmental 296 302 295 285 275 ---------- ---------- ---------- ---------- ---------- Total retail 27,493 27,014 26,309 25,854 24,279 Sales for resale 666 540 1,049 1,180 916 ---------- ---------- ---------- ---------- ---------- Total Electric Department 28,159 27,554 27,358 27,034 25,195 Steam Department 1,597 1,722 1,711 1,930 2,271 ---------- ---------- ---------- ---------- ---------- Total 29,756 29,276 29,069 28,964 27,466 ========== ========== ========== ========== ==========
Louisiana Power & Light Company 1993 Financial Statements LOUISIANA POWER & LIGHT COMPANY DEFINITIONS Certain abbreviations or acronyms used in LP&L's Financial Statements, Notes to Financial Statements, and Management's Financial Discussion and Analysis are defined below: Abbreviation or Acronym Term AFUDC Allowance for Funds Used During Construction AP&L Arkansas Power & Light Company DOE United States Department of Energy Entergy or System Entergy Corporation and its various direct and indirect subsidiaries Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy Corporation that has operating responsibility for Grand Gulf 1, Waterford 3, ANO, and River Bend FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission Grand Gulf 1 Unit No. 1 of the Grand Gulf Station Grand Gulf 2 Unit No. 2 of the Grand Gulf Station Grand Gulf Station Grand Gulf Steam Electric Generating Station GSU Gulf States Utilities Company (including wholly owned subsidiaries - Varibus Corporation, GSG&T, Inc., Prudential Oil and Gas, Inc., and Southern Gulf Railway Company) KWH Kilowatt-Hour(s) LP&L Louisiana Power & Light Company LPSC Louisiana Public Service Commission Money Pool Entergy Money Pool, which allows certain System companies to borrow from, or lend to, certain other System companies MP&L Mississippi Power & Light Company NOPSI New Orleans Public Service Inc. OBRA Omnibus Budget Reconciliation Act of 1993 Owner Participant A corporation that, in connection with the Waterford 3 sale and leaseback transactions, has acquired a beneficial interest in a trust, the Owner Trustee of which is the owner and lessor of undivided interest in Waterford 3 Owner Trustee Each institution and/or individual acting as owner trustee under a trust agreement with an Owner Participant in connection with the Waterford 3 sale and leaseback transactions SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the FASB SFAS 106 SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS No. 109, "Accounting for Income Taxes" System or Entergy Entergy Corporation and its various direct and indirect subsidiaries System Energy System Energy Resources, Inc. System Fuels System Fuels, Inc. System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively Waterford 3 Unit No. 3 of LP&L's Waterford Steam Electric Generating Station LOUISIANA POWER & LIGHT COMPANY REPORT OF MANAGEMENT The management of Louisiana Power & Light Company has prepared and is responsible for the financial statements and related financial information included herein. The financial statements are based on generally accepted accounting principles. Financial information included elsewhere in this report is consistent with the financial statements. To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls that is designed to provide reasonable assurance, on a cost-effective basis, as to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. This system includes communication through written policies and procedures, an employee Code of Conduct, 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. The independent public accountants provide an objective assessment of the degree to which 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 these policies and procedures provide reasonable assurance that its operations are carried out with a high standard of business conduct. /S/ EDWIN LUPBERGER /S/ GERALD D. MCINVALE EDWIN LUPBERGER GERALD D. MCINVALE Chairman and Chief Executive Officer Senior Vice President and Chief Financial Officer LOUISIANA POWER & LIGHT COMPANY AUDIT COMMITTEE CHAIRMAN'S LETTER The Louisiana Power & Light Company Audit Committee of the Board of Directors is comprised of three directors, who are not officers of LP&L: Joseph J. Krebs, Jr. (Chairman), William K. Hood, and H. Duke Shackelford. The committee held four meetings during 1993. The Audit Committee oversees LP&L's financial reporting process on behalf of the Board of Directors and provides reasonable assurance to the Board that sufficient operating, accounting, and financial controls are in existence and are adequately reviewed by programs of internal and external audits. The Audit Committee discussed with Entergy's internal auditors and the independent public accountants (Deloitte & Touche) the overall scope and specific plans for their respective audits, as well as LP&L's financial statements and the adequacy of LP&L's internal controls. The committee met, together and separately, with Entergy's internal auditors and independent public accountants, without management present, to discuss the results of their audits, their evaluation of LP&L's internal controls, and the overall quality of LP&L's financial reporting. The meetings also were designed to facilitate and encourage any private communication between the committee and the internal auditors or independent public accountants. /S/ JOSEPH J. KREBS, JR. JOSEPH J. KREBS, JR. Chairman, Audit Committee INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directors of Louisiana Power & Light Company We have audited the accompanying balance sheets of Louisiana Power & Light Company (LP&L) as of December 31, 1993 and 1992, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of LP&L's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. 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 LP&L at December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. As discussed in Notes 3 and 10 to the financial statements, in 1993 LP&L changed its methods of accounting for income taxes and postretirement benefits other than pensions, respectively. /S/ DELOITTE & TOUCHE DELOITTE & TOUCHE New Orleans, Louisiana February 11, 1994 LOUISIANA POWER & LIGHT COMPANY BALANCE SHEETS ASSETS
December 31, ------------------------ 1993 1992 ---------- ---------- (In Thousands) Utility Plant (Note 1): Electric $4,646,020 $4,577,410 Electric plant under lease (Note 9) 225,083 225,083 Construction work in progress 133,536 67,535 Nuclear fuel under capital leases (Note 9) 61,375 63,190 Nuclear fuel 3,823 3,437 ---------- ---------- Total 5,069,837 4,936,655 Less - accumulated depreciation and amortization 1,496,107 1,380,282 ---------- ---------- Utility plant - net 3,573,730 3,556,373 ---------- ---------- Other Property and Investments: Nonutility property 20,060 20,060 Decommissioning trust fund (Note 8) 22,109 17,121 Investment in subsidiary company - at equity (Note 8) 14,230 14,230 Other 984 922 ---------- ---------- Total 57,383 52,333 ---------- ---------- Current Assets: Cash equivalents (Note 1): Temporary cash investments - at cost, which approximates market: Associated companies (Note 4) - 593 Other 33,489 22,189 ---------- ---------- Total cash equivalents 33,489 22,782 Special deposits 19,077 4,080 Accounts receivable: Customer (less allowance for doubtful accounts of $1.1 million in 1993 and $2.0 million in 1992) 66,575 58,067 Associated companies (Note 11) 2,952 8,863 Other 10,656 11,805 Accrued unbilled revenues (Note 1) 64,314 57,716 Deferred fuel costs (Note 1) - 2,939 Accumulated deferred income taxes (Note 3) 6,031 4,915 Materials and supplies - at average cost 87,204 87,856 Rate deferrals (Note 2) 28,422 28,422 Prepayments and other 16,510 41,527 ---------- ---------- Total 335,230 328,972 ---------- ---------- Deferred Debits: Rate deferrals (Note 2) 54,031 82,453 SFAS 109 regulatory asset - net (Note 3) 349,703 - Unamortized loss on reaquired debt 47,853 48,203 Other (Note 8) 46,068 40,814 ---------- ---------- Total 497,655 171,470 ---------- ---------- TOTAL $4,463,998 $4,109,148 ========== ========== See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES
December 31, ------------------------ 1993 1992 ---------- ---------- (In Thousands) Capitalization: Common stock, no par value, authorized 250,000,000 shares; issued and outstanding 165,173,180 shares in 1993 and 1992 (Note 5) $1,088,900 $1,088,900 Capital stock expense and other (6,109) (7,469) Retained earnings (Note 7) 89,849 94,510 ---------- ---------- Total common shareholder's equity 1,172,640 1,175,941 Preferred stock (Note 5): Without sinking fund 160,500 160,500 With sinking fund 126,302 148,802 Long-term debt (Note 6) 1,457,626 1,445,947 ---------- ---------- Total 2,917,068 2,931,190 ---------- ---------- Other Noncurrent Liabilities: Obligations under capital leases (Note 9) 27,508 28,160 Other (Note 8) 27,672 17,027 ---------- ---------- Total 55,180 45,187 ---------- ---------- Current Liabilities: Currently maturing long-term debt (Note 6) 25,315 1,275 Notes payable-associated companies (Note 4) 52,041 - Accounts payable: Associated companies (Note 11) 33,523 37,693 Other 76,284 100,312 Customer deposits 52,234 49,558 Taxes accrued 15,110 8,249 Interest accrued 42,141 41,138 Dividends declared 5,938 6,675 Gas contract settlement - liability to customers - 55,998 Deferred revenue - gas supplier judgment proceeds (Note 2) 14,632 42,256 Deferred fuel cost (Note 1) 605 - Obligations under capital leases (Note 9) 33,867 35,029 Other 9,741 11,428 ---------- ---------- Total 361,431 389,611 ---------- ---------- Deferred Credits: Accumulated deferred income taxes (Note 3) 834,899 441,064 Accumulated deferred investment tax credits (Note 3) 188,843 191,528 Deferred revenue - gas supplier judgment proceeds (Note 2) - 14,846 Deferred interest - Waterford 3 lease obligation (Note 9) 25,372 24,796 Other 81,205 70,926 ---------- ---------- Total 1,130,319 743,160 ---------- ---------- Commitments and Contingencies (Notes 2, 8, and 9) TOTAL $4,463,998 $4,109,148 ========== ========== See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS
For the Years Ended December 31, ---------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Operating Activities: Net income $188,808 $182,989 $166,572 Noncash items included in net income: Change in rate deferrals (Note 2) 28,422 28,422 28,422 Depreciation and decommissioning 142,051 138,290 130,898 Deferred income taxes and investment tax credits 40,261 42,896 73,795 Allowance for equity funds used during construction (2,581) (1,714) (1,244) Amortization of deferred revenues (Note 2) (42,470) (38,646) (36,310) Changes in working capital: Receivables (8,046) (5,135) (8,753) Accounts payable (28,198) 7,733 13,971 Taxes accrued 6,861 6,002 (22,642) Interest accrued 1,003 2,917 (6,680) Other working capital accounts 15,205 (16,037) (2,939) Refunds to customers - gas contract settlement (56,027) (56,066) (56,098) Decommissioning trust contributions (4,000) (2,000) (7,227) Other 18,299 5,982 4,403 -------- -------- -------- Net cash flow provided by operating activities 299,588 295,633 276,168 -------- -------- -------- Investing Activities: Construction expenditures (163,142) (150,527) (135,986) Allowance for equity funds used during construction 2,581 1,714 1,244 -------- -------- -------- Net cash flow used in investing activities (160,561) (148,813) (134,742) -------- -------- -------- Financing Activities: Proceeds from the issuance of: First mortgage bonds 100,000 269,000 - Preferred stock - 87,000 85,000 Common stock - - 100,000 Other long-term debt 58,000 44,094 49,907 Changes in short-term borrowings 52,041 - - Retirement of: First mortgage bonds (100,919) (309,205) (320,786) Other long-term debt (22,052) (15,977) (4,702) Redemption of preferred stock (22,500) (63,981) (60,500) Dividends paid: Common stock (167,600) (174,600) (63,552) Preferred stock (25,290) (28,845) (26,894) -------- -------- -------- Net cash flow used in financing activities (128,320) (192,514) (241,527) -------- -------- -------- Net increase (decrease) in cash and cash equivalents 10,707 (45,694) (100,101) Cash and cash equivalents at beginning of period 22,782 68,476 168,577 -------- -------- -------- Cash and cash equivalents at end of period $33,489 $22,782 $68,476 ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $127,497 $126,674 $172,421 Income taxes $62,414 $32,668 $33,133 Noncash investing and financing activities: Capital lease obligations incurred $33,210 $37,689 $10,002 See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES Liquidity is important to LP&L due to the capital intensive nature of our business, which requires large investments in long-lived assets. However, large capital expenditures for the construction of new generating capacity are not currently planned. LP&L requires significant capital resources for the periodic maturity of certain series of debt and preferred stock. Net cash flow from operations totaled $300 million, $296 million, and $276 million in 1993, 1992, and 1991, respectively. In recent years, this cash flow, supplemented by cash on hand, has been sufficient to meet substantially all investing and financing requirements, including capital expenditures, dividends, and debt/preferred stock maturities. LP&L's ability to fund these capital requirements results, in part, from our continued efforts to streamline operations and reduce costs, as well as collections under our Waterford 3 rate phase-in plan which exceed the current cash requirements for Waterford 3-related costs. (In the income statement, these revenue collections are offset by the amortization of previously deferred costs, therefore, there is no effect on net income.) See Note 2, incorporated herein by reference, for additional information on LP&L's rate phase-in plan. See Note 8, incorporated herein by reference, for additional information on LP&L's capital and refinancing requirements in 1994 - 1996. Also, in order to take advantage of lower interest and dividend rates, LP&L may continue to refinance high-cost debt and preferred stock prior to maturity. Earnings coverage tests and bondable property additions limit the first mortgage bonds and preferred stock that LP&L can issue. Based on the most restrictive applicable tests as of December 31, 1993, and assuming an annual interest or dividend rate of 8%, LP&L could have issued $92 million of additional first mortgage bonds or $686 million of additional preferred stock. Further, LP&L has the conditional ability to issue first mortgage bonds against the retirement of first mortgage bonds, in some cases without satisfying an earnings coverage test. See Notes 5 and 6, incorporated herein by reference, for information on LP&L's financing activities and Note 4, incorporated herein by reference, for information on LP&L's short-term borrowings and lines of credit. LOUISIANA POWER & LIGHT COMPANY STATEMENTS OF INCOME
For the Years Ended December 31, ------------------------------------- 1993 1992 1991 ---------- ---------- ---------- (In Thousands) Operating Revenues (Notes 1, 2, and 11): $1,729,666 $1,553,745 $1,528,934 ---------- ---------- ---------- Operating Expenses: Operation (Note 11): Fuel for electric generation and fuel-related expenses 338,670 256,313 212,973 Purchased power (Notes 2 and 8) 381,252 335,750 344,637 Other 260,419 250,836 253,080 Maintenance (Note 11) 98,281 92,363 101,896 Depreciation and decommissioning 142,051 138,290 130,898 Taxes other than income taxes 50,391 49,507 48,428 Income taxes (Note 3) 108,568 83,984 76,104 Amortization of rate deferrals (Note 2) 28,422 28,422 28,422 ---------- ---------- ---------- Total 1,408,054 1,235,465 1,196,438 ---------- ---------- ---------- Operating Income 321,612 318,280 332,496 ---------- ---------- ---------- Other Income: Allowance for equity funds used during construction 2,581 1,714 1,244 Miscellaneous - net 2,069 6,676 8,739 Income taxes (Note 3) (2,245) (3,053) (8,616) ---------- ---------- ---------- Total 2,405 5,337 1,367 ---------- ---------- ---------- Interest Charges: Interest on long-term debt 124,632 128,672 158,816 Other interest - net 12,325 12,691 9,206 Allowance for borrowed funds used during construction (1,748) (735) (731) ---------- ---------- ---------- Total 135,209 140,628 167,291 ---------- ---------- ---------- Net Income 188,808 182,989 166,572 Preferred Stock Dividend Requirements 24,754 28,416 27,343 ---------- ---------- ---------- Earnings Applicable to Common Stock $164,054 $154,573 $139,229 ========== ========== ========== See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, -------------------------------- 1993 1992 1991 ------- -------- -------- (In Thousands) Retained Earnings, January 1 $94,510 $117,820 $46,583 Add: Net income 188,808 182,989 166,572 ------- -------- -------- Total 283,318 300,809 213,155 ------- -------- -------- Deduct: Dividends declared: Preferred stock 24,553 28,416 27,343 Common stock 167,600 174,600 63,552 Capital stock expenses 1,316 3,283 4,440 ------- -------- -------- Total 193,469 206,299 95,335 ------- -------- -------- Retained Earnings, December 31 (Note 7) $89,849 $94,510 $117,820 ======= ======== ======== See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Excluding the effects of implementing SFAS 109 and SFAS 106 (see Notes 3 and 10, incorporated herein by reference), net income for 1993 would have been $198.8 million resulting in an increase of $15.8 million. This increase is due primarily to increased retail energy sales. Net income increased in 1992 due primarily to a decrease in interest expense. Significant factors affecting the results of operations and causing variances between the years 1993 and 1992, and 1992 and 1991, are discussed under "Revenues and Sales" and "Expenses" below. Revenues and Sales See "Selected Financial Data - Five-Year Comparison," incorporated herein by reference, following the notes, for information on operating revenues by source and KWH sales. Electric operating revenues were higher in 1993 due primarily to increased fuel adjustment revenues, which do not affect net income, and to increased residential and commercial energy sales resulting primarily from a return to more normal weather as compared to milder weather in 1992. Industrial energy sales also increased primarily in the petrochemical industry. Electric operating revenues were higher in 1992 due primarily to increased fuel adjustment revenues and revenue from sales for resale. These increases were partially offset by decreased retail base revenues as a result of milder temperatures. Total energy sales remained relatively flat in 1992 with higher sales for resale offset by lower residential and commercial sales resulting from these milder temperatures. Expenses Fuel for electric generation and fuel-related expenses and purchased power increased in 1993 due primarily to an increase in generation requirements resulting primarily from increased retail energy sales and increased fuel costs. Fuel for electric generation and fuel-related expenses increased in 1992 due primarily to a higher average per unit cost for gas resulting from increased gas prices in 1992. Total income taxes increased in 1993 due primarily to higher pretax income, an increase in the federal income tax rate as a result of OBRA, and the effect of implementing SFAS 109. Interest expense decreased in 1993 and 1992 as a result of the continued refinancing of high cost debt during 1993 and 1992. LOUISIANA POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Competition LP&L welcomes competition in the electric energy business and believes that a more competitive environment should benefit our customers, employees, and shareholders of Entergy Corporation. We also recognize that competition presents us with many challenges, and we have identified the following as our major competitive challenges: Retail and Wholesale Rate Issues Increasing competition in the utility industry brings an increased need to stabilize or reduce retail rates. LP&L is scheduled for a review of its rates and rate structure by the LPSC upon expiration of LP&L's current rate freeze in March 1994. Under the same LPSC order, an approximate $46 million per year increase in LP&L's retail rates will also expire in March 1994. See Note 2, incorporated herein by reference, for additional information. Retail wheeling, a major industry issue which may require utilities to "wheel" or move power from third parties to their own retail customers, is evolving gradually. As a result, the retail market could become more competitive. In the wholesale rate area, FERC approved in 1992, with certain modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power, Inc. to sell wholesale power at market-based rates and to provide to electric utilities "open access" to the System's transmission system (subject to certain requirements). GSU was later added to this filing. Various intervenors in the proceeding filed petitions for review with the United States Court of Appeals for the District of Columbia Circuit. FERC's order, once it takes effect, will increase marketing opportunities for LP&L, but will also expose LP&L to the risk of loss of load or reduced revenues due to competition with alternative suppliers. In light of the rate issues discussed above, LP&L is aggressively reducing costs to avoid potential earnings erosions that might result as well as to successfully compete by becoming a low-cost producer. To help minimize future costs, LP&L remains committed to least cost planning. In December 1992, LP&L filed a Least Cost Integrated Resource Plan (Least Cost Plan) with its retail regulators. Least cost planning includes demand-side measures such as customer energy conservation and supply-side measures such as more efficient power plants. These measures are designed to delay the building of new power plants for the next 20 years. LP&L plans to periodically file revised Least Cost Plans. The Energy Policy Act of 1992 The Energy Policy Act of 1992 (Energy Act) is changing the transmission and distribution of electricity. This act encourages competition and affords us the opportunities, and the risks, associated with an open and more competitive market environment. The Energy Act increases competition in the wholesale energy market through the creation of exempt wholesale generators (EWGs). The Energy Act also gives FERC the authority to order investor-owned utilities to provide transmission access to or for other utilities, including EWGs. LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES LP&L maintains accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications. Revenues and Fuel Costs LP&L records revenues when billed to its customers and, in addition, accrues revenue for the nonfuel portion of estimated revenues for energy delivered since the latest billings. LP&L's rate schedules include fuel adjustment clauses that allow deferral of fuel costs until such costs are reflected in the related revenues. Utility Plant Utility plant is stated at original cost. Partial disallowances of plant cost ordered by the regulators have been recorded as an adjustment to utility plant. The original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of LP&L's utility plant is subject to the lien of its mortgage indenture. In addition, certain assets of LP&L are subject to the liens of second mortgages related to pollution control revenue bonds. 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 utility plant and increases earnings, it is only realized in cash through depreciation provisions included in rates. LP&L's effective composite rates for AFUDC were 10.4%, 10.7%, and 10.6% for 1993, 1992, and 1991, respectively. Utility plant includes the portions of Waterford 3 that were sold and are currently under lease. LP&L retired this property from its continuing property records as formerly owned property released from and no longer subject to LP&L's first mortgage indenture. LP&L is reflecting such leased property for financial reporting purposes as property under lease from others and depreciating this property over the life of the plant. See Note 9 for additional lease disclosure. Depreciation is computed on the straight-line basis at rates based on the estimated service lives and costs of removal of the various classes of property. Depreciation provisions on average depreciable property approximated 3.0% in 1993 and 2.9% in 1992 and 1991. Income Taxes LP&L, its parent, and affiliates (excluding GSU prior to 1994) file a consolidated federal income tax return. Income taxes are allocated to LP&L in proportion to its contribution to consolidated taxable income. SEC regulations require that no System company pay more taxes than it would have had a separate income tax return been filed. Deferred taxes are recorded for all temporary differences between book and taxable income. Investment tax credits are deferred and amortized based upon the average useful life of the related property in accordance with rate treatment. As discussed in Note 3, effective January 1, 1993, LP&L changed its accounting for income taxes to conform with SFAS 109. Reacquired Debt The premiums and costs associated with reacquired debt are being amortized over the life of the related new issuances, in accordance with ratemaking treatment. Cash and Cash Equivalents LP&L considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Fair Value Disclosure The estimated fair value amounts of financial instruments have been determined by LP&L, using available market information and appropriate valuation methodologies. However, considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that LP&L could realize in a current market exchange. In addition, gains or losses realized on financial instruments may be reflected in future rates and not accrue to the benefit of stockholders. LP&L considers the carrying amounts of 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. In addition, LP&L does not presently expect that performance of its obligations will be required in connection with certain off-balance sheet commitments and guarantees considered financial instruments. Due to this factor, and because of the related party nature of these commitments and guarantees, determination of fair value is not considered practicable. See Notes 5, 6, and 8 for additional fair value disclosure. NOTE 2. RATE AND REGULATORY MATTERS LPSC Investigation Pursuant to an LPSC request to explain LP&L's "relatively high cost of debt" compared to other electric utilities subject to LPSC jurisdiction, LP&L sent a response to the LPSC in August 1993. In an August 1993 report to the LPSC, the LPSC's legal consultants acknowledged LP&L's rationale for its cost of debt in comparison to two other utilities subject to the LPSC's jurisdiction. Further, the legal consultants suggested that certain aspects of the LP&L cost of debt could be taken up in any rate proceedings after the expiration of LP&L's rate freeze in March 1994. In October 1993, the LPSC approved a schedule to conduct a review of LP&L's rates and rate structure upon the expiration of LP&L's current rate freeze. Waterford 3 and Grand Gulf 1 In a series of LPSC orders, court decisions, and agreements between November 1985 and June 1988, LP&L was granted Waterford 3 and Grand Gulf 1 rate relief. In addition, LP&L, in accordance with judicial decisions and LPSC rate orders, deferred a net amount of $266 million of its Waterford 3 costs related to the period November 14, 1985 through January 31, 1988. These deferred costs are being recovered over approximately 8.6 years beginning in April 1988. In November 1985, LP&L agreed to permanently absorb, and not recover from its retail customers, 18% of its 14% (approximately 2.52%) FERC-allocated share of the costs of capacity and energy of Grand Gulf 1. However, LP&L was allowed to recover, through the fuel adjustment clause, 4.6 cents per KWH (currently 2.55 cents per KWH through May 1994) for the energy related to the permanently absorbed percentage, with LP&L's permanently retained percentage to be available for sale to non-affiliated parties, subject to LPSC approval. For the year ended December 31, 1993, $91 million was billed to LP&L by System Energy. March 1989 Order A March 1989 LPSC Order, which expires in March 1994, entitled LP&L to an annual increase in retail rates of approximately $45.9 million. Instead of a rate increase, the LPSC allowed LP&L to retain $188.6 million of proceeds LP&L received in October 1988 as a result of litigation with a gas supplier. Therefore, in March 1989 LP&L began amortizing over a 5.3 year period, for the benefit of ratepayers, the proceeds plus accrued interest through February 1989. As of December 31, 1993, the unamortized balance of such jurisdictional proceeds was approximately $14.6 million. LP&L believes that the March 1989 Order has provided approximately the same amount of additional net income as would an annual rate increase of $45.9 million. LP&L agreed to a five-year base rate freeze, at the then current level, except for, among other things, recovery of certain taxes, net increases or decreases in LP&L's costs resulting from proceedings at FERC relating to the Grand Gulf Station, or as a result of catastrophic events. The impact of the March 1989 Order was to increase net income in 1993, 1992, and 1991 by approximately $26.1, $28.5, and $27.7 million, respectively. NOTE 3. INCOME TAXES Effective January 1, 1993, LP&L adopted SFAS 109. This new standard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that deferred tax balances be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 requires that regulated enterprises recognize adjustments resulting from implementation as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. A substantial majority of the adjustments required by SFAS 109 was recorded to deferred tax balance sheet accounts with offsetting adjustments to regulatory assets and liabilities. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. As a result of the adoption of SFAS 109, 1993 net income was reduced by $5.7 million, assets were increased by $309.7 million, and liabilities were increased by $315.4 million. Income tax expense consisted of the following:
For the Years Ended December 31, -------------------------------- 1993 1992 1991 -------- ------- ------- (In Thousands) Current: Federal $62,037 $30,326 $5,180 State 8,514 6,139 3,504 -------- ------- ------- Total 70,551 36,465 8,684 -------- ------- ------- Deferred - net: Liberalized depreciation 54,297 53,751 56,132 Unbilled revenue 3,474 (7,906) 489 Deferred Waterford 3 expenses (14,043) (14,043) (14,043) Adjustment of prior years' tax provisions 2,665 (5,331) (3,659) Waterford 3 sale and leaseback (3,632) (3,526) (3,898) Gas contract settlement 9,513 15,180 15,342 Nuclear refueling and maintenance (5,768) 1,989 5,485 Materials and supplies inventory adjustments (2,505) (2,497) (841) Alternative minimum tax (8,781) - 10,361 Contract deferred revenue 438 344 540 Property insurance reserve 23 3,119 (682) Deferred fuel (1,337) 2,977 (357) Bond reacquisition (243) 4,868 64 Decontamination and decommissioning fund 5,273 - - Other 3,643 2,964 2,859 -------- ------- ------- Total 43,017 51,889 67,792 -------- ------- ------- Investment tax credit adjustments - net (2,755) (1,317) 8,244 -------- ------- ------- Recorded income tax expense $110,813 $87,037 $84,720 ======== ======= ======= Charged to operations $108,568 $83,984 $76,104 Charged to other income 2,245 3,053 8,616 -------- ------- ------- Recorded income tax expense 110,813 87,037 84,720 Income taxes applied against the debt component of AFUDC - 442 440 -------- ------- ------- Total income taxes $110,813 $87,479 $85,160 ======== ======= =======
Total income taxes differ from the amounts computed by applying the statutory federal income tax rate to income before taxes. The reasons for the differences were:
For the Years Ended December 31, ------------------------------------------------------ 1993 1992 1991 -------------------- ---------------- --------------- % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income -------- -------- ------- ------ ------- ------ (Dollars in Thousands) Computed at statutory rate $104,867 35.0 $91,809 34.0 $85,439 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 6,727 2.2 4,272 1.6 3,797 1.5 Depreciation 2,550 0.9 3,064 1.1 3,182 1.3 Impact of change in tax rate (2,767) (0.9) (3,989) (1.5) (3,012) (1.2) Recapture of prior years' consolidated income tax savings 573 0.2 (175) (0.1) 5,032 2.0 Amortization of investment tax credits (6,876) (2.3) (6,780) (2.5) (6,561) (2.6) SFAS 109 adjustment 4,193 1.4 - - - - Other - net 1,546 0.5 (1,164) (0.5) (3,157) (1.3) -------- ---- ------- ---- ------- ---- Recorded income tax expense $110,813 37.0 $87,037 32.1 $84,720 33.7 Income taxes applied against the debt component of AFUDC - - 442 .2 440 0.2 -------- ---- ------- ---- ------- ---- Total income taxes $110,813 37.0 $87,479 32.3 $85,160 33.9 ======== ==== ======= ==== ======= ====
Significant components of LP&L's net deferred tax liabilities as of December 31, 1993, were (in thousands): Deferred tax liabilities: Net regulatory assets $ (422,371) Plant related basis differences (665,517) Rate deferrals (40,737) Bond reacquisition loss (17,368) Other (14,429) ----------- Total $(1,160,422) =========== Deferred tax assets: Unbilled revenues $ 13,190 Accumulated deferred investment tax credit 72,667 Gas contract settlement 12,917 Removal cost 47,603 Alternative minimum tax credit 41,618 Standard coal plant 12,898 Waterford 3 sale/leaseback 98,541 Other 32,120 ----------- Total $ 331,554 =========== Net deferred tax liabilities $ (828,868) =========== The alternative minimum tax (AMT) credit as of December 31, 1993, was $41.6 million. This AMT credit can be carried forward indefinitely and will reduce LP&L's federal income tax liability in future years. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized LP&L to effect short-term borrowings up to $125 million, subject to increase to as much as $259 million after further SEC approval. This authorization is effective through November 30, 1994. As of December 31, 1993, LP&L had unused lines of credit for short-term borrowings of $20.2 million from banks within its service territory. In addition, LP&L can borrow from the Money Pool, subject to its maximum authorized level of short- term borrowings and the availability of funds. LP&L had $52 million in outstanding borrowings under the Money Pool arrangement as of December 31, 1993. NOTE 5. PREFERRED AND COMMON STOCK The number of shares and dollar value of LP&L's preferred stock was:
As of December 31, ---------------------------------------- Shares Call Price Per Authorized and Total Share as of Outstanding Dollar Value December 31, 1993 1992 1993 1992 1993 ------- ------- ------- -------- ------------- (Dollars in Thousands) 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 8.56% Series 100,000 100,000 10,000 10,000 $103.14 Cumulative, $25 par value 8.00% Series (1) 1,480,000 1,480,000 37,000 37,000 - 9.68% Series (1) 2,000,000 2,000,000 50,000 50,000 - --------- --------- -------- -------- Total without sinking fund 4,215,000 4,215,000 $160,500 $160,500 ========= ========= ======== ======== With sinking fund: Cumulative, $100 par value 7.00% Series (1) 500,000 500,000 $50,000 $50,000 - 8.00% Series (1) 350,000 350,000 35,000 35,000 - Cumulative, $25 par value 10.72% Series 390,211 630,211 9,755 15,755 $26.34 13.12% Series 61,121 221,121 1,528 5,528 $26.64 14.72% Series 416 200,416 10 5,010 $26.84 12.64% Series 1,200,370 1,500,370 30,009 37,509 $27.37 --------- --------- -------- -------- Total with sinking fund 2,502,118 3,402,118 $126,302 $148,802 ========= ========= ======== ========
(1) These series are not redeemable as of December 31, 1993. The fair value of LP&L's preferred stock with sinking fund was estimated to be approximately $141.9 million and $171.5 million as of December 31, 1993 and 1992, respectively. The fair value was determined using quoted market prices or estimates from nationally recognized investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. As of December 31, 1993, LP&L had 2,195,000 and 6,320,000 shares of cumulative, $100 and $25 par value preferred stock, respectively, that were authorized but unissued. Changes in the common stock and preferred stock, with and without sinking fund, during the last three years were: Number of Shares -------------------------------------- 1993 1992 1991 ---------- ----------- ----------- Common stock issuances - - 15,168,800 Preferred stock issuances: $100 par value - 500,000 350,000 $25 par value - 1,480,000 2,000,000 Preferred stock retirements: $100 par value - (370,000) (350,000) $25 par value (900,000) (1,015,160) (1,020,000) Cash sinking fund requirements for the next five years for preferred stock outstanding as of December 31, 1993 are (in millions): 1994 - $8.3; 1995 - $6.8; 1996 - $6.8; 1997 - $4.5; and 1998 - $3.8. LP&L has the annual non-cumulative option to redeem, at par, additional amounts of certain series of its outstanding preferred stock. LP&L has SEC authorization for the issuance and sale, through December 31, 1994, of up to $285 million of preferred stock (of which $113 million remained available as of December 31, 1993). The proceeds would be used for the refinancing of higher cost debt and preferred stock and general corporate purposes. LP&L has SEC authorization through December 31, 1994 for the acquisition, in whole or in part, of up to $75 million aggregate par value of certain outstanding series of its preferred stock. NOTE 6. LONG-TERM DEBT LP&L's long-term debt as of December 31, 1993 and 1992 was:
Maturities Interest Rates From To From To 1993 1992 ---- ----- ----- ------ --------- -------- (In Thousands) First Mortgage Bonds 1994 1998 4-5/8% 10.36% $204,000 $204,000 1999 2003 7-1/2% 9-3/8% 361,520 306,520 2004 2006 8-3/4% - 52,767 2020 2022 8-1/2% 10-1/8% 185,000 185,000 Governmental Obligations* 1993 2008 6-2/5% 8% 37,794 15,520 2009 2023 5.95% 8-1/4% 350,000 314,589 Long-Term Obligation - Purchase Agreement - 21,737 Waterford 3 Lease Obligation, 8.76% (Note 9) 353,600 353,600 Unamortized Premium and Discount - Net (8,973) (6,511) ---------- ---------- Total Long-Term Debt 1,482,941 1,447,222 Less Amount Due Within One Year 25,315 1,275 ---------- ---------- Long-Term Debt Excluding Amount Due Within One Year $1,457,626 $1,445,947 ========== ==========
* Consists of pollution control bonds and municipal revenue bonds, certain series of which are secured by non-interest bearing first mortgage bonds. The fair value of LP&L's long-term debt, excluding Waterford 3 lease obligation and long-term Purchase Agreement, as of December 31, 1993 and 1992 was estimated to be $1,205.1 million and $1,123.0 million, respectively. The fair value was determined using quoted market prices or estimates from nationally recognized investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. For the years 1994, 1995, 1996, 1997, and 1998, LP&L has long-term debt maturities and cash sinking fund requirements of (in millions): $25.3, $75.3, $35.3, $34.3, and $35.3, respectively. In addition, other sinking fund requirements of approximately $6 million annually may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements. LP&L has SEC authorization for the issuance and sale through December 31, 1994, of up to $625 million of first mortgage bonds (of which $256 million remained available as of December 31, 1993) and to enter into agreements, subject to meeting certain conditions, with the Parish of St. Charles, Louisiana (Parish) whereby the Parish would issue and sell up to $250 million of tax-exempt revenue bonds (of which $98 million remained available as of December 31, 1993) in order to reimburse LP&L for, or to permanently finance, the costs of certain solid waste disposal, sewage disposal, and/or air or water pollution control facilities. LP&L also has SEC authorization for the acquisition, in whole or in part, through December 31, 1994 and prior to their respective maturities, (1) up to $436 million of its outstanding first mortgage bonds, including, but not limited to, the 10.36% Series due December 1, 1995, and (2) up to $75 million of outstanding pollution control revenue bonds, including, but not limited to, the 8.25% St. Charles Parish Pollution Control Revenue Bonds, Series 1984 due 2014, and the 8% Second Series 1984 Bonds due 2014. NOTE 7. DIVIDEND RESTRICTIONS LP&L's Restated Articles of Incorporation, as amended, and certain of its indentures, contain provisions restricting the payment of cash dividends or other distributions on common stock. As of December 31, 1993, none of LP&L's retained earnings were restricted against the payment of cash dividends or other distributions on common stock. On February 1, 1994, LP&L paid Entergy Corporation a $17.9 million cash dividend on common stock. NOTE 8. COMMITMENTS AND CONTINGENCIES Capital Requirements and Financing Construction expenditures (excluding nuclear fuel) for the years 1994, 1995, and 1996 are estimated to total $156 million, $143 million, and $142 million, respectively. LP&L will also require $158 million during the period 1994-1996 to meet long-term debt and preferred stock maturities and cash sinking fund requirements. LP&L plans to meet the above requirements with internally generated funds and cash on hand, supplemented by the issuance of debt and preferred stock. See Notes 5 and 6 regarding the possible refunding, redemption, purchase or other acquisition of certain outstanding series of preferred stock and long-term debt. Unit Power Sales Agreement System Energy has agreed to sell all of its 90% owned and leased share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this agreement are paid in consideration for LP&L's 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 approved by FERC, most likely upon Grand Gulf 1's retirement from service. LP&L's monthly obligation for payments under the agreement is approximately $8 million. Availability Agreement AP&L, LP&L, MP&L, and NOPSI are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 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. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Payments or advances under the Availability Agreement are only required if funds available to System Energy from all sources are less than the amount required under the Availability Agreement. 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 have ever been required. In 1989, the Availability Agreement was amended to provide that the write-off of $900 million of Grand Gulf 2 costs would be amortized for Availability Agreement purposes over a period of 27 years, in order to avoid the need for payments by AP&L, LP&L, MP&L, and NOPSI. If AP&L, MP&L, or NOPSI fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, LP&L could be liable for payments to System Energy, in amounts that cannot be determined, over and above its payments under the Unit Power Sales Agreement. Reallocation Agreement System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation Agreement relating to the sale of capacity and energy from the Grand Gulf Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and obligations with respect to the Grand Gulf Station under the Availability Agreement. FERC's decision allocating a portion of Grand Gulf 1 capacity and energy to AP&L supersedes the Reallocation Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect AP&L's obligation to System Energy's lenders under the assignments referred to in the preceding paragraph. AP&L would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual obligations. No payments of any amortization amounts will be required as 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. System Fuels LP&L has a 33% interest in System Fuels, a jointly owned subsidiary of AP&L, LP&L, MP&L, and NOPSI. The parent companies of System Fuels, including LP&L, agreed to make loans to System Fuels to finance its fuel procurement, delivery, and storage activities. As of December 31, 1993, LP&L had approximately $14.2 million of loans outstanding to System Fuels which mature in 2008. In addition, System Fuels entered into a revolving credit agreement with a bank that provides $45 million in borrowings to finance System Fuels' nuclear materials and services inventory. Should System Fuels default on its obligations under its credit agreement, AP&L, LP&L, and System Energy have agreed to purchase the nuclear materials and services financed under the agreement. Long-Term Contracts LP&L has a long-term agreement through 2031 to purchase energy generated by a hydroelectric facility. During 1993, 1992, and 1991, LP&L made payments under the contract of approximately $73.1 million, $39.1 million, and $43.2 million, respectively. If the maximum percentage (94%) of the energy is made available to LP&L, current production projections would require estimated payments of approximately $47 million per year through 1996, $54 million in 1997, and a total of $3.5 billion for the years 1998 through 2031. LP&L recovers the costs of purchased energy through its fuel adjustment clause. In June 1992, LP&L agreed to a renegotiated 20-year natural gas supply contract. LP&L has 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 $9 million through 1997, and a total of $124 million for the years 1998 through 2012. LP&L recovers the cost of fuel consumed during the generation of electricity through its fuel adjustment clause. Nuclear Insurance The Price-Anderson Act limits public liability for a single nuclear incident to approximately $9.4 billion, as of December 31, 1993. LP&L has protection for this liability through a combination of private insurance (currently $200 million) and an industry assessment program. Under the assessment program, the maximum amount that would be required for each nuclear incident would be $79.28 million per reactor, payable at a rate of $10 million per licensed reactor per incident per year. LP&L has one licensed reactor. In addition, LP&L participates in a private insurance program which provides coverage for worker tort claims filed for bodily injury caused by radiation exposure. LP&L's maximum assessment under the program is an aggregate of approximately $3.1 million in the event losses exceed accumulated reserve funds. LP&L is a member of certain insurance programs that provide coverage for property damage, including decontamination and premature decommissioning expense, to members' nuclear generating plants. As of December 31, 1993, LP&L was insured against such losses up to $2.7 billion, with $250 million of this amount designated to cover any shortfall in the NRC required decommissioning trust funding. In addition, LP&L is a member of an insurance program that covers certain costs of replacement power and business interruption incurred due to prolonged nuclear unit outages. Under the property damage and replacement power/business interruption insurance programs, LP&L could be subject to assessments if losses exceed the accumulated funds available to the insurers. As of December 31, 1993, the maximum amount of such possible assessments to LP&L was $24.34 million. The amount of property insurance presently carried by LP&L exceeds the Nuclear Regulatory Commission's (NRC) minimum requirement for nuclear power plant licensees of $1.06 billion per site. NRC regulations provide that the proceeds of this insurance must be used, first, to place and maintain the reactor in a safe and stable condition 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. Spent Nuclear Fuel and Decommissioning Costs LP&L provides for estimated future disposal costs for spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. LP&L entered into a contract 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. The fees payable to the DOE may be adjusted in the future to assure full recovery. LP&L considers all costs incurred or to be incurred, except accrued interest, for the disposal of spent nuclear fuel to be proper components of nuclear fuel expense and provisions to recover such costs have been accepted by the LPSC. Due to delays of the DOE's repository program for the acceptance of spent nuclear fuel, it is uncertain when shipments of spent fuel from LP&L will commence. In the meantime, LP&L is responsible for spent fuel storage. Current on-site spent fuel storage capacity at Waterford 3 is estimated to be sufficient until 2000. Thereafter, LP&L will provide additional storage capacity at an estimated initial cost of $5.0 million to $10.0 million. In addition, approximately $3.0 million to $5.0 million will be required every four to five years subsequent to 2000 until the DOE's repository begins accepting Waterford 3's spent fuel. Decommissioning costs for Waterford 3 were estimated to be $203.0 million (in 1988 dollars), based on a 1988 update to the original cost study. LP&L had LPSC authorization to fund and recover $4.0 million of decommissioning costs annually through 1993, based on the 1988 study update. LP&L will begin funding $4.8 million in 1994 in anticipation of a 1994 study update and a related LPSC review and determination of appropriate funding levels. These amounts are deposited in an external trust fund which has a market value of $23.5 million and $17.4 million as of December 31, 1993 and 1992, respectively. The accumulated decommissioning liability of $22.1 million as of December 31, 1993 has been recorded in accumulated depreciation. Decommissioning expense in the amount of $4.0 million was recorded in 1993. The actual decommissioning costs may vary from the above estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment, and management believes that actual decommissioning costs are likely to be higher than the amounts presented above. The Energy Act has a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning of the DOE's past uranium enrichment operations. The decontamination and decommissioning assessments will be used to set up a fund into which contributions from utilities and the federal government will be placed. LP&L's annual assessment, which will be adjusted annually for inflation, is $1.2 million (in 1993 dollars) annually for approximately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortized. The cumulative liability of $17.1 million at December 31, 1993 is recorded in other current liabilities and other noncurrent liabilities, according to FERC guidelines, and is offset in the financial statements by a regulatory asset, recorded as a deferred debit. NOTE 9. LEASES General As of December 31, 1993, LP&L had noncancelable operating leases with minimum lease payments as follows (in thousands): 1994 $4,024 1995 3,844 1996 3,706 1997 3,644 1998 3,549 Years thereafter 6,717 ------- Minimum lease payments $25,484 ======= Rental expense for operating leases amounted to approximately $6.6 million, $8.7 million, and $8.6 million in 1993, 1992, and 1991, respectively. Nuclear Fuel Lease LP&L has an arrangement to lease nuclear fuel in an amount up to $95 million. The lessor finances its acquisition of nuclear fuel through a credit agreement and the issuance of notes. The credit agreement, which was entered into in 1989, has been extended to January 1997 and the notes have varying remaining maturities of up to 5 years. It is expected that the credit arrangement will be extended or alternative financing will be secured by the lessor upon the maturity of the current arrangements. If the lessor cannot arrange for alternative financing upon maturity of its borrowings, LP&L must purchase nuclear fuel in an amount sufficient to enable the lessor to retire such borrowings. Lease payments are based on nuclear fuel use. Nuclear fuel lease expense of $39.9 million, $38.3 million, and $39.8 million (including interest of $4.9 million, $5.4 million, and $7.5 million) was charged to operations in 1993, 1992, and 1991, respectively. Waterford 3 Lease Obligations On September 28, 1989, LP&L entered into three substantially identical, but entirely separate, transactions for the sale (for an aggregate cash consideration of $353.6 million) and leaseback of three undivided portions of its 100% ownership interest in Waterford 3. The three undivided interests in Waterford 3 sold and leased back exclude certain transmission, pollution control, and other facilities that are part of Waterford 3. The interests sold and leased back, as described above, are equivalent on an aggregate cost basis to approximately 9.3% of Waterford 3. The sales were made to an Owner Trustee under three separate, but identical, trust agreements with three Owner Participants. LP&L is leasing back the sold interests from the Owner Trustee on a net lease basis over an approximate 28-year basic lease term. LP&L has options to terminate the lease and to repurchase the sold interests in Waterford 3 at certain intervals during the basic lease term. Further, at the end of the basic lease term, LP&L has an option to renew the lease or to repurchase the undivided interests in Waterford 3. The Owner Trustee acquired the interests with funds provided by the Owner Participants and with funds obtained from the issuance and sale by the Owner Trustee of intermediate-term and long-term bonds. The lease payments to be made by LP&L will be sufficient to service the debt incurred by the Owner Trustee. If LP&L does not exercise its option to repurchase the undivided interests in Waterford 3 on the fifth anniversary (September 1994) of the closing date of the sale and leaseback transactions, LP&L will be required to provide collateral to the Owner Participants for the equity portion of certain amounts payable by LP&L under the lease. Such collateral requirements are to be in the form of either a bank letter of credit or the pledge of new series of first mortgage bonds issued by LP&L under its first mortgage bond indenture. Upon the occurrence of certain adverse events (including lease events of default, events of loss, deemed loss events or certain adverse "Financial Events" with respect to LP&L), LP&L may be obligated to pay amounts sufficient to permit the Owner Participants to withdraw from the lease transactions and LP&L may be required to assume the outstanding bonds issued by the Owner Trustee to finance its acquisition of the undivided interests in Waterford 3. "Financial Events" include, among other things, failure by LP&L, following the expiration of any applicable grace or cure periods, to maintain (1) as of the end of any fiscal quarter, total equity capital (including preferred stock) at least equal to 30% of adjusted capitalization, or (2) in respect of the 12-month period ending on the last day of any fiscal quarter, a fixed charge coverage ratio of at least 1.50. As of December 31, 1993, LP&L's total equity capital (including preferred stock) was 48.59% of adjusted capitalization and its fixed charge coverage ratio was 3.18. In accordance with SFAS No. 98, "Accounting for Leases," due to "continuing involvement" by LP&L, the sale and leaseback by LP&L of the undivided portions of Waterford 3, as described above, are required to be reflected for financial reporting purposes as financing transactions in LP&L's financial statements even though such portions are no longer owned by LP&L. See Note 1 for further information regarding financial reporting treatment. As of December 31, 1993, LP&L had future minimum lease payments (reflecting an overall implicit rate of 8.76%) in connection with the Waterford 3 sale and leaseback transactions as follows (in thousands): 1994 $32,568 1995 32,569 1996 35,165 1997 39,805 1998 41,447 Years thereafter 726,744 -------- Minimum lease payments $908,298 ======== NOTE 10. POSTRETIREMENT BENEFITS Pension Plan LP&L has a defined benefit pension plan covering substantially all of its employees. The pension plan is noncontributory and provides pension benefits based on employees' credited service and average compensation, generally during the last five years before retirement. LP&L funds 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 plan consist primarily of common and preferred stocks, fixed income securities, interest in a money market fund, and insurance contracts. Effective October 1, 1988, LP&L amended its plan to designate NOPSI as a participating employer. LP&L's pension expense allocation policy results in substantially the same expense as that which would have been recorded if LP&L had not designated NOPSI as a participating employer. Pension costs are allocated to NOPSI based on an evaluation determined by an independent actuary. Effective June 6, 1990, LP&L's Waterford 3 nuclear employees became employees of Entergy Operations. However, the employees still remain under LP&L's plan, and no transfers of related pension liabilities and assets have been made. LP&L's 1993, 1992, and 1991 pension cost, including amounts capitalized, included the following components:
For the Years Ended December 31, -------------------------------- 1993 1992 1991 ------- ------ ------ (In Thousands) Service cost - benefits earned during the period $4,900 $4,307 $4,102 Interest cost on projected benefit obligation 14,684 14,110 13,121 Actual return on plan assets (26,533) (14,329) (38,644) Net amortization and deferral 8,712 (3,113) 21,940 Other - - 559 ------- ------ ------- Net pension cost $1,763 $ 975 $1,078 ======= ====== ======
The funded status of LP&L's pension plan as of December 31, 1993 and 1992, was (excluding amounts allocable to NOPSI):
1993 1992 -------- -------- (In Thousands) Actuarial present value of accumulated pension plan benefits: Vested $179,049 $160,001 Nonvested 768 558 -------- -------- Accumulated benefit obligation $179,817 $160,559 ======== ======== Plan assets at fair value $224,203 $209,667 Projected benefit obligation 211,928 183,985 -------- -------- Plan assets in excess of projected benefit obligation 12,275 25,682 Unrecognized prior service cost 6,257 6,723 Unrecognized transition asset (22,460) (25,268) Unrecognized net gain (5,734) (15,036) -------- -------- (9,662) (7,899) Unfunded portion of NOPSI pension liability (12,256) (23,161) -------- -------- Accrued pension liability $(21,918) $(31,060) ======== ========
The significant actuarial assumptions used in computing the information above for 1993, 1992, and 1991 were as follows: weighted average discount rate, 7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in future compensation levels, 5.6%; and expected long-term rate of return on plan assets, 8.5%. Transition assets are being amortized over 15 years. Other Postretirement Benefits LP&L also provides certain 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 LP&L. The cost of providing these benefits, recorded on a cash basis, to retirees in 1992 was approximately $3.7 million. Prior to 1992, the cost of providing these benefits for retirees was not separable from the cost of providing benefits for active employees. Based on the ratio of the number of retired employees to the total number of active and retired employees in 1991, the cost of providing these benefits in 1991, recorded on a cash basis, for retirees was approximately $3.5 million. Effective January 1, 1993, LP&L adopted SFAS 106. The new standard requires a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. LP&L continues to fund these benefits on a pay-as-you-go basis. As of January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $59.4 million. This obligation is being amortized over a 20-year period beginning in 1993. The LPSC ordered LP&L to use the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions, but the LPSC retains the flexibility to examine individual companies' accounting for postretirement benefits to determine if special exceptions to this order are warranted. LP&L's net income in 1993 was decreased by approximately $4.2 million as a result of adopting SFAS 106. LP&L's 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components (in thousands): Service cost - benefits earned during the period $2,083 Interest cost on APBO 4,749 Actual return on plan assets - Amortization of transition obligation 2,971 ------ Net periodic postretirement benefit cost $9,803 ====== The funded status of LP&L's postretirement plan as of December 31, 1993, was as follows (in thousands): Accumulated postretirement benefit obligation: Retirees $41,769 Other fully eligible participants 6,825 Other active participants 21,085 ------- 69,679 Plan assets at fair value - ------- Plan assets less than APBO (69,679) Unrecognized transition obligation 56,459 Unrecognized net loss 7,579 ------- Accrued post retirement benefit liability $(5,641) ======= The assumed health care cost trend rate used in measuring the APBO was 9.9% for 1994, gradually decreasing each successive year until it reaches 5.6% in 2020. A one percentage-point increase in the assumed health care cost trend rate for each year would have increased the APBO as of December 31, 1993, by 9.1% and the sum of the service cost and interest cost by approximately 11.8%. The assumed discount rate and rate of increase in future compensation used in determining the APBO were 7.5% and 5.5%, respectively. NOTE 11. TRANSACTIONS WITH AFFILIATES LP&L buys electricity from and/or sells electricity to AP&L, MP&L, NOPSI, and System Energy under rate schedules filed with FERC. In addition, LP&L purchases fuel from System Fuels, receives technical and advisory services from Entergy Services, Inc. and receives operating services from Entergy Operations. Operating revenues include revenues from sales to affiliates amounting to $4.8 million in 1993, $5.5 million in 1992, and $0.2 million in 1991. Operating expenses include charges from affiliates for fuel costs, purchased power and related charges, management services, and technical and advisory services totaling $322 million in 1993, $314.3 million in 1992, and $327.9 million in 1991. LP&L pays directly or reimburses Entergy Operations for the costs associated with operating Waterford 3 (excluding nuclear fuel), which were approximately $118.9 million in 1993, $152.1 million in 1992, and $151.1 million in 1991. NOTE 12. QUARTERLY FINANCIAL DATA (UNAUDITED) LP&L's business is subject to seasonal fluctuations with the peak period occurring during the third quarter. Operating results for the four quarters of 1993 and 1992 were: Operating Operating Net Revenues Income Income --------- --------- ------- (In Thousands) 1993: First Quarter $357,856 $ 56,875 $25,733 Second Quarter $399,570 $ 79,472 $46,932 Third Quarter $545,487 $124,789 $92,287 Fourth Quarter $426,753 $ 60,476 $23,856 1992: First Quarter $336,588 $ 59,585 $25,366 Second Quarter $364,694 $ 81,679 $46,560 Third Quarter $464,975 $116,797 $82,627 Fourth Quarter $387,488 $ 60,219 $28,436 LOUISIANA POWER & LIGHT COMPANY SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1993 1992 1991 1990 1989 ---------- ---------- ---------- ---------- ---------- (In Thousands) Operating revenues $1,729,666 $1,553,745 $1,528,934 $1,485,572 $1,426,806 Net income $ 188,808 $ 182,989 $ 166,572 $ 155,049 $ 106,613 Total assets $4,463,998 $4,109,148 $4,131,751 $4,262,124 $4,280,474 Long-term obligations (1) $1,611,436 $1,622,909 $1,582,606 $1,867,369 $1,915,286
(1) Includes long-term debt (excluding currently maturing debt), preferred stock with sinking fund, and noncurrent capital lease obligations. See Notes 3 and 10 for the effect of accounting changes in 1993.
1993 1992 1991 1990 1989 ---------- ---------- ---------- ---------- ---------- (Dollars in Thousands) Operating Revenues: Residential $572,738 $518,255 $525,594 $520,800 $496,800 Commercial 345,254 320,688 318,613 314,700 305,600 Industrial 652,574 578,741 558,036 532,800 541,200 Governmental 29,723 27,780 28,303 26,500 25,800 ---------- ---------- ---------- ---------- ---------- Total retail 1,600,289 1,445,464 1,430,546 1,394,800 1,369,400 Sales for resale 49,388 38,632 31,997 41,800 38,100 Other 79,989 69,649 66,391 49,000 19,300 ---------- ---------- ---------- ---------- ---------- Total $1,729,666 $1,553,745 $1,528,934 $1,485,600 $1,426,800 ========== ========== ========== ========== ========== Billed Electric Energy Sales (Millions of KWH): Residential 7,368 6,996 7,182 7,169 6,865 Commercial 4,435 4,307 4,367 4,299 4,175 Industrial 15,914 15,013 14,832 14,170 14,025 Governmental 398 385 405 382 369 ---------- ---------- ---------- ---------- ---------- Total retail 28,115 26,701 26,786 26,020 25,434 Sales for resale 1,325 1,305 1,201 1,149 1,014 ---------- ---------- ---------- ---------- ---------- Total 29,440 28,006 27,987 27,169 26,448 ========== ========== ========== ========== ==========
Mississippi Power & Light Company 1993 Financial Statements MISSISSIPPI POWER & LIGHT COMPANY DEFINITIONS Certain abbreviations or acronyms used in MP&L's Financial Statements, Notes to Financial Statements, and Management's Financial Discussion and Analysis are defined below: Abbreviation or Acronym Term AFUDC Allowance for Funds Used During Construction AP&L Arkansas Power & Light Company Entergy or System Entergy Corporation and its various direct and indirect subsidiaries FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission Final Order on Rehearing An order issued by the MPSC on September 16, 1985, with respect to MP&L's Grand Gulf 1-related rate issues G&R Bonds General and Refunding Mortgage Bonds issued and issuable under MP&L's G&R Mortgage dated as of February 1, 1988, as amended G&R Mortgage General and Refunding Mortgage established by MP&L effective February 1, 1988, to provide for issuances of G&R Bonds Grand Gulf Station Grand Gulf Steam Electric Generating Station Grand Gulf 1 Unit No. 1 of the Grand Gulf Station Grand Gulf 2 Unit No. 2 of the Grand Gulf Station GSU Gulf States Utilities Company (including wholly owned subsidiaries - Varibus Corporation, GSG&T, Inc., Prudential Oil and Gas, Inc., and Southern Gulf Railway Company) Independence Station Independence Steam Electric Generating Station KWH Kilowatt-Hours LP&L Louisiana Power & Light Company MWH Megawatt-Hours Merger The combination transaction, consummated on December 31, 1993, by which GSU became a subsidiary of Entergy Corporation and Entergy Corporation became a Delaware Corporation Money Pool Entergy Money Pool, which allows certain System companies to borrow from, or lend to, certain other System companies MP&L Mississippi Power & Light Company MPSC Mississippi Public Service Commission NOPSI New Orleans Public Service Inc. OBRA Omnibus Budget Reconciliation Act of 1993 Revised Plan MP&L's Grand Gulf 1-related rate phase-in plan, originally approved by the MPSC in the Final Order on Rehearing, as modified by the MPSC order issued September 29, 1988, to bring such plan into compliance with the requirements of SFAS No. 92 SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the FASB SFAS 106 SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS No. 109, "Accounting for Income Taxes" System Energy System Energy Resources, Inc. System Fuels System Fuels, Inc. System or Entergy Entergy Corporation and its various direct and indirect subsidiaries System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively MISSISSIPPI POWER & LIGHT COMPANY REPORT OF MANAGEMENT The management of Mississippi Power & Light Company has prepared and is responsible for the financial statements and related financial information included herein. The financial statements are based on generally accepted accounting principles. Financial information included elsewhere in this report is consistent with the financial statements. To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls that is designed to provide reasonable assurance, on a cost-effective basis, as to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. This system includes communication through written policies and procedures, an employee Code of Conduct, 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. The independent public accountants provide an objective assessment of the degree to which 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 these policies and procedures provide reasonable assurance that its operations are carried out with a high standard of business conduct. /S/ EDWIN LUPBERGER /S/ GERALD D. MCINVALE EDWIN LUPBERGER GERALD D. MCINVALE Chairman and Chief Executive Officer Senior Vice President and Chief Financial Officer MISSISSIPPI POWER & LIGHT COMPANY AUDIT COMMITTEE CHAIRMAN'S LETTER The Mississippi Power & Light Company Audit Committee of the Board of Directors is comprised of four directors, who are not officers of MP&L: John O. Emmerich, Jr. (Chairman), John N. Palmer, Sr., Dr. Clyda S. Rent, and Robert M. Williams, Jr. The committee held four meetings during 1993. The Audit Committee oversees MP&L's financial reporting process on behalf of the Board of Directors and provides reasonable assurance to the Board that sufficient operating, accounting, and financial controls are in existence and are adequately reviewed by programs of internal and external audits. The Audit Committee discussed with Entergy's internal auditors and the independent public accountants (Deloitte & Touche) the overall scope and specific plans for their respective audits, as well as MP&L's financial statements and the adequacy of MP&L's internal controls. The committee met, together and separately, with Entergy's internal auditors and independent public accountants, without management present, to discuss the results of their audits, their evaluation of MP&L's internal controls, and the overall quality of MP&L's financial reporting. The meetings also were designed to facilitate and encourage any private communication between the committee and the internal auditors or independent public accountants. /S/ JOHN O. EMMERICH JOHN O. EMMERICH Chairman, Audit Committee INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directors of Mississippi Power & Light Company We have audited the accompanying balance sheets of Mississippi Power & Light Company (MP&L) as of December 31, 1993 and 1992, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of MP&L's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. 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 MP&L at December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. As discussed in Note 1 to the financial statements, MP&L changed its method of accounting for revenues in 1993 and, as discussed in Notes 3 and 9 to the financial statements, in 1993 MP&L changed its methods of accounting for income taxes and postretirement benefits other than pensions, respectively. /S/ DELOITTE & TOUCHE DELOITTE & TOUCHE New Orleans, Louisiana February 11, 1994 MISSISSIPPI POWER & LIGHT COMPANY BALANCE SHEETS ASSETS
December 31, ----------------------- 1993 1992 ---------- ---------- (In Thousands) Utility Plant (Note 1): Electric $1,389,229 $1,364,464 Construction work in progress 62,699 25,879 ---------- ---------- Total 1,451,928 1,390,343 Less - accumulated depreciation and amortization 577,728 549,150 ---------- ---------- Utility plant - net 874,200 841,193 ---------- ---------- Other Property and Investments: Investment in subsidiary company - at equity (Note 8) 5,531 5,531 Other 4,760 4,382 ---------- ---------- Total 10,291 9,913 ---------- ---------- Current Assets: Cash and cash equivalents (Note 1): Cash 7,999 3,438 Temporary cash investments - at cost, which approximates market: Associated companies (Note 4) - 2,356 Other - 28,214 ---------- ---------- Total cash and cash equivalents 7,999 34,008 Notes receivable (Note 1) 7,118 7,405 Accounts receivable: Customer (less allowance for doubtful accounts of $2.5 million in 1993 and $1.3 million in 1992) 33,155 29,284 Associated companies (Note 10) 7,342 3,605 Other 3,672 4,718 Accrued unbilled revenues (Note 1) 57,414 - Fuel inventory - at average cost 8,652 7,325 Materials and supplies - at average cost 20,886 21,472 Rate deferrals (Note 2) 96,935 72,816 Prepayments and other 13,763 1,354 ---------- ---------- Total 256,936 181,987 ---------- ---------- Deferred Debits and Other Assets: Rate deferrals (Note 2) 504,428 600,102 Notes receivable (Note 1) 9,951 15,739 Other 20,931 11,792 ---------- ---------- Total 535,310 627,633 ---------- ---------- TOTAL $1,676,737 $1,660,726 ========== ========== See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES
December 31, ----------------------- 1993 1992 ---------- ---------- (In Thousands) Capitalization: Common stock, no par value, authorized 15,000,000 shares; issued and outstanding 8,666,357 shares in 1993 and 1992 (Note 5) $199,326 $199,326 Capital stock expense and other (1,864) (2,716) Retained earnings (Note 7) 236,337 230,201 ---------- ---------- Total common shareholder's equity 433,799 426,811 Preferred stock (Note 5): Without sinking fund 57,881 57,881 With sinking fund 46,770 63,270 Long-term debt (Note 6) 516,156 512,675 ---------- ---------- Total 1,054,606 1,060,637 ---------- ---------- Other Noncurrent Liabilities: Obligations under capital leases 686 842 Other 6,231 2,946 ---------- ---------- Total 6,917 3,788 ---------- ---------- Current Liabilities: Currently maturing long-term debt (Note 6) 48,250 55,230 Notes payable - associated companies 11,568 - Accounts payable: Associated companies (Note 10) 29,181 27,634 Other 12,157 8,649 Customer deposits 21,474 20,460 Taxes accrued 24,252 28,452 Accumulated deferred income taxes (Note 3) 41,758 31,842 Interest accrued 23,171 22,391 Dividends declared 1,985 2,472 Obligations under capital leases 156 151 Other 17,147 7,745 ---------- ---------- Total 231,099 205,026 ---------- ---------- Deferred Credits: Accumulated deferred income taxes (Note 3) 311,616 346,107 Accumulated deferred investment tax credits (Note 3) 37,193 36,999 SFAS 109 regulatory liability - net (Note 3) 23,626 - Other 11,680 8,169 ---------- ---------- Total 384,115 391,275 ---------- ---------- Commitments and Contingencies (Note 8) TOTAL $1,676,737 $1,660,726 ========== ========== See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS
For the Years Ended December 31, -------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Operating Activities: Net income $101,743 $65,036 $63,088 Noncash items included in net income: Cumulative effect of a change in accounting principle (32,706) - - Change in rate deferrals (Note 2) 71,555 17,530 14,626 Depreciation and amortization 32,152 31,493 30,089 Deferred income taxes and investment tax credits (17,881) 18,685 30,857 Allowance for equity funds used during construction (928) (668) (1,302) Changes in working capital: Receivables (11,814) (924) (3,743) Fuel inventory (1,327) 2,061 (2,577) Accounts payable 5,055 (14,365) (3,255) Taxes accrued (4,200) 2,174 640 Interest accrued 780 105 (2,712) Other working capital accounts (1,120) 1,918 230 Other 8,073 (4,272) 2,564 -------- -------- -------- Net cash flow provided by operating activities 149,382 118,773 128,505 -------- -------- -------- Investing Activities: Construction expenditures (66,404) (53,481) (58,368) Allowance for equity funds used during construction 928 668 1,302 -------- -------- -------- Net cash flow used in investing activities (65,476) (52,813) (57,066) -------- -------- -------- Financing Activities: Proceeds from issuance of: General and refunding bonds 250,000 65,000 - Common stock - 25,000 - Preferred stock - 19,777 - Retirement of: First mortgage bonds (204,501) (101,416) - General and refunding bonds (55,000) - - Other long-term debt (230) (210) (200) Redemption of preferred stock (16,500) (9,500) (9,500) Dividends paid: Common stock (85,800) (68,400) (7,847) Preferred stock (9,452) (9,445) (10,322) Changes in short-term borrowings 11,568 - (3,000) -------- -------- -------- Net cash flow used in financing activities (109,915) (79,194) (30,869) -------- -------- -------- Net increase (decrease) in cash and cash equivalents (26,009) (13,234) 40,570 Cash and cash equivalents at beginning of period 34,008 47,242 6,672 -------- -------- -------- Cash and cash equivalents at end of period $7,999 $34,008 $47,242 ======== ======= ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $52,459 $62,727 $69,548 Income taxes $58,831 $14,866 $2,108 See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES Liquidity is important to MP&L due to the capital intensive nature of our business, which requires large investments in long-lived assets. However, large capital expenditures for the construction of new generating capacity are not currently planned. MP&L also requires significant capital resources for the periodic maturity of certain series of debt and preferred stock. Net cash flow from operations totaled $149 million, $119 million, and $129 million in 1993, 1992, and 1991, respectively. In recent years, this cash flow, supplemented by cash on hand and issuances of debt and common and preferred stock, has been sufficient to meet substantially all investing and financing requirements, including capital expenditures, dividends, and debt/preferred stock maturities. MP&L's ability to fund these capital requirements results, in part, from our continued efforts to streamline operations and reduce costs, as well as collections under our Grand Gulf 1 rate phase-in plan, which exceed the current cash requirements for Grand Gulf 1-related costs. (In the income statement, these revenue collections are offset by the amortization of previously deferred costs, therefore, there is no effect on net income.) See Note 2, incorporated herein by reference, for additional information on MP&L's rate phase-in plan. See Note 8, incorporated herein by reference, for additional information on MP&L's capital and refinancing requirements in 1994 - 1996. Also, in order to take advantage of lower interest and dividend rates, MP&L may continue to refinance high-cost debt and preferred stock prior to maturity. Earnings coverage tests (which are impacted by the inclusion of the cumulative effect of the change in accounting principle for accruing unbilled revenues discussed in Note 1), bondable property additions, and accumulated deferred Grand Gulf 1-related costs recorded as assets, limit the G&R Bonds and preferred stock that MP&L can issue. Based on the most restrictive applicable tests as of December 31, 1993 and assuming an annual interest or dividend rate of 8%, MP&L could have issued $219 million of additional G&R Bonds or $548 million of additional preferred stock. Further, MP&L has the conditional ability to issue G&R Bonds against the retirement of bonds, in some cases without satisfying an earnings coverage test. See Notes 5 and 6, incorporated herein by reference, for information on MP&L's financing activities and Note 4, incorporated herein by reference, for information on MP&L's short-term borrowings and lines of credit. MISSISSIPPI POWER & LIGHT COMPANY STATEMENTS OF INCOME
For the Years Ended December 31, ---------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Operating Revenues (Notes 1, 2, and 10): $895,806 $817,650 $754,632 -------- -------- -------- Operating Expenses: Operation (Note 10): Fuel for electric generation and fuel-related expenses 140,391 112,032 104,553 Purchased power 289,016 301,912 284,868 Other 110,301 104,287 98,884 Maintenance 46,104 42,153 37,660 Depreciation and amortization 32,152 31,493 30,089 Taxes other than income taxes 41,878 40,738 37,534 Income taxes (Note 3) 33,074 21,681 29,936 Rate deferrals (Note 2): Rate deferrals - (22,876) (53,333) Amortization of rate deferrals 77,570 61,456 58,480 -------- -------- -------- Total 770,486 692,876 628,671 -------- -------- -------- Operating Income 125,320 124,774 125,961 -------- -------- -------- Other Income (Deductions): Allowance for equity funds used during construction 928 668 1,302 Miscellaneous - net 948 4,562 1,525 Income taxes - (debit) (Note 3) (3,462) (1,467) 81 -------- -------- -------- Total (1,586) 3,763 2,908 -------- -------- -------- Interest Charges: Interest on long-term debt 52,100 60,709 63,628 Other interest - net 3,260 3,357 4,013 Allowance for borrowed funds used during construction (663) (565) (1,860) -------- -------- -------- Total 54,697 63,501 65,781 -------- -------- -------- Income before Cumulative Effect of a Change in Accounting Principle 69,037 65,036 63,088 Cumulative Effect to January 1, 1993, of Accruing Unbilled Revenues (net of income taxes of $19,456) (Note 1) 32,706 - - -------- -------- -------- Net Income 101,743 65,036 63,088 Preferred Stock Dividend Requirements 9,160 9,513 10,074 -------- -------- -------- Earnings Applicable to Common Stock $92,583 $55,523 $53,014 ======== ======== ======== See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, ---------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Retained Earnings, January 1 $230,201 $243,819 $199,393 Add: Net income 101,743 65,036 63,088 -------- -------- -------- Total 331,944 308,855 262,481 -------- -------- -------- Deduct: Dividends declared: Preferred stock 8,964 9,513 10,074 Common stock 85,800 68,400 7,847 Preferred stock expenses 843 741 741 -------- -------- -------- Total 95,607 78,654 18,662 -------- -------- -------- Retained Earnings, December 31 (Note 7) $236,337 $230,201 $243,819 ======== ======== ======== See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income increased in 1993 due primarily to the one-time recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1, incorporated herein by reference) and its ongoing effects, partially offset by the effects of implementing SFAS 109 and SFAS 106 (see Notes 3 and 9, incorporated herein by reference). Effective January 1, 1993, MP&L began accruing as revenues the charges for energy delivered to customers but not yet billed. Electric revenues were previously recorded on a cycle-billing basis. Excluding the above mentioned items, net income for 1993 would have been $71.9 million. This $6.9 million increase is due primarily to an increase in retail energy sales and a decrease in interest expense from the refinancing of high-cost debt. Net income increased in 1992 due primarily to increased operating revenues and decreased interest expense and income tax expense, partially offset by increased maintenance expense. Significant factors affecting the results of operations and causing variances between the years 1993 and 1992, and 1992 and 1991, are discussed under "Revenues and Sales," "Expenses," and "Other" below. Revenues and Sales See "Selected Financial Data - Five-Year Comparison," incorporated herein by reference, following the notes, for information on operating revenues by source and KWH sales. Electric operating revenues were higher in 1993 due to increased residential and commercial energy sales resulting primarily from a return to more normal weather as compared to milder weather in 1992. Industrial energy sales also increased due to higher sales to the rubber and plastics, petroleum refining, and petroleum pipelines sectors. Sales for resale to associated companies were higher due to changes in generation availability and requirements among AP&L, LP&L, MP&L, and NOPSI . Additionally, electric operating revenues increased due to increased fuel adjustment revenues and increased collections of previously deferred Grand Gulf 1-related costs, neither of which affects net income. These increases were partially offset by a decrease in other revenue related to MP&L's rate deferral over/under recovery which reflects adjustments for the difference between actual and estimated costs, and does not affect net income. Electric operating revenues were higher in 1992 resulting from an increase in other revenue related to MP&L's rate deferral over/under recovery and an increase in retail operating revenues due to lower fuel adjustment credits. Neither of these revenue fluctuations affected net income. Revenues from sales for resale were higher in 1992 resulting from the September 1991 one-time intra- system equalization billing adjustment. (Certain 1985-1991 intra-system equalization billings under the System Agreement were adjusted in 1991, reducing operating revenues by approximately $10.6 million.) While total energy sales were relatively flat in 1992, increased sales for resale to nonassociated companies, resulting from changes in generation availability and requirements among AP&L, LP&L, MP&L, and NOPSI, were offset by lower retail sales resulting from milder temperatures. Expenses Fuel for electric generation and fuel-related expenses increased in 1993 due primarily to an increase in generation requirements resulting primarily from increased energy sales, as discussed in "Revenues and Sales" above, and increased fuel costs. Rate deferrals decreased in 1993 and 1992 as the deferral period for MP&L's phase-in plan for Grand Gulf 1-related costs ended in 1992. Further, the amortization of rate deferrals increased in 1993 reflecting the fact that MP&L, based on the Revised Plan, collected more Grand Gulf 1-related costs from its customers in 1993 than it recovered in 1992. Maintenance expense was higher in 1993 and 1992 due primarily to an increase in scheduled maintenance at MP&L's power plants. Total income taxes increased in 1993 due to the effect of higher pretax income, an increase in the federal income tax rate as a result of OBRA, and the effect of implementing SFAS 109. Total income taxes were lower in 1992 due primarily to an increase in estimated income tax benefits related to tax depreciation resulting from certain elections made in 1991. Other Miscellaneous other income - net increased in 1992 due primarily to interest income in connection with the settlement of deferred coal charges from System Fuels. Interest on long-term debt decreased in 1993 due primarily to the continued refinancing of high-cost debt. MISSISSIPPI POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Competition MP&L welcomes competition in the electric energy business and believes that a more competitive environment should benefit our customers, employees, and shareholders of Entergy Corporation. We also recognize that competition presents us with many challenges, and we have identified the following as our major competitive challenges: Retail and Wholesale Rate Issues Increasing competition in the utility industry brings an increased need to stabilize or reduce retail rates. The retail regulatory environment is shifting from traditional rate-base regulation to incentive-rate regulation. Incentive- rate and performance-based plans encourage efficiencies and productivity while permitting utilities to share in the results. In February 1994, the MPSC conducted a general review of MP&L's current rates and in March 1994, the MPSC issued a final order adopting a formula rate plan for MP&L that will allow for periodic small adjustments in rates based on a comparison of earned to benchmark returns and upon certain performance factors. The order also adopted previously agreed-upon stipulations of 1) a required return on equity of 11% and 2) certain accounting adjustments that result in a 4.3% ($28.1 million) reduction in MP&L's June 30, 1993, test-year operating revenues. The MPSC's order requires MP&L to file rates designed to provide for this reduction in operating revenues for the test year on or before March 18, 1994, to become effective for service rendered on or after March 25, 1994. See Note 2, incorporated herein by reference, for further information. Further in connection with the Merger, MP&L agreed with its retail regulator not to request any general retail rate increases or implement increases under the incentive plan that would take effect before November 1998, with certain exceptions. See Note 2, incorporated herein by reference, for further information. Retail wheeling, a major industry issue which may require utilities to "wheel" or move power from third parties to their own retail customers, is evolving gradually. As a result, the retail market could become more competitive. In the wholesale rate area, FERC approved in 1992, with certain modifications, the proposals of AP&L, LP&L, MP&L, NOPSI and Entergy Power, Inc. to sell wholesale power at market-based rates and to provide to electric utilities "open access" to the System's transmission system (subject to certain requirements). GSU was later added to the filing. Various intervenors in the proceeding filed petitions for review with the United States Court of Appeals for the District of Columbia Circuit. FERC's order, once it takes effect, will increase marketing opportunities for MP&L, but will also expose MP&L to the risk of loss of load or reduced revenues due to competition with alternative suppliers. In light of the rate issues discussed above, MP&L is aggressively reducing costs to avoid potential earnings erosions that might result as well as to successfully compete by becoming a low-cost producer. To help minimize future costs, MP&L remains committed to least cost planning. In December 1992, MP&L filed a Least Cost Integrated Resource Plan (Least Cost Plan) with its retail regulator. Least cost planning includes demand-side measures such as customer energy conservation and supply-side measures such as more efficient power plants. These measures are designed to delay the building of new power plants for the next 20 years. MP&L plans to periodically file revised Least Cost Plans. The Energy Policy Act of 1992 The Energy Policy Act of 1992 (Energy Act) is changing the transmission and distribution of electricity. This act encourages competition and affords us the opportunities, and the risks, associated with an open and more competitive market environment. The Energy Act increases competition in the wholesale energy market through the creation of exempt wholesale generators (EWGs). The Energy Act also gives FERC the authority to order investor-owned utilities to provide transmission access to or for other utilities, including EWGs. MISSISSIPPI POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES MP&L maintains accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications. Revenues and Fuel Costs Prior to January 1, 1993, MP&L recorded revenues when billed to its customers with no accrual for energy delivered but not yet billed. To provide a better matching of revenues and expenses, effective January 1, 1993, MP&L adopted a change in accounting principle to provide for accrual of estimated unbilled revenues. The cumulative effect of this accounting change as of January 1, 1993, increased net income by $32.7 million. Had this new accounting method been in effect during prior years, net income before the cumulative effect would not have been materially different from that shown in the accompanying financial statements. MP&L's rate schedules include fuel adjustment clauses that allow current recovery of estimated fuel costs, with subsequent adjustments of estimates to actual. Utility Plant Utility plant is stated at original cost. The original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of MP&L's utility plant is subject to the lien of its first mortgage bond indenture and the second lien of its G&R Mortgage bond indenture. 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 utility plant and increases earnings, it is only realized in cash through depreciation provisions included in rates. MP&L's effective composite rates for AFUDC were 11.8%, 12.0%, and 10.4% for 1993, 1992, and 1991, respectively. Depreciation is computed on the straight-line basis at rates based on the estimated service lives and costs of removal of the various classes of property. Depreciation provisions on average depreciable property approximated 2.4% in 1993, 2.5% in 1992, and 2.4% in 1991. Jointly-Owned Generating Station MP&L owns 25% of the Independence Station, a two-unit, coal -fired generating station located near Newark, Arkansas. The total capability of Independence Station is 528 megawatts. MP&L records its investment in and expenses associated with this station to the extent of its ownership and participation. MP&L's investment in the Independence Station was approximately $219.8 million less accumulated depreciation of approximately $67.3 million as of December 31, 1993. Notes Receivable MP&L currently has a program, wherein it finances heat pumps for its customers through notes receivable. Such notes are repayable in equal monthly installments of principal and interest over a five-year period and bear interest at a market-based rate at the time of sale. The amounts financed are classified on its balance sheet as current and noncurrent notes receivable. Income Taxes MP&L, its parent, and affiliates (excluding GSU prior to 1994) file a consolidated federal income tax return. Income taxes are allocated to MP&L in proportion to its contribution to consolidated taxable income. SEC regulations require that no System company pay more taxes than it would have had a separate income tax return been filed. Deferred taxes are recorded for all temporary differences between book and taxable income. Investment tax credits are deferred and amortized based upon the average useful life of the related property, in accordance with rate treatment. As discussed in Note 3, effective January 1, 1993, MP&L changed its accounting for income taxes to conform with SFAS 109. In addition, MP&L files a consolidated Mississippi state income tax return with certain other System companies. Cash and Cash Equivalents MP&L considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Fair Value Disclosure The estimated fair value amounts of financial instruments have been determined by MP&L, using available market information and appropriate valuation methodologies. However, considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that MP&L could realize in a current market exchange. In addition, gains or losses realized on financial instruments may be reflected in future rates and not accrue to the benefit of stockholders. MP&L considers the carrying amounts of 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. In addition, MP&L does not presently expect that performance of its obligations will be required in connection with certain off-balance sheet commitments and guarantees considered financial instruments. Due to this factor, and because of the related party nature of these commitments and guarantees, determination of fair value is not considered practicable. See Notes 5 and 6 for additional fair value disclosure. NOTE 2. RATE AND REGULATORY MATTERS Incentive Rate Plan In July 1993, the MPSC ordered MP&L to file a formulary incentive rate plan designed to allow for periodic small adjustments in rates based upon a comparison of earned to benchmark returns and upon performance factors incorporated in the plan. In November 1993, MP&L filed a formula rate plan (Proposed Plan) with the MPSC to become effective on March 1, 1994, with any initial adjustment to base rates in June 1994. Under the Proposed Plan, a formula would be established under which MP&L's earned rate of return would be calculated automatically every 12 months and compared to a benchmark rate of return, which would be calculated under a separate formula within the Proposed Plan. If MP&L's earned rate of return falls within a bandwidth around the benchmark rate of return, there would be no adjustment in rates. If MP&L's earnings are above the bandwidth, the Proposed Plan would automatically reduce MP&L's base rates. Alternatively, if MP&L's earnings are below the bandwidth, the Proposed Plan would automatically increase MP&L's base rates (subject to the five-year rate cap described below). The reduction or increase in base rates would be an amount representing 50% of the difference between the earned rate of return and the nearest limit of the bandwidth. In no event would the annual adjustment in rates exceed the lesser of 2% of MP&L's aggregate retail revenues, or $14.5 million. Under the Proposed Plan, the benchmark rate of return, and consequently the bandwidth, would be adjusted slightly upward or downward based upon MP&L's performance on three performance factors: customer reliability, customer satisfaction, and customer price. Subsequently, the MPSC conducted a general review of MP&L's current rates and later issued a final order adopting the Proposed Plan and previously agreed- upon stipulations of 1) a required return on equity of 11% and 2) certain accounting adjustments that result in a 4.3% ($28.1 million) reduction in MP&L's June 30, 1993, test-year base revenues. The MPSC's order requires MP&L to file rates designed to provide for this reduction in operating revenues for the test year on or before March 18, 1994, to become effective for service rendered on or after March 25, 1994. Rate Agreement In November 1993, MP&L and the MPSC entered into a settlement agreement whereby the MPSC agreed to withdraw its request for hearings and its objections in the SEC proceeding related to the Merger. MP&L agreed that MP&L's retail ratepayers would be protected from (1) increases in MP&L's cost of capital resulting from risks associated with the Merger; (2) recovery of any portion of the acquisition premium or transactional costs associated with the Merger; (3) certain direct allocations of costs associated with GSU's River Bend nuclear unit; and (4) any losses of GSU resulting from resolution of litigation in connection with its ownership of River Bend. In a related stipulation, MP&L also agreed (a) that retail base rates under its proposed formula rate plan would not be increased above November 1, 1993 levels, and (b) that MP&L would not request any general retail rate increase that would increase retail rates above the level of MP&L's rates in effect as of November 1, 1993, except, among other things, for increases associated with the Least Cost Plan, recovery of deferred Grand Gulf 1-related costs, recovery under the fuel adjustment clause, adjustments for certain taxes, and force majeure (defined to include, among other things, war, natural catastrophes, and high inflation), in each case for a period of five years beginning November 9, 1993. Grand Gulf 1 MP&L's Revised Plan provides, among other things, for the recovery by MP&L, in equal annual installments over ten years beginning October 1, 1988, of all Grand Gulf 1-related costs deferred through September 30, 1988 pursuant to the Final Order on Rehearing. Additionally, the Revised Plan provided that MP&L defer, in decreasing amounts, a portion of its Grand Gulf 1-related costs over four years beginning October 1, 1988. These deferrals are being recovered by MP&L over a six-year period beginning in October 1992 and ending in September 1998. The Revised Plan also allows for the current recovery of carrying charges on all deferred amounts. NOTE 3. INCOME TAXES Effective January 1, 1993, MP&L adopted SFAS 109. This new standard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that deferred tax balances be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 requires that regulated enterprises recognize adjustments resulting from implementation as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. A substantial majority of the adjustments required by SFAS 109 was recorded to deferred tax balance sheet accounts with offsetting adjustments to regulatory assets and liabilities. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. As a result of the adoption of SFAS 109, 1993 net income was reduced by $1.7 million, assets were increased by $50.2 million, and liabilities were increased by $51.9 million.
Income tax expense consisted of the following: For the Years Ended December 31, -------------------------------- 1993 1992 1991 ------ ------ ------- (In Thousands) Current: Federal $46,744 $4,532 $(1,000) State 7,673 (69) - ------- ------- ------- Total 54,417 4,463 (1,000) ------- ------- ------- Deferred - net: Federal reclassification due to net - 28,561 29,756 operating loss State reclassification due to net - 4,883 4,587 operating loss Liberalized depreciation 5,293 9,448 8,565 Rate Deferral - net (31,317) (11,220) (10,137) Unbilled revenue 21,373 (5,722) 1,207 Pension liability (647) (1,233) (157) Adjustments of prior year taxes 4,299 (3,471) (84) Bond reacquisition 3,208 264 (228) Other (1,670) (1,079) (1,020) ------- ------- ------- Total 539 20,431 32,489 ------- ------- ------- Investment tax credit adjustments - net 1,036 (1,746) (1,634) ------- ------- ------- Recorded income tax expense $55,992 $23,148 $29,855 ======= ======= ======= Charged to operations $33,074 $21,681 $29,936 Charged (credited) to other income 3,462 1,467 (81) Charged to cumulative effect 19,456 - - ------- ------- ------- Total income taxes $55,992 $23,148 $29,855 ======= ======= =======
Total income taxes differ from the amounts computed by applying the statutory federal income tax rate to income before taxes. The reasons for the differences were:
For the Years Ended December 31, -------------------------------------------------------- 1993 1992 1991 ----------------- ---------------- ---------------- % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income ------- -------- -------- ------- ------- ------- (Dollars in Thousands) Computed at statutory rate $55,207 35.0 $29,983 34.0 $31,601 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 3,253 2.0 2,703 3.1 3,175 3.4 Depreciation (5,890) (3.7) (2,571) (2.9) 944 1.0 Amortization of excess deferred income taxes (4,680) (3.0) (2,456) (2.8) (3,257) (3.5) Amortization of investment tax credits (1,772) (1.1) (1,746) (2.0) (1,634) (1.8) Adjustments of prior year taxes 5,228 3.3 (2,760) (3.2) (1,149) (1.2) SFAS 109 adjustment 3,439 2.2 - - - - Other - net 1,207 0.8 (5) - 175 0.2 ------- ---- ------- ---- ------- ---- Total income taxes $55,992 35.5 $23,148 26.2 $29,855 32.1 ======= ==== ======= ==== ======= ====
Significant components of MP&L's net deferred tax liabilities as of December 31, 1993, were (in thousands): Deferred tax liabilities: Plant related basis differences $(166,650) Rate deferrals (246,604) Other (6,406) --------- Total $(419,660) ========= Deferred tax assets: Net regulatory liabilities $9,411 Accumulated deferred investment tax credits 13,420 Recoverable income tax 13,854 Alternative minimum tax credit 1,192 Removal cost 10,725 Standard coal plant 4,854 Pension related items 2,488 Other 10,342 ------- Total $66,286 ======= Net deferred tax liabilities $(353,374) ========= The alternative minimum tax (AMT) credit as of December 31, 1993, was $1.2 million. This AMT credit can be carried forward indefinitely and will reduce MP&L's federal income tax liability in future years. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized MP&L to effect short-term borrowings up to $100 million, subject to increase to as much as $113 million after further SEC approval. These authorizations are effective through November 30, 1994. As of December 31, 1993, MP&L had unused lines of credit for short-term borrowing of $30 million from banks within its service territory. In addition, MP&L can borrow from the Money Pool, subject to its maximum authorized level of short-term borrowings and the availability of funds. MP&L's short-term borrowings are limited by the terms of its G&R Mortgage to amounts not exceeding the greater of 10% of capitalization or 50% of Grand Gulf 1 rate deferrals available to support the issuance of G&R Bonds. MP&L had $11.6 million in outstanding borrowings under the Money Pool arrangement as of December 31, 1993. NOTE 5. PREFERRED AND COMMON STOCK The number of shares and dollar value of MP&L's cumulative, $100 par value preferred stock was:
As of December 31, ---------------------------------------- Shares Call Price Per Authorized and Total Share as of Outstanding Dollar Value December 31, 1993 1992 1993 1992 1993 ------- ------- ------- -------- ----------- (Dollars in Thousands) Without sinking fund: 4.36% Series 59,920 59,920 $5,992 $5,992 $103.86 4.56% Series 43,888 43,888 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 - 9.16% Series 75,000 75,000 7,500 7,500 $104.06 -------- -------- ------- ------- Total without sinking fund 578,808 578,808 $57,881 $57,881 ======== ======== ======= ======= With sinking fund: 9.00% Series 140,000 210,000 $14,000 $21,000 $106.75 9.76% Series 280,000 350,000 28,000 35,000 $103.26 12.00% Series 47,700 57,700 4,770 5,770 $106.00 16.16% Series - 15,000 - 1,500 - -------- -------- ------- ------- Total with sinking fund 467,700 632,700 $46,770 $63,270 ======== ======== ======= =======
The fair value of MP&L's preferred stock with sinking fund was estimated to be approximately $49.3 million and $66.2 million as of December 31, 1993 and 1992, respectively. The fair value was determined using quoted market prices or estimates from nationally recognized investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. As of December 31, 1993, MP&L had 175,000 shares of cumulative, $100 par value preferred stock that were authorized but unissued. On February 4, 1994, MP&L amended its charter authorizing 1,500,000 additional shares of $100 par value preferred stock. Changes in the common stock and preferred stock, with and without sinking fund, during the last three years were: Number of Shares ------------------------------- 1993 1992 1991 -------- --------- ------- Common stock issuances($23 issuance price) - 1,086,957 - Preferred stock issuances: - 200,000 - Preferred stock retirements: (165,000) (95,000) (95,000) Cash sinking fund requirements for the next five years for preferred stock outstanding as of December 31, 1993, are (in thousands): 1994 - $14,500; 1995 - $14,500; 1996 - $7,500; 1997 - $7,500; and 1998 - $500. MP&L has the annual non-cumulative option to redeem at par, additional amounts of its 12.00% series preferred stock outstanding. MP&L has SEC authorization for the issuance and sale through December 31, 1995, of up to $70 million of preferred stock (of which $50 million remained available as of December 31, 1993), and for the possible acquisition, in whole or in part, of not more than $50 million aggregate par value of MP&L's outstanding preferred stock, including but not limited to the 12.00% Series and the 9.76% Series. The proceeds of any sales of preferred stock would be used for the refinancing of higher cost of debt and preferred stock and general corporate purposes. NOTE 6. LONG-TERM DEBT The long-term debt of MP&L as of December 31, 1993 and 1992, was:
Maturities Interest Rates From To From To 1993 1992 -------- --------- (In Thousands) First Mortgage Bonds 1994 1998 4-5/8% 6-3/8% $55,000 $55,000 1999 2003 7-3/4% 9-5/8% - 102,500 2004 2008 9-7/8% - 25,000 2014 2018 9-5/8% - 70,000 G&R Bonds 1993 1997 5.95% 14.95%* 215,000 270,000 2003 2023 6-5/8% 8.65% 250,000 - Governmental Obligations** 1992 2008 7-1/2% 8-1/2% 17,925 18,155 2012 2014 9% 9-1/2% 30,000 30,000 Unamortized Premium and Discount-Net (3,519) (2,750) -------- -------- Total Long-Term Debt 564,406 567,905 Less Amount Due Within One Year 48,250 55,230 -------- -------- Long-Term Debt Excluding Amount Due Within One Year $516,156 $512,675 ======== ========
* The 14.95% series of $20 million is due 2/1/95. All other series are at interest rates within the range of 5.95% - 11.2%. ** Consists of pollution control revenue bonds, certain series of which are secured by non-interest bearing first mortgage bonds. The fair value of MP&L's long-term debt as of December 31, 1993 and 1992, was estimated to be $594.0 million and $595.0 million, respectively. The fair value was determined using quoted market prices or estimates from nationally recognized investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. For the years 1994, 1995, 1996, 1997 and 1998, MP&L has long-term debt maturities and cash sinking fund requirements of (in millions) $48.2, $66.2, $61.3, $96.3, and $0.3, respectively. In addition, other sinking fund requirements of approximately $0.2 million annually may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements. The G&R Mortgage prohibits the issuance of additional first mortgage bonds (including for refunding purposes) under MP&L's first mortgage indenture, except such first mortgage bonds as may hereafter be issued from time to time at MP&L's option to the corporate trustee under the G&R Mortgage to provide additional security for MP&L's G&R Bonds. Under MP&L's G&R Mortgage indenture and subject to the earnings coverage test discussed below, G&R Bonds are issuable based upon 70% of property additions since December 31, 1987, plus up to 50% of cumulative deferred Grand Gulf 1-related costs recorded as an asset on the books of MP&L, provided that the maximum amount of G&R Bonds issuable against cumulative deferred Grand Gulf 1-related costs may not exceed $400 million. The G&R Mortgage contains an earnings coverage test requiring a minimum earnings coverage (except for certain refunding issues) of twice the pro-forma annual mortgage interest requirements for the issuance of additional G&R Bonds. As of December 31, 1993, the total amount of G&R Bonds outstanding aggregated $465 million. MP&L has requested SEC authorization allowing the issuance and sale through December 31, 1995, of up to $550 million of G&R Bonds (of which $235 million remained available as of December 31, 1993) and up to $25 million of tax -exempt bonds. MP&L has also received SEC authorization through December 31, 1995, for the possible acquisition, in whole or in part, of not more than $200 million aggregate principal amount of outstanding bonds, including, but not limited to MP&L's G&R Bonds, 14.95% Series due 1995; and not more than $25 million aggregate principal amount of outstanding pollution control revenue bonds, including but not limited to Independence County Pollution Control Revenue Bonds, 9% 1982 Series B due 2013, 9.50% 1982 Series C due 2014, 9% 1982 -A Series A due 2013, and 9.50% 1982-A Series B due 2014. NOTE 7. DIVIDEND RESTRICTIONS MP&L's bond indentures relating to long-term debt contain provisions restricting the payment of cash dividends or other distributions on common stock. As of December 31, 1993, $139.6 million of MP&L's retained earnings were restricted against the payment of cash dividends or other distributions on common stock. On February 1, 1994, MP&L paid Entergy Corporation a $4.6 million cash dividend on common stock. NOTE 8. COMMITMENTS AND CONTINGENCIES Capital Requirements and Financing Construction expenditures for the years 1994, 1995, and 1996 are estimated to total $61 million, $63 million, and $63 million, respectively. MP&L will also require $212 million during the period 1994-1996 to meet long-term debt and preferred stock maturities and cash sinking fund requirements. MP&L plans to meet the above requirements with internally generated funds and cash on hand, supplemented by the issuance of long-term debt. See Notes 5 and 6 regarding the possible issuance, refunding, redemption, purchase or other acquisition of certain outstanding series of preferred stock and long-term debt. See Note 11 for information on additional capital requirements related to a February 1994 ice storm. Unit Power Sales Agreement System Energy has agreed to sell all of its 90% owned and leased share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this agreement are paid in consideration for MP&L's 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 approved by FERC, most likely upon Grand Gulf 1's retirement from service. MP&L's monthly obligation for payments to System Energy for Grand Gulf 1 capacity and energy is approximately $18 million. Availability Agreement AP&L, LP&L, MP&L, and NOPSI are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 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. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Payments or advances under the Availability Agreement are only required if funds available to System Energy from all sources are less than the amount required under the Availability Agreement. 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 have ever been required. In 1989, the Availability Agreement was amended to provide that the write-off of $900 million of Grand Gulf 2 costs would be amortized for Availability Agreement purposes over a period of 27 years in order to avoid the need for payments by AP&L, LP&L, MP&L, and NOPSI. Reallocation Agreement System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation Agreement relating to the sale of capacity and energy from the Grand Gulf Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and obligations with respect to the Grand Gulf Station under the Availability Agreement. FERC's decision allocating a portion of Grand Gulf 1 capacity and energy to AP&L supersedes the Reallocation Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect AP&L's obligation to System Energy's lenders under the assignments referred to in the preceding paragraph. AP&L would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual obligations. No payments of any amortization amounts will be required as 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. System Fuels MP&L has a 19% interest in System Fuels, a jointly-owned subsidiary of AP&L, LP&L, MP&L, and NOPSI. The parent companies of System Fuels, including MP&L, agreed to make loans to System Fuels to finance its fuel procurement, delivery, and storage activities. As of December 31, 1993, MP&L had approximately $5.5 million of loans outstanding to System Fuels which mature in 2008. On April 30, 1993, AP&L assumed System Fuels' rights and obligations in connection with System Fuels' coal car leases. The other parent companies of System Fuels have been released from their obligations with respect to the coal car leases. However, MP&L, as a co-owner of the Independence Station, which uses the coal transported by the leased coal cars, will continue to reimburse AP&L for MP&L's share of the costs associated with the leases. Fuel Purchase Commitments MP&L has a four-year gas purchase agreement with Koch Gateway Pipeline Company (formerly United Gas Pipeline Company) under which, beginning January 1, 1991, MP&L is purchasing approximately 34.1 billion cubic feet of gas. As of December 31, 1993, MP&L had purchased approximately 23.4 billion cubic feet of gas. MP&L owns certain coal mining equipment and facilities at a mine in Wyoming. The mine's estimated reserves are presently expected to provide the projected requirements of the Independence Station through at least 2014. NOTE 9. POSTRETIREMENT BENEFITS Pension Plan MP&L has a defined benefit pension plan covering substantially all of its employees. The pension plan is noncontributory and provides pension benefits based on employees' credited service and average compensation, generally during the last five years before retirement. MP&L funds 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 plan consist primarily of common and preferred stocks, fixed income securities, interest in a money market fund, and insurance contracts. MP&L's 1993, 1992, and 1991 pension cost, including amounts capitalized, included the following components:
For the Years Ended December 31, -------------------------------- 1993 1992 1991 ------ ------ ------ (In Thousands) Service cost - benefits earned during the period $2,409 $2,059 $2,061 Interest cost on projected benefit obligation 8,583 8,269 7,472 Actual return on plan assets (15,053) (8,474) (22,422) Net amortization and deferral 5,325 (1,009) 13,323 Other - - 403 ------ ---- ------ Net pension cost $1,264 $845 $837 ====== ==== ======
The funded status of MP&L's pension plan as of December 31, 1993 and 1992, was:
1993 1992 -------- -------- (In Thousands) Actuarial present value of accumulated pension plan benefits: Vested $101,664 $92,473 Nonvested 390 283 -------- -------- Accumulated benefit obligation $102,054 $92,756 ======== ======== Plan assets at fair value $126,990 $119,173 Projected benefit obligation 122,056 107,658 -------- -------- Plan assets in excess of projected benefit obligation 4,934 11,515 Unrecognized prior service cost 3,574 3,856 Unrecognized transition asset (10,003) (11,253) Unrecognized net gain (1,798) (6,146) -------- -------- Accrued pension liability $ (3,293) $ (2,028) ======== ========
The significant actuarial assumptions used in computing the information above for 1993, 1992, and 1991 were as follows: weighted average discount rate, 7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in future compensation levels, 5.6%; and expected long-term rate of return on plan assets, 8.5%. Transition assets are being amortized over 15 years. Other Postretirement Benefits MP&L also provides certain 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 MP&L. The cost of providing these benefits, recorded on a cash basis, to retirees in 1992 was approximately $1.6 million. Prior to 1992, the cost of providing these benefits for retirees was not separable from the cost of providing benefits for active employees. Based on the ratio of the number of retired employees to the total number of active and retired employees in 1991, the cost of providing these benefits in 1991, recorded on a cash basis, for retirees was approximately $1.1 million. Effective January 1, 1993, MP&L adopted SFAS 106. The new standard requires a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. MP&L continues to fund these benefits on a pay-as-you-go basis. At January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $30 million. This obligation is being amortized over a 20-year period beginning in 1993. MP&L is expensing its SFAS 106 costs, which will be reflected in rates pursuant to an order from the MPSC in connection with MP&L's formulary incentive rate plan (see Note 2). MP&L's net income in 1993 was decreased by approximately $2.0 million as a result of adopting SFAS 106. MP&L's 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components (in thousands): Service cost - benefits earned during the period $812 Interest cost on APBO 2,400 Actual return on plan assets - Amortization of transition obligation 1,502 ------ Net periodic postretirement benefit cost $4,714 ====== The funded status of MP&L's postretirement plan as of December 31, 1993, was (in thousands): Accumulated postretirement benefit obligations: Retirees $21,435 Other fully eligible participants 5,816 Other active participants 7,794 ------- 35,045 Plan assets at fair value - ------- Plan assets less than APBO (35,045) Unrecognized transition obligation 28,537 Unrecognized net loss 3,745 ------- Accrued post retirement benefit liability $(2,763) ======= The assumed health care cost trend rate used in measuring the APBO was 9.9% for 1994, gradually decreasing each successive year until it reaches 5.6% in 2020. A one percentage-point increase in the assumed health care cost trend rate for each year would have increased the APBO as of December 31, 1993, by 8.6% and the sum of the service cost and interest cost by approximately 10.9%. The assumed discount rate and rate of increase in future compensation used in determining the APBO were 7.5% and 5.5%, respectively. NOTE 10. TRANSACTIONS WITH AFFILIATES MP&L buys electricity from and/or sells electricity to AP&L, LP&L, NOPSI, and System Energy under rate schedules filed with FERC. In addition, MP&L purchases fuel from System Fuels and receives technical and advisory services from Entergy Services, Inc.. Operating revenues include revenues from sales to affiliates amounting to $40.6 million in 1993, $18.0 million in 1992, and $9.8 million in 1991. As a result of an internal review designed to ensure consistency among the System operating companies, certain 1985-1991 intra-system equalization billings pursuant to the System Agreement were adjusted in 1991 and reduced operating revenue in the amount of approximately $10.6 million. Operating expenses include charges from affiliates for fuel costs, purchased power and related charges, and technical and advisory services totaling $360.5 million in 1993, $364.0 million in 1992, $310.8 million in 1991. See Note 1 for information on MP&L's jointly-owned generating station. NOTE 11. SUBSEQUENT EVENT (UNAUDITED) In early February 1994, an ice storm left more than 80,000 MP&L customers without electric power in its service area. The storm was the most severe natural disaster ever to affect MP&L, causing damage to transmission and distribution lines, equipment, poles, and facilities in certain areas. A substantial portion of the related costs, which are estimated to be $75 million to $100 million, are expected to be capitalized. Estimated construction expenditures (see Note 8) have not yet been updated to reflect the above amounts. The MPSC acknowledged that there is precedent in Mississippi for recovery of certain costs associated with storms and natural disasters and the restoration of service resulting from such events. MP&L plans to immediately file for rate recovery of the costs related to the ice storm. NOTE 12. QUARTERLY FINANCIAL DATA (UNAUDITED) MP&L's business is subject to seasonal fluctuations with the peak period occurring during the third quarter. Operating results for the four quarters of 1993 and 1992 were: Operating Operating Net Revenues Income Income ----------- ---------- ---------- (In Thousands) 1993: First Quarter (1) $179,467 $24,134 $42,782 Second Quarter $229,506 $38,471 $25,339 Third Quarter $264,419 $39,896 $26,921 Fourth Quarter $222,414 $22,819 $ 6,701 1992: First Quarter $186,791 $26,866 $11,083 Second Quarter $202,297 $25,830 $10,306 Third Quarter $229,209 $40,673 $25,002 Fourth Quarter $199,353 $31,405 (2) $18,645 (2) (1) The first quarter of 1993 reflects a nonrecurring increase in net income of $32.7 million, net of taxes of $19.5 million, due to the recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1). Beginning with the second quarter, the remaining quarters are not generally comparable to prior year quarters because of the ongoing effects of the accounting change. (2) The fourth quarter of 1992 reflects a decrease in income tax expense of $4.8 million due to estimates of income tax benefits related to tax depreciation having been adjusted as a result of certain elections made in conjunction with the filing of the 1991 tax return.
MISSISSIPPI POWER & LIGHT COMPANY SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1993 1992 1991 1990 1989 ---------- ---------- ---------- ---------- ---------- (In Thousands) Operating revenues $ 895,806 $ 817,650 $ 754,632 $ 761,188 $ 709,746 Income before cumulative effect of a change in accounting principle $ 69,037 $ 65,036 $ 63,088 $ 60,830 $ 12,419 Total assets $1,676,737 $1,660,726 $1,672,275 $1,616,522 $1,565,707 Long-term obligations (1) $ 563,612 $ 576,787 $ 576,599 $ 679,458 $ 693,333
(1) Includes long-term debt (excluding currently maturing debt), preferred stock with sinking fund, and noncurrent capital lease obligations. See Notes 1, 3, and 9 for the effect of accounting changes in 1993.
1993 1992 1991 1990 1989 -------- -------- -------- -------- -------- (Dollars in Thousands) Operating Revenues: Residential $343,585 $308,346 $307,283 $302,622 $274,841 Commercial 252,798 235,137 229,597 227,140 212,107 Industrial 183,537 168,853 162,072 160,007 147,146 Governmental 28,708 26,250 25,630 25,117 23,624 -------- -------- -------- -------- -------- Total retail 808,628 738,586 724,582 714,886 657,718 Sales for resale 55,740 37,983 25,487 35,678 45,886 Other 31,438 41,081 4,563 10,624 6,142 -------- -------- -------- -------- -------- Total $895,806 $817,650 $754,632 $761,188 $709,746 ======== ======== ======== ======== ======== Billed Electric Energy Sales (Millions of KWH): Residential 3,983 3,644 3,739 3,701 3,452 Commercial 2,928 2,804 2,807 2,802 2,679 Industrial 2,787 2,631 2,582 2,564 2,368 Governmental 336 318 321 318 308 -------- -------- -------- -------- -------- Total retail 10,034 9,397 9,449 9,385 8,807 Sales for resale 1,428 1,190 1,032 902 1,038 -------- -------- -------- -------- -------- Total 11,462 10,587 10,481 10,287 9,845 ======== ======== ======== ======== ========
New Orleans Public Service Inc. 1993 Financial Statements NEW ORLEANS PUBLIC SERVICE INC. DEFINITIONS Certain abbreviations or acronyms used in NOPSI's Financial Statements, Notes to Financial Statements, and Management's Financial Discussion and Analysis are defined below: Abbreviation or Acronym Term AFUDC Allowance for Funds Used During Construction Alliance The Alliance for Affordable Energy, and others AP&L Arkansas Power & Light Company City of New Orleans or City New Orleans, Louisiana Council Council of the City of New Orleans, Louisiana Entergy or System Entergy Corporation and its various direct and indirect subsidiaries FASB Financial Accounting Standards Board February 4 Resolution The Resolution (including the Determinations and Order referred to therein) adopted by the Council on February 4, 1988, disallowing the recovery by NOPSI of $135 million of previously deferred Grand Gulf 1-related costs FERC Federal Energy Regulatory Commission G&R Bonds General and Refunding Mortgage Bonds issued and issuable by NOPSI Grand Gulf 1 Unit No. 1 of the Grand Gulf Station Grand Gulf 2 Unit No. 2 of the Grand Gulf Station Grand Gulf Station Grand Gulf Steam Electric Generating Station GSU Gulf States Utilities Company (including wholly owned subsidiaries - Varibus Corporation, GSG&T, Inc., Prudential Oil and Gas, Inc., and Southern Gulf Railway Company) KWH Kilowatt-Hour(s) LP&L Louisiana Power & Light Company Merger The combination transaction, consummated on December 31, 1993, by which GSU became a subsidiary of Entergy Corporation and Entergy Corporation became a Delaware Corporation Money Pool Entergy Money Pool, which allows certain System companies to borrow from, or lend to, certain other System companies MP&L Mississippi Power & Light Company 1986 Rate Settlement Agreement, effective March 25, 1986, between NOPSI and the Council regarding NOPSI's Grand Gulf 1-related rate issues 1989 Settlement Agreement An agreement between the Council and NOPSI, effective July 21, 1989, that settled certain local retail rate issues regarding Grand Gulf 1 1991 NOPSI Settlement Settlement, retroactive to October 4, 1991, among NOPSI, the Council and the Alliance that settled certain Grand Gulf 1 prudence issues and pending litigation related to the February 4 Resolution NOPSI New Orleans Public Service Inc. OBRA Omnibus Budget Reconciliation Act of 1993 SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the FASB SFAS 106 SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS No. 109, "Accounting for Income Taxes" System Energy System Energy Resources, Inc. System Fuels System Fuels, Inc. System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively System or Entergy Entergy Corporation and its various direct and indirect subsidiaries NEW ORLEANS PUBLIC SERVICE INC. REPORT OF MANAGEMENT The management of New Orleans Public Service Inc. has prepared and is responsible for the financial statements and related financial information included herein. The financial statements are based on generally accepted accounting principles. Financial information included elsewhere in this report is consistent with the financial statements. To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls that is designed to provide reasonable assurance, on a cost-effective basis, as to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. This system includes communication through written policies and procedures, an employee Code of Conduct, 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. The independent public accountants provide an objective assessment of the degree to which 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 these policies and procedures provide reasonable assurance that its operations are carried out with a high standard of business conduct. /S/ EDWIN LUPBERGER /S/ GERALD D. MCINVALE EDWIN LUPBERGER GERALD D. MCINVALE Chairman and Chief Executive Officer Senior Vice President and Chief Financial Officer NEW ORLEANS PUBLIC SERVICE INC. AUDIT COMMITTEE CHAIRMAN'S LETTER The New Orleans Public Service Inc. Audit Committee of the Board of Directors is comprised of four directors, who are not officers of NOPSI: Anne M. Milling (Chairman), James M. Cain, Brooke H. Duncan and Dr. Norman C. Francis. The committee held four meetings during 1993. The Audit Committee oversees NOPSI's financial reporting process on behalf of the Board of Directors and provides reasonable assurance to the Board that sufficient operating, accounting, and financial controls are in existence and are adequately reviewed by programs of internal and external audits. The Audit Committee discussed with Entergy's internal auditors and the independent public accountants (Deloitte & Touche) the overall scope and specific plans for their respective audits, as well as NOPSI's financial statements and the adequacy of NOPSI's internal controls. The committee met, together and separately, with Entergy's internal auditors and independent public accountants, without management present, to discuss the results of their audits, their evaluation of NOPSI's internal controls, and the overall quality of NOPSI's financial reporting. The meetings also were designed to facilitate and encourage any private communication between the committee and the internal auditors or independent public accountants. /S/ ANNE M. MILLING ANNE M. MILLING Chairman, Audit Committee INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directors of New Orleans Public Service Inc. We have audited the accompanying balance sheets of New Orleans Public Service Inc. (NOPSI) as of December 31, 1993 and 1992, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of NOPSI's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. 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 NOPSI at December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. As discussed in Note 1 to the financial statements, NOPSI changed its method of accounting for revenues in 1993 and, as discussed in Notes 3 and 9 to the financial statements, in 1993 NOPSI changed its methods of accounting for income taxes and postretirement benefits other than pensions, respectively. /S/ DELOITTE & TOUCHE DELOITTE & TOUCHE New Orleans, Louisiana February 11, 1994 NEW ORLEANS PUBLIC SERVICE INC. BALANCE SHEETS ASSETS
December 31, ---------------------- 1993 1992 -------- -------- (In Thousands) Utility Plant (Note 1): Electric $476,976 $466,319 Natural gas 113,666 110,399 Construction work in progress 15,205 6,906 -------- -------- Total 605,847 583,624 Less - accumulated depreciation and amortization 330,268 315,439 -------- -------- Utility plant - net 275,579 268,185 -------- -------- Other Investments: Investment in subsidiary company - at equity (Note 8) 3,259 3,259 -------- -------- Current Assets: Cash and cash equivalents (Note 1): Cash 1,176 - Temporary cash investments - at cost, which approximates market: Associated companies (Note 4) 10,034 3,513 Other 32,107 42,557 -------- -------- Total cash and cash equivalents 43,317 46,070 Accounts receivable: Customer (less allowance for doubtful accounts of $0.8 million in 1993 and $1.4 million in 1992) 35,801 30,525 Associated companies (Note 10) 1,378 2,232 Other 876 676 Accrued unbilled revenues (Note 1) 19,643 - Deferred electric fuel and resale gas costs (Note 1) 6,323 486 Accumulated deferred income taxes (Note 3) - 4,566 Materials and supplies - at average cost 11,885 11,925 Rate deferrals (Note 2) 24,587 15,617 Prepayments and other 2,994 3,633 -------- -------- Total 146,804 115,730 -------- -------- Deferred Debits: Rate deferrals (Note 2) 204,190 229,002 SFAS 109 regulatory asset - net (Note 3) 9,004 - Other 8,769 5,515 -------- -------- Total 221,963 234,517 -------- -------- TOTAL $647,605 $621,691 ======== ======== See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC. BALANCE SHEETS CAPITALIZATION AND LIABILITIES
December 31, ---------------------- 1993 1992 -------- -------- (In Thousands) Capitalization: Common stock, $4 par value, authorized 10,000,000 shares; issued and outstanding 8,435,900 shares in 1993 and 1992 $33,744 $33,744 Paid-in capital 36,156 36,097 Retained earnings subsequent to the elimination of the accumulated deficit of $13.9 million on November 30, 1988 (Note 7) 100,556 98,560 -------- -------- Total common shareholder's equity 170,456 168,401 Preferred stock (Note 5): Without sinking fund 19,780 19,780 With sinking fund 4,950 6,450 Long-term debt (Note 6) 188,312 159,467 -------- -------- Total 383,498 354,098 -------- -------- Other Noncurrent Liabilities: Accumulated provision for losses (Note 1) 18,022 17,799 Other 3,351 - -------- -------- Total 21,373 17,799 -------- -------- Current Liabilities: Currently maturing long-term debt (Note 6) 15,000 44,400 Accounts payable: Associated companies (Note 10) 23,080 21,527 Other 22,011 22,395 Customer deposits 16,617 15,552 Accumulated deferred income taxes (Note 3) 4,968 - Taxes accrued 5,161 5,243 Interest accrued 5,472 6,791 Dividends declared 432 490 Other 6,935 1,477 -------- -------- Total 99,676 117,875 -------- -------- Deferred Credits: Accumulated deferred income taxes (Note 3) 105,096 100,423 Accumulated deferred investment tax credits (Note 3) 11,592 12,338 Other 26,370 19,158 -------- -------- Total 143,058 131,919 -------- -------- Commitments and Contingencies (Notes 2 and 8) TOTAL $647,605 $621,691 ======== ======== See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC. STATEMENTS OF CASH FLOWS
For the Years Ended December 31, --------------------------------- 1993 1992 1991 ------- ------- -------- (In Thousands) Operating Activities: Net income $47,709 $26,424 $74,699 Noncash items included in net income: Cumulative effect of a change in accounting principle (10,948) - - Change in rate deferrals (Note 2) 15,842 2,856 (55,151) Depreciation and amortization 17,284 16,619 15,973 Deferred income taxes and investment tax credits (2,132) (865) 36,180 Allowance for equity funds used during construction (141) (119) (102) Changes in working capital: Receivables (6,725) 1,579 2,007 Accounts payable 1,169 (1,455) 2,802 Taxes accrued (82) 1,473 2,471 Interest accrued (1,319) (1,687) (168) Other working capital accounts 1,365 (6,344) 58 Pension payment - (23,131) - Other 8,345 7,047 2,888 ------- ------- -------- Net cash flow provided by operating activities 70,367 22,397 81,657 ------- ------- -------- Investing Activities: Construction expenditures (24,813) (21,043) (22,535) Allowance for equity funds used during construction 141 119 102 ------- ------- -------- Net cash flow used in investing activities (24,672) (20,924) (22,433) ------- ------- -------- Financing Activities: Proceeds from the issuance of general and refunding bonds 100,000 - - Retirement of: General and refunding bonds (44,400) - - First mortgage bonds (56,823) (28,000) (16,400) Redemption of preferred stock (1,500) (1,500) (1,500) Dividends paid: Common stock (43,900) (32,154) (4,453) Preferred stock (1,825) (2,057) (2,289) ------- ------- -------- Net cash flow used in financing activities (48,448) (63,711) (24,642) ------- ------- -------- Net increase (decrease) in cash and cash equivalents (2,753) (62,238) 34,582 Cash and cash equivalents at beginning of period 46,070 108,308 73,726 ------- ------- -------- Cash and cash equivalents at end of period $43,317 $46,070 $108,308 ======= ======= ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $21,953 $26,330 $25,341 Income taxes $25,661 $15,632 $6,357 See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES Liquidity is important to NOPSI due to the capital intensive nature of our business, which requires large investments in long-lived assets. However, large capital expenditures for the construction of new generating capacity are not currently planned. NOPSI requires significant capital resources for the periodic maturity of certain series of debt and preferred stock. Net cash flow from operations totaled $70 million, $22 million, and $82 million in 1993, 1992, and 1991, respectively. In recent years, this cash flow, supplemented by cash on hand, has been sufficient to meet substantially all investing and financing requirements, including capital expenditures, dividends, and debt/preferred stock maturities. NOPSI's ability to fund these capital requirements results, in part, from our continued efforts to streamline operations and reduce costs, as well as collections under our Grand Gulf 1 rate phase-in plan which exceed the current cash requirements for Grand Gulf 1-related costs. (In the income statement, these revenue collections are offset by the amortization of previously deferred costs, therefore, there is no effect on net income.) See Note 2, incorporated herein by reference, for additional information on NOPSI's rate phase-in plan. See Note 8, incorporated herein by reference, for additional information on NOPSI's capital and refinancing requirements in 1994 - 1996. Also, in order to take advantage of lower interest and dividend rates, NOPSI may continue to refinance high-cost debt and preferred stock prior to maturity. Earnings coverage tests (which are impacted by the inclusion of the cumulative effect of the change in accounting principle for accruing unbilled revenues discussed in Note 1), bondable property additions, and accumulated deferred Grand Gulf 1-related costs recorded as assets, limit the G&R Bonds and preferred stock that NOPSI can issue. Based on the most restrictive applicable tests as of December 31, 1993 and an assumed annual interest or dividend rate of 8%, NOPSI could have issued $40 million of additional G&R Bonds or $306 million of additional preferred stock. Further, NOPSI has the conditional ability to issue G&R bonds against the retirement of bonds, in some cases without satisfying an earnings coverage test. See Notes 5 and 6, incorporated herein by reference, for information on NOPSI's financing activities and Note 4, incorporated herein by reference, for information on NOPSI's short-term borrowings and lines of credit. NEW ORLEANS PUBLIC SERVICE INC. STATEMENTS OF INCOME
For the Years Ended December 31, --------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Operating Revenues (Notes 1, 2, and 10): Electric $423,830 $391,936 $399,214 Natural gas 90,992 72,943 76,951 -------- -------- -------- Total 514,822 464,879 476,165 -------- -------- -------- Operating Expenses: Operation (Note 10): Fuel for electric generation and fuel-related expenses 59,859 47,566 38,428 Purchased power 165,963 170,703 168,315 Gas purchased for resale 52,592 43,212 49,986 Other 69,658 74,696 74,713 Maintenance 18,139 17,039 18,118 Depreciation and amortization 17,284 16,619 15,973 Taxes other than income taxes 26,643 27,487 25,733 Income taxes (Note 3) 24,232 14,382 41,998 Rate deferrals (Note 2): Rate deferrals (1,651) (1,300) (3,348) Amortization of rate deferrals 22,351 4,426 38,627 Deferral of previously incurred Grand Gulf 1-related costs - - (90,000) -------- -------- -------- Total 455,070 414,830 378,543 -------- -------- -------- Operating Income 59,752 50,049 97,622 -------- -------- -------- Other Income (Deductions): Allowance for equity funds used during construction 141 119 102 Miscellaneous - net (1,055) 3,056 5,329 Income taxes (Note 3) (1,115) (1,683) (3,242) -------- -------- -------- Total (2,029) 1,492 2,189 -------- -------- -------- Interest Charges: Interest on long-term debt 19,478 22,934 23,865 Other interest - net 1,614 2,290 1,358 Allowance for borrowed funds used during construction (130) (107) (111) -------- -------- -------- Total 20,962 25,117 25,112 -------- -------- -------- Income before Cumulative Effect of a Change in Accounting Principle 36,761 26,424 74,699 Cumulative Effect to January 1, 1993 of Accruing Unbilled Revenues (net of income taxes of $6,592) (Note 1) 10,948 - - -------- -------- -------- Net Income 47,709 26,424 74,699 Preferred Stock Dividend Requirements 1,768 1,999 2,231 -------- -------- -------- Earnings Applicable to Common Stock $45,941 $24,425 $72,468 ======== ======== ======== See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC. STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, ----------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Retained Earnings, January 1 $98,560 $106,341 $33,918 Add: Net income 47,709 26,424 74,699 -------- -------- -------- Total 146,269 132,765 108,617 -------- -------- -------- Deduct: Dividends declared: Preferred stock 1,768 1,999 2,231 Common stock 43,900 32,154 - Capital stock expenses 45 52 45 -------- -------- -------- Total 45,713 34,205 2,276 -------- -------- -------- Retained Earnings, December 31 (Note 7) $100,556 $98,560 $106,341 ======== ======== ======== See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income increased in 1993 due primarily to the one-time recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1, incorporated herein by reference) and its ongoing effects, partially offset by the effect of implementing SFAS 106 (see Note 9, incorporated herein by reference). Effective January 1, 1993, NOPSI began accruing as revenues the charges for energy delivered to customers but not yet billed. Electric and gas revenues were previously recorded on a cycle-billing basis. Excluding the above mentioned items, net income for 1993 would have been $37.8 million. This $11.4 million increase is due primarily to increased gas revenues and increased electric retail energy sales. Net income decreased in 1992 due primarily to the net income effect of the $90 million 1991 NOPSI Settlement, which resulted in a $48.6 million increase in 1991 net income. Significant factors affecting the results of operations and causing variances between the years 1993 and 1992, and 1992 and 1991, are discussed under "Revenues and Sales" and "Expenses" below. Revenues and Sales See "Selected Financial Data-Five-Year Comparison," incorporated herein by reference, following the notes, for information on electric operating revenues by source and KWH sales. Electric operating revenues were higher in 1993 due primarily to increased fuel adjustment revenues and increased collections of previously deferred Grand Gulf 1-related costs, neither of which affects net income, and increased residential energy sales resulting primarily from a return to more normal weather as compared to milder weather in 1992. Electric operating revenues were slightly lower in 1992 due primarily to decreased retail sales as a result of milder temperatures. Total electric energy sales were lower in 1992 resulting from these milder temperatures. Gas operating revenues increased in 1993 due primarily to an increase in gas rates and increased fuel adjustment revenues resulting from higher average per unit cost for gas purchased. Gas operating revenues decreased in 1992 due primarily to decreased recovery of resale gas costs through the city gate adjustment clause, partially offset by higher base revenues due to the gas rate increase in May 1992. Expenses Fuel for electric generation and fuel-related expenses increased in 1993 due primarily to increased gas costs and increased generation requirements resulting primarily from increased energy sales as discussed in "Revenues and Sales" above. Fuel for electric generation and fuel-related expenses increased in 1992 due to increased generation. Gas purchased for resale increased in 1993 due primarily to a higher average per unit cost for gas purchased while it declined in 1992 due primarily to a lower average per unit cost. The changes in the amortization of rate deferrals in 1993 and 1992 are primarily a result of the 1991 NOPSI Settlement, which allowed NOPSI to record an additional $90 million of previously incurred Grand Gulf 1-related costs. Total income taxes increased in 1993 due primarily to higher pretax income and an increase in the federal income tax rate as a result of OBRA. Total income taxes decreased in 1992 due primarily to lower pretax income resulting from the effect of the 1991 NOPSI Settlement. NEW ORLEANS PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Competition NOPSI welcomes competition in the electric energy business and believes that a more competitive environment should benefit our customers, employees, and shareholders of Entergy Corporation. We also recognize that competition presents us with many challenges, and we have identified the following as our major competitive challenges: Retail and Wholesale Rate Issues Increasing competition in the utility industry brings an increased need to stabilize or reduce retail rates. NOPSI is currently operating under electric and gas base rate freezes through October 31, 1996. Also, in connection with the Merger, NOPSI agreed with the Council to reduce its annual electric base rates by $4.8 million effective for bills rendered on or after November 1, 1993. See Note 2, incorporated herein by reference, for further information. Retail wheeling, a major industry issue which may require utilities to "wheel" or move power from third parties to their own retail customers, is evolving gradually. As a result, the retail market could become more competitive. In the wholesale rate area, FERC approved in 1992, with certain modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power, Inc. to sell wholesale power at market-based rates and to provide to electric utilities "open access" to the System's transmission system (subject to certain requirements). GSU was later added to this filing. Various intervenors in the proceeding filed petitions for review with the United States Court of Appeals for the District of Columbia Circuit. FERC's order, once it takes effect, will increase marketing opportunities for NOPSI, but will also expose NOPSI to the risk of loss of load or reduced revenues due to competition with alternative suppliers. In light of the rate issues discussed above, NOPSI is aggressively reducing costs to avoid potential earnings erosions that might result as well as to successfully compete by becoming a low-cost producer. To help minimize future costs, NOPSI remains committed to least cost planning. In December 1992, NOPSI filed a Least Cost Integrated Resource Plan (Least Cost Plan) with its retail regulator. Least cost planning includes demand-side measures such as customer energy conservation and supply-side measures such as more efficient power plants. These measures are designed to delay the building of new power plants for the next 20 years. NOPSI plans to periodically file revised Least Cost Plans. The Energy Policy Act of 1992 The Energy Policy Act of 1992 (Energy Act) is changing the transmission and distribution of electricity. This act encourages competition and affords us the opportunities, and the risks, associated with an open and more competitive market environment. The Energy Act increases competition in the wholesale energy market through the creation of exempt wholesale generators (EWGs). The Energy Act also gives FERC the authority to order investor-owned utilities to provide transmission access to or for other utilities, including EWGs. NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES NOPSI maintains accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications. Revenues and Fuel Costs Prior to January 1, 1993, NOPSI recorded revenues when billed to its customers with no accrual for energy delivered but not yet billed. To provide a better matching of revenues and expenses, effective January 1, 1993, NOPSI adopted a change in accounting principle to provide for accrual of the nonfuel portion of estimated unbilled revenues. The cumulative effect of this accounting change as of January 1, 1993, increased net income by $10.9 million. Had this new accounting method been in effect during prior years, net income before the cumulative effect would not have been materially different from that shown in the accompanying financial statements. NOPSI's rate schedules include electric fuel adjustment and city gate gas cost adjustment clauses that allow deferral of fuel costs until such costs are reflected in the related revenues. Utility Plant Utility plant is stated at original cost. The original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of NOPSI's utility plant is subject to the liens of its mortgage bond indentures. 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 utility plant and increases earnings, it is only realized in cash through depreciation provisions included in rates. NOPSI's effective composite rates for AFUDC were 11.4%, 12.1%, and 11.3% for 1993, 1992, and 1991, respectively. Depreciation is computed on the straight-line basis at rates based on the estimated service lives and costs of removal of the various classes of property. Depreciation provisions on average depreciable property approximated 3.1% in 1993 and 1992, and 3.2% in 1991. Income Taxes NOPSI, its parent, and affiliates (excluding GSU prior to 1994) file a consolidated federal income tax return. Income taxes are allocated to NOPSI in proportion to its contribution to consolidated taxable income. SEC regulations require that no System company pay more taxes than it would have had a separate income tax return been filed. Deferred taxes are recorded for all temporary differences between book and taxable income. Investment tax credits are deferred and amortized based upon the average useful life of the related property in accordance with rate treatment. As discussed in Note 3, effective January 1, 1993, NOPSI changed its accounting for income taxes to conform with SFAS 109. Other Noncurrent Liabilities NOPSI records provisions for uninsured property risks and claims for injuries and damages through charges to operation expenses on an accrual basis. Provisions for these accruals, classified as other noncurrent liabilities, have been allowed for ratemaking purposes. Cash and Cash Equivalents NOPSI considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Fair Value Disclosure The estimated fair value amounts of financial instruments have been determined by NOPSI, using available market information and appropriate valuation methodologies. However, considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that NOPSI could realize in a current market exchange. In addition, gains or losses realized on financial instruments may be reflected in future rates and not accrue to the benefit of stockholders. NOPSI considers the carrying amounts of 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. In addition, NOPSI does not presently expect that performance of its obligations will be required in connection with certain off-balance sheet commitments and guarantees considered financial instruments. Due to this factor, and because of the related party nature of these commitments and guarantees, determination of fair value is not considered practicable. See Notes 5 and 6 for additional fair value disclosure. NOTE 2. RATE AND REGULATORY MATTERS Rate Agreement In November 1993, the Council adopted resolutions accepting a proposal by NOPSI to settle certain issues related to the Merger. Pursuant to the resolutions, the Council agreed to withdraw from the SEC proceeding related to the Merger. In return, NOPSI agreed, among other things, that retail ratepayers in the City of New Orleans would be protected from (1) increases in NOPSI's cost of capital resulting from risks associated with the Merger; (2) recovery of any portion of the acquisition premium or transactional costs associated with the Merger; (3) certain direct allocations of costs associated with GSU's River Bend nuclear unit; and (4) any losses of GSU resulting from resolution of litigation in connection with its ownership of River Bend. NOPSI was required to reduce its annual electric base rates by $4.8 million effective for bills rendered on or after November 1, 1993, and to expense its SFAS 106 costs. NOPSI's SFAS 106 expenses through October 31, 1996, will be allowed by the Council for purposes of evaluating the appropriateness of NOPSI's rates. The Council also agreed not to seek to disallow the first $3.5 million of costs incurred through October 31, 1993, in connection with the Least Cost Plan. Prudence Settlement and Finalized Phase-In Plan The February 4 Resolution required NOPSI to write off, and not recover from its retail electric customers, $135 million of its previously deferred costs associated with Grand Gulf 1. This write-off, which was recorded in NOPSI's 1987 financial statements, was in addition to the $51.2 million of Grand Gulf 1-related costs originally absorbed and not recovered by NOPSI as part of the 1986 Rate Settlement. In 1991, NOPSI reached a settlement (1991 NOPSI Settlement) with the Council and with the Alliance that resolved the Grand Gulf 1 prudence issues and the pending litigation related to the February 4 Resolution. The 1991 NOPSI Settlement supersedes both the 1986 Rate Settlement (which established a rate phase-in plan designed to reduce the immediate effect on ratepayers of the inclusion of Grand Gulf 1 costs in rates) and the February 4 Resolution and provides that there will be no further disallowance of the recovery of any Grand Gulf 1-related costs incurred by NOPSI based on any alleged imprudence by NOPSI that may have occurred or may be alleged to have occurred prior to the effective date of the 1991 NOPSI Settlement. The 1991 NOPSI Settlement included the following terms: (i) Effective Date Base Electric Rates(1) ---------------- ------------------------ October 4, 1991 $11.3 million decrease(2) October 31, 1992 $ 7.3 million increase October 31, 1993 $ 6.7 million increase(3) October 31, 1994 $ 5.2 million increase October 31, 1995 $ 4.4 million increase (1) These changes are subject to adjustment to reflect implementation of the Least Cost Plan. (2) The October 4, 1991 decrease partly offset an April 1991 increase of $18.9 million. (3) This increase was partially offset by the $4.8 million base rate reduction described above. (ii) In connection with the rate changes set forth in (i) above, NOPSI implemented a finalized phase-in plan covering a ten-year period from October 1, 1991 through September 30, 2001, for recovery of all Grand Gulf 1 deferred costs, including associated carrying charges. (iii) NOPSI agreed to a five-year electric base rate freeze extending through October 31, 1996, excluding the annual rate increases provided for in (i) above and except for increases to reflect an increase in state and/or federal income tax rates or a catastrophic event such as a hurricane. NOPSI also agreed that during the period October 1, 1993 through October 31, 1996 the Council will have the right to investigate the appropriateness of NOPSI's rates if NOPSI's return on average equity on its electric operations (calculated in accordance with the applicable provisions of the 1991 NOPSI Settlement) for twelve month periods subsequent to September 30, 1992 were to exceed 13.76%, and, after hearing(s), to impose a credit on NOPSI's customers' bills in an amount that would have allowed NOPSI, during the relevant test year, to earn a return on equity incident to its electric operations of no less than 12.76%. The Council agreed otherwise not to reduce NOPSI's base electric rates during the period through October 31, 1996 except to reflect a decrease in state and/or federal income tax rates. (iv) NOPSI will include in the "over/under" provision of its fuel adjustment clause, on a monthly basis, the difference, if any, between the non-fuel Grand Gulf 1 costs billed by System Energy to NOPSI and the estimate of such costs attached to the 1991 NOPSI Settlement, with the Council having the right to suspend this provision in the event of a catastrophe involving Grand Gulf 1. In the event the Council suspends this provision, NOPSI will have the right to seek a rate increase notwithstanding (iii) above. NOPSI recorded on its balance sheet in 1991 as a deferred asset an additional $90 million of previously incurred Grand Gulf 1-related costs with a corresponding pretax gain on the income statement. The $90 million represents the increase in the present value of the recovery stream of deferred Grand Gulf 1-related costs consistent with the recoverable costs as set forth in (ii) above. The gain increased 1991 net income by $48.6 million after taxes. Gas Rate Filing In May 1992, NOPSI and the Council reached a settlement regarding NOPSI's application for an increase in gas rates. The settlement includes the following terms, among others: (i) an aggregate net rate increase of $7.5 million, effective on May 22, 1992, phased in over a two-year period. The year one net increase is stipulated to be $3.8 million, with an additional $3.0 million being deferred for recovery in equal annual installments in years two through six. The net increase in year two of $3.7 million includes $730,000 for recovery of the costs deferred in year one (including associated carrying charges). (ii) except as provided above, and except for increases to reflect an increase in state and/or federal income tax rates or a catastrophic event such as a hurricane, NOPSI has agreed to a gas base rate freeze through October 31, 1996. In addition, the settlement provides that earnings from gas operations will be included with those from electric operations for purposes of the return on average equity ceiling provisions of the 1991 NOPSI Settlement (discussed above) and revises the method of calculating such return on equity ceiling. NOTE 3. INCOME TAXES Effective January 1, 1993, NOPSI adopted SFAS 109. This new standard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that deferred tax balances be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 requires that regulated enterprises recognize adjustments resulting from implementation as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. A substantial majority of the adjustments required by SFAS 109 was recorded to deferred tax balance sheet accounts with offsetting adjustments to regulatory assets and liabilities. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. As a result of the adoption of SFAS 109, 1993 net income was increased by $0.3 million, assets were increased by $4.1 million, and liabilities were increased by $3.8 million. Income tax expense consisted of the following:
For the Years Ended December 31, -------------------------------- 1993 1992 1991 ------- ------- ------ (In Thousands) Current: Federal $23,400 $16,575 $8,885 State 4,079 - - ------- ------- ------- Total 27,479 16,575 8,885 ------- ------- ------- Deferred - net: Rate deferrals - net (7,395) (1,185) 20,548 1989 Settlement Agreement - - 1,821 Net operating loss carryforward utilization 42 2,747 15,186 Unbilled revenue 4,621 (2,800) 1,513 Pension expense 2,935 (1,044) (1,041) Liberalized depreciation (19) (286) (469) Deferred fuel or gas costs 2,251 1,904 (479) Bond reacquisition 1,074 328 - Alternative Minimum Tax 2,317 (3) (590) Other (623) (1) 458 ------- ------- ------- Total 5,203 (340) 36,947 ------- ------- ------- Investment tax credit adjustments - net (743) (170) (592) ------- ------- ------- Recorded income tax expense $31,939 $16,065 $45,240 ======= ======= ======= Charged to operations $24,232 $14,382 $41,998 Charged to other income 1,115 1,683 3,242 Charged to cumulative income 6,592 - - ------- ------- ------- Total income taxes $31,939 $16,065 $45,240 ======= ======= =======
Total income taxes differ from the amounts computed by applying the statutory federal income tax rate to income before taxes. The reasons for the differences were:
For the Years Ended December 31, ---------------------------------------------------- 1993 1992 1991 --------------- ---------------- ---------------- % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income ------ ------ ------- ------ ------- ------ (Dollars in Thousands) Computed at statutory rate $27,877 35.0 $14,446 34.0 $40,779 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 3,411 4.3 1,462 3.5 4,420 3.7 Depreciation (780) (1.0) (731) (1.7) (654) (0.6) Amortization of investment tax credits (745) (0.9) (752) (1.8) (650) (0.6) Recapture of prior years' consolidated income tax savings 323 0.4 481 1.1 1,180 1.0 Amortization of excess deferred income tax 384 0.5 376 0.9 376 0.3 Adjustment of prior year taxes 2,413 3.0 391 0.9 (400) (0.3) SFAS 109 adjustment (1,170) (1.5) - - - - Other--net 226 0.3 391 0.9 189 0.2 ------- ---- ------- ---- ------- ---- Total income taxes $31,939 40.1 $16,064 37.8 $45,240 37.7 ======= ==== ======= ==== ======= ====
Significant components of NOPSI's net deferred tax liabilities as of December 31, 1993, were (in thousands): Deferred tax liabilities: Net regulatory assets $(13,465) Plant related basis differences (49,753) Rate deferrals (80,380) Other (5,194) --------- Total $(148,792) ========= Deferred tax assets: Unbilled revenues $5,812 Accumulated deferred investment tax credit 4,460 Pension related items 5,804 Removal cost 8,197 Standard coal plant 2,861 Operating reserves 6,934 Other 4,660 --------- Total $38,728 ========= Net deferred tax liabilities $(110,064) ========= NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized NOPSI to effect short-term borrowings of up to $43 million. This authorization is effective through November 30, 1994. In addition, NOPSI can borrow from the Money Pool, subject to its maximum authorized level of short-term borrowings and the availability of funds. NOPSI's short-term borrowings are also limited by the terms of its G&R Bond indenture to amounts not exceeding, in general, the greater of 10% of capitalization or 50% of Grand Gulf 1 rate deferrals available to support the issuance of G&R Bonds. NOPSI had no outstanding short-term borrowings under these arrangements as of December 31, 1993. NOTE 5. PREFERRED STOCK The number of shares and dollar value of NOPSI's cumulative, $100 par value preferred stock was:
As of December 31, --------------------------------- Shares Call Price Per Authorized and Total Share as of Outstanding Dollar Value December 31, 1993 1992 1993 1992 1993 ------- ------- ------- ------- ------------ (Dollars in Thousands) Without sinking fund: 4 3/4% Preferred Stock 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 ======= ======= ======= ======= With sinking fund: 15.44% Series 49,495 64,495 $4,950 $6,450 $107.72 ======= ======= ====== ======
The fair value of NOPSI's preferred stock with sinking fund was estimated to be approximately $5.3 million and $6.5 million as of December 31, 1993 and 1992, respectively. The fair value was determined using quoted market prices or estimates from nationally recognized investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. Changes in the preferred stock during the last three years were: Number of Shares ------------------------------- 1993 1992 1991 --------- -------- -------- Preferred stock retirements: $100 par value (15,000) (15,000) (15,000) Cash sinking fund requirements for the next five years for preferred stock outstanding as of December 31, 1993, are $750,000 annually. NOPSI has the annual non-cumulative option to redeem, at par, up to an additional $750,000 of its 15.44% Series preferred stock outstanding. NOPSI has regulatory authorization for the issuance and sale through December 31, 1994, of up to $20 million of preferred stock and, for the acquisition through December 31, 1994, of up to $6.5 million of its outstanding preferred stock. NOTE 6. LONG-TERM DEBT NOPSI's long-term debt as of December 31, 1993 and 1992, was:
Maturities Interest Rates From To From To 1993 1992 ---- ---- ----- ---- ------- ------- (In Thousands) First Mortgage Bonds 1994 1998 5-5/8% 11.0% $35,250 $60,250 2004 2008 9-1/2% 10.0% - 30,000 G&R Bonds 1993 1998 10.95% 13.9% 69,200 113,600 1999 2023 7.0% 8.0% 100,000 - Unamortized Premium and Discount-Net (1,138) 17 -------- -------- Total Long-Term Debt 203,312 203,867 Less Amount Due Within One Year 15,000 44,400 -------- -------- Long-Term Debt Excluding Amount Due Within One Year $188,312 $159,467 ======== ========
The fair value of NOPSI's long-term debt as of December 31, 1993 and 1992 was estimated to be (in millions) $211.5 and $216.1 respectively. Fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. For the years 1994, 1995, 1996, 1997, and 1998, NOPSI has long-term debt maturities and cash sinking fund requirements of (in millions) $15, $24.2, $38.3, $27, and $0, respectively. In addition, other sinking fund requirements of approximately $0.2 million annually may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements. NOPSI has regulatory authorization for the issuance and sale through December 31, 1994, of up to $145 million of G&R Bonds (of which $45 million remained available as of December 31, 1993) and for the acquisition, through December 31, 1994, in whole or in part, prior to their respective maturities, of up to $135 million of its outstanding first mortgage and/or G&R Bonds. Under NOPSI's G&R Mortgage, G&R Bonds are issuable based upon 70% of bondable property additions or based upon 50% of accumulated deferred Grand Gulf 1-related costs. The G&R Mortgage precludes the issuance of any additional G&R Bonds if the total amount of outstanding Rate Recovery Mortgage Bonds issued on the basis of the uncollected balance of deferred Grand Gulf 1-related costs exceeds 66 2/3% of the balance of such deferred costs. As of December 31, 1993, the total amount of Rate Recovery Mortgage Bonds outstanding aggregated $69.2 million, or 30.2% of NOPSI's accumulated deferred Grand Gulf 1-related costs. NOTE 7. DIVIDEND RESTRICTIONS NOPSI's Restatement of Articles of Incorporation, as amended, and certain of its indentures contain provisions restricting the payment of cash dividends or other distributions on common stock. As of December 31, 1993, $24.2 million of NOPSI's retained earnings were restricted against the payment of cash dividends or other distributions on common stock. NOTE 8. COMMITMENTS AND CONTINGENCIES Capital Requirements and Financing Construction expenditures for the years 1994, 1995, and 1996 are estimated to total $26 million each year. NOPSI will also require $80 million during the period 1994-1996 to meet long-term debt and preferred stock maturities and cash sinking fund requirements. NOPSI plans to meet the above requirements with internally generated funds and cash on hand. See Notes 5 and 6 regarding the possible refinancing, redemption, purchase, or other acquisition of certain outstanding series of preferred stock and long-term debt. Unit Power Sales Agreement System Energy has agreed to sell all of its 90% owned and leased share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this agreement are paid in consideration for NOPSI's 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 approved by FERC, most likely upon Grand Gulf 1's retirement from service. NOPSI's monthly obligation for payments under the agreement is approximately $9 million. Availability Agreement AP&L, LP&L, MP&L, and NOPSI are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 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. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Payments or advances under the Availability Agreement are only required if funds available to System Energy from all sources are less than the amount required under the Availability Agreement. 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 have ever been required. In 1989, the Availability Agreement was amended to provide that the write-off of $900 million of Grand Gulf 2 costs would be amortized for Availability Agreement purposes over a period of 27 years, in order to avoid the need for payments by AP&L, LP&L, MP&L, and NOPSI. If AP&L, LP&L, or MP&L fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, NOPSI could be liable for payments to System Energy, in amounts that cannot be determined, over and above its payments under the Unit Power Sales Agreement. Reallocation Agreement System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation Agreement relating to the sale of capacity and energy from the Grand Gulf Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and obligations with respect to the Grand Gulf Station under the Availability Agreement. FERC's decision allocating a portion of Grand Gulf 1 capacity and energy to AP&L supersedes the Reallocation Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect AP&L's obligation to System Energy's lenders under the assignments referred to in the preceding paragraph. AP&L would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual obligations. No payments of any amortization amounts will be required as 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. System Fuels NOPSI has a 13% interest in System Fuels, a jointly owned subsidiary of AP&L, LP&L, MP&L, and NOPSI. The parent companies of System Fuels, including NOPSI, agreed to make loans to System Fuels to finance its fuel procurement, delivery, and storage activities. As of December 31, 1993, NOPSI had approximately $3.3 million of loans outstanding to System Fuels which mature in 2008. City Franchise Ordinances NOPSI provides electric and gas service in the City of New Orleans pursuant to City franchise ordinances which state, among other things, that the City has a continuing option to purchase NOPSI's electric and gas utility properties. NOTE 9. POSTRETIREMENT BENEFITS Pension Plan NOPSI is a participating employer in a defined benefit pension plan sponsored by LP&L, covering substantially all employees. The pension plan is noncontributory and provides pension benefits based on employees' credited service and average compensation, generally during the last five years before retirement. Pension costs are funded 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 plan consist primarily of common and preferred stocks, fixed income securities, interest in a money market fund, and insurance contracts. NOPSI's 1993, 1992, and 1991 pension cost, including amounts capitalized, included the following components:
For the Years Ended December 31, -------------------------------- 1993* 1992* 1991* ------- ------ ------- (In Thousands) Service cost - benefits earned during the period $1,387 $1,253 $1,366 Interest cost on projected benefit obligation 2,422 2,119 1,572 Net amortization and deferral (49) 173 35 Other - - 600 ------ ------ ------ Net pension cost $3,760 $3,545 $3,573 ====== ====== ======
* Pension cost represents NOPSI's allocated portion of the total pension expense (as calculated by an independent actuary) for the defined benefit pension plan sponsored by LP&L. The funded status of LP&L's pension plan allocable to NOPSI employees as of December 31, 1993 and 1992, was:
1993 1992 ------- ------- (In Thousands) Actuarial present value of accumulated pension plan benefits: Vested $26,173 $22,276 Nonvested 36 26 ------- ------- Accumulated benefit obligation $26,209 $22,302 ======= ======== Plan assets at fair value $7,523 $ (2,289) Projected benefit obligation 36,831 29,944 -------- -------- Plan assets less than projected benefit obligation (29,308) (32,233) Unrecognized prior service cost 2,462 2,702 Unrecognized transition asset (1,354) (1,550) Unrecognized net loss 12,184 7,920 -------- -------- (16,016) (23,161) Unfunded portion of NOPSI pension liability 12,256 23,161 -------- -------- Accrued pension liability $ (3,760) $ - ======== ========
The significant actuarial assumptions used in computing the information above for 1993, 1992, and 1991 were as follows: weighted average discount rate, 7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in future compensation levels, 5.6%; and expected long-term rate of return on plan assets, 8.5%. Transition assets are being amortized over the average remaining service period of active participants. Other Postretirement Benefits NOPSI also provides certain 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 NOPSI. The cost of providing these benefits, recorded on a cash basis, to retirees in 1992 was approximately $3.7 million. Prior to 1992, the cost of providing these benefits for retirees was not separable from the cost of providing benefits for active employees. Based on the ratio of the number of retired employees to the total number of active and retired employees in 1991, the cost of providing these benefits in 1991, recorded on a cash basis, for retirees was approximately $2.6 million. Effective January 1, 1993, NOPSI adopted SFAS 106. The new standard requires a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. NOPSI continues to fund these benefits on a pay-as-you-go basis. As of January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $53.6 million. This obligation is being amortized over a 20-year period beginning in 1993. NOPSI is expensing its SFAS 106 costs pursuant to resolutions adopted in November 1993 by the Council related to the Merger. NOPSI's SFAS 106 expenses through October 31, 1996, will be allowed by the Council for purposes of evaluating the appropriateness of NOPSI's rates. NOPSI's net income in 1993 was decreased by approximately $2.2 million as a result of adopting SFAS 106. NOPSI's 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components (in thousands): Service cost - benefits earned during the period $822 Interest cost on APBO 4,248 Actual return on plan assets - Amortization of transition obligation 2,678 ------ Net periodic postretirement benefit cost $7,748 ====== The funded status of NOPSI's postretirement plan as of December 31, 1993, was (in thousands): Accumulated postretirement benefit obligation: Retirees $46,218 Other fully eligible participants 3,565 Other active participants 9,152 ------- 58,935 Plan assets at fair value - ------- Plan assets less than APBO (58,935) Unrecognized transition obligation 50,895 Unrecognized net loss 4,835 ------- Accrued post retirement benefit liability $(3,205) ======= The assumed health care cost trend rate used in measuring the APBO was 9.9% for 1994, gradually decreasing each successive year until it reaches 5.6% in 2020. A one percentage-point increase in the assumed health care cost trend rate for each year would have increased the APBO as of December 31, 1993, by 7.7% and the sum of the service cost and interest cost by approximately 9.6% The assumed discount rate and rate of increase in future compensation used in determining the APBO were 7.5% and 5.5%, respectively. NOTE 10. TRANSACTIONS WITH AFFILIATES NOPSI buys electricity from and/or sells electricity to AP&L, LP&L, MP&L, and System Energy under rate schedules filed with FERC. In addition, NOPSI purchases fuel from System Fuels and receives technical and advisory services from Entergy Services, Inc. Operating revenues include revenues from sales to affiliates amounting to $2.5 million in 1993, $3.1 million in 1992, and $2.8 million in 1991. Operating expenses include charges from affiliates for fuel costs, purchased power and related charges, and technical and advisory services totaling $176.3 million in 1993, $183.0 million in 1992, and $187.9 million in 1991. NOTE 11. BUSINESS SEGMENT INFORMATION NOPSI supplies electric and natural gas services in the City. NOPSI's segment information follows:
1993 1992 1991 ----------------- ------------------ ---------------------- Electric Gas Electric Gas Electric Gas -------- ------- -------- ------- -------- ------- (In Thousands) Operating revenues $423,830 $90,992 $391,936 $72,943 $399,214 $76,951 Revenue from sales to unaffiliated customers (1) $421,343 $90,992 $388,851 $72,943 $396,456 $76,951 Operating income (loss) before income taxes $ 72,572 $11,412 $ 63,167 $ 1,264 $143,031 (2) $(3,411) Operating income (loss) $ 52,046 $ 7,706 $ 47,194 $ 2,855 $ 98,096 (2) $ (474) Net utility plant $211,776 $63,803 $206,402 $61,783 $204,200 $59,237 Depreciation expense $ 14,308 $ 2,976 $ 13,776 $ 2,843 $ 13,278 $ 2,695 Construction expenditures $ 19,774 $ 5,039 $ 15,724 $ 5,319 $ 18,084 $ 4,451
(1) NOPSI's intersegment transactions are not material (less than 1% of sales to unaffiliated customers). (2) Operating income before income taxes and operating income reflect a nonrecurring increase of $90.0 million and $48.6 million, respectively, in connection with the 1991 NOPSI Settlement. NOTE 12. QUARTERLY FINANCIAL DATA (UNAUDITED) NOPSI's business is subject to seasonal fluctuations with the peak periods occurring during the third quarter for electric and during the first quarter for gas. Operating results for the four quarters of 1993 and 1992 were: Net Operating Operating Income Revenues Income (Loss) --------- --------- ------ (In Thousands) 1993: First Quarter (1) $108,566 $ 8,828 $14,930 Second Quarter $120,182 $17,789 $12,714 Third Quarter $154,610 $29,648 $24,843 Fourth Quarter $131,464 $ 3,487 $(4,778) 1992: First Quarter $106,598 $11,423 $ 5,819 Second Quarter $101,993 $ 7,382 $ 1,672 Third Quarter $139,362 $25,551 $19,931 Fourth Quarter $116,926 $ 5,693 $ (998) (1) The first quarter of 1993 reflects a nonrecurring increase in net income of $10.9 million, net of taxes of $6.6 million, due to the recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1). Beginning with the second quarter, the remaining quarters are not generally comparable to prior year quarters because of the ongoing effects of the accounting change. NEW ORLEANS PUBLIC SERVICE INC. SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1993 1992 1991 1990 1989 --------- -------- -------- -------- -------- (In Thousands) Operating revenues $514,822 $464,879 $476,165 $485,246 $470,909 Income before cumulative effect of a change in accounting principle $ 36,761 $ 26,424 $ 74,699 $ 27,542 $ 14,464 Total assets $647,605 $621,691 $685,217 $577,283 $564,251 Long-term obligations (1) $193,262 $165,917 $231,901 $243,239 $261,495 (1) Includes long-term debt (excluding currently maturing debt) and preferred stock with sinking fund. See Notes 1, 3, and 9 for the effect of accounting changes in 1993.
1993 1992 1991 1990 1989 -------- -------- -------- -------- -------- (Dollars in Thousands) Electric Operating Revenues: Residential $151,423 $137,668 $136,030 $141,900 $134,000 Commercial 167,788 160,229 159,118 162,600 158,000 Industrial 26,205 23,860 24,062 27,000 25,200 Governmental 61,548 56,023 55,097 53,500 51,500 -------- -------- -------- -------- -------- Total retail 406,964 377,780 374,307 385,000 368,700 Sales for resale 11,778 10,320 9,805 8,400 8,000 Other 5,088 3,836 15,102 3,900 3,800 -------- -------- -------- -------- -------- Total $423,830 $391,936 $399,214 $397,300 $380,500 ======== ======== ======== ======== ======== Billed Electric Energy Sales (Millions of KWH): Residential 1,914 1,806 1,844 1,903 1,830 Commercial 1,989 1,977 2,023 2,054 2,035 Industrial 499 457 487 530 490 Governmental 924 888 887 846 837 -------- -------- -------- -------- -------- Total retail 5,326 5,128 5,241 5,333 5,192 Sales for resale 351 405 418 294 284 -------- -------- -------- -------- -------- Total 5,677 5,533 5,659 5,627 5,476 ======== ======== ======== ======== ========
System Energy Resources, Inc. 1993 Financial Statements SYSTEM ENERGY RESOURCES, INC. DEFINITIONS Certain abbreviations or acronyms used in System Energy's Financial Statements, Notes to Financial Statements, and Management's Financial Discussion and Analysis are defined below: Abbreviation or Acronym Term AFUDC Allowance for Funds Used During Construction ALJ Administrative Law Judge AP&L Arkansas Power & Light Company APSC Arkansas Public Service Commission Capital Funds Agreement Agreement, dated as of June 21, 1974, as amended, between System Energy and Entergy Corporation, and the assignments thereof City of New Orleans or City New Orleans, Louisiana DOE United States Department of Energy Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy Corporation that has operating responsibility for Grand Gulf 1, Waterford 3, ANO, and River Bend Entergy or System Entergy Corporation and its various direct and indirect subsidiaries FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission FERC Complaint Case Settlement Settlement, effective May 21, 1991, whereby System Energy credited approximately $47.6 million in the aggregate (including interest) against its June 1991 bills to AP&L, LP&L, MP&L, and NOPSI for capacity and energy from Grand Gulf 1 FERC Return on Equity Case Settlement, effective October 25, 1993, whereby System Energy refunded approximately $29.6 million in the aggregate (including interest) against its October 1993 bills to AP&L, LP&L, MP&L, and NOPSI when FERC reduced System Energy's Return on Equity from 13% to 11% prospectively from November 3, 1992 Grand Gulf Station Grand Gulf Steam Electric Generating Station Grand Gulf 1 Unit No. 1 of the Grand Gulf Station Grand Gulf 2 Unit No. 2 of the Grand Gulf Station GSU Gulf States Utilities Company (including wholly owned subsidiaries - Varibus Corporation, GSG&T, Inc., Prudential Oil and Gas, Inc., and Southern Gulf Railway Company) KWH Kilowatt-Hours LP&L Louisiana Power & Light Company LPSC Louisiana Public Service Commission Money Pool Entergy Money Pool which allows certain System companies to borrow from, or lend to, certain other System companies MP&L Mississippi Power & Light Company MPSC Mississippi Public Service Commission NOPSI New Orleans Public Service Inc. NRC Nuclear Regulatory Commission OBRA Omnibus Budget Reconciliation Act of 1993 Reallocation Agreement 1981 Agreement, superseded in part by a June 13, 1985 decision of FERC, among AP&L, LP&L, MP&L, NOPSI, and System Energy relating to the sale of capacity and energy from the Grand Gulf Station SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the FASB SFAS 109 SFAS No. 109, "Accounting for Income Taxes" SMEPA South Mississippi Electric Power Association System or Entergy Entergy Corporation and its various direct and indirect subsidiaries System Energy System Energy Resources, Inc. System Fuels System Fuels, Inc. System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively Unit Power Sales Agreement Agreement, dated as of June 10, 1982, as amended, among AP&L, LP&L, MP&L, NOPSI, and System Energy, relating to the sale of capacity and energy from System Energy's share of Grand Gulf 1 SYSTEM ENERGY RESOURCES, INC. REPORT OF MANAGEMENT The management of System Energy Resources, Inc. has prepared and is responsible for the financial statements and related financial information included herein. The financial statements are based on generally accepted accounting principles. Financial information included elsewhere in this report is consistent with the financial statements. To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls that is designed to provide reasonable assurance, on a cost-effective basis, as to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. This system includes communication through written policies and procedures, an employee Code of Conduct, 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. The independent public accountants provide an objective assessment of the degree to which 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 these policies and procedures provide reasonable assurance that its operations are carried out with a high standard of business conduct. /S/ DONALD C. HINTZ /S/ GERALD D. MCINVALE DONALD C. HINTZ GERALD D. MCINVALE President and Chief Executive Officer Senior Vice President and Chief Financial Officer SYSTEM ENERGY RESOURCES, INC. AUDIT COMMITTEE CHAIRMAN'S LETTER The Entergy Operations Board of Directors' Audit Committee functions as the Audit Committee for System Energy. The Audit Committee is comprised of three directors, who are not officers of System Energy or Entergy Operations: Brooke H. Duncan (Chairman), Robert D. Pugh, and William Clifford Smith. The committee held four meetings during 1993. The Audit Committee oversees System Energy's financial reporting process on behalf of the Board of Directors and provides reasonable assurance to the Board that sufficient operating, accounting, and financial controls are in existence and are adequately reviewed by programs of internal and external audits. The Audit Committee discussed with Entergy's internal auditors and the independent public accountants (Deloitte & Touche) the overall scope and specific plans for their respective audits, as well as System Energy's financial statements and the adequacy of System Energy's internal controls. The committee met, together and separately, with Entergy's internal auditors and independent public accountants, without management present, to discuss the results of their audits, their evaluation of System Energy's internal controls, and the overall quality of System Energy's financial reporting. The meetings also were designed to facilitate and encourage any private communication between the committee and the internal auditors or independent public accountants. /S/ BROOKE H. DUNCAN BROOKE H. DUNCAN Chairman, Audit Committee INDEPENDENT AUDITORS' REPORT To the Shareholder and the Board of Directors of System Energy Resources, Inc. We have audited the accompanying balance sheets of System Energy Resources, Inc. (System Energy) as of December 31, 1993 and 1992, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of System Energy's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. 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 at December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. As discussed in Note 2, "Rate and Regulatory Matters - FERC Audit" of Notes to Financial Statements, a regulatory proceeding is pending, which, if ultimately resolved in an adverse manner, would require that System Energy (1) write off and not recover in rates approximately $95 million of costs charged to utility plant resulting from System Energy's accounting for certain allocated income tax charges and (2) make refunds for overcollections from the Entergy System operating companies related thereto. The ultimate outcome of this uncertainty cannot presently be determined. Accordingly, no provision has been made in the accompanying financial statements for the possible effects of a decision adverse to System Energy. As discussed in Note 3 to the financial statements, in 1993 System Energy changed its method of accounting for income taxes. /S/ DELOITTE & TOUCHE DELOITTE & TOUCHE New Orleans, Louisiana February 11, 1994 SYSTEM ENERGY RESOURCES, INC. BALANCE SHEETS ASSETS
December 31, ------------------------- 1993 1992 ---------- ---------- (In Thousands) Utility Plant (Note 1): Electric $3,027,537 $3,019,241 Electric plant under lease (Note 8) 437,941 437,317 Construction work in progress 41,442 30,658 Nuclear fuel under capital lease (Note 7 and 8) 79,625 67,991 ---------- ---------- Total 3,586,545 3,555,207 Less - accumulated depreciation 669,666 572,302 ---------- ---------- Utility plant - net 2,916,879 2,982,905 ---------- ---------- Other Investments: Decommissioning trust funds (Note 7) 24,787 19,127 ---------- ---------- Current Assets: Cash and cash equivalents (Note 1): Cash 2,424 - Temporary cash investments - at cost, which approximates market: Associated companies (Note 4) 46,601 13,993 Other 147,107 167,802 ---------- ---------- Total cash and cash equivalents 196,132 181,795 Accounts receivable: Associated companies (Note 10) 57,216 60,601 Other 2,057 4,871 Materials and supplies - at average cost 69,765 71,660 Recoverable income taxes (Note 3) 63,400 47,900 Prepayments and other 4,835 3,497 ---------- ---------- Total 393,405 370,324 ---------- ---------- Deferred Debits: Recoverable income taxes (Note 3) 29,289 174,941 SFAS 109 regulatory asset - net (Note 3) 384,317 - Unamortized loss on reacquired debt 17,258 14,723 Other (Note 7 and 8) 125,131 110,421 ---------- ---------- Total 555,995 300,085 ---------- ---------- TOTAL $3,891,066 $3,672,441 ========== ========== See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC. BALANCE SHEETS CAPITALIZATION AND LIABILITIES
December 31, ------------------------- 1993 1992 ---------- ---------- (In Thousands) Capitalization: Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 1993 and 1992 $789,350 $789,350 Paid-in capital 7 - Retained earnings (Note 6) 228,574 367,747 ---------- ---------- Total common shareholder's equity 1,017,931 1,157,097 Long-term debt (Note 5) 1,511,914 1,755,308 ---------- ---------- Total 2,529,845 2,912,405 ---------- ---------- Other Noncurrent Liabilities: Obligations under capital leases (Note 8) 24,679 12,991 Other (Note 7) 18,229 18,919 ---------- ---------- Total 42,908 31,910 ---------- ---------- Current Liabilities: Currently maturing long-term debt (Note 5) 230,000 30,000 Accounts payable: Associated companies (Note 10) 1,928 2,164 Other 18,223 33,110 Taxes accrued 20,952 23,224 Interest accrued 48,929 50,560 Obligations under capital leases (Note 8) 55,000 55,000 Other 2,805 530 ---------- ---------- Total 377,837 194,588 ---------- ---------- Deferred Credits: Accumulated deferred income taxes (Note 3) 775,630 349,081 Accumulated deferred investment tax credits (Note 3) 113,849 144,284 Other 50,997 40,173 ---------- ---------- Total 940,476 533,538 ---------- ---------- Commitments and Contingencies (Notes 2, 7, and 8) TOTAL $3,891,066 $3,672,441 ========== ========== See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF CASH FLOWS
For the Years Ended December 31, ------------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Operating Activities: Net income $93,927 $130,141 $104,622 Noncash items included in net income: Depreciation and decommissioning 90,920 85,932 85,986 Deferred income taxes and investment tax credits 15,832 70,356 79,660 Allowance for equity funds used during construction (772) (681) (763) Amortization of debt discount 4,520 6,417 7,495 Changes in working capital: Receivables 6,199 225 (5,530) Accounts payable (15,123) (30,517) 37,511 Taxes accrued (2,272) 2,672 (178) Interest accrued (1,631) 1,252 (10,245) Other working capital accounts 2,832 (4,412) 15,716 Recoverable income taxes (Note 3) 130,152 (3,475) (14,277) Decommissioning trust contributions (4,911) (5,641) (2,201) Other (1,617) 86 (15,454) -------- -------- -------- Net cash flow provided by operating activities 318,056 252,355 282,342 -------- -------- -------- Investing Activities: Construction expenditures (23,083) (21,671) (21,663) Allowance for equity funds used during construction 772 681 763 Nuclear fuel purchases (32,822) (13,724) (28,922) Proceeds from sale and leaseback of nuclear fuel 32,822 28,094 14,552 Change in other temporary investments - - 125,225 -------- -------- -------- Net cash flow provided by (used in) investing activities (22,311) (6,620) 89,955 -------- -------- -------- Financing Activities: Proceeds from the issuance of first mortgage bonds 60,000 220,000 - Retirement of first mortgage bonds (108,308) (240,750) (294,000) Common stock dividend payments (233,100) (137,700) (115,785) -------- -------- -------- Net cash flow used in financing activities (281,408) (158,450) (409,785) -------- -------- -------- Net increase (decrease) in cash and cash equivalents 14,337 87,285 (37,488) Cash and cash equivalents at beginning of period 181,795 94,510 131,998 -------- -------- -------- Cash and cash equivalents at end of period $196,132 $181,795 $94,510 ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid (received) during the period for: Interest - net of amount capitalized $186,786 $201,287 $238,199 Income taxes (refund) ($65,992) $21,431 ($12,667) Noncash investing and financing activities: Capital lease obligations incurred $45,089 $28,094 $14,552 See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES The financial condition of System Energy significantly depends on the continued commercial operation of Grand Gulf 1 and on the receipt of payments from AP&L, LP&L, MP&L, and NOPSI. Payments under the Unit Power Sales Agreement are System Energy's only source of operating revenues. Net cash flow from operations totaled $318 million, $252 million, and $282 million in 1993, 1992, and 1991, respectively. In recent years, this cash flow has been sufficient to meet substantially all investing and financing requirements, including capital expenditures, dividends, and debt maturities. See Note 7, incorporated herein by reference, for information on System Energy's capital and refinancing requirements in 1994 - 1996. Further, in order to take advantage of lower interest rates, System Energy may continue to refinance high-cost debt prior to maturity. In addition, System Energy's financial condition could be affected by the outcome of a pending FERC audit matter. In December 1990, FERC Division of Audits issued a report for System Energy that recommended that System Energy write off and not recover in its rates approximately $95 million of Grand Gulf 1 costs included in utility plant, and compute refunds for over collections from AP&L, LP&L, MP&L, and NOPSI. In August 1992, FERC issued an opinion and order (August 4 Order) affirming an initial decision by a FERC ALJ. System Energy filed a Request for Rehearing, and in October 1992, FERC issued an order allowing additional time for its consideration of the request, and it deferred System Energy's refund obligation until 30 days after FERC issues an order on rehearing. If the decision is implemented, System Energy estimates that as of December 31, 1993, net income would be reduced by $151.6 million. This amount includes refund obligations of approximately $113.0 million (including interest). See Note 2, incorporated herein for reference, for additional information. Earnings coverage tests, bondable property additions, and equity ratio requirements contained in its mortgage, and in its letters of credit and reimbursement agreement in connection with its sale and leaseback transactions, limit the amount of first mortgage bonds that System Energy can issue. Based on the most restrictive applicable tests as of December 31, 1993, and assuming an annual interest rate of 8%, System Energy could have issued $290 million of additional first mortgage bonds. System Energy has the conditional ability to issue first mortgage bonds against the retirement of first mortgage bonds, in some cases, without satisfying an earnings coverage test. In connection with the financing of Grand Gulf 1, Entergy Corporation has undertaken, in the Capital Funds Agreement, to provide to System Energy sufficient capital to (1) maintain System Energy's equity capital at an amount equal to at least 35% of System Energy's total capitalization (excluding short-term debt), (2) permit the continuation of commercial operation of Grand Gulf 1, and (3) enable System Energy to pay in full all borrowings, whether at maturity, on prepayment, on acceleration, or otherwise. In addition, Entergy Corporation has agreed in the Capital Funds Agreement to make certain cash capital contributions, if required, to enable System Energy to make payments when due on specific issues of its long-term debt. See Note 4, incorporated herein by reference, for information regarding System Energy's short-term borrowings. SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF INCOME
For the Years Ended December 31, --------------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Operating Revenues (Note 2): $650,768 $723,410 $686,664 -------- -------- -------- Operating Expenses: Operation (Note 10): Fuel for electric generation and fuel-related expenses 42,296 55,110 78,060 Other 114,086 102,971 79,494 Maintenance (Note 10) 21,263 29,370 14,358 Depreciation and decommissioning (Note 7) 90,920 90,628 87,296 Taxes other than income taxes 26,589 28,717 27,342 Income taxes (Note 3) 83,412 93,438 81,302 -------- -------- -------- Total 378,566 400,234 367,852 -------- -------- -------- Operating Income 272,202 323,176 318,812 -------- -------- -------- Other Income: Allowance for equity funds used during construction 772 681 763 Miscellaneous - net 6,518 5,816 6,378 Income taxes (Notes 1 and 3) 4,859 4,584 7,726 -------- -------- -------- Total 12,149 11,081 14,867 -------- -------- -------- Interest Charges: Interest on long-term debt 184,818 196,618 218,538 Other interest - net 6,120 7,923 11,111 Allowance for borrowed funds used during construction (514) (425) (592) -------- -------- -------- Total 190,424 204,116 229,057 -------- -------- -------- Net Income $93,927 $130,141 $104,622 ======== ======== ======== See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, ---------------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Retained Earnings, January 1 $367,747 $375,306 $386,469 Add: Net income 93,927 130,141 104,622 -------- -------- -------- Total 461,674 505,447 491,091 -------- -------- -------- Deduct: Dividends declared 233,100 137,700 115,785 -------- -------- -------- Retained Earnings, December 31 (Note 6) $228,574 $367,747 $375,306 ======== ======== ======== See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income decreased in 1993 primarily due to the impact of the FERC Return on Equity Case settlement regarding the return on equity component of System Energy's formula wholesale rates (see Note 2, incorporated herein by reference). This decrease in revenue was partially offset by a reduction in interest expense due to the refinancing of high-cost debt. Net income increased in 1992 primarily due to the impact of the FERC Complaint Case settlement recorded in June 1991, which reduced net income in 1991. See Note 2, incorporated herein by reference, for further information on this settlement. In addition, 1992 net income was impacted by a reduction in interest expense (as a result of the repayment of and refunding of higher cost debt) not recovered through rates and the lower return System Energy earned on its net investment in Grand Gulf 1 during 1992. Significant factors affecting the results of operations and causing variances between the years 1993 and 1992, and 1992 and 1991 are discussed under "Revenues" and "Expenses" below. Revenues System Energy's operating revenues recover operating expenses, depreciation, and capital costs attributable to Grand Gulf 1. The capital costs are computed by allowing a return, currently set at a rate of 11.0%, (see Note 2, incorporated herein by reference, for further information on the FERC Return on Equity Case) on System Energy's common equity funds allocable to its investment in Grand Gulf 1 plus System Energy's effective interest cost for its debt allocable to this investment. Operating revenues decreased in 1993 due primarily to the effect of the FERC Return on Equity Case settlement which reduced System Energy's return on equity as discussed in "Net Income" above and a lower return on System Energy's decreasing investment in Grand Gulf 1 (caused by depreciation of the unit). Future revenues attributable to the return on equity will consequently be lower as a result of the reduction in return on equity. Also, future revenues attributable to the return on investment are expected to decline each year as a result of the depreciation of System Energy's investment in Grand Gulf 1. Operating revenues were higher in 1992 due primarily to the effect of the FERC Complaint Case settlement in 1991. The higher operating revenues in 1992 also reflect the increase in 1992 operating expenses primarily associated with the scheduled fifth refueling outage partially offset by a lower return earned on its investment in Grand Gulf 1 resulting from a decrease in net unit investment. Expenses Grand Gulf 1 was on-line for 284 of 365 days in 1993 as compared with 298 of 366 days in 1992. The unit capability factor, which is a measure of the unit's performance (based on a ratio of available energy generation to the maximum power capability multiplied by the period hours), was 76.1% for 1993 as compared with 79.9% for 1992. These variances are primarily due to the unit's sixth and fifth refueling outages that lasted from September 28, 1993 to December 3, 1993, (67 days) and April 17, 1992 to June 9, 1992; (52 days), respectively and, to a lesser extent, to unplanned outages in September 1993 (14 days) and January 1992 (10 days). These outages contributed significantly to the decrease in fuel for electric generation and fuel related expenses. The decrease in fuel expense in 1993 and 1992 is also due to refueling with less expensive nuclear fuel. (Approximately one-third of the reactor core was replaced during each outage.) Increased operating efficiency also contributed to the 1993 decrease. Nonfuel operation and maintenance expense increased in 1992 due primarily to the fifth refueling outage as mentioned above. The FERC Complaint Case settlement, recorded by System Energy in June 1991, contributed to fluctuations in 1992 operating results. Other operation expense increased in 1992 due, in part, to the provision of that settlement that called for 1991 credits from System Energy to AP&L, LP&L, MP&L, and NOPSI relating to System Energy's rate treatment of the portions of Grand Gulf 1 sold and leased back. Total income taxes decreased in 1993 due primarily to lower pretax book income partially offset by an increase in the federal income tax rate as a result of OBRA. Income taxes increased in 1992 due primarily to the effects of the FERC Complaint Case settlement. SYSTEM ENERGY RESOURCES, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS FERC Audit See Note 2, incorporated herein by reference, for information with respect to possible write-offs and refunds which may result from a decision issued by FERC. SYSTEM ENERGY RESOURCES, INC. NOTES TO FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES System Energy maintains accounts in accordance with FERC guidelines. Certain previously reported amounts have been reclassified to conform to current classifications. Organization System Energy is a generating company providing electricity to AP&L, LP&L, MP&L, and NOPSI and has a 90% interest in Grand Gulf 1, a nuclear generating station that began commercial operation in 1985. In June 1990, Entergy Operations assumed responsibility for the operation and maintenance of Grand Gulf 1. System Energy has a combined ownership and leasehold interest of 90% and SMEPA has an undivided ownership interest of 10% in Grand Gulf 1. System Energy records its investment associated with Grand Gulf 1 to the extent to which it owns and maintains a leasehold interest in the generating station. Likewise, System Energy's operating expenses reflected in the accompanying financial statements represent 90% of such Grand Gulf 1 expenses. Utility Plant Utility plant is stated at original cost. The original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the utility plant owned by System Energy is subject to the lien of its first mortgage bond indenture. 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 utility plant and represents current earnings, it is only realized in cash through depreciation provisions included in rates. System Energy's effective composite rates for AFUDC were 11.6%, 12.3%, and 12.4% for 1993, 1992, and 1991, respectively. Utility plant includes the portions of Grand Gulf 1 that were sold and are currently under lease. System Energy retired this property from its continuing property records as formerly owned property released from and no longer subject to System Energy's mortgage and deed of trust. System Energy is reflecting such leased property for financial reporting purposes as property under lease from others and is depreciating this property over the life of the basic lease term. Such depreciation is being deferred until recoverable from customers in future periods. See Note 8. Depreciation is computed on a straight-line basis at rates based on the estimated service lives and costs of removal of the various classes of property. Depreciation provisions on average depreciable property approximated 2.9% in 1993, 1992, and 1991. Income Taxes System Energy, its parent, and affiliates (excluding GSU prior to 1994) file a consolidated federal income tax return. Income taxes are allocated to System Energy in proportion to its contribution to consolidated taxable income. SEC regulations require that no System company pay more taxes than it would have had a separate income tax return been filed. Deferred taxes are recorded for all temporary differences between book and taxable income. Investment tax credits are deferred and amortized based upon the average useful life of the related property in accordance with rate treatment. As discussed in Note 3, effective January 1, 1993, System Energy changed its accounting for income taxes to conform with the SFAS 109. In addition, System Energy files a consolidated Mississippi state income tax return with certain other System companies. Cash and Cash Equivalents System Energy considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Fair Value Disclosure The estimated fair value amounts of financial instruments have been determined by System Energy, using available market information and appropriate valuation methodologies. However, considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that System Energy could realize in a current market exchange. In addition, gains or losses realized on financial instruments may be reflected in future rates and not accrue to the benefit of stockholders. System Energy considers the carrying amounts of 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. In addition, System Energy does not presently expect that performance of its obligations will be required in connection with certain off-balance sheet commitments and guarantees considered financial instruments. Due to this factor, and because of the related party nature of these commitments and guarantees, determination of fair value is not considered practicable. See Notes 5 and 7 for additional fair value disclosure. NOTE 2. RATE AND REGULATORY MATTERS FERC Audit In December 1990, FERC Division of Audits issued a report for System Energy for the years 1986 through 1988. The report recommended that System Energy (1) write off and not recover in rates approximately $95 million of Grand Gulf 1 costs included in utility plant related to certain System income tax allocation procedures (and System Energy's accounting resulting from certain allocated income tax charges) alleged to be inconsistent with FERC's accounting requirements and (2) compute refunds for the years 1987 to date to correct for over collections from AP&L, LP&L, MP&L, and NOPSI. In August 1992, FERC issued an opinion and order (August 4 Order) which found that System Energy overstated its Grand Gulf 1 utility plant account by approximately $95 million as indicated in FERC's report. The order required System Energy to make adjusting accounting entries and refunds, with interest, to AP&L, LP&L, MP&L, and NOPSI within 90 days from the date of the order. System Energy filed a Request for Rehearing, and in October 1992, FERC issued an order allowing additional time for its consideration of the request. In addition, it deferred System Energy's refund obligation until 30 days after FERC issues an order on rehearing. Should such refunds and adjusting entries be necessary, System Energy estimates that as of December 31, 1993, its net income would be reduced by approximately $152.3 million. This amount includes System Energy's potential refund obligation which is estimated to be $113.0 million (including interest) as of December 31, 1993. The ongoing effect of this order, if implemented, would be to reduce System Energy's revenues by approximately $19.8 million during the first twelve months following the write-off and by a comparable amount (but decreasing by approximately $0.4 million per year) in each subsequent year. If the August 4 Order is implemented, System Energy would need the consent of certain banks to temporarily waive the fixed charge coverage and equity ratio covenants in the letters of credit and reimbursement agreement related to the Grand Gulf 1 sale and leaseback transactions (see Note 7) in order to avoid violation of the covenant. System Energy has obtained the consent of the banks to waive these covenants, for the 12-month period beginning with the earlier of the write-off or the first refund, if the August 4 Order is implemented prior to December 31, 1994. The waiver is conditioned upon System Energy not paying any common stock dividends to Entergy Corporation until the equity ratio covenant is once again met. Absent a waiver, System Energy's failure to perform these covenants could cause a draw under the letters of credit and/or early termination of the letters of credit. If the letters of credit were not replaced in a timely manner, a default or early termination of System Energy's leases could result. System Energy believes that its consolidated income tax accounting procedures and related rate treatment are in compliance with SEC and FERC requirements and is vigorously contesting this issue. The ultimate resolution of this matter cannot be predicted. FERC Return on Equity Case In August 1992, FERC instituted an investigation of the return on equity (ROE) component of all formula wholesale rates for System Energy as well as AP&L, LP&L, MP&L, and NOPSI. Payments received by System Energy under the Unit Power Sales Agreement are its only source of operating revenue. Rates under the Unit Power Sales Agreement are based on System Energy's cost of service including a return on common equity which had been set at 13% (see below). In August 1993, Entergy and the state regulatory agencies that intervened in the proceeding reached an agreement (Settlement Agreement) in this matter. The Settlement Agreement, which was approved by FERC on October 25, 1993, provides that an 11.0% ROE will be included in the formula rates under the Unit Power Sales Agreement. The Unit Power Sales Agreement formula rate, including the 11.0% ROE component, will remain in effect without change for two years, until early August 1995. System Energy's refunds payable to AP&L, LP&L, MP&L, and NOPSI, which were due prospectively from November 3, 1992, were reflected as a credit to their bills in October 1993. These refunds decreased System Energy's 1993 revenues and net income by approximately $29.4 million and $18.2 million, respectively. FERC Complaint Case Settlement In February 1990, the APSC, the LPSC, the MPSC, the Mississippi Attorney General, and the City of New Orleans filed a complaint with FERC against System Energy and Entergy Services, Inc. (as agent for Entergy Corporation, AP&L, LP&L, MP&L, and NOPSI) alleging that the rates being charged to AP&L, LP&L, MP&L, and NOPSI by System Energy for capacity and energy from Grand Gulf 1 were not just and reasonable. This filing was consolidated with proceedings related to System Energy's decommissioning collections. In May 1991, a settlement was reached which, among other things (1) reduced System Energy's rate of return on common equity from 14% to 13% effective retroactively to April 1990 (pursuant to a subsequent settlement in the FERC Return on Equity Case - see above - the allowed rate of return was further reduced to 11% effective November 3, 1992); (2) imposed no ceiling for ratemaking purposes on System Energy's common equity ratio; (3) established a zero cash working capital allowance, effective retroactively to April 1990; (4) resolved the cost of service treatment of certain Grand Gulf 2 assets transferred to Grand Gulf 1; (5) set the amount to be collected in rates for the cost of decommissioning System Energy's 90% interest in Grand Gulf 1 at approximately $198 million in 1989 dollars (with a new study of these costs to be prepared and submitted to FERC on or before June 1, 1995); (6) increased System Energy's decommissioning expense collections from approximately $1.1 million to approximately $4.3 million per year, effective retroactively to June 1990, subject to a 5% annual inflation adjustment; and (7) provided for 1991 credits from System Energy to AP&L, LP&L, MP&L, and NOPSI totaling approximately $17 million relating to System Energy's rate treatment of the portions of Grand Gulf 1 sold and leased back. The settlement did not resolve income tax accounting issues raised in the complaint (see "FERC Audit" above). The settlement was approved by FERC in September 1991. Based on the settlement, System Energy credited in 1991 approximately $47.6 million in the aggregate (including interest) against its bills to AP&L, LP&L, MP&L, and NOPSI for capacity and energy from Grand Gulf 1. As a result of the FERC Complaint Case settlement, 1991 net income was reduced by approximately $36.0 million, of which approximately $15.8 million relates to billings in 1990. NOTE 3. INCOME TAXES Effective January 1, 1993, System Energy adopted SFAS 109. This new standard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that deferred tax balances be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 requires that regulated enterprises recognize adjustments resulting from implementation as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. A substantial majority of the adjustments required by SFAS 109 was recorded to deferred tax balance sheet accounts with offsetting adjustments to regulatory assets and liabilities. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. As a result of the adoption of SFAS 109, 1993 net income was increased by $0.4 million, assets were increased by $327.9 million, and liabilities were increased by $327.5 million. Income tax expense consisted of the following:
For the Years Ended December 31, -------------------------------- 1993 1992 1991 ------- ------- -------- (In Thousands) Current: Federal $59,049 $13,890 $(31,900) State 3,671 6,786 5,052 ------- ------- -------- Total 62,720 20,676 (26,848) ------- ------- -------- Deferred - net: Liberalized depreciation 46,600 43,873 45,551 Nuclear fuel 2,706 (3,299) (2,927) Capitalized interest (456) (1,402) (1,441) Taxes capitalized (929) (935) (572) Decontamination and decommissioning fund 5,601 - - Bond reacquisition (787) 852 (1,857) Sale and leaseback (4,057) (4,122) (4,044) Other (2,394) 3,088 2,458 ------- ------- -------- Total 46,284 38,055 37,168 ------- ------- -------- Investment tax credit adjustments - net (30,452) 30,123 63,256 ------- ------- -------- Recorded income tax expense $78,552 $88,854 $73,576 ======= ======= ======== Charged to operations $83,412 $93,438 $81,302 Credited to other income (4,859) (4,584) (7,726) ------- ------- -------- Recorded income tax expense 78,553 88,854 73,576 Income taxes applied against the debt - 253 352 component of AFUDC ------- ------- -------- Total income taxes $78,553 $89,107 $73,928 ======= ======= ========
Total income taxes differ from the amounts computed by applying the statutory federal income tax rate to income or loss before taxes. The reasons for the differences were:
For the Years Ended December 31, ------------------------------------------------------ 1993 1992 1991 ----------------- --------------- --------------- % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income -------- ------ ------- ------- ------- ------ (Dollars in Thousands) Computed at statutory rate $60,368 35.0 $74,458 34.0 $60,587 34.0 Increases (reductions) in tax resulting from: Depreciation 12,839 7.4 11,520 5.3 8,343 4.7 State income taxes net of federal income tax effect 6,778 3.9 8,380 3.8 6,084 3.4 Amortization of investment tax credits (3,759) (2.2) (3,865) (1.8) (1,928) (1.1) Other - (net) 2,327 1.4 (1,639) (0.7) 490 0.3 ------- ---- ------- ---- ------- ---- Recorded income tax expense 78,553 45.5 88,854 40.6 73,576 41.3 Income taxes applied against the debt component of AFUDC - - 253 0.1 352 0.2 ------- ---- ------- ---- ------- ---- Total income taxes $78,553 45.5 $89,107 40.7 $73,928 41.5 ======= ==== ======= ==== ======= ====
Significant components of System Energy's net deferred tax liabilities as of December 31, 1993, were (in thousands): Deferred tax liabilities: Net regulatory assets $(425,318) Plant related basis differences (552,782) Other (16,343) --------- Total $(994,443) ========= Deferred tax assets: Sale and leaseback $142,850 Accumulated deferred investment tax credit 43,547 Alternative minimum tax credit 20,452 Recoverable income tax 92,689 Other 11,964 -------- Total $311,502 ======== Net deferred tax liabilities $(682,941) ========= Recoverable income taxes include the tax effects of the substantial loss generated in September 1989 by the Grand Gulf 2 write-off. The loss increased System Energy's tax net operating loss carryforward to a total of approximately $265.5 million as of December 31, 1993, which may be utilized in the future to offset taxable income. If not utilized to offset Federal taxable income, income tax benefits related to the net operating loss carryforwards will expire in the years 2004 through 2007. In connection with an Internal Revenue Service (IRS) audit of Entergy's 1988, 1989, and 1990 consolidated federal income tax returns, the IRS is proposing that adjustments be made to the Grand Gulf 2 abandonment loss deduction claimed on Entergy's 1989 consolidated federal income tax return. If any such adjustments are necessary, the effect on System Energy's net income should be immaterial. Entergy intends to contest the proposed adjustments if finalized by the IRS. The outcome of such proceedings cannot be predicted at this time. The alternative minimum tax (AMT) credit at December 31, 1993, was $20.5 million. This AMT credit can be carried forward indefinitely and will reduce System Energy's federal income tax liability in the future. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized System Energy to effect short-term borrowings up to $125 million, subject to increase to as much as $238 million after further SEC approval. These authorizations are effective through November 30, 1994. In addition, System Energy can borrow from the Money Pool, subject to its maximum authorized level of short-term borrowings and the availability of funds. System Energy had no short-term borrowings or bank lines of credit as of December 31, 1993. NOTE 5. LONG-TERM DEBT The long-term debt of System Energy as of December 31, 1993 and 1992, was as follows: Maturities Interest Rates From To From To 1993 1992 ---- ---- ----- ----- --------- --------- (In Thousands) First Mortgage Bonds 1994 1998 6.0% 14%* $615,000 $555,000 1999 2003 8-1/4% 11% 130,000 235,000 2016 11-3/8% 90,319 90,319 Governmental Obligations** 2013 2016 8-1/4% 12-1/2% 416,600 416,600 Grand Gulf Lease Obligation, 7.02% (Note 8) 500,000 500,000 Unamortized Discount (10,005) (11,611) ---------- ---------- Total Long-Term Debt 1,741,914 1,785,308 Less Amount Due Within One Year 230,000 30,000 ---------- ---------- Long-Term Debt Excluding Amount Due Within $1,511,914 $1,755,308 One Year ========== ========== * The 14% series of $200 million is due 11/15/94. All other series are at interest rates within the range of 6% - 11.375%. ** Consists of pollution control bonds, certain series of which are secured by non-interest bearing first mortgage bonds. The fair value of System Energy's long-term debt, excluding Grand Gulf lease obligation, as of December 31, 1993 and 1992, was estimated to be $1,397.8 million and $1,442.7 million, respectively. Fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. For the years 1994, 1995, 1996, 1997, and 1998 System Energy has long-term debt maturities and sinking fund requirements (in millions) of $230, $135, $250, $10, and $70, respectively. System Energy has SEC authorization for the issuance and sale of up to $500 million of first mortgage bonds through December 31, 1994, (of which $220 million remained available as of December 31, 1993). In addition, System Energy has SEC authorization for the acquisition of not more than $500 million of its outstanding first mortgage bonds through December 31, 1994, all of which remained available as of December 31, 1993. NOTE 6. DIVIDEND RESTRICTIONS Various agreements relating to the long-term debt of System Energy restrict the payment of cash dividends or other distributions on its common stock. As of December 31, 1993, $152.7 million of System Energy's retained earnings were restricted against the payment of cash dividends or other distributions on common stock. On February 1, 1994, System Energy paid Entergy Corporation a $57.8 million cash dividend on common stock. NOTE 7. COMMITMENTS AND CONTINGENCIES Capital Requirements and Financing Construction expenditures (excluding nuclear fuel) for the years 1994, 1995, and 1996 are estimated to total $26 million, $22 million, and $23 million, respectively. System Energy will also require $615 million during the period 1994-1996 to meet long-term debt and preferred stock maturities and sinking fund requirements. System Energy plans to meet the above requirements with internally generated funds and cash on hand, supplemented by the issuance of long-term debt. See Note 5 for the possible issuance of new first mortgage bonds and the potential refunding, redemption, purchase, or other acquisition of certain series of outstanding first mortgage bonds. Capital Funds Agreement Entergy Corporation has agreed to arrange for or supply to System Energy sufficient amounts of capital to (1) maintain System Energy's equity capital at not less than 35% of System Energy's total capitalization (excluding short-term debt) and (2) continue commercial operation of Grand Gulf 1 and enable System Energy to pay its borrowings under any circumstances. In addition, under supplements to the Capital Funds Agreement assigning System Energy's rights as security for specific debt of System Energy, Entergy Corporation has agreed to make cash capital contributions to enable System Energy to make payments on such debt when due. System Energy has entered into various agreements with AP&L, LP&L, MP&L, and NOPSI, whereby AP&L, LP&L, MP&L, and NOPSI are obligated to purchase their respective entitlements of capacity (discussed below) and energy from System Energy's 90% ownership and leasehold 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's obligations under the Capital Funds Agreement, to cover any shortfalls from payments received from AP&L, LP&L, MP&L, and NOPSI under these agreements. Unit Power Sales Agreement System Energy has agreed to sell all of its 90% owned and leased share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this agreement are paid in consideration for the respective entitlements of AP&L, LP&L, MP&L, and NOPSI 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 approved by FERC, which most likely would occur after Grand Gulf 1's retirement from service. The monthly obligation for payments from AP&L, LP&L, MP&L, and NOPSI to System Energy is approximately $54 million. Availability Agreement AP&L, LP&L, MP&L, and NOPSI are individually obligated in accordance with stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 24.7%) to make payments or subordinated advances to System Energy 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 Grand Gulf 2 over 27 years, as discussed below. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Payments or advances under the Availability Agreement are only required if funds available to System Energy from all sources are less than the amount required under the Availability Agreement. 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 have ever been required. In 1989, the Availability Agreement was amended to provide that the write-off of approximately $900 million of Grand Gulf 2 costs would be amortized for Availability Agreement purposes over a period of 27 years, in order to avoid the need for payments under the Availability Agreement by AP&L, LP&L, MP&L, and NOPSI. Reallocation Agreement System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation Agreement relating to the sale of capacity and energy from the Grand Gulf Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and obligations with respect to the Grand Gulf Station under the Availability Agreement. FERC's decision allocating a portion of Grand Gulf 1 capacity and energy to AP&L supersedes the Reallocation Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect AP&L's obligation to System Energy's lenders under the assignments referred to in the preceding paragraph. AP&L would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual obligations. No payments of any amortization amounts will be required as 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 In December 1988, System Energy entered into two entirely separate, but identical, arrangements for the sales and leasebacks of an approximate aggregate 11.5% ownership interest in Grand Gulf 1 (see Note 8). 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 current letters of credit are effective until January 15, 1997. Under the provisions of the Reimbursement Agreement, as amended, related to the letters of credit, System Energy has agreed to a number of covenants relating to the maintenance of certain capitalization and fixed charge coverage ratios. System Energy agreed, during the term of the reimbursement agreement, to maintain its equity at not less than 33% of its adjusted capitalization (as defined in the Reimbursement Agreement to include certain amounts not included in capitalization for financial statement purposes). 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 (calculated, in each case, as specified in the reimbursement agreement) of at least 1.60. As of December 31, 1993, System Energy's equity approximated 34.74% of its adjusted capitalization, and its fixed charge coverage ratio was 1.88. Failure by System Energy to perform its covenants under the Reimbursement Agreement could give rise to a draw under the letters of credit and/or an early termination of the letters of credit. If such letters of credit were not replaced in a timely manner, a default under System Energy's related leases could result. Draws under the letters of credit must be repaid by System Energy within 5 days (or in some cases, 90 days) following the date of drawing. See Note 2 for information with respect to a FERC order that, if ultimately sustained and implemented, could cause System Energy to fall below the required equity and fixed charge coverage covenant levels. Nuclear Insurance The Price-Anderson Act limits public liability for a single nuclear incident to approximately $9.4 billion, as of December 31, 1993. System Energy has protection for this liability through a combination of private insurance (currently $200 million) and an industry assessment program. Under the assessment program, the maximum amount that would be required for each nuclear incident would be $79.28 million per reactor, payable at a rate of $10 million per licensed reactor per incident per year. As a co-licensee of Grand Gulf 1 with System Energy, SMEPA would share 10% of this obligation. System Energy has one licensed reactor. In addition, System Energy participates in a private insurance program which provides coverage for worker tort claims filed for bodily injury caused by radiation exposure. System Energy's maximum assessment under the program is an aggregate of approximately $3.1 million in the event losses exceed accumulated reserve funds. System Energy on behalf of itself and other insured interests (including other co-owners of Grand Gulf 1) is a member of certain insurance programs that provide coverage for property damage, including decontamination and premature decommissioning expense. As of December 31, 1993, System Energy was insured against such losses up to $2.7 billion with $250 million of this amount designated to cover any shortfall in the NRC required decommission trust funding. Under the property damage insurance programs, System Energy could be subject to assessments if losses exceed the accumulated funds available to the insurers. As of December 31, 1993, the maximum amount of such possible assessments to System Energy was $21.89 million. Under its agreement with System Energy, SMEPA would share in System Energy's obligation. The amount of property insurance presently carried by System Energy exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per site. NRC regulations provide that the proceeds of this insurance must be used, first, to place and maintain the reactor in a safe and stable condition 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. Spent Nuclear Fuel and Decommissioning Costs System Energy provides for estimated future disposal costs for spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. System Energy entered into a contract 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. The fees payable to the DOE may be adjusted in the future to assure full recovery. System Energy considers all costs incurred or to be incurred for the disposal of spent nuclear fuel to be proper components of nuclear fuel expense and recovers such costs in rates. Due to delays of the DOE's repository program for the acceptance of spent nuclear fuel, it is uncertain when shipments of spent fuel from System Energy will commence. In the meantime, System Energy is responsible for spent fuel storage. Current on-site spent fuel storage capacity at Grand Gulf 1 is estimated to be sufficient until 2004. Thereafter, System Energy will provide additional storage capacity at an estimated initial cost of $5 million to $10 million. In addition, approximately $3 million to $5 million will be required every four to five years subsequent to 2004 until DOE's repository begins accepting Grand Gulf 1 spent fuel. Decommissioning costs were estimated to approximate $248.7 million in 1989 dollars based on a 1989 decommissioning cost study. However, as a result of the FERC Complaint Case settlement, the amount to be collected in rates for the total cost of decommissioning System Energy's 90% interest in Grand Gulf 1 was set at approximately $198 million (in 1989 dollars). These collections are deposited in external trust funds which have a market value of $26.8 million and $20.1 million at December 31, 1993 and 1992, respectively. The accumulated decommissioning liability of $24.8 million has been recorded in other deferred credits as of December 31, 1993. Decommissioning expense in the amount of $4.9 million was recorded in 1993. System Energy regularly reviews and updates estimated decommissioning costs (an updated cost study is scheduled to be completed by mid-1994), and applications will be made to the appropriate regulatory authorities to reflect in rates any future change in projected decommissioning costs. The actual decommissioning costs may vary from the above estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment, and management believes that actual decommissioning costs are likely to be higher than the amounts presented above. The Energy Act has a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning of DOE's past uranium enrichment operations. The decontamination and decommissioning provisions will be used to set up a fund into which contributions from utilities and the federal government will be placed. System Energy's annual assessment, which will be adjusted annually for inflation, is approximately $1.3 million (in 1993 dollars) for approximately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortized. The cumulative liability of $16.8 million as of December 31, 1993, is recorded in other current liabilities and other non-current liabilities, according to FERC guidelines, and is offset in the financial statements by a regulatory asset, recorded as a deferred debit. System Fuels System Fuels entered into a revolving credit agreement with a bank that provides $45 million in borrowings to finance System Fuels' nuclear materials and services inventory. Should System Fuels default on its obligations under its credit agreement, AP&L, LP&L, and System Energy have agreed to purchase the nuclear materials and services financed under the agreement. NOTE 8. LEASES Nuclear Fuel Lease System Energy has an arrangement to lease nuclear fuel in an aggregate amount up to $105 million. The lessor finances its acquisition of nuclear fuel through a credit agreement and the issuance of notes. The credit agreement which was entered into in 1989 has been extended to February 1997 and the notes have varying remaining maturities of up to 4 years. It is expected that the credit arrangements will be extended or alternative financing will be secured by the lessor upon the maturity of the current arrangements. If the lessor cannot arrange for alternative financing upon maturity of its borrowings, System Energy must purchase nuclear fuel in an amount sufficient to enable the lessor to retire such borrowings. Lease payments are based on nuclear fuel use. Nuclear fuel lease expense of $36.2 million, $48.4 million, and $66.9 million (including interest of $5.1 million, $8.5 million, and $11.1 million) was charged to operations in 1993, 1992, and 1991, respectively. Sale and Leaseback Transactions On December 28, 1988, System Energy entered into two entirely separate, but identical, arrangements for the sales and leasebacks of an approximate aggregate 11.5% undivided ownership interest in Grand Gulf 1 for an aggregate cash consideration of $500 million. System Energy is leasing back the undivided interest on a net lease basis over a 26 1/2-year basic lease term. System Energy has options to terminate the leases and to repurchase the undivided interest in Grand Gulf 1 at certain intervals during the basic lease term. Further, at the end of the basic lease term, System Energy has an option to renew the leases or to repurchase the undivided interest in Grand Gulf 1. See Note 7 with respect to certain other terms of the transaction. On January 11, 1994, System Energy refinanced the debt portion of the sale and leaseback arrangements of the undivided portions of Grand Gulf 1. The secured lease obligation bonds of $356 million, 7.43% series due 2011 and $79 million, 8.2% series due 2014 will be indirectly secured by liens on, and a security interest in, certain ownership interests and the respective leases relating to Grand Gulf 1. See Note 7, incorporated herein by reference, for information on letters of credit maintained by System Energy for the benefit of the equity investors in the transactions. In accordance with SFAS No. 98, "Accounting for Leases," due to "continuing involvement" by System Energy, the sale and leaseback arrangements of the undivided portions of Grand Gulf 1, as described above, are required to be reflected for financial reporting purposes as financing transactions in System Energy's financial statements. The amounts charged to expense for financial reporting purposes include the interest portion of the lease obligations and depreciation of the plant. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as sales and leasebacks for rate-making purposes. The total of interest and depreciation expense exceeds the corresponding revenues realized during the early part of the lease term. Consistent with a recommendation contained in a FERC audit report, System Energy recorded as a deferred asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and is recording such difference as a deferred asset on an ongoing basis. The amount of this deferred asset was $71.2 million and $59.1 million as of December 31, 1993 and 1992, respectively. See Note 1 for further information regarding the accounting for the sale and leaseback transactions. As of December 31, 1993, System Energy had future minimum lease payments (reflecting an implicit rate of 7.02% after the above refinancing) as follows (in thousands): 1994 $ 17,423* 1995 42,464 1996 42,753 1997 42,753 1998 42,753 Years thereafter 845,573 ---------- Total $1,033,719 ========== * An additional $24 million payment was made in January 1994 prior to the refinancing of the debt portion of the sale and leaseback arrangements. NOTE 9. POSTRETIREMENT BENEFITS Pension Plan System Energy participates in a defined benefit pension plan sponsored by Entergy. Effective June 1990, all of System Energy's employees became employees of Entergy Operations. However, the employees still remain under System Energy's plan and no transfers of related pension liabilities and assets have been made. The pension plan, which covers substantially all of its employees, is noncontributory and provides pension benefits based on employees' credited service and average compensation, generally during the last five years before retirement. System Energy funds 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 plan consist primarily of common and preferred stocks, fixed income securities, interest in a money market fund, and insurance contracts. System Energy's 1993, 1992, and 1991 pension cost (credit), including amounts capitalized, included the following components:
For the Years Ended December 31, ------------------------------- 1993 1992 1991 ------ ------ ------ (In Thousands) Service cost - benefits earned during the period $2,045 $1,737 $1,327 Interest cost on projected benefit obligation 1,709 1,439 1,035 Actual return on plan assets (3,828) (2,070) (5,432) Net amortization and deferral 972 (587) 2,991 Other - - 17 ------ ------ ------ Net pension cost (income) $898 $519 $(62) ====== ====== ======
The funded status of System Energy's pension plan as of December 31, 1993 and 1992, was:
1993 1992 ------- ------- (In Thousands) Actuarial present value of accumulated pension plan benefits: Vested $16,728 $12,400 Non vested 615 428 ------- ------- Accumulated benefit obligation $17,343 $12,828 ======= ======= Plan assets at fair value $33,914 $30,167 Projected benefit obligation 28,933 20,759 ------- ------- Plan assets in excess of projected benefit obligation 4,981 9,408 Unrecognized prior service cost 879 925 Unrecognized transition asset (7,080) (7,677) Unrecognized net loss (gain) 1,802 (1,176) ------- ------- Accrued pension asset $582 $1,480 ======= =======
The significant actuarial assumptions used in computing the information above for 1993, 1992, and 1991 were as follows: weighted average discount rate, 7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in future compensation levels, 5.6%; and expected long-term rate of return on plan assets, 8.5%. Transition assets are being amortized over the average remaining service period of active participants. NOTE 10. TRANSACTIONS WITH AFFILIATES System Energy sells all of the capacity and energy from its share of Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI under rate schedules approved by FERC. Accordingly, all of System Energy's operating revenues consist of billings to AP&L, LP&L, MP&L, and NOPSI. MP&L provides a minimal amount of technical and advisory services and other miscellaneous services to System Energy. In addition, pursuant to a service agreement, System Energy receives technical and advisory services from Entergy Services, Inc. Charges from MP&L and Entergy Services, Inc. for technical, advisory and miscellaneous services amounted to approximately $12.3 million in 1993, $13.8 million in 1992, and $10.9 million in 1991. System Energy pays directly or reimburses Entergy Operations for the costs associated with operating Grand Gulf 1 (excluding nuclear fuel) which were approximately $151.3 million in 1993, $179 million in 1992, and $136 million in 1991. In addition, certain materials and services required for fabrication of nuclear fuel are acquired and financed by System Fuels and then sold to System Energy as needed. Charges for these materials and services, which represent additions to nuclear fuel, amounted to approximately $32.8 million in 1993, $13.7 million in 1992, and $28.9 million in 1991. NOTE 11. QUARTERLY FINANCIAL DATA (UNAUDITED) Operating results for the four quarters of 1993 and 1992 were: Operating Operating Net Revenue Income Income ---------- ---------- ------- (In Thousands) 1993: First Quarter $164,630 $76,331 $31,782 Second Quarter $153,527 $65,539 $21,268 Third Quarter (1) $155,071 $63,992 $23,040 Fourth Quarter $177,540 $66,340 $17,837 1992: First Quarter $177,466 $82,294 $33,198 Second Quarter $194,140 $81,688 $32,321 Third Quarter $177,464 $80,784 $32,584 Fourth Quarter $174,340 $78,410 $32,038 (1) The third quarter of 1993 reflects a nonrecurring decrease in operating revenues of $14.3 million and a decrease in operating income and net income of $8.7 million, net of tax, due to the settlement of the FERC Return on Equity Case (See Note 2).
SYSTEM ENERGY RESOURCES, INC. SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1993 1992 1991 1990 1989 ---------- ---------- ---------- ---------- ---------- (Dollars in Thousands) Operating revenues $ 650,768 $ 723,410 $ 686,664 $ 801,618 $ 837,307 Net income (loss) $ 93,927 $ 130,141 $ 104,622 $ 168,677 $ (655,524) Total assets $3,891,066 $3,672,441 $3,642,203 $3,883,241 $3,987,055 Long-term obligations (1) $1,536,593 $1,768,299 $1,707,470 $1,849,000 $2,229,022 Electric energy sales (Millions of KWH) 7,113 7,354 8,220 6,666 7,064
(1) Includes long-term debt (excluding current maturities) and noncurrent capital lease obligations. See Note 2 for information with respect to possible write-offs and refunds which may result from a decision issued by FERC and Note 3 for the effect of the accounting change for income taxes in 1993. 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, System Energy, AP&L, GSU, LP&L, MP&L, or NOPSI. PART III Item 10. Directors and Executive Officers Of The Registrants. All officers and directors listed below held the specified positions with their respective companies as of the date of filing this report. ENTERGY CORPORATION Directors Information required by this item concerning directors of Entergy Corporation is set forth under the heading "Election of Directors" contained in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held May 6, 1994, and is incorporated herein by reference. Name Age Position Period Officers Edwin Lupberger(a) 57 Chairman of the Board, Chief Executive Officer of Entergy Corporation 1985-Present Chairman of the Board, Chief Executive Officer of AP&L, LP&L, MP&L, and NOPSI 1993-Present Chairman of the Board, Chief Executive Officer of GSU 1994-Present Chairman of the Board of System Energy and Entergy Enterprises 1986-Present Chairman of the Board of Entergy Operations 1990-Present Chairman of the Board of Entergy Services 1985-Present Chief Executive Officer of Entergy Services and Entergy Enterprises 1991-Present Director of Entergy Enterprises 1984-Present Chief Executive Officer of Entergy Power, Inc., Entergy Power Development Corporation, and Entergy-Richmond Power Corporation 1993-Present President of Entergy Corporation 1985-1991 Chairman of the Board of Entergy Power 1990-1993 President of Entergy Services and Entergy Enterprises 1990-1991 Chairman of the Board of System Fuels 1986-1990 Director of System Fuels 1986-1992 Jerry L. Maulden 57 President and Chief Operating Officer of Entergy Corporation 1993-Present Vice Chairman and Chief Operating Officer of AP&L, GSU, LP&L, MP&L, and NOPSI 1993-Present Director of AP&L 1979-Present Director of GSU 1993-Present Director of LP&L and NOPSI 1991-Present Director of MP&L 1988-Present Director of Entergy Operations 1990-Present Director of System Energy 1987-Present Vice Chairman of Entergy Services 1992-Present Chairman of the Board of AP&L 1989-1993 Chief Executive Officer of AP&L 1979-1993 Chairman of the Board and Chief Executive Officer of LP&L and NOPSI 1991-1993 Chairman of the Board and Chief Executive Officer of MP&L 1989-1993 Group President, System Executive - Transmission, Distribution, and Customer Service of Entergy Corporation 1991-1993 Senior Vice President, System Executive - Arkansas/Mississippi/Missouri Division of Entergy Corporation 1988-1991 Director of System Fuels 1979-1992 Group President, System Executive - Transmission, Distribution, and Customer Service of Entergy Services 1991-1992 Director of Entergy Enterprises 1984-1991 Jerry D. Jackson 49 Executive Vice President - Finance and External Affairs of Entergy Corporation 1990-Present Executive Vice President - Finance and External Affairs, Secretary and Director of AP&L, LP&L, MP&L and NOPSI 1992-Present Executive Vice President - Finance and External Affairs of GSU 1993-Present President and Chief Administrative Officer of Entergy Services 1992-Present Secretary of Entergy Corporation 1991-Present Director of System Entergy 1993-Present Director of Entergy Services 1990-Present Executive Vice President - Finance and External Affairs of Entergy Services 1990-1992 Director of Entergy Power 1990-1992 President of Entergy Enterprises 1991-1992 Director of Entergy Enterprises 1990-1992 Senior Vice President, System Executive - Legal and External Affairs of Entergy Corporation and Entergy Services 1987-1990 Donald C. Hintz 51 Senior Vice President and Chief Nuclear Officer of Entergy Corporation 1993-Present Senior Vice President - Nuclear of AP&L 1990-Present Senior Vice President - Nuclear of GSU 1993-Present Senior Vice President - Nuclear of LP&L 1992-Present Director of AP&L, LP&L, NOPSI, System Energy, System Fuels, and Entergy Services 1992-Present Director of GSU and MP&L 1993-Present Chief Executive Officer and President of System Energy and Entergy Operations 1992-Present Director of Entergy Operations 1990-Present Chief Operating Officer and Executive Vice President of Entergy Operations 1990-1992 Group Vice President - Nuclear of LP&L 1990-1992 Chief Operating Officer and Executive Vice President of System Energy 1989-1990 Senior Vice President - Power Production of Wisconsin Public Service 1988-1989 Donald Hunter 60 Senior Vice President of Entergy Corporation 1992-Present Senior Vice President and Director of Entergy Services 1992-Present Senior Vice President - Fossil Operations of AP&L, LP&L, MP&L, NOPSI, and Entergy Services 1990-1992 President and Chief Operating Officer of LP&L 1989-1990 Chief Operating Officer of NOPSI 1989-1990 Executive Vice President of LP&L and NOPSI 1987-1990 President, Chief Executive Officer, and Director of System Fuels 1990-1992 Director of Entergy Enterprises 1991-1992 Jack L. King(b) 54 Senior Vice President of Entergy Corporation 1987-Present Chief Operating Officer, President, and Director of Entergy Enterprises 1992-Present Chairman of the Board of Entergy Systems and Service, Inc., Entergy Argentina S.A., and Entergy S.A. 1992-Present Chief Executive Officer and President of Entergy Power Development Corporation 1992-1993 Director of AP&L, LP&L, MP&L, NOPSI, Entergy Power, and Entergy Services 1990-1992 Chairman of the Board of Entergy Power 1993-1993 Chief Executive Officer of Entergy Power 1990-1993 Chairman of the Board, Chief Executive Officer, and President of Entergy- Richmond Power Corporation 1992-1993 President of Entergy Power 1990-1993 Executive Vice President - Operations of Entergy Services 1990-1992 Chairman of the Board of System Fuels 1990-1992 Senior Vice President, System Executive - Operations of Entergy Services 1987-1990 Chief Executive Officer and President of Entergy Systems and Service, Inc., Entergy Argentina S.A., and Entergy S.A. 1992-1993 Gerald D. McInvale 50 Senior Vice President and Chief Financial Officer of Entergy Corporation, AP&L, LP&L, MP&L, NOPSI, System Energy, Entergy Operations, Entergy Services, and Entergy Enterprises 1991-Present Senior Vice President and Chief Financial Officer of GSU 1993-Present Senior Vice President, Chief Financial Officer, Director, and Treasurer of Entergy Power 1993-Present Director of System Fuels 1992-Present Treasurer of Entergy Enterprises 1992-Present Director of Entergy Systems and Service, Inc. 1993-Present Vice President, Director, and Treasurer of Entergy Power Development Corporation and Entergy-Richmond Power Corporation 1993-Present President - Executive Information Strategies (consulting firm), Dallas, Texas 1990-1991 Senior Vice President and Chief Financial Officer of Frito-Lay, Inc. (Subsidiary of PepsiCo, Inc.) Dallas, Texas 1987-1990 Michael G. Thompson 53 Senior Vice President and Chief Legal Officer of Entergy Corporation and Entergy Services 1992-Present Senior Vice President, Chief Legal Officer, Director, and Secretary of Entergy Power 1993-Present Senior Vice President, Chief Legal Officer, and Secretary of Entergy Enterprises 1992-Present Vice President, Director, and Secretary of Entergy Power Development Corporation and Entergy-Richmond Power Corporation 1992-Present Director of Entergy Systems and Service, Inc. 1992-Present Secretary of Entergy Systems and Service, Inc. 1993-Present Assistant Secretary of Entergy Corporation 1993-Present Senior Partner of Friday, Eldredge & Clark (law firm) 1987-1992 S. M. Henry Brown, Jr. 55 Vice President - Federal Governmental Affairs of Entergy Corporation and Entergy Services 1989-Present Director - Public Affairs - Carolina Power & Light Company 1988-1989 Charles L. Kelly 57 Vice President - Corporate Communications and Public Relations of Entergy Corporation 1992-Present Vice President - Corporate Communications and Public Relations of Entergy Services 1991-Present Vice President - Corporate Communications of AP&L 1981-1991 Lee W. Randall 44 Vice President and Chief Accounting Officer of Entergy Corporation, AP&L, LP&L, MP&L, NOPSI, System Energy, Entergy Operations, and Entergy Services 1991-Present Vice President, Chief Accounting Officer, and Assistant Secretary of GSU 1993-Present Assistant Secretary of AP&L, LP&L, MP&L, NOPSI, Entergy Operations, and Entergy Services 1991-Present Senior Vice President - Finance and Administration and Chief Financial Officer of AP&L 1988-1991 Secretary of AP&L 1989-1991 Assistant Treasurer of AP&L 1988-1991 Glenn E. Harder 43 Treasurer of Entergy Corporation and Entergy Services 1993-Present Vice President - Financial Strategies and Treasurer of AP&L, LP&L, MP&L, NOPSI, System Energy, and Entergy Operations 1993-Present Vice President - Financial Strategies and Treasurer of GSU 1993-Present Vice President - Financial Strategies of Entergy Services 1991-Present Treasurer and Assistant Secretary of System Fuels 1993-Present Vice President - Administrative Services and Regulatory Affairs of System Energy 1991-1993 Vice President - Accounting and Treasurer of System Energy 1986-1991 Vice President - Accounting and Treasurer of Entergy Operations 1990-1991 Vice President - Administrative Services and Regulatory Affairs of Entergy Operations 1991-1991 ARKANSAS POWER & LIGHT COMPANY Directors Michael B. Bemis(c) 46 Executive Vice President - Customer Service and Director of AP&L, LP&L, MP&L, and NOPSI 1992-Present Executive Vice President - Customer Service of GSU 1993-Present Executive Vice President - Customer Service of Entergy Services 1992-Present Director of System Fuels 1992-Present President and Chief Operating Officer of LP&L and NOPSI 1992-1992 President and Chief Operating Officer of MP&L 1989-1991 Secretary of MP&L 1991-1991 John A. Cooper, Jr.(d) 55 Director of Entergy Corporation 1985-Present Director of AP&L 1992-Present Chairman of the Board of Cooper Communities, Inc., Bella Vista, AR 1990-Present Chairman of the Board of COFAM, Inc. 1991-Present Cathy Cunningham(e) 48 Director of AP&L 1983-Present Self employed in real estate development and contracting, Heber Springs, West Helena and Helena, AR 1982-Present Richard P. Herget, Jr.(f) 54 Director of AP&L 1981-Present Vice Chairman of Rebsamen Insurance, Little Rock, AR 1992-Present Managing Director of Marsh & McLennan, Inc. (Insurance) 1987-1992 Tommy H. Hillman(g) 57 Director of AP&L 1985-Present President of Winrock Farms, Inc. (Agriculture), Carlisle, AR 1980-Present Chairman of Riceland Foods, Inc. 1985-1993 Donald C. Hintz 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Kaneaster Hodges, Jr.(h) 55 Director of Entergy Corporation 1984-Present Director of AP&L 1981-Present Attorney-at-Law, Sole Practitioner, Newport, AR 1981-Present Jerry D. Jackson 49 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. R. Drake Keith 58 President and Director of AP&L 1989-Present Chief Operating Officer of AP&L 1989-1992 Secretary of AP&L 1991-1992 Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Dr. Raymond P. Miller, Sr.(i) 57 Director of AP&L 1982-Present Physician, Little Rock, AR 1970-Present Roy L. Murphy(j) 66 Director of AP&L 1977-Present Chairman of the Board of Mid-South Engineering Co. (consulting engineers), Hot Springs, AR 1969-Present President of Mid-South Engineering Co. 1969-1991 William C. Nolan, Jr.(k) 54 Director of AP&L 1971-Present Attorney-at-Law, Nolan & Alderson, Attorneys, El Dorado, AR 1969-Present Robert D. Pugh(l) 65 Director of Entergy Corporation 1977-Present Director of AP&L 1971-Present Director of Entergy Operations 1990-Present Chairman of the Board of Portland Bank and Portland Bankshares, Inc. 1991-Present Chairman of the Board of Portland Gin Company (Agricultural and Agri-Business) Portland, AR 1981-Present Woodson D. Walker(m) 43 Director of AP&L 1985-Present Attorney-at-Law, Walker, Roaf, Campbell, Ivory & Dunklin, P.A., Little Rock, AR 1977-Present Gus B. Walton, Jr. 52 Director of AP&L 1981-Present Vice President, Secretary, and part owner of Frederick Poe Travel Service, Inc. (Travel Service), Little Rock, AR 1983-Present Michael E. Wilson(n) 51 Director of AP&L 1980-Present Chairman of the Board and Chief Executive Officer of Lee Wilson & Company (Agricultural and Agri-Business), Wilson, AR 1987-Present President and Director of Delta Valley & Southern Railway Company 1979-Present Officers Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. R. Drake Keith 58 See the information under the AP&L Directors Section above, incorporated herein by reference. Michael B. Bemis 46 See the information under the AP&L Directors Section above, incorporated herein by reference. Jerry D. Jackson 49 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Frank F. Gallaher 48 Executive Vice President - Fossil Operations of AP&L, LP&L, MP&L, NOPSI, and Entergy Services 1993-Present President of GSU 1994-Present Director of GSU 1993-Present Chairman of the Board of System Fuels 1992-Present Director of Entergy Services 1992-Present Senior Vice President - Fossil Operations of AP&L, LP&L, MP&L, NOPSI, and Entergy Services 1992-1993 Vice President and Chief Engineer of MP&L 1985-1990 Vice President - System Planning of Entergy Services 1990-1992 Donald C. Hintz 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Gerald D. McInvale 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael R. Niggli 44 Senior Vice President - Marketing of AP&L, GSU, LP&L, MP&L, NOPSI, and Entergy Services 1993-Present Vice President - Customer Service of LP&L, NOPSI, and Entergy Services 1993-1993 Vice President - Strategic Planning of Entergy Services 1990-1992 Vice President - Fuels Management of Entergy Services 1988-1990 Vice President and Director of Entergy Enterprises 1991-1992 Cecil L. Alexander(o) 58 Vice President - Governmental Affairs of AP&L 1991-Present Vice President - Public Affairs of AP&L 1989-1991 Vice President - Governmental Relations of AP&L 1985-1989 Glenn E. Harder 43 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Richard J. Landy 48 Vice President - Human Resources and Administration of AP&L, LP&L, MP&L, NOPSI, Entergy Services, and EOI 1991-Present Vice President - Human Resources and Administration of GSU 1993-Present Vice President - Human Resources and Administration of System Energy 1986-1990 Vice President - Human Resources and Administration of Entergy Operations 1990-1991 James S. Pilgrim 58 Vice President - Customer Service of AP&L 1994-Present Vice President - Northern Region, Operations Customer Service of Entergy Services 1993-Present Director, Central Region, TDCS Customer Service 1993-1994 Central Division Manager of MP&L 1991-1993 Northern Division Manager of MP&L 1988-1991 Lee W. Randall 44 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. C. Hiram Walters 57 Vice President - Customer Service of AP&L 1993-Present Vice President - Customer Service of LP&L 1994-Present Vice President - Central Region of Entergy Services 1993-Present Vice President - Customer Service of MP&L 1984-1991 Senior Vice President - Customer Service of Entergy Services 1991-1992 GULF STATES UTILITIES COMPANY Directors Robert H. Barrow (p) 72 Director of GSU 1984-Present General of United States Marine Corps. 1969-Present Frank F. Gallaher 48 See the information under the AP&L Officers Section above, incorporated herein by reference. Frank W. Harrison Jr.(q) 65 Director of GSU 1990-Present Independent Geologist, Lafayette, LA 1959-Present Donald C. Hintz 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. William F. Klausing 65 Director of GSU 1991-Present Senior Vice President and Manager of Irving Trust Company's Public Utilities Division, New York, NY 1985-1989 Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Paul W. Murrill(r) 59 Director of Entergy Corporation 1993-Present Director of GSU 1978-Present Director of Entergy Operations 1994-Present Eugene H. Owen(s) 64 Director of Entergy Corporation 1993-Present Director of GSU 1989-Present Chairman of the Board and Chief Executive Officer of Owen and White, Inc. (engineering consulting firm) 1956-Present Chairman of the Board and President of Utility Holdings, Inc., (holding company for Baton Rouge Water Company, Parish Water Company and Louisiana Water Company) Baton Rouge, LA 1986-Present President of Parish Water Company, Inc., Baton Rouge, LA 1987-Present President of Baton Rouge Water Company, Baton Rouge, LA 1987-Present President of Louisiana Water Company, Baton Rouge, LA 1982-Present M. Bookman Peters 60 Director of GSU 1990-Present Certified Public Accountant 1961-Present Financial Consultant 1990-Present Chairman of the Board and Chief Executive Officer of First City Texas-Bryan, N.A., Bryan, TX 1962-1990 Regional Director of First City Bancorporation of Texas, Inc. 1981-1990 Monroe J. Rathbone, Jr.(t) 68 Director of GSU 1975-Present General Surgeon 1958-Present Medical Director of Our Lady of the Lake Regional Medical Center, Baton Rouge, LA 1983-Present Sam F. Segnar(u) 66 Director of GSU 1988-Present Chairman and Chief Executive Officer of Sam F. Segnar (Interests which include construction, development, heavy equipment, aviation, and insurance), The Woodlands, TX 1989-Present Chairman of the Board of Collecting Bank, N.A., Houston, TX 1989-1992 Bismark A. Steinhagen 59 Director of Entergy Corporation 1993-Present Director of GSU 1974-Present Chairman of the Board of Steinhagen Oil Company, Inc., (oil and gasoline distributor), Beaumont, TX 1984-Present Chairman of the Board of Starmart Holdings, Inc. 1991-Present James E. Taussig, II 57 Director of GSU 1975-Present Director of Varibus Corporation 1980-Present Director and President of Taussig Corporation (real estate development and investments), Lake Charles, LA 1978-Present Director and President of Taussig Properties Corporation, (real estate brokerage), Lake Charles, LA 1968-Present Chairman of the Board and Director of Calcasieu Financial Services Corporation, (consumer finance and mortgage lender) Lake Charles, LA 1978-Present Officers Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Frank F. Gallaher 48 See the information under the AP&L Officers Section above, incorporated herein by reference. Michael B. Bemis 46 See the information under the AP&L Directors Section above, incorporated herein by reference. Jerry D. Jackson 49 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Donald C. Hintz 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Gerald D. McInvale 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael R. Niggli 44 See the information under the AP&L Officers Section above, incorporated herein by reference. Leslie D. Cobb 59 Vice President and Secretary of GSU 1989-Present Director of GSG&T, Inc. 1990-Present Director of Prudential Oil and Gas, Inc. 1988-Present Secretary of GSG&T, Inc. 1987-Present Secretary of Prudential Oil and Gas, Inc. 1988-Present Secretary-Treasurer of Southern Gulf Railway Co. 1993-Present Corporate Secretary of GSU 1979-1989 Glenn E. Harder 43 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Richard J. Landy 48 See the information under the AP&L Officers Section above, incorporated herein by reference. Lee W. Randall 44 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Calvin J. Hebert 59 Vice President - Customer Service of GSU 1993-Present Senior Vice President - Division Operations of GSU 1992-1993 Senior Vice President - External Affairs of GSU 1986-1992 Bobby J. Willis 57 Vice President and Controller of GSU 1985-Present President and Treasurer of Prudential Oil & Gas, Inc. 1987-Present President and Controller of Varibus Corporation 1986-Present Director of GSG&T, Inc. 1992-Present Director of Prudential Oil & Gas, Inc. 1987-Present Director of Varibus Corporation 1986-Present LOUISIANA POWER & LIGHT COMPANY Directors Michael B. Bemis 46 See the information under the AP&L Directors Section above, incorporated herein by reference. John J. Cordaro 60 President and Director of LP&L and NOPSI 1992-Present Group Vice President - External Affairs of LP&L and NOPSI 1989-1992 Donald C. Hintz 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. William K. Hood(v) 43 Director of LP&L 1989-Present Manages the daily operations of four automobile dealerships and various related companies 1972-Present Jerry D. Jackson 49 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Tex R. Kilpatrick 60 Director of LP&L 1972-Present Chairman and Chief Executive Officer of Central American and Ashley Life Insurance Company 1993-Present President of Central American Life Insurance Company, West Monroe, LA 1957-Present Joseph J. Krebs, Jr. 63 Director of LP&L 1983-Present Chairman and Chief Executive Officer of J. J. Krebs & Sons, Inc. (Engineering, Planning and Surveying) 1977-Present Director of NOPSI 1983-1992 Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. H. Duke Shackelford(w) 67 Director of Entergy Corporation 1981-Present Director of LP&L 1972-Present Planter 1950-Present President of Shackelford Company, Inc. 1973-Present President of Bonita Gin, Inc. 1991-Present President of Louisiana Cotton Warehouse Co., Inc. (Agricultural and Agri-Business) 1978-Present President of Shackelford Gin, Inc. 1976-1991 Chairman, Union Oil Mill, Inc. (Agricultural and Agri-Business), Bonita, LA 1981-1989 Wm. Clifford Smith(x) 58 Director of Entergy Corporation 1983-Present Director of LP&L 1981-Present Director of Entergy Operations 1990-Present President of T. Baker Smith & Son, Inc. (Consultants-Civil Engineer and Land Survey) 1962-Present Officers Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. John J. Cordaro 60 See the information under the LP&L Directors Section above, incorporated herein by reference. Michael B. Bemis 46 See the information under the AP&L Directors Section above, incorporated herein by reference. Jerry D. Jackson 49 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Frank F. Gallaher 48 See the information under the AP&L Officers Section above, incorporated herein by reference. Donald C. Hintz 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Gerald D. McInvale 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael R. Niggli 44 See the information under the AP&L Officers Section above, incorporated herein by reference. Shelton G. Cunningham, Jr. 53 Vice President - Rates and Regulatory Affairs of LP&L and NOPSI 1991-Present Vice President - Entergy Corporation/GSU Transition Regulatory Affairs of Entergy Services 1993-Present Vice President - Regulatory Affairs of Entergy Services 1992-1993 Senior Vice President - Rates and Regulatory Affairs of LP&L and NOPSI 1989-1991 Richard C. Guthrie 51 Vice President - Governmental Affairs of LP&L and NOPSI 1992-Present Vice President - Public Affairs of LP&L and NOPSI 1986-1992 Glenn E. Harder 43 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Richard J. Landy 48 See the information under the AP&L Officers Section above, incorporated herein by reference. James D. Bruno 54 Vice President - Customer Service of LP&L and NOPSI 1994-Present Vice President - Metro Region of Entergy Services 1993-Present Region Director - Metro Region 1991-1993 Vice President - Division Manager - Orleans Division 1988-1991 William E. Colston 58 Vice President - Customer Service of LP&L 1993-Present Vice President - Southern Region of Entergy Services 1993-Present Vice President - Division Manager of LP&L 1988-1991 Regional Director of LP&L 1991-1992 Lee W. Randall 44 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. C. Hiram Walters 57 See the information under the AP&L Officers Section above, incorporated herein by reference. MISSISSIPPI POWER & LIGHT COMPANY Directors Michael B. Bemis 46 See the information under the AP&L Directors Section above, incorporated herein by reference. Frank R. Day(y) 62 Director of MP&L 1981-Present Chairman of the Board and Chief Executive Officer of Trustmark National Bank, Jackson, MS 1981-Present Chairman of the Board and Chief Executive Officer of Trustmark Corporation (Bank Holding Company) 1981-Present Chairman of the Board of Smith County Bank, Taylorsville, MS 1972-Present Chairman of the Board of the Bank of Edwards, Edwards, MS 1985-1992 President of Smith County Bank, Taylorsville, MS 1972-1993 John O. Emmerich, Jr. 64 Director of MP&L 1989-Present Editor & Publisher of Greenwood Commonwealth, Greenwood, MS 1973-Present Norman B. Gillis, Jr.(z) 66 Director of MP&L 1966-Present Attorney-at-Law, Gillis & Gillis, Attorneys, McComb, MS 1950-Present Donald C. Hintz 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry D. Jackson 49 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Robert E. Kennington, II 61 Director of MP&L 1974-Present Chairman of the Board of Grenada Sunburst System Corporation (Bank Holding Company) and of Sunburst Bank, Grenada, MS 1975-Present Chief Executive Officer of Grenada Sunburst System Corporation (Bank Holding Company) and of Sunburst Bank, Grenada, MS 1975-1992 Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Donald E. Meiners(aa) 58 President and Director of MP&L 1992-Present Senior Vice President, System Executive - Services Division of Entergy Corporation 1988-1990 President and Chief Operating Officer of LP&L and NOPSI 1990-1991 Chief Operating Officer and Secretary of MP&L 1992-1992 President and Chief Executive Officer of Entergy Services, System Fuels, and Entergy Enterprises 1987-1990 John N. Palmer, Sr.(bb) 59 Director of Entergy Corporation 1992-Present Director of MP&L 1987-Present Chairman of the Board and Chief Executive Officer of Mobile Telecommunication Technologies Corporation 1989-Present Dr. Clyda S. Rent 52 Director of MP&L 1991-Present President of Mississippi University for Women, Columbus, MS 1989-Present Vice President of Queens College, Charlotte, NC 1984-1989 E. B. Robinson, Jr .(cc) 52 Director of MP&L 1984-Present Chairman of the Board and Chief Executive Officer of Deposit Guaranty Corporation and Deposit Guaranty National Bank, Jackson, MS 1984-Present Dr. Walter Washington 70 Director of Entergy Corporation and MP&L 1977-Present President of Alcorn State University, Lorman, MS 1969-Present Robert M. Williams, Jr. 58 Director of MP&L 1976-Present Partner - Reeves-Williams (Building and Development) Southhaven, MS 1969-Present Officers Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Donald E. Meiners 58 See the information under the MP&L Directors Section above, incorporated herein by reference. Michael B. Bemis 46 See the information under the AP&L Directors Section above, incorporated herein by reference. Jerry D. Jackson 49 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Frank F. Gallaher 48 See the information under the AP&L Officers Section above, incorporated herein by reference. Gerald D. McInvale 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael R. Niggli 44 See the information under the AP&L Officers Section above, incorporated herein by reference. Bill F. Cossar 55 Vice President - Governmental Affairs of MP&L 1987-Present Johnny D. Ervin 44 Vice President - Customer Service of MP&L 1991-Present Vice President - Eastern Region of Entergy Services 1993-Present Director of Entergy Enterprises 1991-1992 Vice President - Marketing of LP&L and NOPSI 1990-1991 Vice President - Division Manager of LP&L 1988-1990 Glenn E. Harder 43 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Richard J. Landy 48 See the information under the AP&L Officers Section above, incorporated herein by reference. Lee W. Randall 44 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. NEW ORLEANS PUBLIC SERVICE INC. Directors Michael B. Bemis 46 See the information under the AP&L Directors Section above, incorporated herein by reference. James M. Cain(dd) 60 Director of NOPSI 1978-Present Vice Chairman of Entergy Corporation and Entergy Services 1991-1993 Director of LP&L 1978-1993 Director of System Energy 1978-1993 Director of Entergy Operations 1990-1993 Director of Systems Fuels 1978-1993 Senior Vice President, System Executive, Louisiana Division of Entergy Corporation 1988-1991 Chairman of the Board of LP&L 1989-1991 Chief Executive Officer of LP&L 1983-1991 Chairman of the Board of NOPSI 1990-1991 Chief Executive Officer of NOPSI 1989-1990 President of NOPSI 1978-1990 Chief Administrative Officer of Entergy Services 1991-1992 Director of Entergy Services 1975-1993 Director of Entergy Enterprises 1984-1991 John J. Cordaro 60 See the information under the LP&L Directors Section above, incorporated herein by reference. Brooke H. Duncan(ee) 70 Director of Entergy Corporation 1983-Present Director of NOPSI 1967-Present Director of Entergy Operations 1992-Present President and Chief Executive Officer of Jno. Worner Hardware, Inc. 1980-Present President of The Montegut Corporation (formerly The Foster Company Inc., a canvas fabricator) 1966-Present Dr. Norman C. Francis(ff) 62 Director of NOPSI 1992-Present President of Xavier University of Louisiana 1968-Present Donald C. Hintz 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry D. Jackson 49 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Anne M. Milling 53 Director of NOPSI 1991-Present John B. Smallpage 68 Director of NOPSI 1969-Present Chairman of the Board and Secretary of Donovan Marine, Inc., New Orleans, LA 1970-Present Charles C. Teamer, Sr.(gg) 60 Director of NOPSI 1978-Present Vice President for Fiscal Affairs of Dillard University, New Orleans, LA 1965-Present Officers Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. John J. Cordaro 60 See the information under the LP&L Directors Section above, incorporated herein by reference. Michael B. Bemis 46 See the information under the AP&L Directors Section above, incorporated herein by reference. Jerry D. Jackson 49 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Frank F. Gallaher 48 See the information under the AP&L Officers Section above, incorporated herein by reference. Gerald D. McInvale 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael R. Niggli 44 See the information under the AP&L Officers Section above, incorporated herein by reference. James D. Bruno 54 See the information under the LP&L Officers Section above, incorporated herein by reference. Shelton G. Cunningham, Jr. 53 See the information under the LP&L Officers Section above, incorporated herein by reference. Richard C. Guthrie 51 See the information under the LP&L Officers Section above, incorporated herein by reference. Glenn E. Harder 43 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Richard J. Landy 48 See the information under the AP&L Officers Section above, incorporated herein by reference. Lee W. Randall 44 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. SYSTEM ENERGY Directors Donald C. Hintz 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry D. Jackson 49 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Officers Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Donald C. Hintz 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Gerald D. McInvale 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Glenn E. Harder 43 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Lee W. Randall 44 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Joseph L. Blount 47 Secretary of System Energy and Entergy Operations 1991-Present Vice President Legal and External Affairs of Entergy Operations 1990-1993 Vice President Legal and External Affairs of System Energy 1989-1990 Assistant Secretary for System Energy 1987-1991 General Counsel and Assistant to President of System Energy 1986-1989 Assistant Secretary for Entergy Operations 1990-1991 (a) Mr. Lupberger is a director of First Commerce Corporation, New Orleans, LA, International Shipholding Corporation, New Orleans, LA, and First National Bank of Commerce, New Orleans, LA. (b) Mr. King is a director of First Pacific Networks, Inc. ("FPN") and Systems and Service International, Inc. ("SASI"). Entergy Enterprises owns 9.95% of the common stock of FPN, and a subsidiary of Entergy Enterprises, Entergy Systems and Service, Inc., owns 9.95% of the common stock of SASI. (c) Mr. Bemis is a director of Deposit Guaranty National Bank, Jackson, MS and Deposit Guaranty Corporation, Jackson, MS. (d) Mr. Cooper is a director of Wal-Mart Stores, Inc., Bentonville, AR and J. B. Hunt Transport Services, Inc., Lowell, AR. (e) Ms. Cunningham is a director of First National Bank of Phillips County, Helena, AR. (f) Mr. Herget is a director of Union National Bank and Union Modern Mortgage Corporation, Little Rock, AR. (g) Mr. Hillman is a director of Riceland Foods, Inc., Hazen, AR, Hazen First State Bank, Hazen, AR, Bank of North Arkansas, Melbourne, AR, First National Bank of Stuttgart, Stuttgart, AR, Investark Bankshares, Inc., Stuttgart, AR, and Carlisle Bankshares, Inc., Carlisle, AR. (h) Mr. Hodges is a director of Worthen Banking Corporation, Little Rock, AR and Newport Federal Savings and Loan Association, Newport, AR. (i) Dr. Miller is a director of Worthen Banking Corporation, Little Rock, AR. (j) Mr. Murphy is a director of Arkansas Bank & Trust Company, Hot Springs, AR. (k) Mr. Nolan is a director of First Financial Bank of El Dorado, El Dorado, AR, First Commercial Corporation, Little Rock, AR, and Murphy Oil Corporation, El Dorado, AR. (l) Mr. Pugh is a director of Portland Bank and Portland Bankshares, Inc., Portland, AR and Worthen National Bank of Pine Bluff, Pine Bluff, AR. (m) Mr. Walker is a director of Worthen Bank and Trust Company, Little Rock, AR. (n) Mr. Wilson is a director of American State Bank, Osceola, AR. (o) Mr. Alexander is a director of First National Bank of Cleburne County, Heber Springs, AR. (p) General Barrow is a director of United Companies Financial Corporation, Baton Rouge, LA. (q) Mr. Harrison is a director of Premier Bancorp, Inc., Baton Rouge, LA, Premier Bank, Baton Rouge, LA, and American Liberty Financial Corporation, Baton Rouge, LA. (r) Dr. Murrill is a director of First Mississippi Corporation, Jackson, MS, Tidewater, Inc., New Orleans, LA, FirstMiss Gold, Inc., Reno, NV, Piccadilly Cafeterias, Baton Rouge, LA, Howell Corporation, Houston, TX, and Zygo Corporation, Middlefield, CT. (s) Mr. Owen is a director of Premier Bancorp, Inc., Baton Rouge, LA and Premier Bank, Baton Rouge, LA. (t) Dr. Rathbone, Jr. is a director of American Liberty Financial Corporation and Insurance Company, Baton Rouge, LA. . (u) Mr. Segnar is a director of Hartmarx Corporation, Chicago, IL, Textron Inc., Providence, RI, Seagull Energy Corporation, Houston, TX, Mapco, Inc., Tulsa, OK, and Pro-Bank, Woodlands and Conroe, TX. (v) Mr. Hood is a director of First Guaranty Bank, Hammond, LA. (w) Mr. Shackelford is a director of Bastrop National Bank, Bastrop, LA. (x) Mr. Smith is a director of American Bank & Trust Company of Houma, Houma, LA and American Bancshares of Houma, Inc., Houma, LA. (y) Mr. Day is a director of Trustmark National Bank, Jackson, MS, Trustmark Corporation, Jackson, MS, Smith County Bank, Taylorsville, MS, Bank of Edwards, Edwards, MS, Bell South Telecommunications, Atlanta, GA, and South Central Bell Telephone Company, Jackson, MS. (z) Mr. Gillis is a director of Trustmark National Bank, Jackson, MS and First Capital Corporation, Jackson, MS. (aa) Mr. Meiners is a director of Trustmark National Bank, Jackson, MS, and Trustmark Corporation, Jackson, MS. (bb) Mr. Palmer is a director of Deposit Guaranty National Bank, Jackson, MS and Mobile Telecommunication Technologies (MTEL), Jackson, MS. (cc) Mr. Robinson is a director of Deposit Guaranty National Bank, Jackson, MS, and Deposit Guaranty Corporation, Jackson, MS. (dd) Mr. Cain is a director of Whitney National Bank and Whitney Holding Corporation (bank holding company), New Orleans, LA and Delchamps, Inc., Mobile, AL. (ee) Mr. Duncan is a director of Hibernia National Bank, Hibernia Corporation, New Orleans, LA. (ff) Dr. Francis is a director of The Equitable Life Assurance Society of the United States, New York, NY, Liberty Bank and Trust, New Orleans, LA, and First National Bank of Commerce, New Orleans, LA. (gg) Mr. Teamer is a director of First National Bank of Commerce, New Orleans, LA. Each director and officer of the applicable System company is elected yearly to serve until the first Board Meeting following the Annual Meeting of Stockholders and until a successor is elected and qualified. Annual meetings are currently expected to be held as follows: Entergy Corporation - May 6, 1994 AP&L - May 25, 1994 GSU - May 24, 1994 LP&L - May 23, 1994 MP&L - May 26, 1994 NOPSI - May 23, 1994 System Energy - April 29, 1994 Directorships shown above are generally limited to entities subject to Section 12 or 15(d) of the Securities and Exchange Act of 1934 or to the Investment Company Act of 1940. Section 16(a) of the Securities Exchange Act of 1934 and Section 17(a) of the Public Utility Holding Company Act of 1935 require each registrant's officers, directors and persons who own more than 10% of a registered class of such registrant's equity securities to file reports of ownership and changes in ownership concerning the securities of Entergy Corporation and its subsidiaries with the Securities and Exchange Commission and to furnish Entergy Corporation with copies of all Section 16(a) and 17(a) forms they file. Numerous forms relating to Sections 16(a) and 17(a) were required to be filed by officers and directors of Entergy Corporation and of GSU because of the Entergy/GSU merger. However, the following persons who became officers or directors of GSU following the Entergy/GSU merger were late in filing their GSU Form 3: Michael B. Bemis, Frank F. Gallaher, Glenn E. Harder, Donald C. Hintz, Jerry D. Jackson, Richard J. Landy, Edwin Lupberger, Jerry L. Maulden, Gerald D. McInvale, Michael R. Niggli, and Lee W. Randall. None of the above-named persons are the beneficial owners of any securities of GSU and, therefore, are required to file Form 3 solely by virtue of their positions as officers or directors of GSU. These forms have now been filed with the Securities and Exchange Commission. Additionally, in 1992, the spouse of Duke Shackelford, a director of Entergy Corporation and LP&L, inherited 450 shares of Entergy Corporation common stock. A Form 5 was not timely filed reporting this transaction. This report has now been filed with the Securities and Exchange Commission. On June 26, 1991, the assets of The Foster Company, Inc. were sold to another company, and all undisputed creditors who notified The Foster Company, Inc. of their claims prior to the sale were paid in full. After the sale of the assets, only a shell corporation remained. Subsequently, several claims and lawsuits were filed against the shell corporation. As a result of these actions, the shell corporation (which was renamed the Montegut Corporation on November 7, 1991) filed a petition for liquidation under the federal bankruptcy laws on November 25, 1991. The matter is pending. Mr. Brooke H. Duncan, who will retire in May, 1994, as a director of Entergy Corporation and NOPSI, served as President and Director of the Foster Company, Inc. and continues in those capacities with the Montegut Corporation. Item 11. Executive Compensation ENTERGY CORPORATION Information called for by this item concerning the directors and officers of Entergy Corporation and the Personnel Committee of Entergy Corporation's Board of Directors is set forth under the headings "Executive Compensation" and "Personnel Committee Interlocks and Insider Participation" contained in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held on May 6, 1994, which information is incorporated herein by reference. AP&L, GSU, LP&L, MP&L, NOPSI, AND SYSTEM ENERGY Summary Compensation Tables The following tables include the Chief Executive Officers and the four other most highly compensated executive officers in office as of December 31, 1993 at AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy. This determination was based on total annual base salary and bonuses (excluding bonuses of an extraordinary and nonrecurring nature) from all System sources earned during the year 1993. See Item 10. "Directors and Executive Officers of the Registrants", incorporated herein by reference, for information on the principal positions of certain of the executive officers named in the table below. AP&L, LP&L, MP&L, NOPSI, and System Entergy As shown in Item 10, most executive officers named below are employed by several System companies. Because it would be impracticable to allocate such officers' salaries among the various companies, the table below includes aggregate compensation paid by all System companies. However, GSU paid none of the reported compensation for the named officers.
Long-Term Compensation Annual Compensation Awards Payouts Other Restricted Securities (d) (e) (f) Annual Stock Underlying LTIP All Other Name Year Salary Bonus Compensation Awards Options Payouts Compensation ---- ---- ------ ----- ------------ ------ ------- ------- ------------ Michael B. Bemis 1993 $258,538 $161,142 $62,372 (b) 2,500 shares $50,125 $74,619 1992 258,059 170,186 35,927 (b) 2,500 45,094 71,492 1991 245,383 87,878 (a) (b) (c) 0 (a) Glenn E. Harder 1993 $145,959 $59,349 $4,236 (b) 0 shares $0 $17,111 1992 139,000 24,845 3,898 (b) 0 0 17,611 1991 122,321 15,291 (a) (b) (c) 0 (a) Donald C. Hintz* 1993 $265,386 $166,560 $48,548 (b) 5,000 shares $85,774 $24,462 1992 228,024 114,822 38,364 (b) 2,500 77,165 24,205 1991 191,653 80,326 (a) (b) (c) 0 (a) Jerry D. Jackson 1993 $288,559 $217,287 $36,166 (b) 6,719 shares $100,250 $25,961 1992 254,167 152,500 27,008 (b) 5,000 90,188 25,447 1991 225,000 82,575 (a) (b) (c) 31,500 (a) Edwin Lupberger** 1993 $542,077 $437,610 $20,327 (b) 13,438 shares $248,313 $32,957 1992 527,499 374,100 39,760 (b) 10,000 180,375 33,671 1991 489,996 147,626 (a) (b) (c) 65,625 (a) Jerry L. Maulden 1993 $385,000 $286,985 $84,655 (b) 5,000 shares $100,250 $25,639 1992 392,233 259,316 79,280 (b) 5,000 90,188 24,920 1991 360,069 156,724 (a) (b) (c) 54,900 (a) Gerald D. McInvale 1993 $221,696 $141,811 $48,805 (b) 2,500 shares $50,125 $22,667 1992 209,975 93,686 45,585 (b) 2,500 45,094 43,594 1991 132,356 28,280 (a) (b) (c) 0 (a) Lee W. Randall 1993 $176,321 $57,142 $8,014 (b) 0 shares $0 $17,986 1992 168,859 37,094 6,818 (b) 0 0 19,555 1991 167,890 24,929 (a) (b) (c) 0 (a)
* Chief Executive Officer of System Energy. ** Chief Executive Officer of AP&L, LP&L, MP&L, and NOPSI. (a) Disclosure in this category is subject to transition rules, and amounts for 1991 are not required to be included herein. (b) Restricted stock awarded under the Equity Ownership Plan is subject to performance based criteria. Restricted stock awards in 1993 are reported under the "Long-Term Incentive Plan Awards" table, and reference is made to this table for information on the aggregate number of restricted shares awarded during 1993 and the vesting schedule for such shares. At December 31, 1993, the number and value of the aggregate restricted stock holdings were as follows: Mr. Bemis: 2,500 shares, $90,000; Mr. Hintz: 4,279 shares, $154,044; Mr. Jackson: 5,000 shares, $180,000; Mr. Lupberger: 15,000 shares, $540,000; Mr. Maulden: 5,000 shares, $180,000; and Mr. McInvale: 2,500 shares, $90,000. Accumulated dividends are paid on restricted stock when vested. The value of stock for which restrictions were lifted in 1993, and the applicable portion of accumulated cash dividends, are reported in the LTIP Payouts column in the above table. The value of restricted stock awards as of December 31, 1993 is determined by multiplying the total number of shares awarded by the closing market price of Entergy Corporation common stock on the New York Stock Exchange Composite Transactions on December 31, 1993 ($36.00 per share). (c) There were no stock options granted in 1991. (d) 1991 amounts shown above include Long-Term Incentive Plan payouts earned in 1991 that were not calculable in time for inclusion in the Compensation Table in the Form 10-K for 1991. 1993 and 1992 amounts include the value of restricted shares that vested in 1993 and 1992 under Entergy's Equity Ownership Plan. (e) Includes the following: (1) 1993 Executive Medical Plan premiums of $3,019 for each of the above- named executives in 1993. (2) 1993 employer contributions to the Defined Contribution Restoration Plan as follows: Mr. Bemis $1,800; Mr. Harder $0; Mr. Hintz $886; Mr. Jackson $1,245; Mr. Lupberger $8,564; Mr. Maulden $5,519; Mr. McInvale $0; Mr. Randall $0. (3) 1993 employer contributions to the Employee Stock Ownership Plan as follows: Mr. Bemis $2,682; Mr. Harder $2,682; Mr. Hintz $2,682; Mr. Jackson $2,682; Mr. Lupberger $2,682; Mr. Maulden $0; Mr. McInvale $2,682; Mr. Randall $2,682. (4) 1993 employer contributions to the System Savings Plan as follows: Mr. Bemis $7,075; Mr. Harder $4,210; Mr. Hintz $7,075; Mr. Jackson $7,075; Mr. Lupberger $7,075; Mr. Maulden $6,031; Mr. McInvale $6,301; Mr. Randall $5,085. (5) 1993 reimbursements under the Executive Financial Counseling Program as follows: Mr. Bemis $0; Mr. Hintz $0; Mr. Jackson $1,140; Mr. Lupberger $4,605; Mr. Maulden $1,350; Mr. McInvale $765. (6) 1993 payments under the Private Ownership Vehicle Plan as follows: Mr. Bemis $9,900; Mr. Harder $7,200; Mr. Hintz $10,800; Mr. Jackson $10,800; Mr. Lupberger $7,012; Mr. Maulden $9,720; Mr. McInvale $9,900; Mr. Randall $7,200. (7) 1993 reimbursement for moving expenses as follows: Mr. Bemis $50,143. (f) Includes bonuses earned pursuant to the Annual Incentive Plan as well as any bonuses of an extraordinary or nonrecurring nature. GSU All of the reported compensation for the officers named below was paid by GSU. The listed positions were held by these officers in 1993. See item 10. "Directors and Executive Officers of the Registrants" for current GSU officers.
Long-Term Compensation Annual Compensation Awards Payouts Other Restricted Securities (c) Annual Stock Underlying LTIP All Other Name Year Salary Bonus Compensation Awards SARs(d) Payouts Compensation ---- ---- ------ ----- ------------ -------- --------- -------- ------------ Donald M. Clements, Jr.(e) 1993 $130,938 $74,345 $0 (b) 11,250 shares (b) $4,614 Senior Vice President - 1992 109,152 25,000 0 (b) 0 (b) 3,850 External Affairs 1991 (e) (e) (a) (b) 0 (b) (a) Joseph L. Donnelly* 1993 $402,083 $229,088 $0 (b) 38,500 shares (b) $28,271 Chief Executive Officer 1992 358,938 100,000 0 (b) 32,600 (b) 40,777 1991 217,667 0 (a) (b) 9,200 (b) (a) Calvin J. Hebert 1993 $169,817 $44,345 $0 (b) 5,350 shares (b) $61,668 Senior Vice President - 1992 159,917 0 0 (b) 8,050 (b) 32,715 Division Operations 1991 147,167 0 (a) (b) 8,000 (b) (a) Edward M. Loggins 1993 $233,750 $57,392 $0 (b) 20,400 shares (b) $16,385 Senior Executive Vice 1992 218,500 0 0 (b) 9,700 (b) 27,423 President 1991 204,000 0 (a) (b) 9,700 (b) (a) Jack L. Schenck 1993 $158,688 $44,345 $0 (b) 10,700 shares (b) $11,225 Sr. Vice President & 1992 145,329 20,000 0 (b) 4,700 (b) 7,732 Chief Financial Officer 1991 107,550 0 (a) (b) 4,700 (b) (a)
* Chief Executive Officer of GSU as of December 31, 1993. (a) Disclosure in this category is subject to transition rules, and amounts for 1991 are not required to be included herein. (b) GSU does not have a Restricted Stock Awards program or a Long-Term Incentive Plan Awards program. (c) Includes the following: (1) 1993 payments by GSU of excess life insurance cost as follows: Mr. Clements $682; Mr. Donnelly $16,146; Mr. Hebert $240; Mr. Loggins $9,140; Mr. Schenck $3,816. (2) 1993 company contributions to the GSU Thrift Plan as follows: Mr. Clements $3,932; Mr. Donnelly $7,075; Mr. Hebert $5,095; Mr. Loggins $7,075; Mr. Schenck $4,776. (3) 1993 company contributions to the GSU Non-qualified Accrued Contributions Plan as follows: Mr. Donnelly $5,050; Mr. Loggins $170. (4) Above market earnings on compensation deferred during the period December 1985-December 1986, as follows: Mr. Donnelly $0; Mr. Hebert $56,333; Mr. Loggins $0; Mr. Schenck $2,633. (d) These SARs were attached to shares of GSU common stock. At December 31, 1993, the SARs were exercised and cash was received by the named executives. See additional disclosure in the "Aggregated Option/SAR Exercises in 1993 and December 31, 1993 Option Values" table. (e) No compensation figures are provided for Mr. Clements for year 1991 because he was not an officer of GSU until June, 1992. All of his 1992 compensation is shown. (f) Mr. Clements, Mr. Donnelly, Mr. Loggins, and Mr. Schenck have subsequently resigned as officers of GSU. Therefore, they are not listed above as GSU officers in Item 10. "Directors and Executive Officers Of The Registrants". Option/SAR Grants in 1993 The following tables summarize option/SAR grants during 1993 to the executive officers named in the Summary Compensation Tables above. The absence, in the table below, of any named officer indicates that no options/SARs were granted to such officer. AP&L, LP&L, MP&L, NOPSI, and System Entergy
Individual Grants Potential Realizable % of Total Value Number of Options at Assumed Annual Securities Granted to Exercise Rates of Stock Underlying Employees Price Price Appreciation Options in (per Expiration for Option Term(c) Name Granted(a) 1993 share)(a) Date 5% 10% ---- ----------- ------- --------- ---------- --------- -------- Michael B. Bemis 2,500 3.4% $34.75 02/01/03 $54,635 $138,456 Donald C. Hintz 5,000 6.8% 34.75 02/01/03 109,270 276,913 Jerry D. Jackson 5,000 6.8% 34.75 02/01/03 109,270 276,913 1,719(b) 2.3% 39.75 09/02/03 42,973 108,901 Edwin Lupberger 10,000 13.6% 34.75 02/01/03 218,541 553,826 3,438(b) 4.7% 39.75 09/02/03 85,945 217,802 Jerry L. Maulden 5,000 6.8% 34.75 02/01/03 109,270 276,913 Gerald D. McInvale 2,500 3.4% 34.75 02/01/03 54,635 138,456
(a) Options were granted on February 1, 1993, pursuant to the Equity Ownership Plan. All options granted on February 1, 1993 have an exercise price equal to the closing price of Entergy Corporation common stock on the New York Stock Exchange Composite Transactions on January 29, 1993. These options became exercisable on August 1, 1993. (b) Pursuant to the Equity Ownership Plan, if a participant exercises an option during the term of employment and pays all or any portion of the price through the surrender of shares of Entergy Corporation common stock, the Personnel Committee may grant to such participant an additional option to purchase the number of shares so surrendered. Any such additional option shall have an exercise price equal to the fair market value of Entergy Corporation common stock as of the date of its grant. On September 2, 1993, Messrs. Jackson and Lupberger exercised stock options and the additional options indicated above were granted pursuant to this reload feature of the Equity Ownership Plan. The reloaded stock options become exercisable six months from the grant date and have an exercise price equal to the closing price of Entergy Corporation common stock on the New York Stock Exchange Composite Transactions on September 2, 1993. (c) Calculation based on the stock option exercise price over a ten-year period assuming annual compounding. The columns present estimates of potential values based on simple mathematical assumptions. The actual value, if any, an executive officer may realize is dependent upon the market price on the date of option exercise. GSU
Individual Grants Potential Realizable % of Total Value Number of SARs at Assumed Annual Securities Granted to Exercise Rates of Stock Underlying Employees Price Price Appreciation SARs in (per Expiration for SARs Term Name Granted(a) 1993 share) Date(a) 5% (a) 10% (a) ---- ---------- ---------- ------ ------- ------ ------- Donald M. Clements, Jr. 11,250 5.8% $16.50 - - - Joseph L. Donnelly 38,500 19.8% 16.50 - - - Calvin J. Hebert 5,350 2.7% 16.50 - - - Edward M. Loggins 20,400 10.5% 16.50 - - - Jack L. Schenck 10,700 5.5% 16.50 - - -
(a) According to the terms of the Stock Appreciation Plan as amended, effective on the merger date of December 31, 1993, all SARs issued and granted more than 6 months prior to the merger date were deemed exercised and payment was made to the named executives. Thus, all SARs were exercised and all value realized on the SARs as of December 31, 1993. Aggregated Option/SAR Exercises in 1993 and December 31, 1993 Option Values The following tables summarize the number and value of options exercised during 1993, as well as, the number and value of unexercised options/SARs as of December 31, 1993 held by the executive officers named in the Summary Compensation Tables above. The absence, in the tables below, of any named officer indicates that such officer did not exercise any options in 1993 and held no unexercised options/SARs as of December 31, 1993. AP&L, LP&L, MP&L, NOPSI, and System Entergy
Number of Securities Underlying Value of Unexercised Unexercised Options In-the-Money Options Shares Acquired Value as of December 31, 1993 as of December 31, 1993(a) Name on Exercise Realized(b) Exercisable Unexercisable(c) Exercisable Unexercisable ---- --------------- ----------- ----------- ---------------- ----------- ------------- Michael B. Bemis 0 0 5,000 0 $19,063 0 Donald C. Hintz 0 0 7,500 0 22,188 0 Jerry D. Jackson 2,308 $23,369 7,692 1,719 23,412 0 Edwin Lupberger 4,614 46,717 15,386 3,438 46,836 0 Jerry L. Maulden 0 0 10,000 0 38,125 0 Gerald D. McInvale 0 0 5,000 0 19,063 0
(a) Based on the difference between the closing price of Entergy Corporation common stock on the New York Stock Exchange Composite Transactions on December 31, 1993, and the option exercise price. (b) Based on the difference between the closing price of Entergy Corporation common stock on the New York Stock Exchange Composite Transactions on the exercise date of September 2, 1993, and the option exercise price. (c) Stock options granted on September 2, 1993 are not exercisable for a period of six months from the date of grant.
GSU Number of Securities Underlying Value of Unexercised Unexercised SARs In-the-Money SARs Shares Acquired Value as of December 31, 1993 (c) as of December 31, 1993 (c) Name on Exercise (a) Realized (b) Exercisable Unexercisable Exercisable Unexercisable ---- --------------- ------------ ----------- ------------- ----------- ------------- Donald M. Clements, Jr. 12,750 $54,469 0 0 0 0 Joseph L. Donnelly 165,500 1,166,625 0 0 0 0 Calvin J. Hebert 41,100 238,925 0 0 0 0 Edward M. Loggins 61,100 342,900 0 0 0 0 Jack L. Schenck 43,500 255,875 0 0 0 0
(a) Amount represents the number of SARs exercised during 1993. (b) Value realized is equal to the difference between the closing price of GSU common stock on the New York Stock Exchange Composite Transactions, on the grant date and such price on the date of exercise. (c) There were no outstanding SARs at December 31, 1993. See additional disclosure regarding SAR exercises in the "Option/SAR Grants in 1993" table. Long-Term Incentive Plan Awards in 1993 AP&L, LP&L, MP&L, NOPSI, and System Energy The following table summarizes awards of restricted shares of Entergy Corporation common stock under the Equity Ownership Plan in 1993 to the executive officers of these companies named in the Summary Compensation Table above. The absence, in the table below, of any named officer indicates that no restricted shares were awarded to such officer in 1993.
Estimated Future Payouts Under Performance Non-Stock Price-Based Plans(a) Number Period Until of Maturation Below Name Shares Or Payout Threshold(b) Threshold(c) Target(d) Maximum(e) ---- ------ ------------ ------------ ------------ --------- ---------- Edwin Lupberger 5,000 01/01/93-12/31/03 0 5,000 5,000 5,000
(a) Restricted shares awarded will vest incrementally over a period not to exceed 10 years, subject to the attainment of specific stockholder earnings goals and cost containment goals for the year. Restrictions are lifted based upon assigned weighted averages of these performance measures, with the specific relative percentage weight of such measures varying depending upon the individual. The value an executive officer may realize is dependent upon both the number of shares that vest and the future market price of Entergy Corporation common stock. (b) If goals are met at less than the 50% level of achievement in a given year, no restrictions will be lifted that year. Thus, if this level of performance is reached in each year, no shares will vest. (c) If goals are met at the 50-99% level of achievement in a given year, 20% of the restrictions will be lifted that year. Thus, if this level of performance is reached in each year, all shares will vest within 5 years. (d) If goals are met at the 100-149% level of achievement in a given year, 25% of the restrictions will be lifted that year. Thus, if this level of performance is reached in each year, all shares will vest within 4 years. (e) If goals are met at the 150% level of achievement (the maximum percent achievable) in a given year, 33 1/3% of the restrictions will be lifted that year. Thus, if this level of performance is reached in each year, all shares will vest within 3 years. Pension Plan Tables AP&L, LP&L, MP&L, NOPSI, and System Energy
Retirement Income Plan Table Annual Covered Years of Service Compensation 10 15 20 25 30 35 ------------ --- -- -- -- -- -- $100,000 $15,000 $ 22,500 $ 30,000 $ 37,500 $ 45,000 $ 52,500 200,000 30,000 45,000 60,000 75,000 90,000 105,000 300,000 45,000 67,500 90,000 112,500 135,000 157,500 400,000 60,000 90,000 120,000 150,000 180,000 210,000 500,000 75,000 112,500 150,000 187,500 225,000 262,500 650,000 97,500 146,250 195,000 243,750 292,500 341,250
AP&L, LP&L, MP&L, and System Energy each individually sponsors or participates in a Retirement Income Plan (a defined benefit plan) that provides a benefit for employees at retirement from the System based upon (1) generally all years of service beginning at age 21 through termination, with a forty-year maximum, times (2) 1.5% for each year of service, times (3) the final average salary. NOPSI is a participating employer in LP&L's Retirement Income Plan. System Energy is a participating employer in the Retirement Income Plan sponsored by Entergy Corporation. Final average salary is based on the highest 60 months of covered compensation in the last 120 months of service. The normal form of benefit for a single employee is a lifetime annuity and for a married employee is a 50% 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 individuals' annual compensation covered by the plan as of December 31, 1993 is represented by the base salary column in the Summary Compensation Table of AP&L, LP&L, MP&L, NOPSI, and System Energy. The maximum benefit under each Retirement Income Plan is limited by Sections 401 and 415 of the Internal Revenue Code; however, AP&L, LP&L, MP&L, NOPSI, 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 amount equal to the benefit payable under the Retirement Income Plans, without regard to the limitations, less the amount actually payable under the Retirement Income Plans. Each Retirement Income Plan was amended effective February 1, 1991 to provide a minimum accrued benefit as of that date to any employee who was vested as of that date. For purposes of calculating such minimum accrued benefit, each eligible employee was deemed to have had an additional five years of service and age as of that date. The additional years of age did not count toward eligibility for early retirement, but served only to reduce the early retirement discount factor for those employees who were at least age 50 as of that date. The credited years of service under the Retirement Income Plan (without giving effect to the five additional years of service credited pursuant to the February 1, 1991 amendment as discussed above) as of December 31, 1993 for the following executive officers named in the Summary Compensation Table of AP&L, LP&L, MP&L, NOPSI, and System Energy were: Mr. Bemis 11; Mr. Harder 15; Mr. Maulden 28; Mr. Randall 14. The credited years of service under the respective Retirement Income Plans, as amended, as of December 31, 1993 for the following executive officers named in the Summary Compensation Table, as a result of entering into supplemental retirement agreements, were as follows: Mr. Hintz 22; Mr. Jackson 14; Mr. Lupberger 30; Mr. McInvale 21. In addition to the Retirement Income Plan discussed above, AP&L, LP&L, MP&L, NOPSI and System Energy participate in the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries (SRP) and the Post-Retirement Plan of Entergy Corporation and Subsidiaries (PRP). Participation is limited to one of these two plans and is at the invitation of AP&L, LP&L, MP&L, NOPSI, and System Energy. The participant may receive from the appropriate System company a monthly benefit payment not in excess of .025 (under the SRP) or .0333 (under the PRP) times the participant's average basic annual salary (as defined in the plans) for a maximum of 120 months. As of January 31, 1994, Mr. Hintz has entered into a SRP participation contract, and all of the other executive officers of AP&L, LP&L, MP&L, NOPSI, and System Energy named in the Summary Compensation Table (except for Mr. McInvale) have entered into PRP participation contracts. System Executive Retirement Plan Table (1) Annual Covered Years of Service Compensation 10 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) 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). AP&L, LP&L, MP&L, NOPSI, 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 executive officers named in the Summary Compensation Table of AP&L, LP&L, MP&L, NOPSI, and System Energy. Participating executives choose, at retirement, between the retirement benefits paid under provisions of the SERP or those payable under the executive retirement benefit plans discussed above. Covered pay under the SERP includes final annual base salary (see the Summary Compensation Table of AP&L, LP&L, MP&L, NOPSI, and System Energy for the base salary covered by the SERP as of December 31, 1993) plus the Target Incentive Award (i.e., a percentage of final annual base salary) for the participant in effect at retirement. The Target Incentive Award as of December 31, 1993, was: 58% for Messrs. Jackson, Lupberger and Maulden; 48% for Messrs. Bemis, Hintz and McInvale; and, 35% for Messrs. Harder and Randall. 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 normal form of benefit for a single employee is a lifetime annuity and for a married employee is a 50% joint and survivor annuity. All SERP payments are guaranteed for ten years. Other actuarially equivalent options are available to each retiree. SERP benefits are offset by any and all defined benefit plan payments from the company and from prior employers. 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 that, without the specific consent of the System company for which such participant was last employed, he may take no employment after retirement with any entity that is in competition with or similar in nature to, AP&L, LP&L, MP&L, NOPSI, and System Energy or any affiliate thereof. Eligibility for benefits is forfeitable for various reasons, including violation of an agreement with AP&L, LP&L, MP&L, NOPSI, and System Energy, resignation of employment, or termination for cause. GSU Employees' Trusteed Retirement Plan Table
Annual Covered Years of Service Compensation 10 15 20 25 30 35 ------------ -- -- -- -- -- -- $100,000 $15,167 $22,751 $30,335 $37,918 $ 45,502 $ 53,086 150,000 23,167 34,751 46,335 57,918 69,502 81,086 200,000 31,167 46,751 62,335 77,918 93,502 109,086 235,840* 36,902 55,353 73,803 92,254 110,705 129,156**
* Maximum 1993 annual covered compensation imposed by Section 401 of the Internal Revenue Code. ** Maximum 1993 annual benefit imposed by Section 415 of the Internal Revenue Code is $115,641 payable at age 65. GSU has an Employees' Trusteed Retirement Plan that provides a benefit for employees at retirement from GSU based upon generally all years of service beginning at age 21 through termination, with a thirty-five year maximum, times (2) 1.2% of that portion of the participant's average final compensation not in excess of his average Social Security wage base, plus 1.6% of the part of such compensation in excess of such average Social Security wage base. This amount is reduced by the total amounts payable under a certain group annuity contract. Average final compensation is based on the 60 consecutive months during the last ten years of credited service which produce the highest average or during all months of credited service if such service is less than 60 months. The normal form of benefit for a single employee is a single life annuity and the actuarial equivalent 50% joint and survivor annuity of the employee is married. The above table illustrates annual retirement benefits expressed in terms of single life annuities based on the base salary and service shown and retirement at age 65. The amount of the named individuals' annual compensation covered by the plan as of December 31, 1993 is represented by the base salary column in the Summary Compensation Table of GSU. The credited years of service under the Employees' Trusteed Retirement Plan as of December 31, 1993 for the following executive officers named in the Summary Compensation Table were: Mr. Clements, 14 years; Mr. Donnelly, 14 years; Mr. Hebert, 29 years; Mr. Loggins, 33 years; Mr. Schenck, 12 years. In addition to the Employees' Trusteed Retirement Plan discussed above, GSU provides, among other benefits to officers, an Executive Income Security Plan for key managerial personnel. The plan provides participants with certain retirement, disability, termination, and survivors' benefits. To the extent that such benefits are not funded by the employee benefit plans of GSU or by vested benefits payable by the participants' former employers, GSU is obligated to make supplemental payments to participants or their survivors. The plan provides that upon the death or disability of a participant during his employment, he or his designated survivors will receive (i) during the first year following his death or disability an amount not to exceed his annual base salary, and (ii) thereafter for a number of years until the participant attains or would have attained age 65, but not less than nine years, an amount equal to one-half of the participant's annual base salary. The plan also provides supplemental retirement benefits for life for participants retiring after reaching age 65 equal to 1/2 of the participant's average final compensation rate, with 1/2 of such benefit upon the death of the participant being payable to a surviving spouse for life. GSU amended and restated the plan effective March 1, 1991, to provide such benefits for life upon termination of employment of a participating officer or key managerial employee without cause (as defined in the plan) or if the participant separates from employment for good reason (as defined in the plan), with 1/2 of such benefits to be payable to a surviving spouse for life. Further, the plan was amended to provide medical benefits for a participant and his family when the participant separates from service. These medical benefits generally continue until the participant is eligible to receive medical benefits from a subsequent employer; but in the case of a participant who is over 50 at the time of separation and was participating in the plan on March 1, 1991, medical benefits continue for life. By virtue of the 1991 amendment and restatement, benefits for a participant cannot be modified once he becomes eligible to participate in the plan. Compensation of Directors Employees of any Entergy System company who serve on the Board of Directors of any Entergy System company receive no compensation as directors. Directors of AP&L, LP&L, MP&L, and NOPSI who are not employees of a System company are paid an attendance fee of $1,000 for attendance at meetings of their respective Board of Directors, $1,000 (except for the chairman of such committee who is paid $1,500) for attendance at meetings of committees of the Board and $1,000 for participation, on behalf of their respective company, in any inspection trip or conference not held on the same day as a Board or committee meeting. All non-employee directors are also compensated on a quarterly basis in the form of fixed awards of Entergy Corporation common stock pursuant to the Stock Plan for Outside Directors (Directors Plan) and cash based on 1/2 the value of the stock awarded pursuant to the Directors Plan. This level of directors' compensation is set to enable Entergy Corporation to attract and retain persons of outstanding competence to serve on the Boards of Directors. Directors are paid a portion of their compensation in the form of Entergy Corporation's common stock in order to assure that directors will have a personal interest in the performance of the stock of Entergy Corporation. Non-employee directors are awarded 50 shares of Entergy Corporation common stock quarterly, which may be authorized but unissued shares or shares acquired in the open market. System Energy has no non-employee directors. Retired non-employee outside directors of AP&L, LP&L, MP&L, and NOPSI with a minimum of five years of service on the respective Boards of Directors are paid $200 a month for a term corresponding to the number of years of service. Retired directors with over ten years of service receive a lifetime benefit of $200 a month. Directors of GSU or its subsidiaries, who are not officers of GSU are paid the following fees: $15,000 per year retainer, an additional retainer of $2,400 to the director who serves as Chairman of the Executive Committee, $700 per day per Board meeting attended plus out-of-pocket expenses, $600 per day per committee meeting attended plus out-of-pocket expenses, and an additional fee of $150 per meeting to each director who serves as Chairman of the Executive, Audit, Compensation, Nominating Committees, the Board Committee on Nuclear Safety, the Business Policy Committee, or any other Committee composed of members of the Board. Also, when an outside director attends a specific business activity on behalf of GSU, at the request of the Chairman of the Board of Directors, he receives a fee of $600 per day plus out-of-pocket expenses. Outside directors of GSU may elect to defer 25 percent, 50 percent or 100 percent of their director's compensation. Under this nonqualified plan, a director's deferred compensation will accrue simple interest at the greater of (1) a rate equivalent to that payable by GSU on its average daily short-term debt during a preceding period or (2) a rate equivalent to that received by GSU on its average daily short-term investments during the preceding year. Directors may select deferred compensation payments to commence after death, upon permanent disability, after a certain age on a specific date, or after cessation of directorship of GSU, and may select payment in a lump sum or in annual installments. In 1993, two GSU directors participated in the deferred compensation plan. In 1991, the GSU Compensation Committee of the Board of Directors approved a retirement plan for directors of GSU. Under this plan all directors who serve 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 will be 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 retire prior to the retirement age as specified in the GSU Bylaws, the benefits will be reduced. The plan also provides disability retirement if the director has served at least five years prior to the disability. The benefits payable under this plan are general unsecured obligations of GSU and no funds or other amendments have been reserved or set aside by GSU to provide a source of payment or funding. In 1983, the GSU Board of Directors approved a proposal to have hospital and medical coverage through GSU's insurance carrier made available to members of the GSU Board. Under the terms of this proposal, (i) hospital and medical coverage will be secondary to coverage by a director's primary place of employment and/or Medicare, if applicable, (ii) two-thirds of the cost of providing the coverage to the director will be paid by GSU and the remaining one-third by the director, (iii) that portion of the premium paid by GSU will be reported as taxable income to the director as required by the Internal Revenue Service, and (iv) a director may retain his coverage after leaving the Board, if he has served five or more full elected terms on the Board. Under this plan in 1993, insurance premiums were paid to Provident Companies on behalf of the following directors: $1,424 for Gen. Barrow, $119 for Mr. Harrison, $3,944 for Mr. Peters, and $1,424 for Dr. Rathbone, Jr. In 1984, the GSU Board of Directors approved a plan whereby Coopers & Lybrand would make available their services to provide counseling and tax service individually to all directors for the purpose of assisting them with the establishment of individual Keogh plans and directed that the necessary changes be made in the compensation, benefit plans and other supplemental arrangements of management directors to enable them to participate also in such Keogh plans. In 1993 Coopers & Lybrand provided tax services to Dr. Murrill in the amount of $9,254. Dr. Murrill received in 1993 and will continue to receive payments from GSU under a retirement agreement and has received payments for consulting services, but none of such payments to him is for services as a director. For 1994, GSU adopted the Entergy System's compensation plans for outside directors. Employment Contracts and Termination of Employment and Change-in-Control Arrangements GSU GSU has agreed to employ Mr. Donnelly to serve at the pleasure of the Board at a salary fixed by the Board, and to assure (i) a pension benefit equivalent to that which would be provided by GSU's Employees' Trusteed Retirement Plan if he were given credit for prior service of 21.16 years, less credits for accrued benefits under certain GSU plans and social security, and calculated without application for the limit imposed by law on benefits that may be paid under qualified plans, (ii) payment upon termination of employment in certain events of a severance benefit equivalent to one year's base salary, (iii) payment after retirement of a death benefit equivalent to three times his highest annual base salary during the three years preceding retirement, (iv) certain financial consulting and other services, and (v) a contingent pension benefit for his spouse equal to fifty percent of his retirement benefit. Except for certain credits described above, these benefits are in addition to those he would be entitled to under GSU plans in which he is a participant. To the extent benefits to which Mr. Donnelly may become entitled are not funded through GSU plans, they will represent general obligations of GSU. In the event of a change of control of GSU and a termination by Mr. Donnelly of his employment for good reason (as defined in the Executive Continuity Plan), the agreement provides he is not entitled to the severance benefit but is entitled to the pension benefit without regard to his age. Effective as of January 5, 1994 Mr. Donnelly resigned from his offices as Chairman of the Board of Directors, President, Chief Executive Officer, and Director of GSU, and agreed that he would retire as an employee of GSU as of April 1, 1994. On January 22, 1994, Mr. Donnelly resigned as Vice Chairman and Director of Entergy Corporation and entered into a three-year consulting contract providing for an annual fee of $200,000. GSU established on January 18, 1991, an Executive Continuity Plan for elected and appointed officers providing for severance benefits equal to 2.99 times the officer's annual compensation upon termination of employment for reasons other than cause or upon a resignation of employment for good reason within two years after a change in control of GSU. Benefits are prorated if the officer is within three years of normal retirement age (65) at termination of employment. The plan further provides for continued participation in medical, dental and life insurance programs for three years following termination unless such benefits are available from a subsequent employer. The plan provides for outplacement assistance to aid a terminated officer in securing another position. Upon consummation of the Entergy/GSU merger on December 31, 1993, GSU made a contribution of $16,330,693 to a trust equivalent to the then present value of the maximum benefits which might be payable under the plan. If and to the extent the benefits are not thereafter paid to the participants, the balance in the trust will be returned to GSU. As a result of the Entergy/GSU merger, GSU is obligated to pay benefits under the Executive Income Security Plan to those persons who were participants at the time of the merger and who later terminated their employment under circumstances described in the plan. For additional description of the benefits under the Executive Income Security Plan, see the "Pension Plan Tables - GSU" section noted above. Personnel/Compensation Committee Interlocks and Insider Participation The following persons served as members of the Personnel Committee of AP&L's, LP&L's, MP&L's, NOPSI's and System Energy's Board of Directors and the Compensation Committee of GSU's Board of Directors in 1993: AP&L John A. Cooper, Jr.* Edwin Lupberger Roy L. Murphy Woodson D. Walker GSU Monroe J. Rathbone, Jr., M.D. Sam F. Segnar* Bismark A. Steinhagen LP&L Tex. R. Kilpatrick* Edwin Lupberger Wm. Clifford Smith MP&L Norman B. Gillis Robert E. Kennington, II* Edwin Lupberger Robert M. Williams, Jr. NOPSI Edwin Lupberger Anne M. Milling John B. Smallpage* System Energy System Energy does not have a Personnel Committee of the Board of Directors. The compensation of System Energy's executive officers (with the exception of one officer) is set by the Personnel Committee of Entergy Corporation's Board of Directors. No officers or employees of System Energy participated in deliberations concerning compensation in 1993. _______________ * Denotes Chairman of the Personnel/Compensation Committee Mr. Lupberger is currently and was during 1993 an officer of AP&L, LP&L, MP&L, and NOPSI and also served as an executive officer of their subsidiary, System Fuels, from 1981-1990. Mr. Jackson, Executive Vice President - Finance and External Affairs and Secretary of AP&L, served until May 13, 1993 on the compensation committee of the Board of Directors of Cooper Communities, Inc., whose chairman is John A. Cooper, Jr., a director of AP&L. During 1993, T. Baker Smith & Son, Inc. performed land surveying services for, and received payments of approximately $153,000 from, LP&L. Mr. Wm. Clifford Smith, a director of LP&L and a member of LP&L's Personnel Committee, is President of T. Baker Smith & Son, Inc. Mr. Smith's children own 100% of the voting stock of T. Baker Smith & Son, Inc. Item 12. Security Ownership of Certain Beneficial Owners and Management Entergy Corporation owns 100% of the outstanding common stock of registrants AP&L, GSU, LP&L, MP&L, NOPSI, 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 common stock is included under the heading "Voting Securities Outstanding" in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held May 6, 1994, which information is incorporated herein by reference. The registrants know of no contractual arrangements which may, at a subsequent date, result in a change in control of any of the registrants. The directors, the executive officers named in the Summary Compensation Tables, and the directors and officers as a group for Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy, respectively, beneficially owned directly or indirectly the following cumulative preferred stock of a System company and common stock of Entergy Corporation:
As of December 31, 1993 Entergy Corporation Common Stock Preferred Stock(a) Amount and Nature Amount and Nature of of Beneficial Beneficial Ownership(b) Ownership(b) Sole Voting Sole Voting Other and Other and Beneficial Investment Beneficial Investment Ownership Name Power(c) Ownership Power(c) (d)(e)(f)(g)(l)(m) ---- -------- ----------- ---------- ------------------ Entergy Corporation W. Frank Blount* - - 2,134 - John A. Cooper, Jr.* 6,000(a) - 5,484 - Joseph L. Donnelly*** - - 126 1,477 Brooke H. Duncan* - - 2,100 - Lucie J. Fjeldstad* - - 1,284 - Dr. Norman C. Francis* - - 100 - Donald C. Hintz** - - 1,519 13,462 Kaneaster Hodges, Jr.* - - 2,000 - Donald Hunter** - - 1,917 10,499 Jerry D. Jackson** - - 5,220 16,888 Robert v.d. Luft* - - 1,384 - Edwin Lupberger** - - 7,867 40,147 Jerry L. Maulden** - - 21,998 25,190 Adm. Kinnaird R. McKee* - - 2,500 - Paul W. Murrill* - - 1,300 - James R. Nichols* - - 2,423 - Eugene H. Owen* - 3,500(a) 558 - John N. Palmer, Sr.* - - 11,907 - Robert D. Pugh* - - 4,500 6,000(h) H. Duke Shackelford* - - 6,200 3,950(h) Wm. Clifford Smith* - - 2,905 - Bismark A. Steinhagen* - - 5,803 - Dr. Walter Washington* - - 442 4,017 All directors and executive officers 6,000 3,578 109,931 185,511 AP&L Michael B. Bemis** - - 5,999 12,297 John A. Cooper, Jr.* 6,000(a) - 5,484 - Cathy Cunningham* - - 1,200 1,000(i) Richard P. Herget, Jr.* - - 725 - Tommy H. Hillman* - - - 200(j) Donald C. Hintz** - - 1,519 13,462 Kaneaster Hodges, Jr.* - - 2,000 - Jerry D. Jackson** - - 5,220 16,888 R. Drake Keith*** - - 2,048 11,306 Edwin Lupberger** - - 7,867 40,147 Jerry L. Maulden** - - 21,998 25,190 Raymond P. Miller, Sr.* - - 500 - Roy L. Murphy* - - 400 - William C. Nolan, Jr.* - - 476 - Robert D. Pugh* - - 4,500 6,000(h) Gus B. Walton, Jr.* - - 20,127 - Michael E. Wilson* - - 255 - All directors and executive 6,000 - 90,107 173,388 officers GSU Robert H. Barrow* - - 61 - Joseph L. Donnelly** - - 126 1,477 Frank F. Gallaher*** - - 1,913 7,691 Frank W. Harrison, Jr.* - - 769 - Calvin J. Hebert** - - 1,016 - Donald C. Hintz*** - - 1,519 13,462 William F. Klausing* - - 334 - Edward M. Loggins** - - 125 2,120 Jerry L. Maulden*** - - 21,998 25,190 Paul W. Murrill* - - 1,300 - Eugene H. Owen* - 3,500(a) 558 - M. Bookman Peters* - - 558 - Monroe J. Rathbone, Jr.* - - 278 - Jack L. Schenck** - - - 641 Sam F. Segnar* - - 279 - Bismark A. Steinhagen* - - 5,803 - James E. Taussig, II* - - 906 - All directors and executive officers - 3,500 67,210 165,108 LP&L Michael B. Bemis** - - 5,999 12,297 John J. Cordaro*** - - 1,131 7,831 Donald C. Hintz** - - 1,519 13,462 William K. Hood* 800(a) - 1,750 - Jerry D. Jackson** - - 5,220 16,888 Tex R. Kilpatrick* - - 1,478 993(k) Joseph J. Krebs, Jr.* - - 453 - Edwin Lupberger** - - 7,867 40,147 Jerry L. Maulden** - - 21,998 25,190 H. Duke Shackelford* - - 6,200 3,950(h) Wm. Clifford Smith* - - 2,905 - All directors and executive officers 800 - 65,553 170,286 MP&L Michael B. Bemis** - - 5,999 12,297 Frank R. Day* - - 2,050 - John O. Emmerich, Jr.* - - 500 - Jerry D. Jackson** - - 5,220 16,888 Edwin Lupberger** - - 7,867 40,147 Jerry L. Maulden** - - 21,998 25,190 Gerald D. McInvale** - - 1,152 7,949 Donald E. Meiners*** - - 830 11,962 John N. Palmer, Sr.* - - 11,907 - Dr. Clyda S. Rent* - - 450 - E. B. Robinson, Jr.* - - 300 - Dr. Walter Washington* - - 442 4,017 Robert M. Williams, Jr.* - - 500 1,200 All directors and executive officers - - 64,928 169,626 NOPSI Michael B. Bemis** - - 5,999 12,297 James M. Cain* - - 1,215 8,421 John J. Cordaro*** - - 1,131 7,831 Brooke H. Duncan* - - 2,100 - Norman C. Francis* - - 100 - Donald C. Hintz* - - 1,519 13,462 Jerry D. Jackson** - - 5,220 16,888 Edwin Lupberger** - - 7,867 40,147 Jerry L. Maulden** - - 21,998 25,190 Gerald D. McInvale** - - 1,152 7,949 John B. Smallpage* - - 500 - Charles C. Teamer, Sr.* - - 324 - All directors and executive officers - - 53,022 170,390 System Energy Glenn E. Harder** - - 58 3,568 Donald C. Hintz** - - 1,519 13,462 Jerry D. Jackson* - - 5,220 16,888 Edwin Lupberger** - - 7,867 40,147 Jerry L. Maulden* - - 21,998 25,190 Gerald D. McInvale** - - 1,152 7,949 Lee W. Randall** - - - 4,094 All directors and executive officers - - 38,348 113,313
* Director of the respective Company ** Named Executive Officer of the respective Company *** Officer and Director of the respective Company (a) Stock ownership amounts refer to Preferred Stock, $100 Par Value, (except for the 6,000 shares of AP&L's $0.01 Par Value ($25 liquidation value), Preferred Stock held by John A. Cooper Trust; 3,500 shares of AP&L's $0.01 Par Value ($25 liquidation value), Preferred Stock held by Eugene H. Owen; and 800 Shares of LP&L's $25 Par Value Preferred Stock held by William K. Hood). Mr. Cooper disclaims any personal interest in these shares. (b) Based on information furnished by the respective individuals. The ownership amounts shown for each individual and for all directors and executive officers as a group do not exceed one percent of the outstanding securities of any class of security so owned. (c) Includes all shares which the individual has the sole power to vote and dispose of, or to direct the voting and disposition of. (d) Includes, for the named persons, shares of Entergy Corporation common stock held in the Employee Stock Ownership Plan of the registrants as follows: Michael B. Bemis, 666 shares; James M. Cain, 802 shares; John J. Cordaro, 940 shares; Glenn E. Harder, 686 shares; Donald C. Hintz, 703 shares; Donald Hunter, 703 shares; Jerry D. Jackson, 703 shares; R. Drake Keith, 703 shares; Edwin Lupberger, 770 shares; Jerry L. Maulden, 743 shares; Gerald D. McInvale, 103 shares; Donald E. Meiners, 516 shares; and Lee W. Randall, 739 shares. (e) Includes, for the named persons, shares of Entergy Corporation common stock held in the System Savings Plan as follows: Michael B. Bemis, 4,131 shares; James M. Cain 7,619 shares; John J. Cordaro, 1,391 shares; Glenn E. Harder, 2,882 shares; Donald C. Hintz, 980 shares; Donald Hunter 2,296 shares; Jerry D. Jackson, 1,774 shares; R. Drake Keith, 3,429 shares; Edwin Lupberger; 5,553 shares; Jerry L. Maulden, 9,447 shares; Gerald D. McInvale, 346 shares; Donald E. Meiners, 3,946 shares; and Lee W. Randall, 3,355 shares. (f) Includes, for the named persons, unvested restricted shares of Entergy Corporation common stock held in the Equity Ownership Plan as follows: Michael B. Bemis, 2,500 shares; John J. Cordaro, 3,000 shares; Donald C. Hintz, 4,279 shares; Donald Hunter, 2,500 shares; Jerry D. Jackson, 5,000 shares; R. Drake Keith, 2,500 shares; Edwin Lupberger, 15,000 shares; Jerry L. Maulden, 5,000 shares; Gerald D. McInvale, 2,500 shares; and Donald E. Meiners, 2,500 shares. (g) Includes, for the named persons, shares of Entergy Corporation common stock in the form of unexercised stock options awarded pursuant to the Equity Ownership Plan as follows: Michael B. Bemis, 5,000 shares; John J. Cordaro 2,500 shares; Donald C. Hintz, 7,500 shares; Donald Hunter, 5,000 shares; Jerry D. Jackson, 9,411 shares; R. Drake Keith, 4,674 shares; Edwin Lupberger, 18,824 shares; Jerry L. Maulden, 10,000 shares; Gerald D. McInvale, 5,000 shares; and Donald E. Meiners, 5,000 shares. (h) Includes, for the named persons, shares of Entergy Corporation common stock held by their spouses. The named persons disclaim any personal interest in these shares as follows: Robert D. Pugh 6,000 shares; and H. Duke Shackleford, 3,950 shares. (i) Reflects 500 shares of Entergy common stock owned by a Profit Sharing Plan at Cunningham Butane Gas Company and 500 shares of Entergy common stock not owned solely by Cathy Cunningham of which she has shared voting and investment power. (j) Reflects 200 shares owned by Tommy Hillman Farms, Inc. (k) Tex R. Kilpatrick is President of Central American Life Insurance Company which owns 993 shares of Entergy common stock. (l) Includes, for the named person, shares of Entergy Corporation common stock held in the GSU Thrift Plan as follows: Jack L. Schenck, 302 shares. (m) Includes, for the named persons, shares of Entergy Corporation common stock held in the GSU Employee Stock Ownership Plan as follows: Joseph L. Donnelly, 1,477 shares; Edward M. Loggins, 2,120 shares; and Jack L. Schenck, 339 shares. Item 13. Certain Relationships and Related Transactions. Information called for by this item concerning the directors and officers of Entergy Corporation is set forth under the heading "Certain Transactions" in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held on May 6, 1994, which information is incorporated herein by reference. See Item 11. "Executive Compensation - Personnel/Compensation Committee Interlocks and Insider Participation" for information on certain transactions required to be reported under this item. The System companies do not have policies whereby transactions involving executive officers and directors of the System are approved by a majority of disinterested directors. However, pursuant to the Entergy Corporation Code of Conduct, transactions involving a System company and its executive officers must have prior approval by the next higher reporting level of that individual, and transactions involving a System company and its directors must be reported to the secretary of the appropriate System company. PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. (a)1. Financial Statements and Independent Auditors' Reports, incorporated herein by reference, for Entergy, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy are listed in the Index to Financial Statements (see pages 57 and 58) (a)2. Financial Statement Schedules Independent Auditors' Reports on Financial Statement Schedules, incorporated herein by reference (see pages 349 and 350. Financial Statement Schedules are listed in the Index to Financial Statement Schedules, incorporated herein by reference (see page S-1) (a)3. Exhibits Exhibits for Entergy, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy are listed in the Exhibit Index, incorporated herein by reference (see page E-1), Each management contract or compensatory plan or arrangement required to be filed as an exhibit hereto is identified as such by footnote in the Exhibit Index. (b) Reports on Form 8-K GSU A current report on Form 8-K, dated November 30, 1993, was filed with the SEC on December 1, 1993, reporting information under Item 7 "Financial Statements and Exhibits". A current report on Form 8-K, dated January 18, 1994, was filed with the SEC on January 18, 1994, reporting information under Item 5 "Other Materially Important Events". A current report on Form 8-K, dated February 1, 1994, was filed with the SEC on February 8, 1994, reporting information under Items 2 and 7. Entergy Corporation, AP&L, GSU, LP&L, MP&L and NOPSI Current Reports on Form 8-K, dated December 31, 1993, were filed by these companies on January 3, 1994 reporting the consummation of the Entergy Corporation - GSU merger under Item 5 (in the case of AP&L, LP&L, MP&L and NOPSI), Items 2 and 7 (in the case of Entergy Corporation and GSU). EXPERTS All statements in Part I of this Annual Report on Form 10-K as to matters of law and legal conclusions, based on the belief or opinion of System Energy or any System operating company or otherwise, pertaining to the titles to properties, franchises and other operating rights of certain of the registrants filing this Annual Report on Form 10-K, and their subsidiaries, the regulations to which they are subject and any legal proceedings to which they are parties are made on the authority of Friday, Eldredge & Clark, 2000 First Commercial Building, 400 West Capitol, Little Rock, Arkansas, as to AP&L and as to Entergy Services in regards to flood litigation; Monroe & Lemann (A Professional Corporation), 201 St. Charles Avenue, Suite 3300, New Orleans, Louisiana, as to LP&L and NOPSI; and Wise Carter Child & Caraway, Professional Association, Heritage Building, Jackson, Mississippi, as to MP&L and System Energy. The statements attributed to Clark, Thomas & Winters, a professional corporation, as to legal conclusions with respect to GSU's rate regulation in Texas under Item 1. "Rate Matters and Regulation - Rate Matters - Retail Rate Matters - GSU" and in Note 2 to Entergy Corporation and Subsidiaries Consolidated Financial Statements and GSU's Financial Statements, "Rate and Regulatory Matters," have been reviewed by such firm and are included herein upon the authority of such firm as experts. The statements attributed to Sandlin Associates regarding the analysis of River Bend Construction costs of GSU under Item 1. "Rate Matters and Regulation - Rate Matters - Retail Rate Matters - GSU" and in Note 2 to Entergy Corporation and Subsidiaries Consolidated Financial Statements and GSU's Financial Statements, "Rate and Regulatory Matters", have been reviewed by such firm and are included herein upon the authority of such firm as experts. ENTERGY CORPORATION SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. ENTERGY CORPORATION By /s/ Lee W. Randall Lee W. Randall, Vice President and Chief Accounting Officer Date: March 14, 1994 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/ Lee W. Randall Vice President and March 14, 1994 Lee W. Randall Chief Accounting Officer (Principal Accounting Officer) Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Senior Vice President and Chief Financial Officer; Principal Financial Officer); W. Frank Blount, John A. Cooper, Jr., Brooke H. Duncan, Lucie J. Fjeldstad, Kaneaster Hodges, Jr., Robert v.d. Luft, Kinnaird R. McKee, Paul W. Murrill, James R. Nichols, Eugene H. Owen, John N. Palmer, Robert D. Pugh, H. Duke Shackelford, Wm. Clifford Smith, Bismark A. Steinhagen, and Walter Washington (Directors). By: /s/ Lee W. Randall March 14, 1994 (Lee W. Randall, Attorney-in-fact) ARKANSAS POWER & LIGHT COMPANY 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. ARKANSAS POWER & LIGHT COMPANY By /s/ Lee W. Randall Lee W. Randall, Vice President and Chief Accounting Officer Date: March 14, 1994 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/ Lee W. Randall Lee W. Randall Vice President and Chief March 14, 1994 Accounting Officer (Principal Accounting Officer) Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Senior Vice President and Chief Financial Officer; Principal Financial Officer); Michael B. Bemis, John A. Cooper, Jr., Cathy Cunningham, Richard P. Herget, Jr., Tommy H. Hillman, Donald C. Hintz, Kaneaster Hodges, Jr., Jerry D. Jackson, R. Drake Keith, Jerry L. Maulden, Raymond P. Miller, Sr., Roy L. Murphy, William C. Nolan, Jr., Robert D. Pugh, Woodson D. Walker, Gus B. Walton, Jr., Michael E. Wilson (Directors). By: /s/ Lee W. Randall March 14, 1994 (Lee W. Randall, Attorney-in-fact) GULF STATES UTILITIES COMPANY 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. GULF STATES UTILITIES COMPANY By /s/ Lee W. Randall Lee W. Randall, Vice President and Chief Accounting Officer Date: March 14, 1994 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/ Lee W. Randall Vice President and March 14, 1994 Lee W. Randall Chief Accounting Officer (Principal Accounting Officer) Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Senior Vice President and Chief Financial Officer; Principal Financial Officer); Robert H. Barrow, Frank F. Gallaher, Frank W. Harrison, Jr., Donald C. Hintz, Jerry L. Maulden, Paul W. Murrill, Eugene H. Owen, M. Bookman Peters, Monroe J. Rathbone, Jr., Sam F. Segnar, Bismark A. Steinhagen, James E. Taussig, II. (Directors). By: /s/ Lee W. Randall March 14, 1994 (Lee W. Randall, Attorney-in-fact) LOUISIANA POWER & LIGHT COMPANY 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. LOUISIANA POWER & LIGHT COMPANY By /s/ Lee W. Randall Lee W. Randall, Vice President and Chief Accounting Officer Date: March 14, 1994 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/ Lee W. Randall Lee W. Randall Vice President and Chief March 14, 1994 Accounting Officer (Principal Accounting Officer) Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Senior Vice President and Chief Financial Officer; Principal Financial Officer); Michael B. Bemis, John J. Cordaro, Donald C. Hintz, William K. Hood, Jerry D. Jackson, Tex R. Kilpatrick, Joseph J. Krebs, Jr., Jerry L. Maulden, H. Duke Shackelford, Wm. Clifford Smith (Directors). By: /s/ Lee W. Randall March 14, 1994 (Lee W. Randall, Attorney-in-fact) MISSISSIPPI POWER & LIGHT COMPANY 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. MISSISSIPPI POWER & LIGHT COMPANY By /s/ Lee W. Randall Lee W. Randall, Vice President and Chief Accounting Officer Date: March 14, 1994 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/ Lee W. Randall Lee W. Randall Vice President and Chief March 14, 1994 Accounting Officer (Principal Accounting Officer) Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Senior Vice President and Chief Financial Officer; Principal Financial Officer); Michael B. Bemis, Frank R. Day, John O. Emmerich, Jr., Norman B. Gillis, Jr., Donald C. Hintz, Jerry D. Jackson, Robert E. Kennington, II, Jerry L. Maulden, Donald E. Meiners, John N. Palmer, Sr., Clyda S. Rent, Walter Washington, Robert M. Williams, Jr. (Directors). By: /s/ Lee W. Randall March 14, 1994 (Lee W. Randall, Attorney-in-fact) NEW ORLEANS PUBLIC SERVICE 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. NEW ORLEANS PUBLIC SERVICE INC. By /s/ Lee W. Randall Lee W. Randall, Vice President and Chief Accounting Officer Date: March 14, 1994 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/ Lee W. Randall Lee W. Randall Vice President and Chief March 14, 1994 Accounting Officer (Principal Accounting Officer) Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Senior Vice President and Chief Financial Officer; Principal Financial Officer); Michael B. Bemis, James M. Cain, John J. Cordaro, Brooke H. Duncan, Norman C. Francis, Donald C. Hintz, Jerry D. Jackson, Jerry L. Maulden, Anne M. Milling, John B. Smallpage, Charles C. Teamer, Sr. (Directors). By: /s/ Lee W. Randall March 14, 1994 (Lee W. Randall, Attorney-in-fact) SYSTEM ENERGY RESOURCES, INC. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. SYSTEM ENERGY RESOURCES, INC. By /s/ Lee W. Randall Lee W. Randall, Vice President and Chief Accounting Officer Date: March 14, 1994 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/ Lee W. Randall Lee W. Randall Vice President and Chief March 14, 1994 Accounting Officer (Principal Accounting Officer) Donald C. Hintz (President, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Senior Vice President and Chief Financial Officer; Principal Financial Officer); Edwin Lupberger (Chairman of the Board), Jerry D. Jackson, Jerry L. Maulden (Directors). By: /s/ Lee W. Randall March 14, 1994 (Lee W. Randall, Attorney-in-fact) EXHIBIT 23(a) INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Post-Effective Amendment Nos. 2, 3, 4A, and 5A on Form S-8 to Registration Statement No. 33-54298 of Entergy Corporation on Form S-4, and the related Prospectuses, of our reports dated February 11, 1994 (which express an unqualified opinion and include explanatory paragraphs as to uncertainties because of certain regulatory and litigation matters), appearing in this Annual Report on Form 10-K of Entergy Corporation for the year ended December 31, 1993. We also consent to the incorporation by reference in Registration Statements Nos. 33-36149, 33-48356 and 33-50289 of Arkansas Power & Light Company on Form S-3, and the related Prospectuses, of our reports dated February 11, 1994, appearing in this Annual Report on Form 10-K of Arkansas Power & Light Company for the year ended December 31, 1993. We also consent to the incorporation by reference in Registration Statements Nos. 33-46085, 33-39221 and 33-50937 of Louisiana Power & Light Company on Form S-3, and the related Prospectuses, of our reports dated February 11, 1994, appearing in this Annual Report on Form 10-K of Louisiana Power & Light Company for the year ended December 31, 1993. We also consent to the incorporation by reference in Registration Statements Nos. 33-53004, 33-55826 and 33-50507 of Mississippi Power & Light Company on Form S-3, and the related Prospectuses, of our reports dated February 11, 1994, appearing in this Annual Report on Form 10-K of Mississippi Power & Light Company for the year ended December 31, 1993. We also consent to the incorporation by reference in Registration Statement No. 33-57926 of New Orleans Public Service Inc. on Form S-3, and the related Prospectus, of our reports dated February 11, 1994, appearing in this Annual Report on Form 10-K of New Orleans Public Service Inc. for the year ended December 31, 1993. We also consent to the incorporation by reference in Registration Statement No. 33-47662 of System Energy Resources, Inc. on Form S-3, and the related Prospectus, of our reports dated February 11, 1994 (which express an unqualified opinion and include an explanatory paragraph as to an uncertainty resulting from a regulatory proceeding), appearing in this Annual Report on Form 10-K of System Energy Resources, Inc. for the year ended December 31, 1993. /s/ Deloitte & Touche DELOITTE & TOUCHE New Orleans, Louisiana March 14, 1994 EXHIBIT 23(b) CONSENT OF INDEPENDENT ACCOUNTANTS We consent to the incorporation by reference in the registration statements of Gulf States Utilities Company on Form S-3 (File Numbers 33-49739 and 33-51181) and Form S-8 (File Numbers 2-76551 and 2-98011) of our reports, dated February 11, 1994, on our audits of the financial statements and financial statement schedules of Gulf States Utilities Company as of December 31, 1993 and 1992, and for the years ended December 31, 1993, 1992 and 1991, which reports include explanatory paragraphs related to rate-related contingencies, legal proceedings and changes in accounting for income taxes, postretirement benefits, unbilled revenue and power plant materials and supplies and are included in this Annual Report on Form 10-K. /s/ Coopers & Lybrand Coopers & Lybrand Houston, Texas March 14, 1994 EXHIBIT 23(c) CONSENT OF EXPERTS We consent to the reference to our firm under the heading "Experts" in this Annual Report on Form 10-K. We further consent to the incorporation by reference of such reference to our firm into Arkansas Power & Light Company's ("AP&L") Registration Statements (Form S-3, File Nos. 33-36149, 33-48356 and 33-50289) and related Prospectuses, pertaining to AP&L's First Mortgage Bonds and Preferred Stock. Very truly yours, /s/ Friday, Eldredge & Clark FRIDAY, ELDREDGE & CLARK Date: March 14, 1994 EXHIBIT 23(d) CONSENT We consent to the reference to our firm under the heading "Experts", and to the inclusion in this Annual Report on Form 10-K of Gulf States Utilities Company ("GSU") of the statements of legal conclusions attributed to us herein (the Statements of Legal Conclusions) under Part I, Item 1. Business - "Rate Matters and Regulation" and in the discussion of Texas jurisdictional matters set forth in Note 2 to GSU's Financial Statements and Note 2 to Entergy Corporation and Subsidiaries Consolidated Financial Statements appearing as Item 8. of Part II of this Form 10-K, which Statements of Legal Conclusions have been prepared or reviewed by us (Clark, Thomas & Winters, a Professional Corporation). We also consent to the incorporation by reference in the registration statements of GSU on Form S-3 and Form S-8 (File Numbers 2-76551, 2-98011, 33-49739, and 33-51181) of such reference and Statements of Legal Conclusions. /s/ Clark, Thomas & Winters, A Professional Corporation CLARK, THOMAS & WINTERS A Professional Corporation Austin, Texas March 14, 1994 EXHIBIT 23(e) CONSENT We consent to the reference to our firm under the heading "Experts" and to the inclusion in this Annual Report on Form 10-K of Gulf States Utilities Company ("GSU") of the statements (Statements) regarding the analysis by our Firm of River Bend construction costs which are made herein under Part I, Item 1. Business - "Rate Matters and Regulation" and in the discussion of Texas jurisdictional matters set forth in Note 2 to GSU's Financial Statements and Note 2 to Entergy Corporation and Subsidiaries' Consolidated Financial Statements appearing as Item 8. of Part II of this Form 10-K, which Statements have been prepared or reviewed by us (Sandlin Associates). We also consent to the incorporation by reference in the registration statements of GSU on Form S-3 and Form S-8 (File Numbers 2-76551, 2- 98011, 33-49739 and 33-51181) of such reference and Statements. /s/ Sandlin Associates Management Consultants SANDLIN ASSOCIATES Management Consultants Pasco, Washington March 14, 1994 EXHIBIT 23(f) CONSENT OF EXPERTS We consent to the reference to our firm under the heading "Experts" in this Annual Report on Form 10-K. We further consent to the incorporation by reference of such reference to our firm into Louisiana Power & Light Company's ("LP&L") Registration Statements (Form S-3, File Nos. 33-46085, 33-39221 and 33-50937) and the related Prospectuses, pertaining to LP&L's First Mortgage Bonds and Preferred Stock, and into New Orleans Public Service Inc.'s ("NOPSI") Registration Statement (Form S-3, File No. 33-57926) and the related Prospectus pertaining to NOPSI's General and Refunding Mortgage Bonds. Very truly yours, /s/ Monroe & Lemann MONROE & LEMANN Date: March 14, 1994 EXHIBIT 23(g) CONSENT OF EXPERTS We consent to the reference to our firm under the heading "Experts" in this Annual Report on Form 10-K. We further consent to the incorporation by reference of such reference to our firm into System Energy Resources, Inc.'s (System Energy) Registration Statement on Form S-3 (File No. 33-47662) and the related prospectus pertaining to System Energy's First Mortgage Bonds, and into Mississippi Power & Light Company's ("MP&L") Registration Statements on Form S-3 (File Nos. 33-53004, 33-55826 and 33-50507) and the related prospectuses pertaining to MP&L's Preferred Stock and General and Refunding Mortgage Bonds. Very truly yours, WISE CARTER CHILD & CARAWAY Professional Association By /s/ Robert B. McGehee Date: March 14, 1994 INDEPENDENT AUDITORS' REPORT ON FINANCIAL STATEMENT SCHEDULES To the Shareholders and the Board of Directors of Entergy Corporation We have audited the consolidated financial statements of Entergy Corporation and subsidiaries and the financial statements of Arkansas Power & Light Company, Louisiana Power & Light Company, Mississippi Power & Light Company, New Orleans Public Service Inc., and System Energy Resources, Inc. as of December 31, 1993 and 1992, and for each of the three years in the period ended December 31, 1993, and have issued our reports thereon dated February 11, 1994, which report as to Entergy Corporation includes explanatory paragraphs as to uncertainties because of certain regulatory and litigation matters, and which report as to System Energy Resources, Inc. includes an explanatory paragraph as to an uncertainty resulting from a regulatory proceeding; such reports are included elsewhere in this Form 10-K. Our audits also included the financial statement schedules of these companies, listed in Item 14(a)2. These financial statement schedules are the responsibility of the companies' managements. Our responsibility is to express an opinion based on our audits. We did not audit the financial statements of Gulf States Utilities Company (a consolidated subsidiary of Entergy Corporation acquired on December 31, 1993), which statements reflect total assets constituting 31% of consolidated total assets at December 31, 1993. Those statements were audited by other auditors whose report (which included explanatory paragraphs regarding uncertainties because of certain regulatory and litigation matters) has been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulf States Utilities Company, is based solely on the report of such other auditors. In our opinion, based on our audits and the report of the other auditors, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein. /s/ Deloitte & Touche DELOITTE & TOUCHE New Orleans, Louisiana February 11, 1994 INDEPENDENT AUDITORS' REPORT ON FINANCIAL STATEMENT SCHEDULES To the Shareholders and the Board of Directors of Gulf States Utilities Company Our report on the financial statements of Gulf States Utilities Company, which includes explanatory paragraphs related to rate-related contingencies, legal proceedings and changes in accounting is included in this Form 10-K. In connection with our audits of such financial statements, we have also audited the related financial statement schedules of Gulf States Utilities Company included in Item 14(a)2 of this Form 10-K. In our opinion, the financial statement schedules referred to above, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein. /s/ Coopers & Lybrand Coopers & Lybrand Houston, Texas February 11, 1994 INDEX TO FINANCIAL STATEMENT SCHEDULES Schedule III Financial Statements of Entergy Corporation: Balance Sheets, December 31, 1993 and 1992 Statements of Income - For the Years Ended December 31, 1993, 1992 and 1991 Statements of Retained Earnings and Paid-In Capital - For the Years Ended December 31, 1993, 1992 and 1991 Statements of Cash Flows - For the Years Ended December 31, 1993, 1992 and 1991 V Utility Plant 1993, 1992 and 1991: Entergy Corporation and Subsidiaries Arkansas Power & Light Company Gulf States Utilities Company Louisiana Power & Light Company Mississippi Power & Light Company New Orleans Public Service Inc. System Energy Resources, Inc. VI Accumulated Depreciation and Amortization of Property 1993, 1992 and 1991: Entergy Corporation and Subsidiaries Arkansas Power & Light Company Gulf States Utilities Company Louisiana Power & Light Company Mississippi Power & Light Company New Orleans Public Service Inc. System Energy Resources, Inc. VIII Valuation and Qualifying Accounts 1993, 1992 and 1991: Entergy Corporation and Subsidiaries Arkansas Power & Light Company Gulf States Utilities Company Louisiana Power & Light Company Mississippi Power & Light Company New Orleans Public Service Inc. X Supplementary Income Statement Information 1993, 1992 and 1991: Entergy Corporation and Subsidiaries Arkansas Power & Light Company Gulf States Utilities Company Louisiana Power & Light Company Mississippi Power & Light Company New Orleans Public Service Inc. System Energy Resources, Inc. 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 III - FINANCIAL STATEMENTS OF ENTERGY CORPORATION BALANCE SHEETS
December 31, --------------------------- 1993 1992 ---------- ---------- (In Thousands) ASSETS Construction work in progress $22,861 - ---------- ---------- Investment in Wholly-owned Subsidiaries 6,449,165 $4,153,966 ---------- ---------- Current Assets: Cash equivalents: Temporary cash investments - at cost, which approximates market: Associated companies 100,401 9,225 Other 52,150 110,481 ---------- ---------- Total cash equivalents 152,551 119,706 Other temporary investments - 17,012 Accounts receivable: Associated companies 3,086 2,805 Other 2,467 2,179 Interest receivable 1,073 560 Other 1,166 481 ---------- ---------- Total 160,343 142,743 ---------- ---------- Deferred Debits 93,479 32,387 ---------- ---------- TOTAL $6,725,848 $4,329,096 ========== ========== CAPITALIZATION AND LIABILITIES Capitalization: Common stock, $.01 par value in 1993 and $5 par value in 1992: authorized 500,000,000 shares; issued and outstanding 231,219,737 shares in 1993; issued 175,137,392 shares in 1992 $2,312 $875,687 Paid-in capital 4,223,682 1,327,589 Retained earnings 2,310,082 2,062,188 Less cost of treasury stock (1,943 shares in 1992) - 54 ---------- ---------- Total common shareholders' equity 6,536,076 4,265,410 ---------- ---------- Current Liabilities: Notes payable 43,000 - Accounts payable: Associated companies 7,556 7,006 Other 10,069 9,252 Other current liabilities 1,849 633 ---------- ---------- Total 62,474 16,891 ---------- ---------- Deferred Credits and Noncurrent Liabilities 127,298 46,795 ---------- ---------- Total $6,725,848 $4,329,096 ========== ========== Entergy Corporation and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8 are incorporated herin by reference.
ENTERGY CORPORATION SCHEDULE III - FINANCIAL STATEMENTS OF ENTERGY CORPORATION STATEMENTS OF INCOME
For the Years Ended December 31, ---------------------------------------------- 1993 1992 1991 -------- -------- -------- (In Thousands) Income: Equity in income of subsidiaries $557,681 $454,947 $471,250 Interest on temporary investments 18,520 20,011 39,664 -------- -------- -------- Total 576,201 474,958 510,914 -------- -------- -------- Expenses and Other Deductions: Administrative and general expenses 25,129 32,412 27,422 Income taxes 3,587 4,734 93 Taxes other than income (credit) (696) 167 1,156 Interest (credit) (3,749) 8 211 -------- -------- -------- Total 24,271 37,321 28,882 -------- -------- -------- Net Income $551,930 $437,637 $482,032 ======== ======== ======== Entergy Corporation and Subsidiaries Notes to Connsolidated Financial Statements in Part II, Item 8 are incorporated herein by reference.
ENTERGY CORPORATION SCHEDULE III - FINANCIAL STATEMENTS OF ENTERGY CORPORATION STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL
For The Year Ended December 31, ---------------------------------------- 1993 1992 1991 ---------- ---------- ---------- (In Thousands) Retained Earnings, January 1 $2,062,188 $1,943,298 $1,775,000 Add - Net income 551,930 437,637 482,032 ---------- ---------- ---------- Total 2,614,118 2,380,935 2,257,032 ---------- ---------- ---------- Deduct: Dividends declared on common stock 288,342 255,479 228,555 Common stock retirements 13,906 59,187 80,009 Capital stock and other expenses 1,788 4,081 5,170 ---------- ---------- ---------- Total 304,036 318,747 313,734 ---------- ---------- ---------- Retained Earnings, December 31 $2,310,082 $2,062,188 $1,943,298 ========== ========== ========== Paid-in Capital, January 1 $1,327,589 $1,357,883 $1,408,640 Add: Gain (loss) on reacquisition of subsidiaries' preferred stock (20) (1,323) 35 Issuance of 56,667,726 shares of common stock in the merger with GSU 2,027,325 - - Issuance of 174,552,011 shares of common stock at $.01 par value net of the retirement of 174,552,011 shares of common stock at $5.00 par value 871,015 - - ---------- ---------- ---------- Total 4,225,909 1,356,560 1,408,675 ---------- ---------- ---------- Deduct: Common stock retirements 4,389 28,127 49,391 Capital stock discounts and other expenses (2,162) 844 1,401 ---------- ---------- ---------- Total 2,227 28,971 50,792 ---------- ---------- ---------- Paid-in Capital, December 31 $4,223,682 $1,327,589 $1,357,883 ========== ========== ========== Entergy Corporation and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8 are incorporated herein by reference.
ENTERGY CORPORATION SCHEDULE III - FINANCIAL STATEMENTS OF ENTERGY CORPORATION STATEMENTS OF CASH FLOWS
For the Years Ended December 31, ----------------------------------------- 1993 1992 1991 ---------- -------- -------- (In Thousands) Operating Activities: Net income $551,930 $437,637 $482,032 Noncash items included in net income: Equity in earnings of subsidiaries (557,681) (454,947) (471,250) Deferred income taxes 3,771 3,146 (3,146) Changes in working capital: Receivables (1,082) 2,875 6,812 Payables 1,367 (26,241) 1,099 Other working capital accounts 531 16,034 (1,368) Common stock dividends received from subsidiaries 686,700 487,854 231,537 Other (20,938) (15,012) (4,259) ---------- -------- -------- Net cash flow provided by operating activities 664,598 451,346 241,457 ---------- -------- -------- Investing Activities: Merger with GSU - cash paid (250,000) - - Investment in subsidiaries (86,221) (79,228) (114,650) Capital expenditures (22,861) - - Decrease in other temporary investments 17,012 114,651 25,355 Advance to subsidiary (24,642) (12,005) (24,163) ---------- -------- -------- Net cash flow provided by (used in) investing activities (366,712) 23,418 (113,458) ---------- -------- -------- Financing Activities: Changes in short-term borrowings 43,000 - - Common stock dividends paid (287,483) (256,117) (228,816) Retirement of common stock (20,558) (105,673) (161,640) ---------- -------- -------- Net cash flow used in financing activities (265,041) (361,790) (390,456) ---------- -------- -------- Net increase (decrease) in cash and cash equivalents 32,845 112,974 (262,457) Cash and cash equivalents at beginning of period 119,706 6,732 269,189 ---------- -------- -------- Cash and cash equivalents at end of period $152,551 $119,706 $6,732 ========== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Noncash investing and financing activities: Merger with GSU-Common stock issued $2,031,101 - - Entergy Corporation and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8 are incorporated herein by reference.
ENTERGY CORPORATION AND SUBSIDIARIES SCHEDULE V - UTILITY PLANT Year Ended December 31, 1993 (In Thousands)
- ----------------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Column G Other Changes- Balance at Debits Balance Classification Beginning Additions Retirements (Credits) Acquisition at End (Note 4) of Period at Cost or Sales (Notes 2-3) of GSU of Period - ----------------------------------------------------------------------------------------------------------------------------- Electric Utility Plant: Intangible $90,813 $16,678 $22,847 $(19,105) - $65,539 Production (Note 3) 9,033,191 84,114 23,939 20,023 $4,571,911 13,685,300 Transmission 1,401,286 22,304 3,054 (19) 833,730 2,254,247 Distribution 2,810,941 154,953 28,062 (10) 1,083,628 4,021,450 General 474,652 48,682 2,393 (52) 123,415 644,304 Leased to others 5,144 - - - - 5,144 Leased from others (Note 1) 662,400 773 149 - 86,039 749,063 Plant and Property held for future use 48,814 - 1,053 (16) 156,724 204,469 Plant In Service-CWIP in rate base - - - - (14,786) (14,786) Louisiana regulatory asset - - - - 71,367 71,367 Natural Gas: Intangible 377 69 - - - 446 Transmission 6,504 409 1 - - 6,912 Distribution 97,324 3,264 489 - 41,454 141,553 General 6,194 15 - - 1,332 7,541 Steam Products Plant: Production - - - - 70,615 70,615 Distribution - - - - 4,811 4,811 General - - - - 263 263 Construction work in progress 309,552 179,425 5,672 (273) 50,080 533,112 Nuclear fuel 254,299 242,259 244,193 - 94,828 347,193 Plant acquisition adjustments 1,133 - - (85) 380,117 381,165 ----------- -------- -------- -------- ---------- ----------- Total Utility Plant $15,202,624 $752,945 $331,852 $463 $7,555,528 $23,179,708 =========== ======== ======== ======== ========== =========== ___________ Notes: (1) Includes amounts associated with the Grand Gulf 1 and Waterford 3 sale and leaseback transactions. (2) Transfers among functional groups of accounts $31 =========== (3) Amortization of plant acquisition adjustments $(85) Transfers to non-utility plant (12,232) Transfers to preliminary survey and investigation charges (273) Transfers to construction work in progress (19) Transfers to electric utility plant - production 13,072 ----------- Total $463 =========== (4) Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation provisions on average depreciable property approximated 3% in 1993.
ENTERGY CORPORATION AND SUBSIDIARIES SCHEDULE V - UTILITY PLANT Year Ended December 31, 1992 (In Thousands)
- ------------------------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Column F Other Changes- Balance at Retirements Debits Balance Classification Beginning Additions or Sales (Credits) at End (Note 4) of Period at Cost (Notes 5-6) (Notes 2-3) of Period - ------------------------------------------------------------------------------------------------------------------------ Electric Utility Plant: Intangible $66,118 $24,339 $(234) $122 $90,813 Production 8,955,524 129,225 51,547 (11) 9,033,191 Transmission 1,363,773 46,623 9,076 (34) 1,401,286 Distribution 2,715,057 165,786 69,887 (15) 2,810,941 General 295,033 47,921 19,464 151,162 474,652 Leased to others 5,144 - - - 5,144 Leased from others (Note 1) 662,150 3,822 3,572 - 662,400 Plant held for future use 47,842 2 3,315 4,285 48,814 Natural Gas: Intangible 377 - - - 377 Transmission 6,488 16 - - 6,504 Distribution 92,465 5,149 290 - 97,324 General 5,630 569 5 - 6,194 Construction work in progress 305,916 3,649 - (13) 309,552 Nuclear fuel 290,136 86,457 120,172 (2,122) 254,299 Plant acquisition adjustments 1,367 - - (234) 1,133 ----------- -------- -------- -------- ----------- Total Utility Plant $14,813,020 $513,558 $277,094 $153,140 $15,202,624 =========== ======== ======== ======== =========== ___________ Notes: (1) Includes amounts associated with the Grand Gulf 1 and Waterford 3 sale and leaseback transactions. (2) Transfers among functional groups of accounts $164 (3) Amortization of plant acquisition adjustments $(234) Transfers of service companies' property to electric utility plant - general 151,221 from other property Transfers to construction work in progress 191 Transfers to non-utility plant (21) Transfers to preliminary survey and investigation charges (205) Refund of state sales tax and related interest paid under protest (2,122) FERC Complaint Case Settlement 4,310 ---------- Total $153,140 (4) Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation provisions on average depreciable property approximated 3.0% in 1992. (5) Transfers to Entergy Services from General Plant $183 ========== (6) Sales of Missouri property $52,783 ==========
ENTERGY CORPORATION AND SUBSIDIARIES SCHEDULE V - UTILITY PLANT Year Ended December 31, 1991 (In Thousands)
- ------------------------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Column F Other Changes- Balance at Debits Balance Classification Beginning Additions Retirements (Credits) at End (Note 4) of Period at Cost or Sales (Notes 2-3) of Period - ------------------------------------------------------------------------------------------------------------------------ Electric Utility Plant: Intangible $48,362 $17,996 $240 - $66,118 Production 8,900,671 96,732 26,249 $(15,630) 8,955,524 Transmission 1,290,481 75,112 1,794 (26) 1,363,773 Distribution 2,577,101 160,656 22,703 3 2,715,057 General 288,044 27,688 8,925 (11,774) 295,033 Leased to others 5,144 - - - 5,144 Leased from others (Note 1) 660,291 2,798 939 - 662,150 Plant held for future use 39,426 1,053 365 7,728 47,842 Natural Gas: Intangible 141 236 - - 377 Transmission 6,500 (12) - - 6,488 Distribution 88,435 4,326 296 - 92,465 General 6,078 (316) 132 - 5,630 Construction work in progress 305,888 3,721 - (3,693) 305,916 Nuclear fuel 373,016 124,717 208,547 950 290,136 Plant acquisition adjustments 1,763 - - (396) 1,367 ----------- -------- -------- -------- ----------- Total Utility Plant $14,591,341 $514,707 $270,190 $(22,838) $14,813,020 =========== ======== ======== ======== =========== ___________ Notes: (1) Includes amounts associated with the Grand Gulf 1 and Waterford 3 sale and leaseback transactions. (2) Transfers among functional groups of accounts $15,802 =========== (3) Amortization of plant acquisition adjustments $(396) Transfers to preliminary survey and investigation charges (3,693) State sales tax and related interest paid under protest 950 FERC Complaint Case Settlement 7,694 Lease reclassification (27,393) ----------- Total $(22,838) =========== (4) Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation provisions on average depreciable property approximated 3.0% in 1991.
ARKANSAS POWER & LIGHT COMPANY SCHEDULE V - UTILITY PLANT Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ----------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Changes- Balance at Retirements Debits Balance Classification Beginning Additions or Sales (Credits) at End (Note 3) of Period at Cost (Note 2) (Notes 1) of Period - ----------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 1993 Electric Utility Plant: Intangible $88,233 $14,687 $22,847 $(19,105) $60,968 Production 2,131,637 48,661 8,380 6,952 2,178,870 Transmission 644,321 10,032 1,091 - 653,262 Distribution 1,081,852 63,222 12,263 - 1,132,811 General 117,244 11,423 870 (79) 127,718 Plant held for future use 6,605 - - - 6,605 Construction work in progress 174,909 22,096 - - 197,005 Nuclear fuel 102,435 50,299 59,128 - 93,606 Plant acquisition adjustments 298 - - (38) 260 ---------- -------- -------- -------- ---------- Total Utility Plant $4,347,534 $220,420 $104,579 $(12,270) $4,451,105 ========== ======== ======== ======== ========== Year Ended December 31, 1992 Electric Utility Plant: Intangible $64,948 $23,290 $5 - $88,233 Production 2,098,632 37,531 4,526 - 2,131,637 Transmission 636,928 15,519 8,126 - 644,321 Distribution 1,079,660 56,856 54,664 - 1,081,852 General 116,611 7,749 7,116 - 117,244 Plant held for future use 6,625 2 - $(22) 6,605 Construction work in progress 139,773 35,136 - - 174,909 Nuclear fuel 121,689 36,624 55,878 - 102,435 Plant acquisition adjustments 340 - - (42) 298 ---------- -------- -------- -------- ---------- Total Utility Plant $4,265,206 $212,707 $130,315 $(64) $4,347,534 ========== ======== ======== ======== ========== Year Ended December 31, 1991 Electric Utility Plant: Intangible $47,007 $17,941 - - $64,948 Production 2,060,032 45,319 $6,719 - 2,098,632 Transmission 625,244 12,214 530 - 636,928 Distribution 1,022,421 66,419 9,180 - 1,079,660 General 130,685 6,490 2,926 $(17,638) 116,611 Plant held for future use 6,625 - - - 6,625 Construction work in progress 138,185 1,588 - - 139,773 Nuclear fuel 151,793 34,883 64,987 - 121,689 Plant acquisition adjustments 387 - - (47) 340 ---------- -------- -------- -------- ---------- Total Utility Plant $4,182,379 $184,854 $84,342 $(17,685) $4,265,206 ========== ======== ======== ======== ========== ___________ Notes: 1993 1992 1991 ---- ---- ---- (1) Amortization of plant acquisition adjustments $(38) $(42) $(47) Transfers to non-utility plant (12,232) (22) - Lease reclassifications - - (17,638) -------- -------- ---------- Total $(12,270) $(64) $(17,685) ======== ======== ========== (2) Includes amounts associated with: Transfer to Entergy Services from General Plant - $183 $2,808 Sale of Missouri Property - 52,783 - -------- -------- ---------- Total - $52,966 $2,808 ======== ======== ========== (3) Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation provisions on average depreciable property approximated 3.4% in 1993, 1992, and 1991.
GULF STATES UTILITIES COMPANY SCHEDULE V - UTILITY PLANT Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ----------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Changes - Balance at Additions Retirements Debits Balance at Classification Beginning at Cost or Sales (Credits) End of (Note 5) of Period (Note 1) (Note 2) (Note 3) Period - ----------------------------------------------------------------------------------------------------------------------- Year ended December 31, 1993 Electric Utility Plant: Production $4,582,874 $7,354 $18,287 $(30) $4,571,911 Transmission 821,013 13,214 799 302 833,730 Distribution 1,034,708 64,318 15,091 (307) 1,083,628 General 118,184 5,867 639 3 123,415 Capital leases 87,214 911 2,086 - 86,039 Property held for future use 156,657 67 - - 156,724 Plant In Service-CWIP in rate base (14,786) - - - (14,786) Louisiana regulatory asset 71,367 - - - 71,367 Natural Gas Utility Plant: Distribution 39,994 1,501 41 - 41,454 General 1,166 211 45 - 1,332 Steam Products Plant: Production 67,209 4,145 739 - 70,615 Distribution 4,818 1 8 - 4,811 General 265 - 2 - 263 Construction work in progress 32,305 17,775 - - 50,080 Nuclear fuel 106,565 19,261 30,998 - 94,828 ---------- -------- ------- ---- ---------- Total Utility Plant $7,109,553 $134,625 $68,735 $(32) $7,175,411 ========== ======== ======= ==== ========== Year ended December 31, 1992 Electric Utility Plant: Production $4,610,743 $33,232 $61,130 $29 $4,582,874 Transmission 807,025 12,260 1,546 3,274 821,013 Distribution 998,406 47,281 7,698 (3,281) 1,034,708 General 113,210 5,624 636 (14) 118,184 Capital leases 19,012 68,948 746 - 87,214 Property held for future use 157,293 (9) 630 3 156,657 Plant In Service-CWIP in rate base (14,786) - - - (14,786) Louisiana regulatory asset 71,367 - - - 71,367 Natural Gas Utility Plant: Distribution 39,027 1,136 169 - 39,994 General 1,062 112 8 - 1,166 Steam Products Plant: Production 66,414 804 9 - 67,209 Distribution 4,729 89 - - 4,818 General 265 1 1 - 265 Construction work in progress 36,538 (4,233) - - 32,305 Nuclear fuel 107,071 18,074 18,580 - 106,565 ---------- -------- ------- ---- ---------- Total Utility Plant $7,017,376 $183,319 $91,153 $11 $7,109,553 ========== ======== ======= ==== ==========
GULF STATES UTILITIES COMPANY SCHEDULE V - UTILITY PLANT (Continued) Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ----------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Changes - Balance at Additions Retirements Debits Balance at Classification Beginning at Cost or Sales (Credits) End of (Note 5) of Period (Note 1) (Note 2) (Note 3) Period - ----------------------------------------------------------------------------------------------------------------------- Year ended December 31, 1991 Electric Utility Plant: Production $4,600,833 $11,095 $1,122 $ (63) $4,610,743 Transmission 794,872 13,673 3,762 2,242 807,025 Distribution 964,420 46,099 9,866 (2,247) 998,406 General 108,463 4,987 259 19 113,210 Capital leases 19,423 - 411 - 19,012 Plant purchased or sold - - - - - Property held for future use 157,449 (156) 1 1 157,293 Plant In Service-CWIP in rate base (14,648) (138) - - (14,786) Louisiana regulatory asset (Note 4) - - - 71,367 71,367 Natural Gas Utility Plant: Distribution 38,522 593 88 - 39,027 General 970 97 5 - 1,062 Steam Products Plant: Production 66,313 333 294 62 66,414 Distribution 4,722 - - 7 4,729 General 262 5 2 - 265 Construction work in progress 24,576 11,962 - - 36,538 Nuclear fuel 135,285 13,958 42,172 - 107,071 ---------- -------- ------- ------- ---------- Total Utility Plant $6,901,462 $102,508 $57,982 $71,388 $7,017,376 ========== ======== ======= ======= ========== ___________ Notes: (1) Additions at cost, as detailed in Column C, consist primarily of construction expenditures, net of amounts transferred to plant-in-service, and expenditures for ordinary extensions and improvements of GSU's transmission and distribution system. (2) In 1992, GSU changed its accounting procedures to include in inventory, power plant materials and supplies previously expensed or capitalized as plant in service. The effect of the change was to decrease amounts previously capitalized as plant in service by $35.7 million. (3) Represents various transfers between functional accounts. (4) In accordance with a rate order in Louisiana effective March 1, 1991, the LPSC required GSU to modify its treatment of certain flow through benefits related to Allowance for Funds Used During Construction recorded on capital expenditures prior to 1986. Accordingly, GSU increased utility plant by $71.4 million, increased accumulated depreciation by $8.4 million and increased the balance of accumulated deferred income taxes by $63 million. (5) Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation provisions on average depreciable property approximated 2.7% in 1993, 1992, and 1991.
LOUISIANA POWER & LIGHT COMPANY SCHEDULE V - UTILITY PLANT Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ----------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Changes- Balance at Debits Balance Classification Beginning Additions Retirements (Credits) at End (Note 4) of Period at Cost or Sales (Notes 1-2) of Period - ----------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 1993 Electric Utility Plant: Intangible $2,222 $968 - - $3,190 Production 3,004,940 20,533 $11,903 $(1) 3,013,569 Transmission 367,794 8,994 1,675 (15) 375,098 Distribution 1,105,360 56,547 10,437 (11) 1,151,459 General 91,834 6,615 1,029 27 97,447 Leased to others 5,144 - - - 5,144 Leased from others (Note 3) 225,083 - - - 225,083 Plant held for future use 114 - - - 114 Construction work in progress 67,535 66,274 - (273) 133,536 Nuclear fuel 66,627 27,894 29,323 - 65,198 Plant acquisition adjustments 2 - - (2) - ---------- -------- ------- ----- ---------- Total Utility Plant $4,936,655 $187,825 $54,367 $(275) $5,069,838 ========== ======== ======= ===== ========== Year Ended December 31, 1992 Electric Utility Plant: Intangible $811 $1,050 ($239) $122 $2,222 Production 2,957,433 57,501 9,984 (10) 3,004,940 Transmission 349,237 19,233 657 (19) 367,794 Distribution 1,044,647 70,204 9,458 (33) 1,105,360 General 74,513 25,240 7,859 (60) 91,834 Leased to others 5,144 - - - 5,144 Leased from others (Note 3) 223,740 1,343 - - 225,083 Plant held for future use 114 - - - 114 Construction Work in Progress 93,954 (26,214) - (205) 67,535 Nuclear Fuel 64,022 38,540 33,813 (2,122) 66,627 Plant Acquisition Adjustments 12 - - (10) 2 ---------- -------- ------- ------- ---------- Total Utility Plant $4,813,627 $186,897 $61,532 $(2,337) $4,936,655 ========== ======== ======= ======= ==========
LOUISIANA POWER & LIGHT COMPANY SCHEDULE V - UTILITY PLANT (Continued) Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ------------------------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Column F Other Changes- Balance at Debits Balance Classification Beginning Additions Retirements (Credits) at End (Note 4) of Period at Cost or Sales (Notes 1-2) of Period - ------------------------------------------------------------------------------------------------------------------------ Year Ended December 31, 1991 Electric Utility Plant: Intangible $1,034 $17 $240 - $811 Production 2,930,598 32,330 5,465 $(30) 2,957,433 Transmission 322,982 26,740 493 8 349,237 Distribution 986,725 66,072 8,153 3 1,044,647 General 69,240 12,121 683 (6,165) 74,513 Leased to others 5,144 - - - 5,144 Leased from others (Note 3) 221,792 1,948 - - 223,740 Plant held for future use 114 - - - 114 Construction work in progress 101,752 (4,105) - (3,693) 93,954 Nuclear fuel 86,869 8,556 32,353 950 64,022 Plant acquisition adjustments 179 - - (167) 12 ---------- -------- ------- ------- ---------- Total Utility Plant $4,726,429 $143,679 $47,387 $(9,094) $4,813,627 ========== ======== ======= ======= ========== ___________ Notes: 1993 1992 1991 ---- ---- ---- (1) Transfers among functional groups of accounts $27 $122 $30 ======= ======= ========== (2) Amortization of plant acquisition adjustments $(2) $(10) $(167) Transfers to preliminary survey and investigation charges (273) (205) (3,693) State sales tax and related interest paid under protest (refunded) - (2,122) 950 Lease reclassifications - - (6,184) ------- ------- ---------- Total $(275) $(2,337) $(9,094) ======= ======= ========== (3) Includes amounts associated with the portion of Waterford 3 placed under lease (4) Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation provisions on average depreciable property approximated 2.9% in 1993, 1992, and 1991.
MISSISSIPPI POWER & LIGHT COMPANY SCHEDULE V - UTILITY PLANT Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ------------------------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Column F Other Changes- Balance at Debits Balance Classification Beginning Additions Retirements (Credits) at End (Note 3) of Period at Cost or Sales (Notes 1-2) of Period - ------------------------------------------------------------------------------------------------------------------------ Year Ended December 31, 1993 Electric Utility Plant: Intangible - $475 - - $475 Production $562,883 114 $100 - $562,897 Transmission 336,677 2,874 288 $(4) 339,259 Distribution 392,523 25,006 4,196 1 413,334 General 70,189 2,472 494 - 72,167 Plant held for future use 2,147 - 1,053 3 1,097 Construction work in progress 25,879 36,820 - - 62,699 Plant acquisition adjustments 45 - - (45) - ---------- ------- ------- -------- ---------- Total Utility Plant $1,390,343 $67,761 $6,131 $(45) $1,451,928 ========== ======= ======= ======== ========== Year Ended December 31, 1992 Electric Utility Plant: Production $559,732 $3,442 $290 $(1) $562,883 Transmission 325,783 11,132 251 13 336,677 Distribution 368,577 28,188 4,232 (10) 392,523 General 67,482 6,649 3,943 1 70,189 Plant held for future use 5,465 - 3,315 (3) 2,147 Construction work in progress 21,219 4,660 - - 25,879 Plant acquisition adjustments 227 - - (182) 45 ---------- ------- ------- -------- ---------- Total Utility Plant $1,348,485 $54,071 $12,031 $(182) $1,390,343 ========== ======= ======= ======== ========== Year Ended December 31, 1991 Electric Utility Plant: Production $572,338 $3,279 $216 $(15,669) $559,732 Transmission 293,788 32,771 742 (34) 325,783 Distribution 352,449 20,408 4,280 - 368,577 General 51,323 9,272 5,211 12,098 67,482 Plant held for future use 4,743 1,053 365 34 5,465 Construction work in progress 25,412 (4,193) - - 21,219 Plant acquisition adjustments 409 - - (182) 227 ---------- ------- ------- -------- ---------- Total Utility Plant $1,300,462 $62,590 $10,814 $(3,753) $1,348,485 ========== ======= ======= ======== ========== ___________ Notes: 1993 1992 1991 ---- ---- ---- (1) Transfers among functional groups of accounts $4 $14 $15,703 ======= ======== ========== (2) Amortization of plant acquisition adjustments $(45) $(182) $(182) Lease reclassifications - - (3,571) ------- -------- ---------- Total $(45) $(182) $(3,753) ======= ======== ========== (3) Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation provisions on average depreciable property approximated 2.4%, 2.5%, and 2.4% in 1993, 1992, and 1991, respectively.
NEW ORLEANS PUBLIC SERVICE INC. SCHEDULE V - UTILITY PLANT Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ----------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Changes- Balance at Debits Balance Classification Beginning Additions Retirements (Credits) at End (Note 2) of Period at Cost or Sales (Note 1) of Period - ----------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 1993 Electric Utility Plant: Intangible - $548 - - $548 Production $128,283 481 $74 - 128,690 Transmission 50,467 404 - - 50,871 Distribution 231,208 10,179 1,166 - 240,221 General 32,842 285 - - 33,127 Plant held for future use 23,519 - - - 23,519 Natural Gas: Intangible 377 69 - - 446 Transmission 6,504 409 1 - 6,912 Distribution 97,324 3,264 489 - 100,099 General 6,194 15 - - 6,209 Construction work in progress 6,906 8,299 - - 15,205 -------- ------- ------ ---- -------- Total Utility Plant $583,624 $23,953 $1,730 - $605,847 ======== ======= ====== ==== ======== Year Ended December 31, 1992 Electric Utility Plant: Production $125,706 $2,650 $73 - $128,283 Transmission 49,798 739 42 $(28) 50,467 Distribution 222,175 10,538 1,533 $28 231,208 General 25,096 8,283 537 - 32,842 Plant held for future use 23,519 - - - 23,519 Natural Gas: Intangible 377 - - - 377 Transmission 6,488 16 - - 6,504 Distribution 92,465 5,149 290 - 97,324 General 5,630 569 5 - 6,194 Construction work in progress 14,146 (7,240) - - 6,906 -------- ------- ------ ---- -------- Total Utility Plant $565,400 $20,704 $2,480 - $583,624 ======== ======= ====== ==== ======== Year Ended December 31, 1991 Electric Utility Plant: Production $123,134 $2,518 $15 $69 $125,706 Transmission 46,440 3,387 29 - 49,798 Distribution 215,507 7,758 1,090 - 222,175 General 25,426 (195) 66 (69) 25,096 Plant held for future use 23,519 - - - 23,519 Natural Gas: Intangible 141 236 - - 377 Transmission 6,500 (12) - - 6,488 Distribution 88,435 4,326 296 - 92,465 General 6,078 (316) 132 - 5,630 Construction work in progress 12,552 1,594 - - 14,146 -------- ------- ------ ---- -------- Total Utility Plant $547,732 $19,296 $1,628 - $565,400 ======== ======= ====== ==== ======== ___________ Notes: 1993 1992 1991 ---- ---- ---- (1) Transfers among functional groups of accounts - $28 $69 ==== ==== ===== (2) Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation provisions on average depreciable property approximated 3.1% in 1993 and 1992 and 3.2% in 1991.
SYSTEM ENERGY RESOURCES, INC. SCHEDULE V - UTILITY PLANT Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ----------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Changes- Balance at Debits Balance Classification Beginning Additions Retirements (Credits) at End (Note 3) of Period at Cost or Sales (Note 1) of Period - ----------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 1993 Electric Utility Plant: Production $3,002,812 $11,678 $3,363 - $3,011,127 Leased from others (Note 2) 437,317 773 149 - 437,941 Plant held for future use 16,429 - - $(19) 16,410 Construction work in progress 30,658 10,784 - - 41,442 Nuclear fuel 67,991 46,258 34,624 - 79,625 ---------- ------- ------- ----- ---------- Total Utility Plant $3,555,207 $69,493 $38,136 $(19) $3,586,545 ========== ======= ======= ===== ========== Year Ended December 31, 1992 Electric Utility Plant: Production $3,011,223 $28,101 $36,512 - $3,002,812 Leased from others (Note 2) 438,410 2,479 3,572 - 437,317 Plant held for future use 12,119 - - $4,310 16,429 Construction work in progress 34,091 (3,433) - - 30,658 Nuclear fuel 99,575 - 31,584 - 67,991 ---------- ------- ------- ------ ---------- Total Utility Plant $3,595,418 $27,147 $71,668 $4,310 $3,555,207 ========== ======= ======= ====== ========== Year Ended December 31, 1991 Electric Utility Plant: Production $3,011,911 $12,953 $13,641 - $3,011,223 Leased from others (Note 2) 438,499 850 939 - 438,410 Plant held for future use 4,425 - - $7,694 12,119 Construction work in progress 26,491 7,600 - - 34,091 Nuclear fuel 133,908 28,922 63,255 - 99,575 ---------- ------- ------- ------ ---------- Total Utility Plant $3,615,234 $50,325 $77,835 $7,694 $3,595,418 ========== ======= ======= ====== ========== ___________ Notes: 1993 1992 1991 ---- ---- ---- (1) Transfer to construction work in progress $(19) - - Transfer of reusable salvage to appropriate accounts - $4,310 - FERC Complaint Case Settlement - - $7,694 ------ ------ ---------- Total $(19) $4,310 $7,694 ====== ====== ========== (2) Includes amounts associated with the Grand Gulf 1 sale and leaseback transactions. (3) Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation provisions on average depreciable property approximated 2.9% in 1993, 1992, and 1991.
ENTERGY CORPORATION AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY Year Ended December 31, 1993 (In Thousands)
- ----------------------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Column G Other Additions Deductions Changes ---------------------- ------------ --------- Charged Balance at to Other Retirements Debits Balance Beginning Charged to Accounts Renewals and (Credits) Acquisition of at End Description of Period Income (Note 1) Replacements (Note 2) GSU of Period - ----------------------------------------------------------------------------------------------------------------------------------- Accumulated Depreciation of Utility Plant: Electric: Intangible $40,521 $10,823 $72 $22,848 $(4,199) - $24,369 Production 2,693,231 260,440 378 21,973 (495) $1,393,679 4,325,260 Transmission 458,957 38,805 - 2,817 - 376,714 871,659 Distribution 1,015,641 96,604 - 32,016 - 424,826 1,505,055 General 123,548 24,258 2,178 179 (35) 45,202 194,972 Leased to others 5,144 - - - - - 5,144 Leased from others (Note 3) 70,529 5,847 14,712 149 - - 90,939 Plant held for future use 5,550 - - - - - 5,550 Depreciation-CWIP in rate base - - - - - (3,504) (3,504) Regulatory item - - - - - 6,735 6,735 Natural Gas: Transmission 4,936 41 - 2 - 4,975 Distribution 41,645 2,614 - 895 - 25,423 68,787 General 2,991 322 - - - 426 3,739 Steam Products: Production - - - - - 49,456 49,456 Distribution - - - - - 4,659 4,659 General - - - - - 188 188 ---------- -------- ------- ------- ------- ---------- ---------- Total $4,462,693 $439,754 $17,340 $80,879 $(4,729) $2,323,804 $7,157,983 ___________ ========== ======== ======= ======= ======= ========== ========== Notes: (1) Provision on basis of usage or estimated life of transportation equipment (automobiles, trucks and aircraft) charged to clearing accounts and allocated on the basis of the use of such equipment $1,502 Provision on basis of usage of other tangible property (coal mining equipment) charged to account(s) and allocated to operating expense as a portion of the cost of coal burned 608 Amortization of equipment charged to fuel expense 518 Depreciation expense deferrals associated with the Grand Gulf 1 sale and leaseback transactions consistent with the FERC audit 14,712 ---------- Total $17,340 ========== (2) Transfer of net gain on sale of property from reserve $(35) Reclassify ISES Synchronization costs as a regulatory asset (4,199) Sale of property (land) in MS credited to Gain on Disposition (495) ---------- Total $(4,729) ========== (3) Includes amounts associated with the Grand Gulf 1 and Waterford 3 sale and leaseback transactions.
ENTERGY CORPORATION AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY Year Ended December 31, 1992 (In Thousands)
- --------------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Additions Deductions Changes --------------------- ------------ --------- Charged Retirements Balance at to Other Renewals and Debits Balance Beginning Charged to Accounts Replacements (Credits) at End Description of Period Income (Note 1) (Note 4) (Note 2) of Period - ---------------------------------------------------------------------------------------------------------------------------- Accumulated Depreciation of Utility Plant: Electric: Intangible $32,550 $7,975 - $4 - $40,521 Production 2,390,095 273,149 $336 48,115 $77,766 2,693,231 Transmission 426,733 34,923 - 2,655 (44) 458,957 Distribution 968,071 89,685 - 42,058 (57) 1,015,641 General 72,009 8,063 1,913 14,723 56,286 123,548 Leased to others 5,144 - - - - 5,144 Leased from others (Note 3) 53,497 5,794 14,810 3,572 - 70,529 Plant held for future use 5,550 - - - - 5,550 Natural Gas: Transmission 4,897 39 - - - 4,936 Distribution 39,712 2,516 - 583 - 41,645 General 2,709 265 - (17) - 2,991 ---------- -------- ------- -------- -------- ---------- Total $4,000,967 $422,409 $17,059 $111,693 $133,951 $4,462,693 ========== ======== ======= ======== ======== ========== ___________ Notes: (1) Provision on basis of usage or or estimated life of transportation equipment (automobiles, trucks and aircraft) charged to clearing accounts and allocated on the basis of the use of such equipment $966 Provision on basis of usage of other tangible property (coal mining equipment) charged to account(s) and allocated to operating expense as a portion of the cost of coal burned 946 Amortization of equipment charged to fuel expense 688 Removal cost of Ritchie 2 (248) Salvage on coal mining equipment (103) Represents depreciation expense deferrals associted with the Grand Gulf 1 sale and leaseback transactions consistent with the FERC audit 14,810 ---------- Total $17,059 ========== (2) Transfer of net gain on sale of property from reserve $(219) Transfers of depreciation on service company property from other investments and special funds 56,350 ANO Decommissioning Trust Fund transferred to investments 77,820 ---------- Total $133,951 ========== (3) Includes amounts associated with the Grand Gulf 1 and Waterford 3 sale and leaseback transactions. (4) Includes transfer of reserve related to the sale of Missouri property $18,415 ==========
ENTERGY CORPORATION AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY Year Ended December 31, 1991 (In Thousands)
- --------------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Additions Deductions Changes ---------------------- ----------- -------- Charged Balance at to Other Retirements Debits Balance Beginning Charged to Accounts Renewals and (Credits) at End Description of Period Income (Note 1) Replacements (Note 2) of Period - ---------------------------------------------------------------------------------------------------------------------------- Accumulated Depreciation of Utility Plant: Electric: Intangible $27,020 $5,530 - - - $32,550 Production 2,176,179 253,828 $(13,111) $27,025 $224 2,390,095 Transmission 395,208 33,705 - 2,115 (65) 426,733 Distribution 905,591 86,370 - 23,951 61 968,071 General 66,502 7,147 1,693 3,336 3 72,009 Leased to others 5,144 - - - - 5,144 Leased from others (Note 3) 36,664 2,883 14,888 938 53,497 Plant held for future use 5,550 - - - - 5,550 Natural Gas: Transmission 4,859 38 - - - 4,897 Distribution 37,849 2,412 - 549 - 39,712 General 2,721 267 - 279 - 2,709 ---------- -------- ------ ------- ---- ---------- Total $3,663,287 $392,180 $3,470 $58,193 $223 $4,000,967 ========== ======== ====== ======= ==== ========== ___________ Notes: (1) Provision on basis of usage or estimated life of transportation equipment (automobiles trucks and aircraft) charged to clearing accounts and allocated on the basis of the use of such equipment $806 Provision on basis of usage of other tangible property (coal mining equipment) charged to account(s) and allocated to operating expense as a portion of the cost of coal burned 887 Amortization of equipment charged to fuel expense 641 ANO Decommissioning Trust Fund Contribution (13,765) Removal cost of Ritchie 2 (9) Salvage on coal mining equipment 22 Depreciation expense deferrals associated with the Grand Gulf 1 sale and leaseback transactions consistent with the FERC audit 14,888 ---------- Total $3,470 ========== (2) Transfer of net gain on sale of property from reserve $(4) Reclassification of decommissioning amounts pursuant to LPSC order 224 Adjustment to the 1989 retirement of the sold portion of Waterford 3 1 Donation of property 2 ---------- Total $223 ========== (3) Includes amounts associated with the Grand Gulf 1 and Waterdford 3 sale and leaseback transactions.
ARKANSAS POWER & LIGHT COMPANY SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- --------------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Additions Deductions Changes --------------------- ------------ --------- Charged Retirements Balance at to Other Renewals and Debits Balance Beginning Charged to Accounts Replacements (Credits) at End Description of Period Income (Note 1) (Note 3) (Note 2) of Period - ---------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 1993 Accumulated Depreciation of Utility Plant: Electric: Intangible $40,353 $10,799 - $22,848 $(4,199) $24,105 Production 858,332 74,487 - 8,520 - 924,299 Transmission 207,115 16,227 - 1,225 - 222,117 Distribution 376,260 36,117 - 13,607 - 398,770 General 25,309 3,525 608 (35) - 29,477 Plant held for future use 5,550 - - - - 5,550 ---------- -------- ------- ------- ------- ---------- Total $1,512,919 $141,155 $608 $46,165 $(4,199) $1,604,318 ========== ======== ======= ======= ======= ========== Year Ended December 31, 1992 Accumulated Depreciation of Utility Plant: Electric: Intangible $32,454 $7,903 - $4 - $40,353 Production 713,531 70,322 - 3,287 $77,766 858,332 Transmission 194,749 15,932 - 3,522 (44) 207,115 Distribution 367,363 35,022 - 26,142 17 376,260 General 25,872 3,280 $569 4,348 (64) 25,309 Plant held for future use 5,550 - - - - 5,550 ---------- -------- ------- ------- ------- ---------- Total $1,339,519 $132,459 $569 $37,303 $77,675 $1,512,919 ========== ======== ======= ======= ======= ========== Year Ended December 31, 1991 Accumulated Depreciation of Utility Plant: Electric: Intangible $26,999 $5,455 - - - 32,454 Production 665,081 69,553 $(13,765) $7,338 - 713,531 Transmission 179,670 15,800 - 656 ($65) 194,749 Distribution 343,347 34,540 - 10,585 $61 367,363 General 25,055 3,062 574 2,819 - 25,872 Plant held for future use 5,550 - - - - 5,550 ---------- -------- ------- ------- ------- ---------- Total $1,245,702 $128,410 $(13,191) $21,398 ($4) $1,339,519 ========== ======== ======= ======= ======= ========== ___________ Notes: 1993 1992 1991 (1) Provision on basis of usage or estimated life of transportion equipment (automobiles, trucks and aircraft) charged to clearing accounts and allocated on the basis of the use of such equipment - - $61 Provision on basis of usage of other tangible property (coal min- ing equipment) charged to account 151 - Fuel Stock and allocated to operating expenses as a portion of the cost of coal burned $608 $569 513 ANO Decommissioning Trust Fund contribution - - (13,765) ------- ------- ---------- Total $608 $569 $(13,191) ======= ======= ========== (2) Reclassify ISES Synchronization costs as a regulatory asset $(4,199) - - Transfer of net gain on sale of property from reserve - $(145) $(4) ANO Decommissioning Trust Fund transferred to investments - 77,820 - ------- ------- ---------- Total $(4,199) $77,675 $(4) ======= ======= ========== (3) Transfer of reserve related to the sale of Missouri property - $18,415 - ======= ======= ==========
GULF STATES UTILITIES COMPANY SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ------------------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Additions Deductions Changes ------------------------ ------------ --------- Balance at Charged Retirements Debits Balance Beginning Charged to to Other Renewals and (Credits) at End Description of Period Income Accounts Replacements (Note 1) of Period - ------------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 1993 Accumulated Depreciation of Utility Plant: Electric: Production $1,289,802 $120,845 - $18,287 $1,319 $1,393,679 Transmission 355,238 22,635 - 791 (368) 376,714 Distribution 407,350 30,472 - 15,127 2,131 424,826 General 41,989 3,853 - 639 (1) 45,202 Depreciation-CWIP in rate base (3,124) (380) - - - (3,504) Regulatory item 4,860 1,875 - - - 6,735 Natural Gas: Distribution 24,088 1,404 - 41 (28) 25,423 General 412 59 - 45 - 426 Steam Products: Production 47,344 3,003 - 739 (152) 49,456 Distribution 4,589 78 - 8 - 4,659 General 171 19 - 2 - 188 ---------- -------- --- ------- ------ ---------- Total $2,172,719 $183,863 - $35,679 $2,901 $2,323,804 ========== ======== === ======= ====== ========== Year Ended December 31, 1992 Accumulated Depreciation of Utility Plant: Electric: Production $1,191,048 $120,625 - $61,760 $39,889 $1,289,802 Transmission 335,875 22,289 - 1,525 (1,401) 355,238 Distribution 385,964 29,327 - 7,650 (291) 407,350 General 38,850 3,667 - 635 107 41,989 Depreciation-CWIP in rate base (2,744) (380) - - - (3,124) Regulatory item 2,985 1,875 - - - 4,860 Natural Gas: Distribution 22,901 1,369 - 169 (13) 24,088 General 365 54 - 7 - 412 Steam Products: Production 44,441 2,930 - 9 (18) 47,344 Distribution 4,512 77 - - - 4,589 General 154 18 - 1 - 171 ---------- -------- --- ------- ------- ---------- Total $2,024,351 $181,851 - $71,756 $38,273 $2,172,719 ========== ======== === ======= ======= ==========
GULF STATES UTILITIES COMPANY SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY (Continued) Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ----------------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Additions Deductions Changes --------------------- ------------ --------- Balance at Charged Retirements Debits Balance Beginning Charged to to Other Renewals and (Credits) at End Description of Period Income Accounts Replacements (Note 1) of Period - ----------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 1991 Accumulated Depreciation of Utility Plant: Electric: Production $1,063,397 $121,558 - $1,098 $7,191 $1,191,048 Transmission 316,684 21,911 - 3,756 1,036 335,875 Distribution 365,962 28,301 - 9,866 1,567 385,964 General 35,722 3,488 - 258 (102) 38,850 Depreciation-CWIP in rate base (2,368) (377) - - 1 (2,744) Regulatory item (Note 2) - 1,583 - - 1,402 2,985 Natural Gas: Transmission - - - - - - Distribution 21,703 1,351 - 89 (64) 22,901 General 321 49 - 5 - 365 Steam Products: Production 41,891 2,911 - 294 (67) 44,441 Distribution 4,432 76 - - 4 4,512 General 138 18 - 2 - 154 ---------- -------- --- ------- ------- ---------- Total $1,847,882 $180,869 - $15,368 $10,968 $2,024,351 ========== ======== === ======= ======= ========== (1) In 1992, GSU changed its accounting procedures to include in inventory, power plant materials and supplies previously capitalized as plant in service. The effect of the change was to decrease amounts previously capitalized as plant in service by $35.7 million. (2) In accordance with the rate order in Louisiana effective March 1, 1991, the LPSC required GSU to modify its treatment of certain flow through benefits related to Allowance for Funds Used During Construction recorded on capital expenditures prior to 1986. Accordingly GSU increased utility plant by $71.4 million, increased accumulated depreciation by $8.4 million and increased the balance of accumulated deferred income taxes by $63 million. In accordance with the March 1991 PUCT rate order, GSU recognized a regulatory asset of $7 million for depreciation for Big Cajun 2 Unit 3 that was accrued from September 1983 through June 1986.
LOUISIANA POWER & LIGHT COMPANY SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- --------------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Additions Deductions Changes --------------------- ------------ --------- Charged Balance at to Other Retirements Debits Balance Beginning Charged to Accounts Renewals and (Credits) at End Description of Period Income (Note 1) Replacements (Note 2) of Period - ---------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 1993 Accumulated Depreciation of Utility Plant: Electric: Production $786,278 $79,606 - $13,748 - $852,136 Transmission 135,376 13,408 - 1,128 - 147,656 Distribution 418,988 40,787 - 12,111 - 447,664 General 15,919 2,828 $554 183 $(35) 19,083 Leased to others 5,144 - - - - 5,144 Leased from others (Note 3) 18,577 5,847 - - - 24,424 ---------- -------- ---- ------- ---- ---------- Total $1,380,282 $142,476 $554 $27,170 $(35) $1,496,107 ========== ======== ==== ======= ==== ========== Year Ended December 31, 1992 Accumulated Depreciation of Utility Plant: Electric: Production $702,710 $97,058 - $13,490 - $786,278 Transmission 125,143 9,973 - (260) - 135,376 Distribution 392,822 35,760 - 9,520 $(74) 418,988 General 19,393 2,453 $297 6,224 - 15,919 Leased to others 5,144 - - - - 5,144 Leased from others (Note 3) 12,783 5,794 - - - 18,577 ---------- -------- ---- ------- ---- ---------- Total $1,257,995 $151,038 $297 $28,974 $(74) $1,380,282 ========== ======== ==== ======= ==== ========== Year Ended December 31, 1991 Accumulated Depreciation of Utility Plant: Electric: Production $629,381 $78,634 - $5,529 $224 $702,710 Transmission 116,401 9,363 - 621 - 125,143 Distribution 366,582 33,840 - 7,600 - 392,822 General 17,451 2,009 $70 140 3 19,393 Leased to others 5,144 - - - - 5,144 Leased from others (Note 3) 9,900 2,883 - - - 12,783 ---------- -------- ---- ------- ---- ---------- Total $1,144,859 $126,729 $70 $13,890 $227 $1,257,995 ========== ======== ==== ======= ==== ========== ___________ Notes: 1993 1992 1991 (1) Provision on basis of usage or estimate life of transportation equipment (automobiles, trucks and aircraft) charged to clearing accounts and allocated on the basis of the use of such equipment $554 $297 $70 ======= ===== ========== (2) Transfer of gain on sale from reserve to other accounts $(35) $(74) - Donation of property - - 2 Reclassification of decommissioning amounts pursuant to LPSC order - - 224 Adjustment to the 1989 retirement of the sold portions of Waterford 3 - - 1 ------- ----- ---------- Total $(35) $(74) $227 ======= ===== ========== (3) Includes amounts associated with the Waterfird 3 sale and leaseback transactions
MISSISSIPPI POWER & LIGHT COMPANY SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ----------------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Additions Deductions Changes ----------------------- ------------ ----------- Balance at Charged Beginning to Other Retirements Debits Balance of Period Charged to Accounts Renewals and (Credits) at End Description (Note 3) Income (Note 1) Replacements (Notes 2-3) of Period - ----------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 1993 Accumulated Depreciation of Utility Plant: Electric: Intangible - $24 - - - $24 Production $326,821 9,975 $70 $(1,398) $(495) 337,769 Transmission 86,773 7,733 - 453 - 94,053 Distribution 119,375 12,711 - 4,833 - 127,253 General 16,181 1,486 993 31 - 18,629 -------- ------- ------ ------- ------ -------- Total $549,150 $31,929 $1,063 $3,919 $(495) $577,728 ======== ======= ====== ======= ====== ======== Year Ended December 31, 1992 Accumulated Depreciation of Utility Plant: Electric: Production $317,093 $9,945 $70 $287 - $326,821 Transmission 78,531 7,592 - (650) - 86,773 Distribution 111,885 12,170 - 4,680 - 119,375 General 17,117 1,426 1,274 3,636 - 16,181 -------- ------- ------ ------- ------ -------- Total $524,626 $31,133 $1,344 $7,953 - $549,150 ======== ======= ====== ======= ====== ======== Year Ended December 31, 1991 Accumulated Depreciation of Utility Plant: Electric: Production $307,182 $9,852 $70 $11 - $317,093 Transmission 72,168 7,156 - 793 - 78,531 Distribution 105,116 11,479 - 4,710 - 111,885 General 14,866 1,242 1,234 225 - 17,117 -------- ------- ------ ------- ------ -------- Total $499,332 $29,729 $1,304 $5,739 - $524,626 ======== ======= ====== ======= ====== ======== ___________ Notes: 1993 1992 1991 (1) Provision on basis of usage or estimated life of transportation equipment (automobiles, trucks and aircraft) charged to clearing accounts and allocated on the basis of the use of such equipment $545 $656 $663 Amortization of coal mining equipment charged to fuel expense 448 618 571 Amortization of gas pipeline charged to fuel expense 70 70 70 ------- ------ -------- Total $1,063 $1,344 $1,304 ======= ====== ======== (2) Sale of property (land) in MS credited to Gain on Disposition of Property $(495) - - ======= ====== ======== (3) Beginning balances for the year 1991 in Production and General have been changed due to a reclassification of coal mining equipment from production function to general plant. This reclassification was not reflected in the original 1991 balances and thereafter. The balances have been revised for the years 1991 and 1992 to update.
NEW ORLEANS PUBLIC SERVICE INC. SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ----------------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Additions Deductions Changes ----------------------- ------------ --------- Charged Balance at to Other Retirements Balance Beginning Charged to Accounts Renewals and Debits at End Description of Period Income (Note 1) Replacements (Credits) of Period - ----------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 1993 Accumulated Depreciation of Utility Plant: Electric: Production $123,512 $4,775 - $86 - $128,201 Transmission 28,972 1,394 - 11 - 30,355 Distribution 101,017 6,989 - 1,465 - 106,541 General 12,365 1,130 $23 - - 13,518 Gas: Transmission 4,936 41 - 2 - 4,975 Distribution 41,645 2,614 - 895 - 43,364 General 2,992 322 - - - 3,314 -------- ------- --- ------ --- -------- Total $315,439 $17,265 $23 $2,459 - $330,268 ======== ======= === ====== === ======== Year Ended December 31, 1992 Accumulated Depreciation of Utility Plant: Electric: Production $119,049 $4,723 - $260 - $123,512 Transmission 27,640 1,375 - 43 - 28,972 Distribution 96,001 6,732 - 1,716 - 101,017 General 11,954 904 $13 506 - 12,365 Gas: Transmission 4,897 39 - - - 4,936 Distribution 39,712 2,516 - 583 - 41,645 General 2,710 265 - (17) - 2,992 -------- ------- --- ------ --- -------- Total $301,963 $16,554 $13 $3,091 - $315,439 ======== ======= === ====== === ======== Year Ended December 31, 1991 Accumulated Depreciation of Utility Plant: Electric: Production $114,443 $4,629 - $23 - $119,049 Transmission 26,350 1,335 - 45 - 27,640 Distribution 90,546 6,511 - 1,056 - 96,001 General 11,221 834 $12 113 - 11,954 Natural Gas: Transmission 4,859 38 - - - 4,897 Distribution 37,849 2,412 - 549 - 39,712 General 2,722 267 - 279 - 2,710 -------- ------- --- ------ --- -------- Total $287,990 $16,026 $12 $2,065 - $301,963 ======== ======= === ====== === ======== ___________ Notes: 1993 1992 1991 ---- ---- ---- (1) Provision on basis of usage or estimated life of transportation equipment (automobiles, trucks and aircraft) charged to clearing accounts and allocated on the basis of the use of such equipment $23 $13 $12 ====== ==== ========
SYSTEM ENERGY RESOURCES, INC. SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ----------------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Additions Deductions Changes --------------------- ------------ -------- Charged Balance at to Other Retirements Balance Beginning Charged to Accounts Renewals and Debits at End Description of Period Income (Note 1) Replacements (Credits) of Period - ----------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 1993 Accumulated Depreciation of Utility Plant: Electric: Production $520,350 $85,988 - $3,187 - $603,151 Leased from others (Note 2) 51,952 - $14,712 149 - 66,515 -------- ------- ------- ------- ------- -------- Total $572,302 $85,988 $14,712 $3,336 - $669,666 ======== ======= ======= ======= ======= ======== Year Ended December 31, 1992 Accumulated Depreciation of Utility Plant: Electric: Production $465,214 $85,927 - $30,791 - $520,350 Leased from others (Note 2) 40,714 - $14,810 3,572 - 51,952 -------- ------- ------- ------- ------- -------- Total $505,928 $85,927 $14,810 $34,363 - $572,302 ======== ======= ======= ======= ======= ======== Year Ended December 31, 1991 Accumulated Depreciation of Utility Plant: Electric: Production $393,159 $85,986 - $13,931 - $465,214 Leased from others (Note 2) 26,764 - $14,888 938 - 40,714 -------- ------- ------- ------- ------- -------- Total $419,923 $85,986 $14,888 $14,869 - $505,928 ======== ======= ======= ======= ======= ======== ___________ Notes: 1993 1992 1991 ---- ---- ---- (1) Represents depreciation expense deferrals associated with the Grand Gulf 1 sale and leaseback transactions consistent with the FERC audit $14,712 $14,810 $14,888 ======= ======= ======== (2) Includes amounts associated with the Grand Gulf 1 sale and leaseback transactions
ENTERGY CORPORATION AND SUBSIDIARIES SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1993, 1992, and 1991 (In Thousands)
- --------------------------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F Other Additions Changes ---------------------- ---------- Charged Deductions Balance at to Other from Balance Beginning Charged to Accounts Provisions Acquistion at End visions Acquistion at End Description of Period Income (Note 1) (Note 2) of GSU of Period - --------------------------------------------------------------------------------------------------------------------------------- Year ended December 31, 1993 Accumulated Provisions Deducted from Assets-- Doubtful accounts $6,193 $8,565 - $8,333 $2,383 $8,808 ======= ======= ===== ======= ======= ======= Accumulated Provisions Not Deducted from Assets: Property insurance $25,178 $5,714 - $7,217 $10,872 $34,547 Injuries and damages (Note 3) 14,728 8,952 - 13,303 8,714 19,091 Pensions and benefits (Note 4) 11,196 18,757 - 25,479 - 4,474 Misc. operating reserves (Note 5) 500 - - - - 500 Coal car maintenance - - - - 3,430 3,430 ------- ------- ----- ------- ------- ------- Total $51,602 $33,423 - $45,999 $23,016 $62,042 ======= ======= ===== ======= ======= ======= Year ended December 31, 1992 Accumulated Provisions Deducted from Assets-- Doubtful accounts $8,125 $3,654 - $5,586 - $6,193 ======= ======= ===== ======= ======= ======= Accumulated Provisions Not Deducted from Assets: Property insurance (Note 6) $35,058 $10,820 - $20,700 - $25,178 Injuries and damages (Note 3) 13,364 11,053 $20 9,709 - 14,728 Pensions and benefits (Note 4) 11,196 17,792 (597) 17,195 - 11,196 Misc. operating reserves (Note 5) 500 - - - - 500 ------- ------- ----- ------- ------- ------- Total $60,118 $39,665 $(577) $47,604 - $51,602 ======= ======= ===== ======= ======= ======= Year ended December 31, 1991 Accumulated Provisions Deducted from Assets-- Doubtful accounts $8,100 $9,831 - $9,806 - $8,125 ======= ======= ===== ======= ======= ======= Accumulated Provisions Not Deducted from Assets: Property insurance $33,181 $8,594 - $6,717 - $35,058 Injuries and damages (Note 3) 12,664 11,444 $20 10,764 - 13,364 Pensions and benefits (Note 4) 8,683 18,249 732 16,468 - 11,196 Misc. operating reserves (Note 5) - 500 - - - 500 ------- ------- ----- ------- ------- ------- Total $54,528 $38,787 $752 $33,949 - $60,118 ======= ======= ===== ======= ======= ======= ___________ Notes: (1) Charged to clearing and other accounts. (2) 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. (3) 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. (4) Pension and benefits provision is provided to account for provisions made by AP&L for group medical insurance coverage on its employees. (5) Miscellaneous operating reserves represents a reserve provided by MP&L for environmental exposures. (6) Property insurance reserves and insurance reimbursements were adequate to cover expenses associated with Hurricane Andrew.
ARKANSAS POWER & LIGHT COMPANY SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1993, 1992, and 1991 (In Thousands)
- ---------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Other Additions Changes ------------------------ ---------- Charged Deductions Balance at to Other from Balance Beginning Charged to Accounts Provisions at End Description of Period Income (Note 1) (Note 2) of Period - ---------------------------------------------------------------------------------------------------------------- Year ended December 31, 1993 Accumulated Provisions Deducted from Assets-- Doubtful accounts $1,613 $3,439 - $3,002 $2,050 ======= ======= ====== ======= ======= Accumulated Provisions Not Deducted from Assets: Property insurance $5,182 $1,952 - $4,313 $2,821 Injuries and damages (Note 3) 5,851 4,070 - 6,662 3,259 Pensions and benefits (Note 4) 11,196 18,757 - 25,479 4,474 ------- ------- ------ ------- ------- Total $22,229 $24,779 - $36,454 $10,554 ======= ======= ====== ======= ======= Year ended December 31, 1992 Accumulated Provisions Deducted from Assets-- Doubtful accounts $3,430 $(3) - $1,814 $1,613 ======= ======= ====== ======= ======= Accumulated Provisions Not Deducted from Assets: Property insurance $7,827 $4,000 - $6,645 $5,182 Injuries and damages (Note 3) 4,254 7,086 - 5,489 5,851 Pensions and benefits (Note 4) 11,196 17,792 $(597) 17,195 11,196 ------- ------- ------ ------- ------- Total $23,277 $28,878 $(597) $29,329 $22,229 ======= ======= ====== ======= ======= Year ended December 31, 1991 Accumulated Provisions Deducted from Assets-- Doubtful accounts $3,430 $2,946 - $2,946 $3,430 ======= ======= ====== ======= ======= Accumulated Provisions Not Deducted from Assets: Property insurance $9,320 $3,274 - $4,767 $7,827 Injuries and damages (Note 3) 3,571 6,017 - 5,334 4,254 Pensions and benefits (Note 4) 8,683 18,249 $732 16,468 11,196 ------- ------- ----- ------- ------- Total $21,574 $27,540 $732 $26,569 $23,277 ======= ======= ====== ======= ======= ___________ Notes: (1) Charged to clearing and other accounts. (2) 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. (3) 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. (4) Pension and benefits provision is provided to account for provisions made by AP&L for group medical insurance coverage on its employees.
GULF STATES UTILITIES COMPANY SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ---------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Other Additions Changes ----------------------- ---------- Charged Deductions Balance at to Other from Balance Beginning Charged to Accounts Provisions at End Description of Period Income (Note 1) (Note 2) of Period - ---------------------------------------------------------------------------------------------------------------- Year ended December 31, 1993 Accumulated Provisions Deducted from Assets-- Doubtful accounts $2,953 $929 - $1,499 $2,383 ======= ======= ====== ====== ======= Accumulated Provisions Not Deducted from Assets-- Property insurance $9,397 $1,302 - $(173) $10,872 Injuries and damages (Note 3) 6,018 11,317 - 8,621 8,714 Coal car maintenance 2,873 - $1,034 477 3,430 ------- ------- ------ ------ ------- Total $18,288 $12,619 $1,034 $8,925 $23,016 ======= ======= ====== ====== ======= Year ended December 31, 1992 Accumulated Provisions Deducted from Assets-- Doubtful accounts $2,796 $2,271 - $2,114 $2,953 ======= ======= ====== ====== ====== Accumulated Provisions Not Deducted from Assets-- Property insurance $10,975 $(1,578) - - $9,397 Injuries and damages (Note 3) 5,102 2,805 - $1,889 6,018 Coal car maintenance 2,459 - $1,006 592 2,873 ------- ------- ------ ------ ------- Total $18,536 $1,227 $1,006 $2,481 $18,288 ======= ======= ====== ====== ======= Year ended December 31, 1991 Accumulated Provisions Deducted from Assets-- Doubtful accounts $2,636 $1,731 - $1,571 $2,796 ======= ======= ====== ====== ======= Accumulated Provisions Not Deducted from Assets-- Property insurance $8,891 $2,084 - - $10,975 Injuries and damages (Note 3) 5,812 1,783 - $2,493 5,102 Coal car maintenance 2,894 - $959 1,394 2,459 ------- ------- ------ ------ ------- Total $17,597 $3,867 $959 $3,887 $18,536 ======= ======= ====== ====== ======= ___________ Notes: (1) Charged to clearing and other accounts. (2) 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. (3) 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.
LOUISIANA POWER & LIGHT COMPANY SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1993, 1992, and 1991 (In Thousands)
- ---------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Other Additions Changes ------------------------ ---------- Deductions Balance at Charged from Balance Beginning Charged to to Other Provisions at End Description of Period Income Accounts (Note 1) of Period - ---------------------------------------------------------------------------------------------------------------- Year ended December 31, 1993 Accumulated Provisions Deducted from Assets-- Doubtful accounts $1,956 $337 - $1,218 $1,075 ======== ====== ====== ======= ======= Accumulated Provisions Not Deducted from Assets: Property insurance $2,474 $1,800 - $1,886 $2,388 Injuries and damages (Note 2) 6,153 2,748 - 4,122 4,779 -------- ------ ------ ------- ------- Total $8,627 $4,548 - $6,008 $7,167 ======== ====== ====== ======= ======= Year ended December 31, 1992 Accumulated Provisions Deducted from Assets-- Doubtful accounts $1,956 $1,324 - $1,324 $1,956 ======== ====== ====== ======= ======= Accumulated Provisions Not Deducted from Assets: Property insurance (Note 3) $9,174 $4,300 - $11,000 $2,474 Injuries and damages (Note 2) 6,153 2,283 - 2,283 6,153 -------- ------ ------ ------- ------- Total $15,327 $6,583 - $13,283 $8,627 ======== ====== ====== ======= ======= Year ended December 31, 1991 Accumulated Provisions Deducted from Assets-- Doubtful accounts $1,956 $2,298 - $2,298 $1,956 ======== ====== ====== ======= ======= Accumulated Provisions Not Deducted from Assets: Property insurance $7,463 $2,800 - $1,089 $9,174 Injuries and damages (Note 2) 6,153 4,421 - 4,421 6,153 -------- ------ ------ ------- ------- Total $13,616 $7,221 - $5,510 $15,327 ======== ====== ====== ======= ======= ___________ 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. (3) Property insurance reserves and insurance reimbursements were adequate to cover expenses associated with Hurricane Andrew.
MISSISSIPPI POWER & LIGHT COMPANY SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1993, 1992, and 1991 (In Thousands)
- ---------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Other Additions Changes ----------------------- ----------- Charged Deductions Balance at to Other from Balance Beginning Charged to Accounts Provisions at End Description of Period Income (Note 1) (Note 2) of Period - ---------------------------------------------------------------------------------------------------------------- Year ended December 31, 1993 Accumulated Provisions Deducted from Assets-- Doubtful accounts $1,274 $3,629 - $2,433 $2,470 ====== ====== === ====== ====== Accumulated Provisions Not Deducted from Assets: Property insurance $2,051 $1,521 - $1,018 $2,554 Injuries and damages (Note 3) 395 452 - 619 228 Misc. operating reserves (Note 4) 500 - - - 500 ------ ------ --- ------ ------ Total $2,946 $1,973 - $1,637 $3,282 ====== ====== === ====== ====== Year ended December 31, 1992 Accumulated Provisions Deducted from Assets-- Doubtful accounts $1,389 $834 - $949 $1,274 ====== ====== === ====== ====== Accumulated Provisions Not Deducted from Assets: Property insurance (Note 5) $3,300 $1,520 - $2,769 $2,051 Injuries and damages (Note 3) 613 333 $20 571 395 Misc. operating reserves (Note 4) 500 - - - 500 ------ ------ --- ------ ------ Total $4,413 $1,853 $20 $3,340 $2,946 ====== ====== === ====== ====== Year ended December 31, 1991 Accumulated Provisions Deducted from Assets-- Doubtful accounts $1,364 $2,012 - $1,987 $1,389 ====== ====== === ====== ====== Accumulated Provisions Not Deducted from Assets: Property insurance $2,642 $1,520 - $862 $3,300 Injuries and damages (Note 3) 545 577 $20 529 613 Misc. operating reserves (Note 4) - 500 - - 500 ------ ------ --- ------ ------ Total $3,187 $2,597 $20 $1,391 $4,413 ====== ====== === ====== ====== ___________ Notes: (1) Charged to clearing and other accounts. (2) 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. ductions are reduced by recoveries of amounts previously written off. (3) 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. (4) Miscellaneous operating reserves represents a reserve provided by MP&L for environmental exposures. (5) Property insurance reserves and insurance reimbursements were adequate to cover expenses associated with Hurricane Andrew.
NEW ORLEANS PUBLIC SERVICE INC. SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1993, 1992, and 1991 (In Thousands)
- ------------------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Other Additions Changes ------------------------ ----------- Deductions Balance at Charged from Balance Beginning Charged to to Other Provisions at End Description of Period Income Accounts (Note 1) of Period - ------------------------------------------------------------------------------------------------------------------ Year ended December 31, 1993 Accumulated Provisions Deducted from Assets-- Doubtful accounts $1,350 $1,160 - $1,680 $830 ======= ====== ==== ====== ======= Accumulated Provisions Not Deducted from Assets: Property insurance $15,470 $441 - - $15,911 Injuries and damages (Note 2) 2,329 1,682 - $1,900 2,111 ------- ------ ---- ------ ------- Total $17,799 $2,123 - $1,900 $18,022 ======= ====== ==== ====== ======= Year ended December 31, 1992 Accumulated Provisions Deducted from Assets-- Doubtful accounts $1,350 $1,499 - $1,499 $1,350 ======= ====== ==== ====== ======= Accumulated Provisions Not Deducted from Assets: Property insurance $14,755 $1,000 - $285 $15,470 Injuries and damages (Note 2) 2,344 1,351 - 1,366 2,329 ------- ------ ---- ------ ------- Total $17,099 $2,351 - $1,651 $17,799 ======= ====== ==== ====== ======= Year ended December 31, 1991 Accumulated Provisions Deducted from Assets-- Doubtful accounts $1,350 $2,575 - $2,575 $1,350 ======= ====== ==== ====== ======= Accumulated Provisions Not Deducted from Assets: Property insurance $13,755 $1,000 - - $14,755 Injuries and damages (Note 2) 2,395 429 - $480 2,344 ------- ------ ---- ------ ------- Total $16,150 $1,429 - $480 $17,099 ======= ====== ==== ====== ======= ___________ 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 AND SUBSIDIARIES SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ------------------------------------------------------------------------------ Column A Column B Charged to costs and expenses Item (Note 1) - ------------------------------------------------------------------------------ Year Ended December 31, 1993 Taxes, other than payroll and income taxes: Ad Valorem $102,898 State and city franchise 45,892 Other 26,948 -------- Total $175,738 ======== Year Ended December 31, 1992 Taxes, other than payroll and income taxes: Ad Valorem $99,337 State and city franchise 47,086 Other 26,114 -------- Total $172,537 ======== Year Ended December 31, 1991 Taxes, other than payroll and income taxes: Ad Valorem $93,036 State and city franchise 44,886 Other 25,311 -------- Total $163,233 ======== __________ Notes: (1) Taxes other than payroll and income taxes include taxes charged to clearing accounts and distributed from those accounts to appropriate operating and construction accounts or charged directly to construction and other appropriate accounts.
ARKANSAS POWER & LIGHT COMPANY SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ------------------------------------------------------------------------------ Column A Column B Charged to costs and expenses Item (Note 1) - ------------------------------------------------------------------------------ Year Ended December 31, 1993 Taxes, other than payroll and income taxes: Ad Valorem $19,672 State and city franchise 536 Other 11,168 ------- Total $31,376 ======= Year Ended December 31, 1992 Taxes, other than payroll and income taxes: Ad Valorem $18,466 State and city franchise 639 Other 10,357 ------- Total $29,462 ======= Year Ended December 31, 1991 Taxes, other than payroll and income taxes: Ad Valorem $14,972 State and city franchise 675 Other 11,579 ------- Total $27,226 ======= __________ Notes: (1) Taxes other than payroll and income taxes include taxes charged to clearing accounts and distributed from those accounts to appropriate operating and construction accounts or charged directly to construction and other appropriate accounts.
GULF STATES UTILITIES COMPANY SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ------------------------------------------------------------------------------ Column A Column B Charged to costs and expenses Item (Note 1) - ------------------------------------------------------------------------------ Year ended December 31, 1993 Taxes, other than payroll and income taxes: Ad Valorem $31,333 State and city franchise 48,724 Other 5,717 ------- - -- Total $85,774 ======= Year ended December 31, 1992 Taxes, other than payroll and income taxes: Ad Valorem $27,897 State and city franchise 48,853 Other 5,563 ------- Total $82,313 ======= Year ended December 31, 1991 Taxes, other than payroll and income taxes: Ad Valorem $27,104 State and city franchise 46,611 Other 4,384 ------- Total $78,099 ======= __________ Notes: (1) Taxes other than payroll and income taxes include taxes charged to clearing accounts and distributed from those accounts to appropriate operating and construction accounts or charged directly to construction and other appropriate accounts.
LOUISIANA POWER & LIGHT COMPANY SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ------------------------------------------------------------------------------ Column A Column B Charged to costs and expenses Item (Note 1) - ------------------------------------------------------------------------------ Year Ended December 31, 1993 Taxes, other than payroll and income taxes: Ad Valorem $24,706 State and city franchise 18,343 Other 7,041 ------- Total $50,090 ======= Year Ended December 31, 1992 Taxes, other than payroll and income taxes: Ad Valorem $23,045 State and city franchise 17,958 Other 7,842 ------- Total $48,845 ======= Year Ended December 31, 1991 Taxes, other than payroll and income taxes: Ad Valorem $22,365 State and city franchise 17,922 Other 4,663 ------- Total $44,950 ======= __________ Notes: (1) Taxes other than payroll and income taxes include taxes charged to clearing accounts and distributed from those accounts to appropriate operating and construction accounts or charged directly to construction and other appropriate accounts.
MISSISSIPI POWER & LIGHT COMPANY SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ------------------------------------------------------------------------------ Column A Column B Charged to costs and expenses Item (Note 1) - ------------------------------------------------------------------------------ Year Ended December 31, 1993 Taxes, other than payroll and income taxes: Ad Valorem $25,538 State and city franchise 11,287 Other 5,344 ------- Total $42,169 ======= Year Ended December 31, 1992 Taxes, other than payroll and income taxes: Ad Valorem $25,101 State and city franchise 10,533 Other 4,562 ------- Total $40,196 ======= Year Ended December 31, 1991 Taxes, other than payroll and income taxes: Ad Valorem $22,389 State and city franchise 9,810 Other 4,482 ------- Total $36,681 ======= __________ Notes: (1) Taxes other than payroll and income taxes include taxes charged to clearing accounts and distributed from those accounts to appropriate operating and construction accounts or charged directly to construction and other appropriate accounts.
NEW ORLEANS PUBLIC SERVICE INC. SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION Years Ended December 31, 1993, 1992 and 1991 (In Thousands) - ------------------------------------------------------------------------------ Column A Column B Charged to costs and expenses Item (Note 1) - ------------------------------------------------------------------------------ Year Ended December 31, 1993 Taxes, other than payroll and income taxes: Ad Valorem $10,739 State and city franchise 13,350 Other 2,628 ------- Total $26,717 ======= Year Ended December 31, 1992 Taxes, other than payroll and income taxes: Ad Valorem $10,480 State and city franchise 13,903 Other 2,083 ------- Total $26,466 ======= Year Ended December 31, 1991 Taxes, other than payroll and income taxes: Ad Valorem $9,857 State and city franchise 12,965 Other 1,783 ------- Total $24,605 ======= __________ Notes: (1) Taxes other than payroll and income taxes include taxes charged to clearing accounts and distributed from those accounts to appropriate operating and construction accounts or charged directly to construction and other appropriate accounts.
SYSTEM ENERGY RESOURCES, INC. SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
- ------------------------------------------------------------------------------ Column A Column B Charged to costs and expenses Item (Note 1) - ------------------------------------------------------------------------------ Year Ended December 31, 1993 Taxes, other than payroll and income taxes: Ad Valorem $20,001 State and city franchise 2,918 Other 729 ------- Total $23,648 ======= Year Ended December 31, 1992 Taxes, other than payroll and income taxes: Ad Valorem $20,002 State and city franchise 3,877 Other 1,235 ------- Total $25,114 ======= Year Ended December 31, 1991 Taxes, other than payroll and income taxes: Ad Valorem $20,001 State and city franchise 3,697 Other 761 ------- Total $24,459 ======= __________ Notes: (1) Taxes other than payroll and income taxes include taxes charged to clearing accounts and distributed from those accounts to appropriate operating and construction accounts or charged directly to construction and other appropriate accounts.
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-K. (3) (i) Articles of Incorporation Entergy Corporation (a) 1 -- Certificate of Incorporation of Entergy Corporation (A-1(a) to Rule 24 Certificate in 70-8059). System Energy (b) 1 -- Amended and Restated Articles of Incorporation of System Energy, as executed April 28, 1989 (A-1(a) to Form U-1 in 70-5399). AP&L (c) 1 -- Amended and Restated Articles of Incorporation of AP&L, as amended (4(c) in 33-50289). GSU (d) 1 -- Restated Articles of Incorporation, as amended, of GSU (A-11 in 70-8059). (d) 2 -- Statement of Resolution amending Restated Articles of Incorporation, as amended, of GSU (A-11(a) in 70-8059). LP&L (e) 1 -- Restated Articles of Incorporation of LP&L, as amended (4(c) in 33-50937). MP&L *(f) 1 -- Restated Articles of Incorporation of MP&L, as amended. NOPSI (g) 1 -- Restatement of Articles of Incorporation of NOPSI, as executed September 30, 1969 (A-1 to Form U-1 in 70-6392). (g) 2 -- Articles of Amendment to Restatement of Articles of Incorporation of NOPSI, as executed February 27, 1980 (A-2(a) to Rule 24 Certificate in 70-6392). (g) 3 -- Articles of Amendment to Restatement of Articles of Incorporation, as amended, of NOPSI, as executed March 19, 1980 (C-1 to Rule 24 Certificate in 70-6404). (g) 4 -- Articles of Amendment to Restatement of Articles of Incorporation, as amended, of NOPSI, as executed January 23, 1984 (A-7(d) to Form U-1 in 70-6962). (g) 5 -- Articles of Amendment to Restatement of Articles of Incorporation, as amended, of NOPSI, as executed February 21, 1985 (3(f)5 to Form 10-K for the year ended December 31, 1984, in 0-5807). (g) 6 -- Articles of Amendment to Restatement of Articles of Incorporation, as amended, of NOPSI, as executed November 21, 1988 (A-2(b) to Rule 24 Certificate in 70-7558). (g) 7 -- Articles of Amendment to Restatement of Articles of Incorporation, as amended, of NOPSI, as executed June 12, 1989 (3(a) to Form 10-Q for the quarter ended June 30, 1989 in 0-5807). (3) (ii) By-Laws (a) -- By-Laws of Entergy Corporation (A-2(a) to Rule 24 Certificate in 70-8059). (b) -- By-Laws of System Energy (A-2(a) in 70-5399). (c) -- By-Laws of AP&L (4(f) in 33-50289). (d) -- By-Laws of GSU (A-12 in 70-8059). (e) -- By-Laws of LP&L (A-4 in 70-6962). *(f) -- By-Laws of MP&L. (g) -- By-Laws of NOPSI (3(b) to Form 10-Q for the quarter ended September 30, 1989 in 0-5807). (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, AP&L, GSU, LP&L, MP&L and NOPSI. (a) 2 -- Revolving Credit Agreement, dated as of January 31, 1989 between System Fuels and Bank of America National Trust and Savings Association (B-1(c) to Rule 24 Certificate, dated February 1, 1989, in 70-7574), as amended by First Amendment to Revolving Credit Agreement, dated as of August 28, 1990 (A to Rule 24 Certificate, dated October 31, 1990, in 70-7574). (a) 3 -- Security Agreement dated as of January 31, 1989 between System Fuels and Bank of America National Trust and Savings Association (B-3(c) to Rule 24 Certificate, dated February 1, 1989, in 70-7574). (a) 4 -- Credit Agreement, dated as of October 3, 1989, between System Fuels and The Yasuda Trust and Banking Co., Ltd., New York Branch, as agent (B-1(c) to Rule 24 Certificate, dated October 6, 1989, in 70-7668). (a) 5 -- First Amendment, dated as of March 1, 1992, to Credit Agreement, dated as of October 3, 1989, between System Fuels and The Yasuda Trust and Banking Co., Ltd., New York Branch, as agent (4(a)5 to Form 10-K for the year ended December 31, 1991 in 1-3517). (a) 6 -- Second Amendment, dated as of September 30, 1992, to Credit Agreement dated as of October 3, 1989, between System Fuels and The Yasuda Trust and Banking Co., Ltd., New York Branch, as agent (4(a)6 to Form 10-K for the year ended December 31, 1992 in 1- 3517). (a) 7 -- Security Agreement, dated as of October 3, 1989, as amended, between System Fuels and The Yasuda Trust and Banking Co., Ltd., New York Branch, as agent (B-3(c) to Rule 24 Certificate, dated October 6, 1989, in 70-7668), as amended by First Amendment to Security Agreement, dated as of March 14, 1990 (A to Rule 24 Certificate, dated March 7, 1990, in 70-7668). (a) 8 -- Consent and Agreement, dated as of October 3, 1989, among System Fuels, The Yasuda Trust and Banking Co., Ltd., New York Branch, as agent, AP&L, LP&L, and System Energy (B-5(c) to Rule 24 Certificate, dated October 6, 1989, in 70-7668). System Energy (b) 1 -- Mortgage and Deed of Trust, as amended by eighteen 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); and A-2(e) to Rule 24 Certificate dated May 4, 1993 in 70-7946 (Eighteenth)). (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) and Lease Supplement No. 2 dated as of January 1, 1994 (B- 3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215). (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) and Lease Supplement No. 2 dated as of January 1, 1994 (B- 4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215). (b) 4 -- Installment Sale Agreement, dated as of December 1, 1983 between System Energy and Claiborne County, Mississippi (B-1 to First Rule 24 Certificate in 70-6913). (b) 5 -- Indenture of Trust, dated as of December 1, 1983, between Claiborne County, Mississippi and Deposit Guaranty National Bank (A-1 to First Rule 24 Certificate in 70-6913). (b) 6 -- Installment Sale Agreement, dated as of June 1, 1984, between System Energy and Claiborne County, Mississippi (B-2 to Second Rule 24 Certificate in 70-6913). (b) 7 -- Indenture of Trust dated as of June 1, 1984, between Claiborne County, Mississippi and Deposit Guaranty National Bank (A-2 to Second Rule 24 Certificate in 70-6913). (b) 8 -- Installment Sale Agreement, dated as of December 1, 1984, between System Energy and Claiborne County, Mississippi (B-1 to First Rule 24 Certificate in 70-7026). (b) 9 -- Indenture of Trust, dated as of December 1, 1984, between Claiborne County, Mississippi and Deposit Guaranty National Bank (B-2 to First Rule 24 Certificate in 70-7026). (b) 10 -- Installment Sale Agreement, dated as of June 15, 1985, between System Energy and Claiborne County, Mississippi (B-1(b) to Third Rule 24 Certificate in 70-7026). (b) 11 -- Indenture of Trust, dated as of June 15, 1985, between Claiborne County, Mississippi and Deposit Guaranty National Bank (B-2(b) to Third Rule 24 Certificate in 70-7026). (b) 12 -- Installment Sale Agreement, dated as of May 1, 1986, between System Energy and Claiborne County, Mississippi (B-1(b) to Rule 24 Certificate in 70-7158). (b) 13 -- Indenture of Trust, dated as of May 1, 1986, between Claiborne County, Mississippi and Deposit Guaranty National Bank (B-2(b) to Rule 24 Certificate in 70-7158). AP&L (c) 1 -- Mortgage and Deed of Trust, as amended by fifty-one Supplemental Indentures (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 7(c) in 2-7605 (Second); 7(d) in 2-8100 (Third); 7(a)-4 in 2-8482 (Fourth); 7(a)-5 in 2-9149 (Fifth); 4(a)-6 in 2-9789 (Sixth); 4(a)-7 in 2-10261 (Seventh); 4(a)-8 in 2-11043 (Eighth); 2(b)-9 in 2-11468 (Ninth); 2(b)-10 in 2-15767 (Tenth); D in 70-3952 (Eleventh); D in 70-4099 (Twelfth); 4(d) in 2-23185 (Thirteenth); 2(c) in 2-24414 (Fourteenth); 2(c) in 2-25913 (Fifteenth); 2(c) in 2-28869 (Sixteenth); 2(d) in 2-28869 (Seventeenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); 2(c) in 2-41080 (Twenty-first); C-1 to Rule 24 Certificate in 70-5151 (Twenty-second); C-1 to Rule 24 Certificate in 70-5257 (Twenty-third); C to Rule 24 Certificate in 70-5343 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-5404 (Twenty-fifth); C to Rule 24 Certificate in 70-5502 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-5556 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-5693 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6078 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6174 (Thirtieth); C-1 to Rule 24 Certificate in 70-6246 (Thirty-first); C-1 to Rule 24 Certificate in 70-6498 (Thirty-second); A-4b-2 to Rule 24 Certificate in 70-6326 (Thirty-third); C-1 to Rule 24 Certificate in 70-6607 (Thirty-fourth); C-1 to Rule 24 Certificate in 70-6650 (Thirty-fifth); C-1 to Rule 24 Certificate, dated December 1, 1982, in 70-6774 (Thirty-sixth); C-1 to Rule 24 Certificate, dated February 17, 1983, in 70-6774 (Thirty-seventh); A-2(a) to Rule 24 Certificate, dated December 5, 1984, in 70-6858 (Thirty-eighth); A-3(a) to Rule 24 Certificate in 70-7127 (Thirty-ninth); A-7 to Rule 24 Certificate in 70-7068 (Fortieth); A-8(b) to Rule 24 Certificate dated July 6, 1989 in 70-7346 (Forty-first); A-8(c) to Rule 24 Certificate, dated February 1, 1990 in 70-7346 (Forty-second); 4 to Form 10-Q for the quarter ended September 30, 1990 in 1-10764 (Forty-third); A-2(a) to Rule 24 Certificate, dated November 30, 1990, in 70-7802 (Forty-fourth); A-2(b) to Rule 24 Certificate, dated January 24, 1991, in 70-7802 (Forty-fifth); 4(d)(2) in 33-54298 (Forty-sixth); 4(c)(2) to Form 10-K for the year ended December 31, 1992 in 1-10764 (Forty-seventh); 4(b) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-eighth); 4(c) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-ninth); 4(b) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fiftieth); and 4(c) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fifty-first)). GSU (d) 1 -- Indenture of Mortgage, 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 1-2703 (Forty-eighth); 4-2 to Form 10-K for the year ended December 31, 1988 in 1-2703 (Fifty-second); 4 to Form 10-K for the year ended December 31, 1991 in 1-2703 (Fifty- third); 4 to Form 8-K dated July 29, 1992 in 1-2703 (Fifth- fourth); 4 to Form 10-K dated December 31, 1992 in 1-2703 (Fifty- fifth); 4 to Form 10-Q for the quarter ended March 31, 1993 in 1- 2703 (Fifty-sixth); and 4-2 to Amendment No. 9 to Registration No. 2-76551 (Fifty-seventh)). (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 -- Trust Indenture for 9.72% Debentures due July 1, 1998 (4 in Registration No. 33-40113). LP&L (e) 1 -- Mortgage and Deed of Trust, as amended by forty-eight Supplemental Indentures (7(d) in 2-5317 (Mortgage); 7(b) in 2-7408 (First); 7(c) in 2-8636 (Second); 4(b)-3 in 2-10412 (Third); 4(b)-4 in 2-12264 (Fourth); 2(b)-5 in 2-12936 (Fifth); D in 70-3862 (Sixth); 2(b)-7 in 2-22340 (Seventh); 2(c) in 2-24429 (Eighth); 4(c)-9 in 2-25801 (Ninth); 4(c)-10 in 2-26911 (Tenth); 2(c) in 2-28123 (Eleventh); 2(c) in 2-34659 (Twelfth); C to Rule 24 Certificate in 70-4793 (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); 2(b)-2 in 2-39437 (Fifteenth); 2(b)-2 in 2-42523 (Sixteenth); C to Rule 24 Certificate in 70-5242 (Seventeenth); C to Rule 24 Certificate in 70-5330 (Eighteenth); C-1 to Rule 24 Certificate in 70-5449 (Nineteenth); C-1 to Rule 24 Certificate in 70-5550 (Twentieth); A-6(a) to Rule 24 Certificate in 70-5598 (Twenty-first); C-1 to Rule 24 Certificate in 70-5711 (Twenty-second); C-1 to Rule 24 Certificate in 70-5919 (Twenty-third); C-1 to Rule 24 Certificate in 70-6102 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-6169 (Twenty-fifth); C-1 to Rule 24 Certificate in 70-6278 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-6355 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-6508 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6556 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6635 (Thirtieth); C-1 to Rule 24 Certificate in 70-6834 (Thirty-first); C-1 to Rule 24 Certificate in 70-6886 (Thirty-second); C-1 to Rule 24 Certificate in 70-6993 (Thirty-third); C-2 to Rule 24 Certificate in 70-6993 (Thirty-fourth); C-3 to Rule 24 Certificate in 70-6993 (Thirty-fifth); A-2(a) to Rule 24 Certificate in 70-7166 (Thirty-sixth); A-2(a) in 70-7226 (Thirty-seventh); C-1 to Rule 24 Certificate in 70-7270 (Thirty-eighth); 4(a) to Quarterly Report on Form 10-Q for the quarter ended June 30, 1988, in 1-8474 (Thirty-ninth); A-2(b) to Rule 24 Certificate in 70-7553 (Fortieth); A-2(d) to Rule 24 Certificate in 70-7553 (Forty-first); A-3(a) to Rule 24 Certificate in 70-7822 (Forty-second); A-3(b) to Rule 24 Certificate in 70-7822 (Forty-third); A-2(b) to Rule 24 Certificate in File No. 70-7822 (Forty-fourth); A-3(c) to Rule 24 Certificate in 70-7822 (Forty-fifth); A-2(c) to Rule 24 Certificate dated April 7, 1993 in 70-7822 (Forty-sixth); A-3(d) to Rule 24 Certificate dated June 4, 1993 in 70-7822 (Forth-seventh); and A-3(e) to Rule 24 Certificate dated December 21, 1993 in 70-7822 (Forty-eighth)). (e) 2 -- Facility Lease No. 1, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and LP&L (4(c)-1 in Registration No. 33-30660). (e) 3 -- Facility Lease No. 2, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and LP&L (4(c)-2 in Registration No. 33-30660). (e) 4 -- Facility Lease No. 3, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and LP&L (4(c)-3 in Registration No. 33-30660). MP&L (f) 1 -- Mortgage and Deed of Trust, as amended by twenty-five Supplemental Indentures (7(d) in 2-5437 (Mortgage); 7(b) in 2-7051 (First); 7(c) in 2-7763 (Second); 7(d) in 2-8484 (Third); 4(b)-4 in 2-10059 (Fourth); 2(b)-5 in 2-13942 (Fifth); A-11 to Form U-1 in 70-4116 (Sixth); 2(b)-7 in 2-23084 (Seventh); 4(c)-9 in 2-24234 (Eighth); 2(b)-9(a) in 2-25502 (Ninth); A-11(a) to Form U-1 in 70-4803 (Tenth); A-12(a) to Form U-1 in 70-4892 (Eleventh); A-13(a) to Form U-1 in 70-5165 (Twelfth); A-14(a) to Form U-1 in 70-5286 (Thirteenth); A-15(a) to Form U-1 in 70-5371 (Fourteenth); A-16(a) to Form U-1 in 70-5417 (Fifteenth); A-17 to Form U-1 in 70-5484 (Sixteenth); 2(a)-19 in 2-54234 (Seventeenth); C-1 to Rule 24 Certificate in 70-6619 (Eighteenth); A-2(c) to Rule 24 Certificate in 70-6672 (Nineteenth); A-2(d) to Rule 24 Certificate in 70-6672 (Twentieth); C-1(a) to Rule 24 Certificate in 70-6816 (Twenty-first); C-1(a) to Rule 24 Certificate in 70-7020 (Twenty-second); C-1(b) to Rule 24 Certificate in 70-7020 (Twenty-third); C-1(a) to Rule 24 Certificate in 70-7230 (Twenty-fourth); and A-2(a) to Rule 24 Certificate in 70-7419 (Twenty-fifth)). (f) 2 -- Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by eight Supplemental Indentures (A-2(a)-2 to Rule 24 Certificate in 70-7461 (Mortgage); A-2(b)-2 in 70-7461 (First); A-5(b) to Rule 24 Certificate in 70-7419 (Second); A-4(b) to Rule 24 Certificate in 70-7554 (Third); A-1(b)-1 to Rule 24 Certificate in 70-7737 (Fourth); A-2(b) to Rule 24 Certificate dated November 24, 1992 in 70-7914 (Fifth); A-2(e) to Rule 24 Certificate dated January 22, 1993 in 70-7914 (Sixth); A-2(g) to Form U-1 in 70-7914 (Seventh); and A-2(i) to Rule 24 Certificate dated November 10, 1993 in 70-7914 (Eighth)). NOPSI (g) 1 -- Mortgage and Deed of Trust, as amended by eleven Supplemental Indentures (B-3 in 2-5411 (Mortgage); 7(b) in 2-7674 (First); 4(a)-2 in 2-10126 (Second); 4(b) in 2-12136 (Third); 2(b)-4 in 2-17959 (Fourth); 2(b)-5 in 2-19807 (Fifth); D to Rule 24 Certificate in 70-4023 (Sixth); 2(c) in 2-24523 (Seventh); 4(c)-9 in 2-26031 (Eighth); 2(a)-3 in 2-50438 (Ninth); 2(a)-3 in 2-62575 (Tenth); and A-2(b) to Rule 24 Certificate in 70-7262 (Eleventh)). (g) 2 -- Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by four Supplemental Indentures (A-2(c) to Rule 24 Certificate in 70-7350 (Mortgage); A-5(b) to Rule 24 Certificate in 70-7350 (First); A-4(b) to Rule 24 Certificate in 70-7448 (Second); 4(f)4 to Form 10-K for the year ended December 31, 1992 in 0-5807 (Third); and 4(a) to Form 10-Q for the quarter ended September 30, 1993 in 0-5807 (Fourth)). (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 fiscal year ended December 31, 1982, in 1-3517). (a) 2 -- Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-2 in 2-41080). (a) 3 -- Amendment, dated February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-4 in 2-41080). (a) 4 -- Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080). (a) 5 -- Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)-5 in 2-41080). (a) 6 -- Amendment, dated January 1, 1972, to Service Agreement with Entergy Services (5(a)-6 in 2-43175). (a) 7 -- Amendment, dated April 27, 1984, to Service Agreement with Entergy Services (10(a)-7 to Form 10-K for the fiscal year ended December 31, 1984, in 1-3517). (a) 8 -- Amendment, dated August 1, 1988, to Service Agreement with Entergy Services (10(a)-8 to Form 10-K for the fiscal year ended December 31, 1988, in 1-3517). (a) 9 -- Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(a)-9 to Form 10-K for the fiscal year ended December 31, 1990, in 1-3517). (a) 10 -- 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) 11 -- First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate, dated June 24, 1977, in 70-5399). (a) 12 -- Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592). (a) 13 -- 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) 14 -- Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399). (a) 15 -- Fourteenth Assignment of Availability Agreement, Consent and Agreement, dated as of June 15, 1985, with Deposit Guaranty National Bank, United States Trust Company of New York and Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate, dated July 31, 1985, in 70-7026). (a) 16 -- Fifteenth Assignment of Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with Deposit Guaranty National Bank, United States Trust Company of New York and Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate, dated June 5, 1986, in 70-7158). (a) 17 -- Sixteenth Assignment of Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with United States Trust Company of New York and Malcolm J. Hood, as Trustees (C to Rule 24 Certificate, dated June 4, 1986, in 70-7123). (a) 18 -- 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) 19 -- 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) 20 -- Twentieth Assignment of Availability Agreement, Consent and Agreement, dated as of November 15, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-1 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (a) 21 -- Twenty-first Assignment of Availability Agreement, Consent and Agreement, dated as of December 1, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-2 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (a) 22 -- Twenty-third Assignment of Availability Agreement, Consent and Agreement, dated as of January 11, 1991, with Chemical Bank, as Agent (B-3(a) to Rule 24 Certificate, dated January 23, 1991, in 70-7561). (a) 23 -- Twenty-fourth Assignment of Availability Agreement, Consent and Agreement, dated as of July 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to Rule 24 Certificate, dated July 14, 1992, in 70-7946). (a) 24 -- Twenty-fifth 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(b) to Rule 24 Certificate, dated November 2, 1992, in 70-7946). (a) 25 -- 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) 26 -- 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) 27 -- Twenty-eighth Assignment of Availability Agreement, Consent and Agreement, dated as of December 17, 1993, with Chemical Bank, as Agent (B-2(a) to Rule 24 Certificate dated December 22, 1993 in 70-7561). (a) 28 -- 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) 29 -- 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) 30 -- Fourteenth Supplementary Capital Funds Agreement and Assignment, dated as of June 15, 1985, with Deposit Guaranty National Bank, United States Trust Company of New York and Malcolm J. Hood, as Trustees (B-4(b) to Rule 24 Certificate, dated July 31, 1985, in 70-7026). (a) 31 -- Fifteenth Supplementary Capital Funds Agreement and Assignment, dated as of May 1, 1986, with Deposit Guaranty National Bank, United States Trust Company of New York and Malcolm J. Hood, as Trustees (B-4(b) to Rule 24 Certificate, dated June 5, 1986, in 70-7158). (a) 32 -- Sixteenth Supplementary Capital Funds Agreement and Assignment, dated as of May 1, 1986, with United States Trust Company of New York and Malcolm J. Hood, as Trustees (D to Rule 24 Certificate, dated June 4, 1986, in 70-7123). (a) 33 -- 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) 34 -- 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) 35 -- Twentieth Supplementary Capital Funds Agreement and Assignment, dated as of November 15, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-1 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (a) 36 -- Twenty-first Supplementary Capital Funds Agreement and Assignment, dated as of December 1, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-2 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (a) 37 -- Twenty-third Supplementary Capital Funds Agreement and Assignment, dated as of January 11, 1991, with Chemical Bank, as agent (B-4(a) to Rule 24 Certificate, dated January 23, 1991, in 70-7561). (a) 38 -- Twenty-fourth Supplementary Capital Funds Agreement and Assignment, dated as of July 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(b) to Rule 24 Certificate dated July 14, 1992 in 70-7946). (a) 39 -- Twenty-fifth 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(b) to Rule 24 Certificate dated November 2, 1992 in 70-7946). (a) 40 -- 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) 41 -- 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) 42 -- Twenty-eighth Supplementary Capital Funds Agreement and Assignment, dated as of December 17, 1993, with Chemical Bank, as Agent (B-3(a) to Rule 24 Certificate dated December 22, 1993 in 70-7561). (a) 43 -- 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) 44 -- 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) 45 -- 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) 46 -- Agreement between Entergy Corporation and Edwin Lupberger (10(a)-42 to Form 10-K for the fiscal year ended December 31, 1985, in 1-3517). (a) 47 -- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). (a) 48 -- 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) 49 -- Operating Agreement dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337). (a) 50 -- 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) 51 -- 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) 52 -- Substitute Power Agreement, dated as of May 1, 1980, among MP&L, System Energy and SMEPA (B(3)(a) in 70-6337). (a) 53 -- Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033). (a) 54 -- Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and LP&L (28(a) to Form 8-K, dated June 4, 1982, in 1-3517). +(a) 55 -- Post-Retirement Plan (10(a)37 to Form 10-K for the fiscal year ended December 31, 1983, in 1-3517). (a) 56 -- Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and AP&L, LP&L, MP&L and NOPSI (10(a)-39 to Form 10-K for the fiscal year ended December 31, 1982, in 1-3517). (a) 57 -- First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and AP&L, LP&L, MP&L and NOPSI (19 to Form 10-Q for the quarter ended September 30, 1984, in 1-3517). (a) 58 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033). (a) 59 -- Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (Exhibit D-1 to Form U5S for the year ended December 31, 1987). (a) 60 -- First Amendment to Tax Allocation Agreement, dated January 1, 1990 (D-2 to Form U5S for the year ended December 31, 1989). (a) 61 -- Guaranty Agreement between Entergy Corporation and AP&L, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate, dated September 27, 1990, in 70-7757). (a) 62 -- Guarantee Agreement between Entergy Corporation and LP&L, dated as of September 20, 1990 (B-2(a) to Rule 24 Certificate, dated September 27, 1990, in 70-7757). (a) 63 -- 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) 64 -- 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) 65 -- 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) 66 -- 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) 67 -- Executive Financial Counseling Program of Entergy Corporation and Subsidiaries (10(a) 52 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(a) 68 -- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(a) 69 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831). +(a) 70 -- Retired Outside Director Benefit Plan (10(a)63 to Form 10-K for the year ended December 31, 1991, in 1-3517). +(a) 71 -- Agreement between Entergy Corporation and Jerry D. Jackson. (10(a) 67 to Form 10-K for the year ended December 31, 1992 in 1- 3517). +(a) 72 -- Agreement between Entergy Services, Inc., a subsidiary of Entergy Corporation, and Gerald D. McInvale (10(a) 68 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(a) 73 -- Supplemental Retirement Plan (10(a) 69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(a) 74 -- Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (10(a)53 to Form 10-K for the year ended December 31, 1989 in 1-3517). +(a) 75 -- 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) 76 -- Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a) 72 to Form 10-K for the year ended December 31, 1992 in 1- 3517). +(a) 77 -- Executive Medical Plan of Entergy Corporation and Subsidiaries (10(a) 73 to Form 10-K for the year ended December 31, 1992 in 1- 3517). +(a) 78 -- Stock Plan for Outside Directors of Entergy Corporation and Subsidiaries, as amended (10(a) 74 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(a) 79 -- Summary Description of Private Ownership Vehicle Plan of Entergy Corporation and Subsidiaries (10(a) 75 to Form 10-K for the year ended December 31, 1992 in 1-3517). (a) 80 -- Agreement and Plan of Reorganization Between Entergy Corporation and Gulf States Utilities Company, dated June 5, 1992 (1 to Current Report on Form 8-K dated June 5, 1992 in 1-3517). +*(a)81 -- Amendment to Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries. +*(a)82 -- System Executive Retirement Plan. System Energy (b) 1 -- Availability Agreement, dated June 21, 1974, among System Energy and certain other System companies (B to Rule 24 Certificate, dated June 24, 1974, in 70-5399). (b) 2 -- First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate, dated June 24, 1977, in 70-5399). (b) 3 -- Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592). (b) 4 -- Third Amendment to Availability Agreement, dated as of June 28, 1984 (B-13(a) to Rule 24 Certificate, dated July 6, 1984, in 70-6985). (b) 5 -- Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399). (b) 6 -- Fourteenth Assignment of Availability Agreement, Consent and Agreement, dated as of June 15, 1985, with Deposit Guaranty National Bank, United States Trust Company of New York and Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate, dated July 31, 1985, in 70-7026). (b) 7 -- Fifteenth Assignment of Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with United States Trust Company of New York, Malcolm J. Hood, and Deposit Guaranty National Bank, as Trustees (B-3(b) to Rule 24 Certificate, dated June 5, 1986, in 70-7158). (b) 8 -- Sixteenth Assignment of Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with United States Trust Company of New York and Malcolm J. Hood, as Trustees (C to Rule 24 Certificate, dated June 4, 1986, in 70-7123). (b) 9 -- 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). (b) 10 -- 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). (b) 11 -- Twentieth Assignment of Availability Agreement, Consent and Agreement, dated as of November 15, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-1 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (b) 12 -- Twenty-first Assignment of Availability Agreement, Consent and Agreement, dated as of December 1, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-2 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (b) 13 -- Twenty-third Assignment of Availability Agreement, Consent and Agreement, dated as of January 11, 1991, with Chemical Bank as Agent (B-3(a) to Rule 24 Certificate, dated January 23, 1991, in 70-7561). (b) 14 -- Twenty-fourth Assignment of Availability Agreement, Consent and Agreement, dated as of July 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to Rule 24 Certificate, dated July 14, 1992, in 70-7946). (b) 15 -- Twenty-fifth 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(b) to Rule 24 Certificate, dated November 2, 1992, in 70-7946). (b) 16 -- 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). (b) 17 -- 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). (b) 18 -- Twenty-eighth Assignment of Availability Agreement, Consent and Agreement, dated as of December 17, 1993, with Chemical Bank, as Agent (B-2(a) to Rule 24 Certificate dated December 22, 1993 in 70-7561). (b) 19 -- 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). (b) 20 -- First Amendment to Capital Funds Agreement, dated as of June 1, 1989 (B to Rule 24 Certificate, dated June 8, 1989, in 70-5399). (b) 21 -- Fourteenth Supplementary Capital Funds Agreement and Assignment, dated as of June 15, 1985, with Deposit Guaranty National Bank, United States Trust Company of New York and Malcolm J. Hood, as Trustees (B-4(b) to Rule 24 Certificate, dated July 31, 1985, in 70-7026). (b) 22 -- Fifteenth Supplementary Capital Funds Agreement and Assignment, dated as of May 1, 1986, with Deposit Guaranty National Bank, United States Trust Company of New York and Malcolm J. Hood, as Trustees (B-4(b) to Rule 24 Certificate, dated June 5, 1986, in 70-7158). (b) 23 -- Sixteenth Supplementary Capital Funds Agreement and Assignment, dated as of May 1, 1986, with United States Trust Company of New York and Malcolm J. Hood, as Trustees (D to Rule 24 Certificate, dated June 4, 1986, in 70-7123). (b) 24 -- 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). (b) 25 -- 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). (b) 26 -- Twentieth Supplementary Capital Funds Agreement and Assignment, dated as of November 15, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-1 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (b) 27 -- Twenty-first Supplementary Capital Funds Agreement and Assignment, dated as of December 1, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-2 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (b) 28 -- Twenty-third Supplementary Capital Funds Agreement and Assignment, dated as of January 11, 1991, with Chemical Bank as Agent (B-4(a) to Rule 24 Certificate, dated January 23, 1991, in 70-7561). (b) 29 -- Twenty-fourth Supplementary Capital Funds Agreement and Assignment, dated as of July 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(b) to Rule 24 Certificate dated July 14, 1992, in 70-7946). (b) 30 -- Twenty-fifth 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(b) to Rule 24 Certificate dated November 2, 1992, in 70-7946). (b) 31 -- 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). (b) 32 -- 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). (b) 33 -- Twenty-eighth Supplementary Capital Funds Agreement and Assignment, dated as of December 17, 1993, with Chemical Bank, as Agent (B-3(a) to Rule 24 Certificate dated December 22, 1993 in 70-7561). (b) 34 -- 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, as Trustees (C to Rule 24 Certificate, dated June 8, 1989, in 70-7026). (b) 35 -- 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, as Trustees (C to Rule 24 Certificate, dated June 8, 1989, in 70-7123). (b) 36 -- 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). (b) 37 -- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). (b) 38 -- 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) 39 -- Operating Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337). (b) 40 -- 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) 41 -- 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) 42 -- Substitute Power Agreement, dated as of May 1, 1980, among MP&L, System Energy and SMEPA (B(3)(a) in 70-6337). (b) 43 -- Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033). (b) 44 -- Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and AP&L, LP&L, MP&L and NOPSI (10(a)-39 to Form 10-K for the fiscal year ended December 31, 1982, in 1-3517). (b) 45 -- First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and AP&L, LP&L, MP&L and NOPSI (19 to Form 10-Q for the quarter ended September 30, 1984, in 1-3517). (b) 46 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033). (b) 47 -- Fuel Lease, dated as of March 3, 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) 48 -- Sales Agreement, dated as of June 21, 1974, between System Energy and MP&L (D to Rule 24 Certificate, dated June 26, 1974, in 70-5399). (b) 49 -- Service Agreement, dated as of June 21, 1974, between System Energy and MP&L (E to Rule 24 Certificate, dated June 26, 1974, in 70-5399). (b) 50 -- Partial Termination Agreement, dated as of December 1, 1986, between System Energy and MP&L (A-2 to Rule 24 Certificate, dated January 8, 1987, in 70-5399). (b) 51 -- 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) 52 -- First Amendment to Tax Allocation Agreement, dated January 1, 1990 (D-2 to Form U5S for the year ended December 31, 1989). (b) 53 -- Service Agreement with Entergy Services, dated as of July 16, 1974, as amended (10(b)-43 to Form 10-K for the fiscal year ended December 31, 1988, in 1-9067). (b) 54 -- Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(b)-45 to Form 10-K for the fiscal year ended December 31, 1990, in 1-9067). (b) 55 -- 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) 56 -- 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) 57 -- Agreement between System Energy and Donald C. Hintz (10(b)47 to Form 10-K for the year ended December 31, 1991, in 1-9067). +(b) 58 -- Agreement between Entergy Corporation and Edwin Lupberger (10(a)-42 to Form 10-K for the year ended December 31, 1985 in 1-3517). +(b) 59 -- Agreement between Entergy Services and Gerald D. McInvale (10(a)-69 to Form 10-K for the year ended December 31, 1992 in 1-3517). AP&L (c) 1 -- Agreement, dated April 23, 1982, among AP&L and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the fiscal 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)-4 in 2-41080). (c) 4 -- Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080). (c) 5 -- Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)-5 in 2-41080). (c) 6 -- Amendment, dated January 1, 1972, to Service Agreement with Entergy Services (5(a)- 6 in 2-43175). (c) 7 -- Amendment, dated April 27, 1984, to Service Agreement, with Entergy Services (10(a)- 7 to Form 10-K for the fiscal year ended December 31, 1984, in 1-3517). (c) 8 -- Amendment, dated August 1, 1988, to Service Agreement with Entergy Services (10(c)- 8 to Form 10-K for the fiscal year ended December 31, 1988, in 1-10764). (c) 9 -- Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(c)-9 to Form 10-K for the fiscal year ended December 31, 1990, in 1-10764). (c) 10 -- 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). (c) 11 -- First Amendment to Availability Agreement, dated June 30, 1977 (B to Rule 24 Certificate, dated June 24, 1977, in 70-5399). (c) 12 -- Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592). (c) 13 -- 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). (c) 14 -- Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399). (c) 15 -- Fourteenth Assignment of Availability Agreement, Consent and Agreement, dated as of June 15, 1985, with Deposit Guaranty National Bank, United States Trust Company of New York and Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate, dated July 31, 1985, in 70-7026). (c) 16 -- Fifteenth Assignment of Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with Deposit Guaranty National Bank, United States Trust Company of New York, and Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate, dated June 5, 1986, in 70-7158). (c) 17 -- Sixteenth Assignment of Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with United States Trust Company of New York and Malcolm J. Hood, as Trustees (C to Rule 24 Certificate, dated June 4, 1986, in 70-7123). (c) 18 -- 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). (c) 19 -- 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). (c) 20 -- Twentieth Assignment of Availability Agreement, Consent and Agreement, dated as of November 15, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-1 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (c) 21 -- Twenty-first Assignment of Availability Agreement, Consent and Agreement, dated as of December 1, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-2 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (c) 22 -- Twenty-third Assignment of Availability Agreement, Consent and Agreement, dated as of January 11, 1991, with Chemical Bank, as Agent (B-3(a) to Rule 24 Certificate, dated January 23, 1991, in 70-7561). (c) 23 -- Twenty-fourth Assignment of Availability Agreement, Consent and Agreement, dated as of July 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to Rule 24 Certificate, dated July 14, 1992, in 70-7946). (c) 24 -- Twenty-fifth 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(b) to Rule 24 Certificate, dated November 2, 1992, in 70-7946). (c) 25 -- 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). (c) 26 -- 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). (c) 27 -- Twenty-eighth Assignment of Availability Agreement, Consent and Agreement, dated as of December 17, 1993, with Chemical Bank, as Agent (B-2(a) to Rule 24 Certificate dated December 22, 1993 in 70-7561). (c) 28 -- Agreement, dated August 20, 1954, between AP&L and the United States of America (SPA)(13(h) in 2-11467). (c) 29 -- Amendment, dated April 19, 1955, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-2 in 2-41080). (c) 30 -- Amendment, dated January 3, 1964, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-3 in 2-41080). (c) 31 -- Amendment, dated September 5, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-4 in 2-41080). (c) 32 -- Amendment, dated November 19, 1970, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-5 in 2-41080). (c) 33 -- Amendment, dated July 18, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-6 in 2-41080). (c) 34 -- Amendment, dated December 27, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-7 in 2-41080). (c) 35 -- Amendment, dated January 25, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-8 in 2-41080). (c) 36 -- Amendment, dated October 14, 1971, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-9 in 2-43175). (c) 37 -- Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-10 in 2-60233). (c) 38 -- Agreement, dated May 14, 1971, between AP&L and the United States of America (SPA) (5(e) in 2-41080). (c) 39 -- Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated May 14, 1971 (5(e)-1 in 2-60233). (c) 40 -- Contract, dated May 28, 1943, Amendment to Contract, dated July 21, 1949, and Supplement to Amendment to Contract, dated December 30, 1949, between AP&L and McKamie Gas Cleaning Company; Agreements, dated as of September 30, 1965, between AP&L and former stockholders of McKamie Gas Cleaning Company; and Letter Agreement, dated June 22, 1966, by Humble Oil & Refining Company accepted by AP&L on June 24, 1966 (5(k)-7 in 2-41080). (c) 41 -- Agreement, dated April 3, 1972, between Entergy Services and Gulf United Nuclear Fuels Corporation (5(l)-3 in 2-46152). (c) 42 -- Fuel Lease, dated as of December 22, 1988, between River Fuel Trust #1 and AP&L (B-1(b) to Rule 24 Certificate in 70-7571). (c) 43 -- White Bluff Operating Agreement, dated June 27, 1977, among AP&L 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) 44 -- White Bluff Ownership Agreement, dated June 27, 1977, among AP&L 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) 45 -- Agreement, dated June 29, 1979, between AP&L and City of Conway, Arkansas (5(r)-3 in 2-66235). (c) 46 -- Transmission Agreement, dated August 2, 1977, between AP&L and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)-3 in 2-60233). (c) 47 -- Power Coordination, Interchange and Transmission Service Agreement, dated as of June 27, 1977, between Arkansas Electric Cooperative Corporation and AP&L (5(r)-4 in 2-60233). (c) 48 -- Independence Steam Electric Station Operating Agreement, dated July 31, 1979, among AP&L and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)-6 in 2-66235). (c) 49 -- Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c) 51 to Form 10-K for the fiscal year ended December 31, 1984, in 1-10764). (c) 50 -- Independence Steam Electric Station Ownership Agreement, dated July 31, 1979, among AP&L and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)-7 in 2-66235). (c) 51 -- Amendment, dated December 28, 1979, to the Independence Steam Electric Station Ownership Agreement (5(r)-7(a) in 2-66235). (c) 52 -- Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c) 54 to Form 10-K for the fiscal year ended December 31, 1984, in 1-10764). (c) 53 -- Owner's Agreement, dated November 28, 1984, among AP&L, MP&L, other co-owners of the Independence Station (10(c) 55 to Form 10-K for the fiscal year ended December 31, 1984, in 1-10764). (c) 54 -- Consent, Agreement and Assumption, dated December 4, 1984, among AP&L, MP&L, 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 fiscal year ended December 31, 1984, in 1-10764). (c) 55 -- Power Coordination, Interchange and Transmission Service Agreement, dated as of July 31, 1979, between AP&L and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)-8 in 2-66235). (c) 56 -- Power Coordination, Interchange and Transmission Agreement, dated as of June 29, 1979, between City of Conway, Arkansas and AP&L (5(r)-9 in 2-66235). (c) 57 -- Agreement, dated June 21, 1979, between AP&L and Reeves E. Ritchie ((10)(b)-90 to Form 10-K for the fiscal year ended December 31, 1980, in 1-10764). (c) 58 -- Agreement, dated as of January 30, 1981, between AP&L and MP&L, relating to the Independence Station (B-3 in 70-6614). (c) 59 -- Amendment No. 1, dated as of June 30, 1981, to Agreement, dated as of January 30, 1981, between AP&L and MP&L, relating to the Independence Station (10(b) in 2-73310). (c) 60 -- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). +(c) 61 -- Post-Retirement Plan (10(b) 55 to Form 10-K for the fiscal year ended December 31, 1983, in 1-10764). (c) 62 -- Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and AP&L, LP&L, MP&L, and NOPSI (10(a) 39 to Form 10-K for the fiscal year ended December 31, 1982, in 1-3517). (c) 63 -- First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy, AP&L, LP&L, MP&L, and NOPSI (19 to Form 10-Q for the quarter ended September 30, 1984, in 1-3517). (c) 64 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033). (c) 65 -- Contract For Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated June 30, 1983, among the DOE, System Fuels and AP&L (10(b)-57 to Form 10-K for the fiscal year ended December 31, 1983, in 1-10764). (c) 66 -- 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) 67 -- First Amendment to Tax Allocation Agreement, dated January 1, 1990 (D-2 to Form U5S for the year ended December 31, 1989). (c) 68 -- Assignment of Coal Supply Agreement, dated December 1, 1987, between System Fuels and AP&L (B to Rule 24 letter filing, dated November 10, 1987, in 70-5964). (c) 69 -- 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) 70 -- Operating Agreement between Entergy Operations and AP&L, dated as of June 6, 1990 (B-1(b) to Rule 24 Certificate, dated June 15, 1990, in 70-7679). (c) 71 -- Guaranty Agreement between Entergy Corporation and AP&L, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate, dated September 27, 1990, in 70-7757). (c) 72 -- Agreement for Purchase and Sale of Independence Unit 2 between AP&L and Entergy Power, dated as of August 28, 1990 (B-3(c) to Rule 24 Certificate, dated September 6, 1990, in 70-7684). (c) 73 -- Agreement for Purchase and Sale of Ritchie Unit 2 between AP&L and Entergy Power, dated as of August 28, 1990 (B-4(d) to Rule 24 Certificate, dated September 6, 1990, in 70-7684). (c) 74 -- Ritchie Steam Electric Station Unit No. 2 Operating Agreement between AP&L and Entergy Power, dated as of August 28, 1990 (B-5(a) to Rule 24 Certificate, dated September 6, 1990, in 70-7684). (c) 75 -- Ritchie Steam Electric Station Unit No. 2 Ownership Agreement between AP&L and Entergy Power, dated as of August 28, 1990 (B-6(a) to Rule 24 Certificate, dated September 6, 1990, in 70-7684). (c) 76 -- Power Coordination, Interchange and Transmission Service Agreement between Entergy Power and AP&L, dated as of August 28, 1990 (10(c)-71 to Form 10-K for the fiscal year ended December 31, 1990, in 1-10764). +(c) 77 -- Executive Financial Counseling Program of Entergy Corporation and Subsidiaries (10(a)52 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(c) 78 -- Entergy Corporation Annual Incentive Plan (10(a)54 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(c) 79 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831). +(c) 80 -- Agreement between Arkansas Power & Light Company and R. Drake Keith. (10(c) 78 to Form 10-K for the year ended December 31, 1992 in 1-10764). +(c) 81 -- Supplemental Retirement Plan (10(a)69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(c) 82 -- Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (10(a)53 to Form 10-K for the year ended December 31, 1989 in 1-3517). +(c) 83 -- 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). +(c) 84 -- Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a)72 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(c) 85 -- Executive Medical Plan of Entergy Corporation and Subsidiaries (10(a)73 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(c) 86 -- Stock Plan for Outside Directors of Entergy Corporation and Subsidiaries, as amended (10(a)74 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(c) 87 -- Summary Description of Private Ownership Vehicle Plan of Entergy Corporation and Subsidiaries (10(a)75 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(c) 88 -- Agreement between Entergy Corporation and Edwin Lupberger (10(a)-42 to Form 10-K for the year ended December 31, 1985 in 1-3517). +(c) 89 -- Agreement between Entergy Corporation and Jerry D. Jackson (10(a)-68 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(c) 90 -- Agreement between Entergy Services and Gerald D. McInvale (10(a)-69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(c) 91 -- Agreement between System Energy and Donald C. Hintz (10(b)-47 to Form 10-K for the year ended December 31, 1991 in 1-9067). +(c) 92 -- Summary Description of Retired Outside Director Benefit Plan. (10(c) 90 to Form 10-K for the year ended December 31, 1992 in 1- 10764). +(c) 93 -- Amendment to Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (10(a) 81 to Form 10-K for the year ended December 31, 1993 in 1-11299). +(c) 94 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for the year ended December 31, 1993 in 1-11299). GSU (d) 1 -- Guaranty Agreement, dated as of December 1, 1971, relating to Pollution Control Revenue Bonds of the Industrial Development Board of the Parish of Calcasieu, Inc. (Louisiana) (5-26 to Registration No. 2-52878). (d) 2 -- Guaranty Agreement, dated July 1, 1976, between GSU and the Parish of Iberville, Louisiana (C and D to Form 8-K, dated August 6, 1976 in 1-2703). (d) 3 -- Lease of Railroad Equipment, dated as of December 1, 1981, between The Connecticut Bank and Trust Company as Lessor and GSU as Lessee and First Supplement, dated as of December 31, 1981, relating to 605 One Hundred-Ton Unit Train Steel Coal Porter Cars (4-12 to Form 10-K for the year ended December 31, 1981 in 1- 2703). (d) 4 -- Guaranty Agreement, dated August 1, 1992, between GSU 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 1-2703). (d) 5 -- Guaranty Agreement, dated January 1, 1993, between GSU 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 1-2703). (d) 6 -- Deposit Agreement, dated as of December 1, 1983 between GSU, Morgan Guaranty Trust Co. as Depositary and the Holders of Despositary 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 1-2703). (d) 7 -- Letter of Credit Agreement between GSU and Bankers Trust Company relating to Pollution Control Revenue Bonds of the Parish of West Feliciana, State of Louisiana, Series 1984A (4-18 to Form 10-K for the year ended December 31, 1984 in 1-2703). (d) 8 -- Letter of Credit and Reimbursement Agreement, dated December 27, 1985, between GSU and Westpack Banking Corporation relating to Variable Rate Demand Pollution Control Revenue Bonds of the Parish of West Feliciana, State of Louisiana, Series 1985-D (4-26 to Form 10-K for the year ended December 31, 1985 in 1-2703) and Letter Agreement amending same dated October 20, 1992 (10-3 to Form 10-K for the year ended December 31, 1992 in 1-2703). (d) 9 -- Reimbursement and Loan Agreement, dated as of April 23, 1986, by and between GSU and The Long-Term Credit Bank of Japan, Ltd., relating to Multiple Rate Demand Pollution Control Revenue Bonds of the Parish of West Feliciana, State of Louisiana, Series 1985 (4-26 to Form 10-K, for the year ended December 31, 1986 in 1- 2703) and Letter Agreement amending same, dated February 19, 1993 (10 to Form 10-K for the year ended December 31, 1992 in 1-2703). (d) 10 -- Agreement effective February 1, 1964, between Sabine River Authority, State of Louisiana, and Sabine River Authority of Texas, and GSU, 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 1-2708). (d) 11 -- Joint Ownership Participation and Operating Agreement regarding River Bend Unit 1 Nuclear Plant, dated August 20, 1979, between GSU, Cajun, and SRG&T; Power Interconnection Agreement with Cajun, dated June 26, 1978, and approved by the REA on August 16, 1979, between GSU and Cajun; and Letter Agreement regarding CEPCO buybacks, dated August 28, 1979, between GSU and Cajun (2, 3, and 4, respectively, to Form 8-K, dated September 7, 1979, in 1- 2703). (d) 12 -- Ground Lease, dated August 15, 1980, between Statmont Associates Limited Partnership (Statmont) and GSU, 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 1-2703). (d) 13 -- Lease and Sublease Agreement, dated August 15, 1980, between Statmont and GSU, 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 1-2703). (d) 14 -- Lease Agreement, dated September 18, 1980, between BLC Corporation and GSU (1 to Form 8-K, dated October 6, 1980 in 1- 2703). (d) 15 -- Joint Ownership Participation Agreement for Big Cajun, between GSU, 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 1-2703); Amendment No. 1, dated December 12, 1980 (7 to Form 8-K, dated January 29, 1981 in 1-2703); Amendment No. 2, dated December 29, 1980 (8 to Form 8-K, dated January 29, 1981 in 1-2703). (d) 16 -- Agreement of Joint Ownership Participation between SRMPA, SRG&T and GSU, 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 1-2703). (d) 17 -- Agreements between Southern Company and GSU, 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 1-2703). +(d) 18 -- GSU Management Incentive Compensation Plan and Administrative Guideline as restated March, 1981, effective for the fiscal year commencing January 1, 1981 (10-33 to Form 10-K for the year ended December 31, 1981 in 1-2703). +(d) 19 -- GSU Stock Appreciation Plan (10-34 to Form 10-K for the year ended December 31, 1981 in 1-2703), and Amendment, dated May 5, 1988 (10-20 to Form 10-K for the year ended December 31, 1988 in 1-2703); Amendment, dated December 4, 1990 (10-2 to Form 10-K for the year ended December 31, 1990 in 1-2703) Amendment, dated December 4, 1991 (10-1 to Form 10-K for the year ended December 31, 1991 in 1-2703). +(d) 20 -- Executive Income Security Plan, effective October 1, 1980, as amended, continued and completely restated effective as of March 1, 1991 (10-2 to Form 10-K for the year ended December 31, 1991 in 1-2703). (d) 21 -- Joint Ownership Participation Agreement for Big Cajun between GSU, Cajun, and SRG&T, dated November 14, 1980 (6 to Form 8-K, dated January 29, 1981 in 1-2703). (d) 22 -- Amendment No. 1 to the Joint Ownership Participation Agreement for Big Cajun, between GSU, Cajun, and SRG&T, dated December 12, 1980 (7 to Form 8-K, dated January 29, 1981 in 1-2703). (d) 23 -- Amendment No. 2 to the Joint Ownership Participation Agreement for Big Cajun, between GSU, Cajun, and SRG&T, dated December 29, 1980 (8 to Form 8-K, dated January 29, 1981 in 1-2703). (d) 24 -- Interchange contract between GSU and Alabama Power Company, Georgia Power & Light Company, Gulf Power Company, Mississippi Power Company and Southern Company Services, Inc. dated February 25, 1981 (A-2-b to Form 10-Q for the quarter ended March 31, 1982 in 1-2703); and Amendment, dated December 6, 1983 (10-42 to Form 10-K, for the year end December 31, 1983 in 1-2703). GSU's position is that Schedule E of this contract was terminated in 1986. (d) 25 -- Transmission Facilities Agreement between GSU 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 1-2703) and Amendment, dated December 6, 1983 (10-43 to Form 10-K, for the year ended December 31, 1983 in 1-2703). +(d) 26 -- Employment Agreement entered into as of May 1, 1986, by GSU and E. Linn Draper and Amendments, dated December 22, 1986 (10-42 to Form 10-K, for the year ended December 31, 1986 in 1-2703), June 4, 1987 (4-14-75 to Form 10-K, for the year ended December 31, 1987 in 1-2703); February 13, 1989 (10-39 to Form 10-K for the year ended December 31, 1988 in 1-2703), February 28, 1990 (10-4 to Form 10-K for the year ended December 31, 1989 in 1-2703); Amendment, dated September 5, 1990 (10-4 to Form 10-K for the year ended December 31, 1990 in 1-2703), and termination agreement effective February 28, 1992 (10-I to Form 10-K for the year ended December 31, 1991 in 1-2703). (d) 27 -- Lease Agreement dated as of June 29, 1983, between GSU and City National Bank of Baton Rouge, as Owner Trustee, in connection with the leasing of a Simulator and Training Center for River Bend Unit 1 (A-2-a to Form 10-Q for the quarter ended June 30, 1983 in 1-2703) and Amendment, dated December 14, 1984 (10-55 to Form 10-K, for the year ended December 31, 1984 in 1-2703). (d) 28 -- Participation Agreement, dated as of June 29, 1983, among GSU, City National Bank of Baton Rouge, PruFunding, Inc. Bank of the Southwest National Association, Houston and Bankers Life Company, in connection with the leasing of a Simulator and Training Center of River Bend Unit 1 (A-2-b to Form 10-Q for the quarter ended June 30, 1983 in 1-2703). (d) 29 -- Tax Indemnity Agreement, dated as of June 29, 1983, between GSU and Prufunding, Inc., in connection with the leasing of a Simulator and Training Center for River Bend Unit I (A-2-c to Form 10-Q for the quarter ended June 30, 1993 in 1-2703). (d) 30 -- Agreement to Lease, dated as of August 28, 1985, among GSU, City National Bank of Baton Rouge, as Owner Trustee, and Prudential Interfunding Corp., as Trustor, in connection with the leasing of improvement to a Simulator and Training Facility for River Bend Unit I (10-69 to Form 10-K, for the year ended December 31, 1985 in 1-2703). (d) 31 -- First Amended Power Sales Agreement, dated December 1, 1985 between Sabine River Authority, State of Louisiana, and Sabine River Authority, State of Texas, and GSU, 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 1-2703). +(d) 32 -- Employment Agreement entered into as of November 8, 1985, by GSU and Joseph L. Donnelly (10-75 to Form 10-K for the year ended December 31, 1986 in 1-2703) and Amendment, dated March 2, 1990 (10-3 to Form 10-K for the year ended December 31, 1989 in 1- 2703); and superseding agreement, dated February 12, 1992 (10-2 to Form 10-K for the year ended December 31, 1991 in 1-2703). +(d) 33 -- Deferred Compensation Plan for Directors of GSU 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 1-2703). Amendment dated December 4, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551). +(d) 34 -- Trust Agreement for Deferred Payments to be made by GSU pursuant to the Executive Income Security Plan, by and between GSU and Bankers Trust Company, effective November 1, 1986 (10-78 to Form 10-K for the year ended December 31, 1986 in 1-2703). +(d) 35 -- Trust Agreement for Deferred Installments under GSU's Management Incentive Compensation Plan and Administrative Guidelines by and between GSU and Bankers Trust Company, effective June 1, 1986 (10-79 to Form 10-K for the year ended December 31, 1986 in 1-2703). +(d) 36 -- 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) 37 -- Trust Agreement for GSU's Nonqualified Directors and Designated Key Employees by and between GSU and First City, Texas-Beaumont, N.A., effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-2703). (d) 38 -- Lease Agreement, dated as of June 29, 1987, among GSG&T, Inc., and GSU related to the leaseback of the Lewis Creek generating station (10-83 to Form 10-K for the year ended December 31, 1988 in 1-2703). (d) 39 -- Nuclear Fuel Lease Agreement between GSU 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 1-2703). (d) 40 -- Credit Agreement between GSU, Morgan Guaranty and Trust Company of New York, Citibank, First City, Texas-Houston, N.A., The Bank of New York, Bankers Trust Company and Canadian Imperial Bank for $100,000,000 line of credit, dated March 17, 1992 (10-5 to Amendment No. 8 in Registration No. 2-76551). (d) 41 -- Trust and Investment Management Agreement between GSU and Morgan Guaranty and Trust Company of New York with respect to decommissioning funds authorized to be collected by GSU, dated March 15, 1989 (10-66 to Form 10-K for the year ended December 31, 1988 in 1-2703). (d) 42 -- Partnership Agreement by and among Conoco Inc., and GSU, 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 1-2703). +(d) 43 -- 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 1-2703). +(d) 44 -- Trust Agreement for GSU's Executive Continuity Plan, by and between GSU and First City, Texas-Beaumont, N.A., effective May 20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992 in 1-2703). +(d) 45 -- 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 1-2703). +(d) 46 -- Gulf States Utilities Company Employees' Trustee Retirement Plan effective July 1, 1955 as amended, continued and completely restated effective January 1, 1989; and Amendment No.1 effective January 1, 1993 (10-6 to Form 10-K for the year ended December 31, 1992 in 1-2703). (d) 47 -- Agreement and Plan of Reorganization, dated June 5, 1992, between GSU and Entergy Corporation (2 to Form 8-K, dated June 8, 1992 in 1-2703). +(d) 48 -- Nonqualified Accrued Contributions Plan for Designated Key Employees effective January 1, 1989; Amendment No. 1 effective as of March 1, 1990; and Amendment No. 2 effective as of December 4, 1990 (10-1 to Amendment No. 1 to Registration No. 33-48889). +(d) 49 -- Gulf States Utilities Company Employee Stock Ownership Plan, as amended, continued, and completely restated effective January 1, 1984, and January 1, 1985 (A to Form 11-K, dated December 31, 1985 in 1-2703). +(d) 50 -- Trust Agreement under the Gulf States Utilities Company Employee Stock Ownership Plan, dated December 30, 1976, between GSU and the Louisiana National Bank, as Trustee (2-A to Registration No. 2-62395). +(d) 51 -- Letter Agreement dated September 7, 1977 between GSU and the Trustee, delegating certain of the Trustee's functions to the ESOP Committee (2-B to Registration Statement No. 2-62395). +(d) 52 -- Gulf States Utilities Company Employees Thrift Plan as amended, continued and completely restated effective as of January 1, 1992 (28-1 to Amendment No. 8 to Registration No. 2-76551). +(d) 53 -- Restatement of Trust Agreement under the Gulf States Utilities Company Employees Thrift Plan, reflecting changes made through January 1, 1989, between GSU and First City, Texas-Beaumont, N.A., (formerly First Security Bank of Beaumont, N.A.), as Trustee (2-A to Form 8-K dated October 20, 1989 in 1-2703). (d) 54 -- Operating Agreement between Entergy Operations and GSU, dated as of December 31, 1993 (B-2(f) to Rule 24 Certificate in 70-8059). (d) 55 -- Guarantee Agreement between Entergy Corporation and GSU, dated as of December 31, 1993 (B-5(a) to Rule 24 Certificate in 70-8059). (d) 56 -- Service Agreement with Entergy Services, dated as of December 31, 1993 (B-6(c) to Rule 24 Certificate in 70-8059). +*(d)57 -- Amendment to Employment Agreement between J. L. Donnelly and GSU, dated December 22, 1993. *(d) 58 -- Amendment to Letter of Credit and Reimbursement Agreement between GSU and Westpac Banking Corporation LP&L (e) 1 -- Agreement, dated April 23, 1982, among LP&L and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the fiscal year ended December 31, 1982, in 1-3517). (e) 2 -- Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-2 in 2-41080). (e) 3 -- Amendment, dated as of February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-4 in 2-41080). (e) 4 -- Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080). (e) 5 -- Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)-5 in 2-42523). (e) 6 -- Amendment, dated as of January 1, 1972, to Service Agreement with Entergy Services (4(a)-6 in 2-45916). (e) 7 -- Amendment, dated as of April 27, 1984, to Service Agreement with Entergy Services (10(a) 7 to Form 10-K for the fiscal year ended December 31, 1984, in 1-3517). (e) 8 -- Amendment, dated as of August 1, 1988, to Service Agreement with Entergy Services (10(d)-8 to Form 10-K for the fiscal year ended December 31, 1988, in 1-8474). (e) 9 -- Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(d)-9 to Form 10-K for the fiscal year ended December 31, 1990, in 1-8474). (e) 10 -- 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). (e) 11 -- First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate, dated June 30, 1977, in 70-5399). (e) 12 -- Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592). (e) 13 -- 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). (e) 14 -- Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399). (e) 15 -- Fourteenth Assignment of Availability Agreement, Consent and Agreement, dated as of June 15, 1985, with Deposit Guaranty National Bank, United States Trust Company of New York and Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate, dated July 31, 1985, in 70-7026). (e) 16 -- Fifteenth Assignment of Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with United States Trust Company of New York, Malcolm J. Hood, and Deposit Guaranty National Bank, as Trustees (B-3(b) to Rule 24 Certificate, dated June 5, 1986, in 70-7158). (e) 17 -- Sixteenth Assignment of Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with United States Trust Company of New York and Malcolm J. Hood, as Trustees (C to Rule 24 Certificate, dated June 4, 1986, in 70-7123). (e) 18 -- 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). (e) 19 -- 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). (e) 20 -- Twentieth Assignment of Availability Agreement, Consent and Agreement, dated as of November 16, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-1 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (e) 21 -- Twenty-first Assignment of Availability Agreement, Consent and Agreement, dated as of December 1, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-2 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (e) 22 -- Twenty-third Assignment of Availability Agreement, Consent and Agreement, dated as of January 11, 1991, with Chemical Bank, as Agent (B-3(a) to Rule 24 Certificate, dated January 23, 1991, in 70-7561). (e) 23 -- Twenty-fourth Assignment of Availability Agreement, Consent and Agreement, dated as of July 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to Rule 24 Certificate, dated July 14, 1992, in 70-7946). (e) 24 -- Twenty-fifth 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(b) to Rule 24 Certificate, dated November 2, 1992, in 70-7946). (e) 25 -- 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). (e) 26 -- 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). (e) 27 -- Twenty-eighth Assignment of Availability Agreement, Consent and Agreement, dated as of December 17,1993, with Chemical Bank, as Agent (B-2(a) to Rule 24 Certificate dated December 22, 1993 in 70-7561). (e) 28 -- Fuel Lease, dated as of January 31, 1989, between River Fuel Company #2, Inc., and LP&L (B-1(b) to Rule 24 Certificate in 70-7580). (e) 29 -- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). (e) 30 -- Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and LP&L (28(a) to Form 8-K, dated June 4, 1982, in 1-8474). +(e) 31 -- Post-Retirement Plan (10(c)23 to Form 10-K for the fiscal year ended December 31, 1983, in 1-8474). (e) 32 -- Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and AP&L, LP&L, MP&L and NOPSI (10(a) 39 to Form 10-K for the fiscal year ended December 31, 1982, in 1-3517). (e) 33 -- First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and AP&L, LP&L, MP&L and NOPSI (19 to Form 10-Q for the quarter ended September 30, 1984, in 1-3517). (e) 34 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033). (e) 35 -- 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) 36 -- First Amendment to Tax Allocation Agreement, dated January 1, 1990 (D-2 to Form U5S for the year ended December 31, 1989). (e) 37 -- Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated February 2, 1984, among DOE, System Fuels and LP&L (10(d)33 to Form 10-K for the fiscal year ended December 31, 1984, in 1-8474). (e) 38 -- Operating Agreement between Entergy Operations and LP&L, dated as of June 6, 1990 (B-2(c) to Rule 24 Certificate, dated June 15, 1990, in 70-7679). (e) 39 -- Guarantee Agreement between Entergy Corporation and LP&L, dated as of September 20, 1990 (B-2(a), to Rule 24 Certificate, dated September 27, 1990, in 70-7757). +(e) 40 -- Executive Financial Counseling Program of Entergy Corporation and Subsidiaries (10(a) 52 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(e) 41 -- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(e) 42 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831). +(e) 43 -- Supplemental Retirement Plan (10(a) 69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(e) 44 -- Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (10(a) 53 to Form 10-K for the year ended December 31, 1989 in 1-3517). +(e) 45 -- 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). +(e) 46 -- Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a) 72 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(e) 47 -- Executive Medical Plan of Entergy Corporation and Subsidiaries (10(a) 73 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(e) 48 -- Stock Plan for Outside Directors of Entergy Corporation and Subsidiaries (10(a) 74 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(e) 49 -- Summary Description of Private Ownership Vehicle Plan of Entergy Corporation and Subsidiaries (10(a) 75 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(e) 50 -- Agreement between Entergy Corporation and Edwin Lupberger (10(a) 42 to Form 10-K for the year ended December 31, 1985 in 1-3517). +(e) 51 -- Agreement between Entergy Corporation and Jerry D. Jackson (10(a) 68 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(e) 52 -- Agreement between Entergy Services and Gerald D. McInvale (10(a) 69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(e) 53 -- Agreement between System Energy and Donald C. Hintz (10(b) 47 to Form 10-K for the year ended December 31, 1991 in 1-9067). +(e) 54 -- Summary Description of Retired Outside Director Benefit Plan (10(c)90 to Form 10-K for the year ended December 31, 1992 in 1-10764). +(e) 55 -- Amendment to Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (10(a) 81 to Form 10-K for the year ended December 31, 1993 in 1-11299). +(e) 56 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for the year ended December 31, 1993 in 1-11299). MP&L (f) 1 -- Agreement dated April 23, 1982, among MP&L and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the fiscal year ended December 31, 1982, in 1-3517). (f) 2 -- Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-2 in 2-41080). (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 -- Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080). (f) 5 -- Service Agreement with Entergy Services, dated as of April 1, 1963 (D in 37-63). (f) 6 -- Amendment, dated January 1, 1972, to Service Agreement with Entergy Services (A to Notice, dated October 14, 1971, in 37-63). (f) 7 -- Amendment, dated April 27, 1984, to Service Agreement with Entergy Services (10(a) 7 to Form 10-K for the fiscal year ended December 31, 1984, in 1-3517). (f) 8 -- Amendment, dated as of August 1, 1988, to Service Agreement with Entergy Services (10(e) 8 to Form 10-K for the fiscal year ended December 31, 1988, in 0-320). (f) 9 -- Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(e) 9 to Form 10-K for the fiscal year ended December 31, 1990, in 0-320). (f) 10 -- 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). (f) 11 -- First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate, dated June 24, 1977, in 70-5399). (f) 12 -- Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592). (f) 13 -- 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). (f) 14 -- Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399). (f) 15 -- Fourteenth Assignment of Availability Agreement, Consent and Agreement, dated as of June 15, 1985, with Deposit Guaranty National Bank, United States Trust Company of New York and Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate, dated July 31, 1985, in 70-7026). (f) 16 -- Fifteenth Assignment of Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with United States Trust Company of New York, Malcolm J. Hood, and Deposit Guaranty National Bank, as Trustees (B-3(b) to Rule 24 Certificate, dated June 5, 1986, in 70-7158). (f) 17 -- Sixteenth Assignment of Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with United States Trust Company of New York and Malcolm J. Hood, as Trustees (C to Rule 24 Certificate, dated June 4, 1986, in 70-7123). (f) 18 -- 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). (f) 19 -- 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). (f) 20 -- Twentieth Assignment of Availability Agreement, Consent and Agreement, dated as of November 15, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-1 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (f) 21 -- Twenty-first Assignment of Availability Agreement, Consent and Agreement, dated as of December 1, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-2 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (f) 22 -- Twenty-third Assignment of Availability Agreement, dated as of January 11, 1991, with Chemical Bank, as Agent (B-3(a) to Rule 24 Certificate, dated January 23, 1991, in 70-7561). (f) 23 -- Twenty-fourth Assignment of Availability Agreement, Consent and Agreement, dated as of July 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to Rule 24 Certificate, dated July 14, 1992, in 70-7946). (f) 24 -- Twenty-fifth 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(b) to Rule 24 Certificate, dated November 2, 1992, in 70-7946). (f) 25 -- 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). (f) 26 -- 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). (f) 27 -- Twenty-eighth Assignment of Availability Agreement, Consent and Agreement, dated as of December 17, 1993, with Chemical Bank, as Agent (B-2(a) to Rule 24 Certificate dated December 22, 1993 in 70-7561). (f) 28 -- Substitute Power Agreement, dated as of May 1, 1980, among MP&L, System Energy and SMEPA (B-3(a) in 70-6337). (f) 29 -- Agreement, dated as of January 30, 1981, between AP&L and MP&L, relating to the Independence Station (B-3 in 70-6614). (f) 30 -- Amendment No. 1, dated as of June 30, 1981, to Agreement, dated as of January 30, 1981, between AP&L and MP&L, relating to the Independence Station (10(f)(2) in 2-73309). (f) 31 -- Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c) 51 to Form 10-K for the fiscal year ended December 31, 1984, in 0-375). (f) 32 -- Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c) 54 to Form 10-K for the fiscal year ended December 31, 1984, in 0-375). (f) 33 -- Owners Agreement, dated November 28, 1984, among AP&L, MP&L and other co- owners of the Independence Station (10(c) 55 to Form 10-K for the fiscal year ended December 31, 1984, in 0-375). (f) 34 -- Consent, Agreement and Assumption, dated December 4, 1984, among AP&L, MP&L, 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 fiscal year ended December 31, 1984, in 0-375). (f) 35 -- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). +(f) 36 -- Post-Retirement Plan (10(d) 24 to Form 10-K for the fiscal year ended December 31, 1983, in 0-320). (f) 37 -- Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and AP&L, LP&L, MP&L, and NOPSI (10(a) 39 to Form 10-K for the fiscal year ended December 31, 1982, in 1-3517). (f) 38 -- First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and AP&L, LP&L, MP&L, and NOPSI (19 to Form 10-Q for the quarter ended September 30, 1984, in 1-3517). (f) 39 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033). (f) 40 -- Sales Agreement, dated as of June 21, 1974, between System Energy and MP&L (D to Rule 24 Certificate, dated June 26, 1974, in 70-5399). (f) 41 -- Service Agreement, dated as of June 21, 1974, between System Energy and MP&L (E to Rule 24 Certificate, dated June 26, 1974, in 70-5399). (f) 42 -- Partial Termination Agreement, dated as of December 1, 1986, between System Energy and MP&L (A-2 to Rule 24 Certificate dated January 8, 1987, in 70-5399). (f) 43 -- 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) 44 -- First Amendment to Tax Allocation Agreement, dated January 1, 1990 (D-2 to Form U5S for the year ended December 31, 1989). +(f) 45 -- Executive Financial Counseling Program of Entergy Corporation and Subsidiaries (10(a) 52 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(f) 46 -- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(f) 47 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831). +(f) 48 -- Supplemental Retirement Plan (10(a)69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(f) 49 -- Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (10(a)53 to Form 10-K for the year ended December 31, 1989 in 1-3517). +(f) 50 -- 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). +(f) 51 -- Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a)72 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(f) 52 -- Executive Medical Plan of Entergy Corporation and Subsidiaries (10(a)73 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(f) 53 -- Stock Plan for Outside Directors of Entergy Corporation and Subsidiaries, as amended (10(a)74 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(f) 54 -- Summary Description of Private Ownership Vehicle Plan of Entergy Corporation and Subsidiaries (10(a)75 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(f) 55 -- Agreement between Entergy Corporation and Edwin Lupberger (10(a)-42 to Form 10-K for the year ended December 31, 1985 in 1-3517). +(f) 56 -- Agreement between Entergy Corporation and Jerry D. Jackson (10(a)-68 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(f) 57 -- Agreement between Entergy Services and Gerald D. McInvale (10(a)-69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(f) 58 -- Agreement between System Energy and Donald C. Hintz (10(b)-47 to Form 10-K for the year ended December 31, 1991 in 1-9067). +(f) 59 -- Summary Description of Retired Outside Director Benefit Plan (10(c)-90 to Form 10-K for the year ended December 31, 1992 in 1-10764). +(f) 60 -- Amendment to Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (10(a) 81 to Form 10-K for the year ended December 31, 1993 in 1-11299). +(f) 61 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for the year ended December 31, 1993 in 1-11299). NOPSI (g) 1 -- Agreement, dated April 23, 1982, among NOPSI and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)-1 to Form 10-K for the fiscal year ended December 31, 1982, in 1-3517). (g) 2 -- Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-2 in 2-41080). (g) 3 -- Amendment dated as of February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-4 in 2-41080). (g) 4 -- Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080). (g) 5 -- Service Agreement with Entergy Services dated as of April 1, 1963 (5(a)-5 in 2-42523). (g) 6 -- Amendment, dated as of January 1, 1972, to Service Agreement with Entergy Services (4(a)-6 in 2-45916). (g) 7 -- Amendment, dated as of April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the fiscal year ended December 31, 1984, in 1-3517). (g) 8 -- Amendment, dated as of August 1, 1988, to Service Agreement with Entergy Services (10(f)-8 to Form 10-K for the fiscal year ended December 31, 1988, in 0-5807). (g) 9 -- Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(f)-9 to Form 10-K for the fiscal year ended December 31, 1990, in 0-5807). (g) 10 -- 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). (g) 11 -- First Amendment to Availability Agreement, dated June 30, 1977 (B to Rule 24 Certificate, dated June 30, 1977, in 70-5399). (g) 12 -- Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592). (g) 13 -- 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). (g) 14 -- Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399). (g) 15 -- Fourteenth Assignment of Availability Agreement, Consent and Agreement, dated as of June 15, 1985, with Deposit Guaranty National Bank, United States Trust Company of New York and Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate, dated July 31, 1985, in 70-7026). (g) 16 -- Fifteenth Assignment of Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with United States Trust Company of New York, Malcolm J. Hood and Deposit Guaranty National Bank, as Trustees (B-3(b) to Rule 24 Certificate, dated June 5, 1986, in 70-7158). (g) 17 -- Sixteenth Assignment of Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with United States Trust Company of New York and Malcolm J. Hood, as Trustees (C to Rule 24 Certificate, dated June 4, 1986, in 70-7123). (g) 18 -- 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). (g) 19 -- 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). (g) 20 -- Twentieth Assignment of Availability Agreement, Consent and Agreement, dated as of November 15, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-1 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (g) 21 -- Twenty-first Assignment of Availability Agreement, Consent and Agreement, dated as of December 1, 1987, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-2 to Rule 24 Certificate, dated December 1, 1987, in 70-7382). (g) 22 -- Twenty-third Assignment of Availability Agreement, Consent and Agreement, dated as of January 11, 1991, with Chemical Bank, as Agent (B-3(a) to Rule 24 Certificate, dated January 23, 1991, in 70-7561). (g) 23 -- Twenty-fourth Assignment of Availability Agreement, Consent and Agreement, dated as of July 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to Rule 24 Certificate, dated July 14, 1992, in 70-7946). (g) 24 -- Twenty-fifth 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(b) to Rule 24 Certificate, dated November 2, 1992, in 70-7946). (g) 25 -- 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). (g) 26 -- 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). (g) 27 -- Twenty-eighth Assignment of Availability Agreement, Consent and Agreement, dated as of December 17, 1993, with Chemical Bank, as Agent (B-2(a) to Rule 24 Certificate dated December 22, 1993 in 70-7561). (g) 28 -- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). +(g) 29 -- Post-Retirement Plan (10(e) 22 to Form 10-K for the fiscal year ended December 31, 1983, in 1-1319). (g) 30 -- Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and AP&L, LP&L, MP&L and NOPSI (10(a) 39 to Form 10-K for the fiscal year ended December 31, 1982, in 1-3517). (g) 31 -- First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and AP&L, LP&L, MP&L and NOPSI (19 to Form 10-Q for the quarter ended September 30, 1984, in 1-3517). (g) 32 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033). (g) 33 -- Transfer Agreement, dated as of June 28, 1983, among the City of New Orleans, NOPSI and Regional Transit Authority (2(a) to Form 8-K, dated June 24, 1983, in 1-1319). (g) 34 -- 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) 35 -- First Amendment to Tax Allocation Agreement, dated January 1, 1990 (D-2 to Form U5S for the year ended December 31, 1989). +(g) 36 -- Executive Financial Counseling Program of Entergy Corporation and Subsidiaries (10(a)52 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(g) 37 -- Entergy Corporation Annual Incentive Plan (10(a)54 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(g) 38 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831). +(g) 39 -- Supplemental Retirement Plan (10(a)69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(g) 40 -- Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (10(a)53 to Form 10-K for the year ended December 31, 1989 in 1-3517). +(g) 41 -- 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). +(g) 42 -- Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a)72 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(g) 43 -- Executive Medical Plan of Entergy Corporation and Subsidiaries (10(a)73 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(g) 44 -- Stock Plan for Outside Directors of Entergy Corporation and Subsidiaries, as amended (10(a)74 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(g) 45 -- Summary Description of Private Ownership Vehicle Plan of Entergy Corporation and Subsidiaries (10(a)75 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(g) 46 -- Agreement between Entergy Corporation and Edwin Lupberger (10(a)-42 to Form 10-K for the year ended December 31, 1985 in 1-3517). +(g) 47 -- Agreement between Entergy Corporation and Jerry D. Jackson (10(a)-68 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(g) 48 -- Agreement between Entergy Services and Gerald D. McInvale (10(a)-69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(g) 49 -- Agreement between System Energy and Donald C. Hintz (10(b)-47 to Form 10-K for the year ended December 31, 1991 in 1-9067). +(g) 50 -- Summary Description of Retired Outside Director Benefit Plan (10(c)-90 to Form 10-K for the year ended December 31, 1992 in 1-10764). +(g) 51 -- Amendment to Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (10(a) 81 to Form 10-K for the year ended December 31, 1993 in 1-11299). +(g) 52 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for the year ended December 31, 1993 in 1-11299). (12) Statement Re Computation of Ratios *(a) AP&L's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. *(b) GSU's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. *(c) LP&L's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. *(d) MP&L's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. *(e) NOPSI's 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 is contained herein at page 342. *(b) The consent of Coopers & Lybrand is contained herein at page 343. *(c) The consent of Friday, Eldredge & Clark is contained herein at page 344. *(d) The consent of Clark, Thomas & Winters is contained herein at page 345. *(e) The consent of Sandlin Associates is contained herein at page 346. *(f) The consent of Monroe & Lemann (A Professional Corporation) is contained herein at page 347. *(g) The consent of Wise Carter Child & Caraway, Professional Association, is contained herein at page 348. *(24) Power of Attorney (99) Additional Exhibits GSU (a) 1 Opinion of Clark, Thomas & Winters, a professional corporation, dated September 30, 1992 regarding the effect of the October 1, 1991 judgment in GSU v. PUCT in the District Court of Travis County, Texas (99-1 in Registration No. 33-48889). (a) 2 Opinion of Clark, Thomas & Winters, a professional corporation, dated September 30, 1992 regarding the effect of the Austin Court of Appeals' ruling on deferred accounting in City of El Paso v. PUCT (99-2 in Registration No. 33-48889). *(a) 3 Opinion of Clark, Thomas & Winters, a professional corporation, confirming its opinions dated September 30, 1992. _________________ * Filed herewith. + Management contracts or compensatory plans or arrangements. EX-3.(I) 2 MP&L ARTICLES OF INCORPORATION Exhibit 3(i)(f)1 RESTATED ARTICLES OF INCORPORATION OF MISSISSIPPI POWER & LIGHT COMPANY Pursuant to the provisions of Section 64 of the Misissippi Business Corporation Law (Section 79-3-127, Mississippi Code of 1972, as amended), the undersigned Corporation adopts the following Restated Articles of In corporation: FIRST: The name of the Corporation is MISSISSIPPI POWER & LIGHT COMPANY. SECOND: The period of its duration is ninety-nine (99) years. THIRD: The purpose or purposes which the Corporation is authorized to pursue are: To acquire, buy, hold, own, sell, lease, exchange, dispose of, finance, deal in, construct, build, equip, improve, use, operate, maintain and work upon: (a) Any and all kinds of plants and systems for the manufacture, production, storage, utilization, purchase, sale, supply, transmission, distribution or disposition of electricity, natural or artificial gas, water or steam, or power produccd tbereby, or of ice and refrigeration of any and every kind; (b) Any and all kinds of telephone, telegraph, radio, wireless and other systems, facilities and devices for the receipt and transmission of sounds and signals, any and all kinds of interurban, city and street railways and railroads and bus lines for the transportation of passengers and/or freight, transmission lines, systems, appliances, equipment and devices and tracks, stations, buildings and other structures and facilities; (c) Any and all kinds of works, power plants, manufactories, structures, substations, systems, tracks, machinery, generators, motors, lamps, poles, pipes, wires, cables, conduits, apparatus, devices, equipment, supplies, articles and merchandise of every kind pertaining to or in anywise connected with the construction, operation or maintenance of telephone, telegraph, radio, wireless and other systems, facilities and devices for the receipt and transmission of sounds and signals, or of interurban, city and street railways and railroads and bus lines, or in anywise connected with or pertaining to the manufacture, production, purchase, use, sale, supply, transmission, distribution, regulation, control or application of electricity, natural or artificial gas, water, steam, ice, refrigeration and power or any other purposes; To acquire, buy, hold, own, sell, lease, exchange, dispose of, transmit, distribute, deal in, use, manufacture, produce, furnish and supply street and interurban railway and bus service, electricity, natural or artificial gas, light, heat, ice, refrigeration, water and steam in any form and for any purposes whatsoever, and any power or force or energy in any form and for any purposes whatsoever; To buy, sell, manufacture, produce and generally deal in milk, cream and any articles or substances used or usable in or in connection with the manufacture and production of ice cream, ices, beverages and soda fountain supplies; to buy, sell, manufacture, produce and generally deal in ice cream and ices; To acquire, organize, assemble, develop, build up and operate constructing and operating and other organizations and systems, and to hire, sell, lease, exchange, turn over, deliver and dispose of such organizations and systems in whole or in part and as going organizations and systems and otherwise, and to enter into and perform contracts, agreements and undertakings of any kind in connection with any or all the foregoing powers; To do a general contracting business; To purchase, acquire, develop, mine, explore, drill, hold, own and dispose of lands, interests in and rights with respect to lands and waters and fixed and movable property; To borrow money and contract debts when necessary for the transaction of the business of the Corporation or for the exercise of its corporate rights, privileges or franchises or for any other lawful purpose of its incorporation; to issue bonds, promissory notes, bills of exchange, debentures and other obligations and evidences of indebtedness payable at a specified time or times or payable upon the happening of a specified event or events, whether secured by mortgage, pledge or otherwise or unsecured, for money borrowed or in payment for property purchased or acquired or any other lawful objects; To guarantee, purchase, hold, sell, assign, transfer, mortgage, pledge or otherwise dispose of the shares of the capital stock of, or any bonds, securities or evidences of indebtedness created by, any other corporation or corporations of the State of Mississippi or any other state or government and, while the owner of such stock, to exercise all the rights, powers and privileges of individual ownership with respect thereto including the right to vote thereon, and to consent and otherwise act with respect thereto; To aid in any manner any corporation or association, domestic or foreign, or any firm or individual, any shares of stock in which or any bonds, debentures, notes, securities, evidences of indebtedness, contracts or obligations of which are held by or for the Corporation or in which or in the welfare of which the Corporation shall have any interest, and to do any acts designed to protect, preserve, improve or enhance the value of any property at any time held or controlled by the Corporation, or in which it may be at any time interested; and to organize or promote or facilitate the organization of subsidiary companies; To purchase, hold, sell and transfer shares of its own capital stock, provided that the Corporation shall not purchase its own shares of capital stock except frorn surplus of its assets over its liabilities including capital; and provided, further, that the shares of its own capital stock owned by the Corporation shall not be voted upon directly or indirectly nor counted as outstanding for the purposes of any stockholders' quorum or vote; In any manner to acquire, enjoy, utilize and to dispose of patents, copyrights and trade-marks and any licenses or other rights or interests therein and thereunder: To purchase, acquire, hold, own or dispose of franchises, concessions, consents, privileges and licenses necessary for and in its opinion useful or desirable for or in connection with the foregoing powers; To do all and everything necessary and proper for the accomplishment of the objects enumerated in these Restated Articles of Incorporation or any amendment thereof or necessary or incidental to the protection and benefits of the Corporation, and in general to carry on any lawful business necessary or not incidental to the attainment of the objects of the Corporation whether or not such business is similar in nature to the objects set forth in these Restated Articles of Incorporation or any amendment thereof. To do any or all things herein set forth, to the same extent and as fully as natural persons might or could do, and in any part of the world, and as principal, agent, contractor or otherwise, and either alone or in conjunction with any other persons, firms, associations or corporations; To conduct its business in all its branches in the State of Mississippi, other states, the District of Columbia, the territories and colonies of the United States, and any foreign countries, and to have one or more offices out of the State of Mississippi and to hold, purchase, mortgage and convey real and personal property both within and without the State of Mississippi; provided, however, that the Corporation shall not exercise any of the powers set forth herein for the purpose of engaging in business as a street railway, telegraph or telephone company unless prior tbereto this Article Third shall have been amended to set forth a description of the line and the points it will traverse. FOURTH: The aggregate number of shares which the Corporation shall have authority to issue is 17,004,478 shares, divided into 2,004,476 shares of Preferred Stock of the par value of $100 per share and 15,000,000 shares of Common Stock without par value. The preferences, limitations and relative rights in respect of the shares of each class and the variations in the relative rights and preferences as between series of any preferred or special class in series are as follows: The Preferred Stock shall be issuable in one or more series from tirne to time and the shares of each series shall have the same rank and be identical with each other and shall have the same relative rights except with respect to the following: (a) The number of shares to constitute each such series and the distinctive designation thereof; (b) The annual rate or rates of dividends payable on shares of such series, the dates on which dividends shall be paid in each year and the date from which such dividends shall commence to accumulate; (c) The amount or amounts payable upon redemption thereof; and (d) The sinking fund provisions, if any, for the redemption or purchase of shares; which different characterics of clauses (a), (b), (c) and (d) above may be stated and expressed with respect to each series in the resolution or resolutions providing for the issue of such series adopted by the Board of Directors or in these Restated Articles of Incorporation of any amendment thereof. A series of 60,000 shares of Preferred Stock shall: (a) be designated "4.36% Preferred Stock Cumulative, $100 Par Value"; (b) have a dividend rate of $4.36 per share per annum payable quarterly on February 1, May 1, August 1 and November 1 of each year, the first dividend date to be February 1, 1963, and such dividends to be cumulative from the last date to which dividends upon the 4.36% Preferred Stock Cumulative, $100 Par Value, of Mississippi Power & Light Company, a Florida corporation, are paid; (c) be subject to redemption in the manner provided herein with respect to the Preferred Stock at the price of $105.36 per share if redeemed on or before February 1, 1964, and of $103.88 per share if redeemed after February 1, 1964, in each case plus an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date fixed for redemption. A series of 44,476 shares of the Preferred Stock shall: (a) be designated "4.56% Preferred Stock, Cumulative, $100 Par Value"; (b) have a dividend rate of $4.56 per share per annum payable quarterly on February 1, May 1, August 1 and November 1 of each year, the first dividend date to be February 1, 1963, and such dividends to be cumulative from the last date to which dividends upon the 4.56% Preferred Stock, Cumulative, $100 Par Value, of Mississippi Power & Light Company, a Florida corporation, are paid; and (c) be subject to redemption in the manner provided herein with respect to the Preferred Stock at the price of $108.50 per share if redeemed on or before November 1, l964, and of $107.00 per share if redeemed after November 1, 1964, in each case plus an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date fixed for redemption. A series of 100,000 shares of the Preferred Stock shall: (a) be designated "4.92% Preferred Stock, Cumulative, $100 Par Value"; (b) have a dividend rate of $4.92 per share per annum payable quarterly on February 1, May 1, August 1 and November 1 of each year, the first dividend date to be February 1, 1966, and such dividends to be cumulative from the date of issue of said series; and (c) be subject to redemption at the price of $106.30 per share if redeemed on or before January 1, 1971, of $104.38 per share if redeemed after January 1, 1971 and on or before January 1, 1976, and of $102.88 per share if redeemed after January 1, 1976, in each case plus an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date fixed for redemption. A series of 75,000 shares of the Preferred Stock shall: (a) be designated "9.16% Preferred Stock, Cumulative, $100 Par Value"; (b) have a dividend rate of $9.16 per share per annum payable quarterly on February 1, May 1, August 1 and November 1 of each year, the first dividend date to be November 1, 1970, and such dividends to be cumulative from the date of issue of said series; and (c) be subject to redemption at the price of $110.93 per share if redeemed on or before August 1, 1975, of $108.64 per share if redeemed after August 1, 1975 and on or before August 1, 1980, of $106.35 per share if redeemed after August 1, 1980 and on or before August 1, 1985, and of $104.06 per share if redeemed after August 1, 1985, in each case plus an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date fixed for redemption; provided, however, that no share of the 9.16% Preferred Stock, Cumulative, $100 Par Value, shall be redeemed prior to August 1, 1975 if such redemption is for the purpose or in anticipation of refunding such share through the use, directly or indirectly, of funds borrowed by the Corporation, or through the use, directly or indirectly, of funds derived through the issuance by the Corporation of stock ranking prior to or on a parity with the 9.16% Preferred Stock, Cumulative, $100 Par Value, as to dividends or assets, if such borrowed funds have an effective interest cost to the Corporation (computed in accordance with generally aocepted financial practice) or such stock has an effective dividend cost to the Corporation (so computed) of less than the effective dividend cost to the Corporation of the 9.16% Preferred Stock, Cumulative, $100 Per Value. A series of 100,000 shares of the Preferred Stock shall: (a) be designated "7.44% Preferred Stock, Cumulative, $100 Par Value"; (b) have a dividend rate of $7.44 per share per annum payable quarterly on February 1, May 1, August 1 and November 1 of each year, the first dividend date to be May 1, 1973, and such dividends to be cumulative from February 14, 1973; and (c) be subject to redemption at the price of $108.39 per share if redeemed on or before February 1, 1978, of $106.53 per share if redeemed after February 1, 1978 and on or before February 1, 1983, of $104.67 per share if redeemed after February 1, 1983 and on or before February 1, 1988, and of $102.81 per share if redeemed after February 1, 1988, in each case plus an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date fixed for redemption; provided, however, that no share of the 7.44% Preferred Stock, Cumulative, $100 Par Value, shall be redeemed prior to February 1, 1978 if such redemption is for the purpose or in anticipation of refunding such share through the use, directly or indirectly, of funds borrowed by the Corporation, or through the use, directly or indirectly, of funds derived through the issuance by the Corporation of stock ranking prior to or on a parity with the 7.44% Preferred Stock, Cumulative, $100 Par Value, as to dividends or assets, if such borrowed funds have an effective interest cost to the Corporation (computed in accordance with generally accepted financial practice) or such stock has an effective dividend cost to the Corporation (so computed) of less than the effective dividend cost to the Corporation of the 7.44% Preferred Stock, Cumulative, S100 Par Value. A series of 200,000 shares of the Preferred Stock shall: (a) be designated "17% Preferred Stock, Cumulative, $100 Par Value" (b) have a dividend rate of $17.00 per share per annum payable quarterly on February 1, May 1, August 1 and November 1 of each year, the first dividend date to be November 1, 1981, and such dividends to be cumulative from the date of issuance; (c) be subject to redemption at the price of $117.00 per share if redeemed on or before September 1, 1986, of $112.75 per share if redeemed after September 1, 1986 and on or before September 1, 1991, of $108.50 per share if redeemed after September 1, 1991 and on or before September 1, 1996, and of $104.25 per share if redeemed after September 1, 1996, in each case plus an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date fixed for redemption; provided, however, that no share of the 17% Preferred Stock Cumulative, $100 Par Value, shall be redeemed prior to September 1, 1986 if such redemption is for the purpose or in anticipation of refunding such share through the use, directly or indirectly, of funds borrowed by the Corporation or through the use, directly or indirectly, of funds derived through the issuance by the Corporation of stock ranking prior to or on a parity with the 17% Preferred Stock, Cumulative, $100 Par Value, as to dividends or assets if such borrowed funds have an effective interest cost to the Corporation (computed in accordance with generally accepted financial practice) or such stock; has an effective dividend cost to the Corporation (so computed) of less than the effective dividend cost to the Corporation of the 17% Preferred Stock, Cumulative, $100 Par Value; and (d) be subject to redemption as and for a sinking fund as follows: On September 1, 1986 and on each September 1 thereafter (each such date being hereinafter referred to as a "17% Sinking Fund Redemption Date"), for so long as any shares of the 17% Preferred Stock, Cumulative, $100 Par Value, shall remain outstanding, the Corporation shall redeem, out of funds legally available therefor, 10,000 shares of the 17% Preferred Stock, Cumulative, $100 Par VaIue (or the number of shares then outstanding if less than 10,000) at the sinking fund redemption price of $100 per share plus, as to each share so redeemed, an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date of redemption (the obligation of the Corporation so to redeem the shares of the 17% Preferred Stock, Cumulative, $100 Par Value, being hereinafter referred to as the "17% Sinking Fund Obligation"); the 17% Sinking Fund Obligation shall be cumulative; if on any 17% Sinking Fund Redemption Date, the Corporation shall not have funds legally available therefor sufficient to redeem the full number of shares required to be redeemed on that date, the 17% Sinking Fund Obligation with respect to the shares not redeemed shall carry forward to each successive 17% Sinking Fund Redemption Date until such shares shall have been redeemed; whenever on any 17% Sinking Fund Redemption Date, the funds of the Corporation legally available for the satisfaction of the 17% Sinking Fund Obligation and all other sinking fund and similar obligations then existing with respect to any other class or series of its stock ranking on a parity as to dividends or assets with the 17% Preferred Stock, Cumulative, $100 Par Value (such Obligation and obligations collectively being hereinafter referred to as the "Total Sinking Fund Obligation") are insufficient to permit the Corporation to satisfy fully its Total Sinking Fund Obligation on that date, the Corporation shall apply to the satisfaction of its 17% Sinking Fund Obligation on that date that proportion of such legally available funds which is equal to the ratio of such 17% Sinking Fund Obligation to such Total Sinking Fund Obligation; in addition to the 17% Sinking Fund Obligation, the Corporation shall have the option, which shall be noncumulative, to redeem, upon authorization of the Board of Directors, on each 17% Sinking Fund Redemption Date, at the aforesaid sinking fund redemption price, up to 10,000 additional shares of the 17% Preferred Stock, Cumulative, $100 Par Value; the Corporation shall be entitled, at its election, to credit against its 17% Sinking Fund Obligation on any 17% Sinking Fund Redemption Date any shares of the 17% Preferred Stock, Cumulative, Stock Par Value (including shares of the 17% Preferred Stock, Cumulative, $100 Par Value optionally redeemed at the aforesaid sinking fund price) theretofore redeemed (other than shares of the 17% Preferred Stock, Cumulative, $100 Par Value redeemed pursuant to the 17% Sinking Fund Obligation) purchased or otherwise acquired and not previously credited against the 17% Sinking Fund Obligation. A series of 100,000 shares of the Preferred Stock shall: (a) be designated "14-3/4% Preferred Stock, Cumulative, $100 Par Value"; (b) have a divedend rate of $14.75 per share per annum payable quarterly on February 1, May 1, August 1 and November 1 of each year, the first dividend date to be May 1 1982, and such dividends to be cumulative from the date of issuance; (c) be subject to redemption at the price of $114.75 per share if redeemed after the issuanoe and sale and on or before March 1, 1983, $113.11 per share if redeemed after March 1, 1983 and on or before March 1, 1984, $111.47 per share if redeemed after March 1, 1984 and on or before March 1, 1985, $109.83 per share if redeemed after March 1, 1985 and on or before March 1, 1986, $108.19 per share if redeemed after March 1, 1986 and on or before March 1, 1987, $106.56 per share if redeemed after March 1, 1987 and on or before March 1, 1988, $104.92 per share if redeemed after March 1, 1988 and on or before March 1, 1989, $103.28 per share if redeemed after March 1, 1989 and on or before March 1, l990, $101.64 per share if redeemed after March 1, 1990 and on or before March 1, 1991, and $100.00 per share if redeemed after March 1, 1991, in each case plus an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date fixed for redemption; provided, however, that no share of the 14- 3/4% Preferred Stock, Cumulative, $100 Par Value, shall be redeemed prior to March 1, 1987 if such redemption is for the purpose or in anticipation of refunding such share through the use, directly or indirectly, of funds borrowed by the Corporation, or through the use, directly or indirectly, of funds derived through the issuance by the Corporation of stock ranking prior to or on a parity with the 14-3/4% Preferred Stock, Cumulative, $100 Par Value, as to dividends or assets, if such borrowed funds have an effective interest cost to the Corporation (computed in accordance with generally accepted financial practice) or such stock has an effective dividend cost to the Corporation (so oomputed) of less than the effective dividend cost to the Corporation of the 14-3/4% Preferred Stock, Cumulative, $100 Par Value; and (d) be subject to redemption as and for a sinking fund as follows. On March 1, 1990, 1991 and 1992 (each such date being hereinafteir referred to as a "14-3/4% Sinking Fund Redemption Date"), the Corporation shall redeem, out of funds legally available therefor, 33,333, 33,333 and 33,334 shares, respectively, of the 14-3/4% Preferred Stock, Cumulative, $100 Par Value, at the sinking fund redemption price of $100 per share plus, as to each share so redeemed, an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date of redemption (the obligation of the Corporation so to redeem the shares of the 14-3/4% Preferred Stock, Cumulative, $100 Par Value, being hereinafter referred to as the "14-3/4% Sinking Fund Obligation"); the 14- 3/4% Sinking Fund Obligation shall be cumulative; if on any 14-3/4% Sinking Fund Redemption Date, the Corporation shall not have funds legally available therefor sufficient to redeem the full number of shares required to be redeemed on that date, the 14-3/4% Sinking Fund Obligation with respect to the shares not redeemed shall carry forward to each successive 14-3/4% Sinking Fund Redemption Date (or, in the event the 14- 3/4% Sinking Fund Obligation is not satisfied on March 1, 1992, to such date as soon thereafter as funds are legally available to satisfy the 14-3/4% Sinking Fund Obligation) until such shares shall have been redeemed; whenever on any 14-3/4% Sinking Fund Redemption Date, the funds of the Corporation legally available for the satisfaction of the 14-3/4% Sinking Fund Obligation and all other sinking fund and similar obligations then existing with respect to any other class or series of its stock ranking on a parity as to dividends or assets with the 14-3/4% Preferred Stock, Cumulative, $100 Par Value (such Obligation and obligations collectively being hereinafter referred to as the "Total Sinking Fund Obligation") are insufficient to permit the Corporation to satisfy fully its Total Sinking Fund Obligation on that date, the Corporation shall apply to the satisfaction of its 14-3/4% Sinking Fund Obligation on that date that proportion of such legally available funds which is equal to the ratio of such 14-3/4% Sinking Fund Obligation to such Total Sinking Fund Obligation. A series of 100,000 shares of the Preferred Stock shall: (a) be designated "12.00% Preferred Stock, Cumulative, $100 Par Value"; (b) have a dividend rate of $12.00 per share per annum payable quarterly on February 1, May 1, August 1 and November l of each year, the first dividend date to be May 1, 1983, and such dividends to be cumulative from the date of issuance; (c) be subject to redemption at the price of $112.00 per share if redeemed on or before March 1, 1988, of $109.00 per share if redeemed after March 1, 1988 and on or before March 1, 1993, of $106.00 per share if redeemed after March 1, 1993 and on or before March 1, 1998, and of $103.00 per share if redeemed after March 1, 1998, in each case plus an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date fixed for redemption; provided, however, that no share of the 12.00% Preferred Stock, Cumulative, $100 Par Value, shall be redeemed prior to March 1, 1988 if such redemption is for the purpose or in anticipation of refunding such share through the use, directly or indirectly, of funds borrowed by the Corporation, or through the use, directly or indirectly, of funds derived through the issuance by the Corporation of stock ranking prior to or on a parity with the 12.00% Preferred Stock, Cumulative, $100 Par Value, as to dividends or assets, if such borrowed funds have an effective interest cost to the Corporation (computed in accordance with generally accepted financial practice) or such stock has an effective dividend cost to the Corporation (so computed) of less than 12.7497% to per annum; and (d) be subject to redemption as and for a sinking fund as follows: on March 1, 1888 and on each March 1 thereafter (each such date being hereinafter referred to as a "12.00% Sinking Fund Redemption Date"), for so long as any shares of the 12.00% Preferred Stock, Cumulative, $100 Par Value, shall remain outstanding, the Corporation shall redeem, out of funds legally available therefor, 5,000 shares of the 12.00% Preferred Stock, Cumulative, $100 Par Value (or the number of shares then outstanding if less than 5,000) at the sinking fund redemption price of $100 per share plus, as to each share so redeemed, an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date of redemption (the obligation of the Corporation so to redeem the shares of the 12.00% Preferred Stock, Cumulative, $100 Par Value, being hereinafter referred to as the "12.00% Sinking Fund Obligation"); the 12.00% Sinking Fund Obligation shall be cumulative; if on any 12.00% Sinking Fund Redemption Date, the Corporation shall not have funds legally available therefor sufficient to redeem the full number of shares required to be redeemed on that date, the 12.00% Sinking Fund Obligation with respect to the shares not redeemed shall carry forward to each successive 12.00% Sinking Fund Redemption Date until such shares shall have been redeemed; whenever on any 12.00% Sinking Fund Redemption Date, the funds of the Corporation legally available for the satisfaction of the 12.00% Sinking Fund Obligation and all other sinking fund and similar obligations then existing with respect to any other class or series of its stock ranking on a parity as to dividends or assets with the 12.00% Preferred Stock Cumulative, $100 Par Value (such Obligation and obligations collectively being hereinafter referred to as the "Total Sinking Fund Obligation") are insufficient to permit the Corporation to satisfy fully its Total Sinking Fund Obligation on that date, the Corporation shall apply to the satisfaction of its 12.00% Sinking Fund Obligation on that date that proportion of such legally available funds which is equal to the ratio of such 12.00% Sinking Fund Obligation to such Total Sinking Fund Obligation; in addition to the 12.00% Sinking Fund Obligation, the Corporation shall have the option, which shall be noncumulative, to redeem, upon authorization of the Board of Directors, on each 12.00% Sinking Fund Redemption Date, at the aforesaid sinking fund redemption price, up to 5,000 additional shares of the 12.00% Preferred Stock Cumulative, $100 Par Value; the Corporation shall be entitled, at its election, to credit against its 12.00% Sinking Fund Obligation on any 12.00% Sinking Fund Redemption Date any shares of the 12.00% Preferred Stock, Cumulative, $100 Par Value (including shares of the 12.00% Preferred Stock Cumulative, $100 Par Value optionally redeemed at the aforesaid sinking fund price) theretofore redeemed (other than shares of the 12.00% Preferred Stock, Cumulative, $100 Par Value redeemed pursuant to the 12.00% Sinking Fund Obligation) purchased or otherwise acquired and not previously credited against the 12.00% Sinking Fund Obligation. Subject to the foregoing, the distinguishing characteristics of the Preferred Stock shall be: (A) Each series of the Preferred Stock, pari passu with all shares of preferred stock of any class or series then outstanding, shall be entitled but only when and as declared by the Board of Directors, out of funds legally available for the payment of dividends in preference to the Common Stock, to dividends at tbe rate stated and expressed with respect to such series herein or by the resolution or resolutions providing for the issue of such series adopted by tbe Board of Directors; such dividends to be cumulative from such date and payable on such dates in each year as may be stated and expressed in said resolution, to stockholders of record as of a date not to exceed 40 days and not less than 10 days preceding the dividend payment dates so fixed. (B) If and when dividends payable on any of the Preferred Stock of the Corporation at any time outstanding shall be in defauIt in an amount equal to four full quarterly payments or more per share, and thereafter until all dividends on any such preferred stock in default shall have been paid, the holders of the Preferred Stock pari passu with the holders of other preferred stock then outstanding, voting separately as a class, shall be entitled to elect the smallest number of directors necessary to constitute a majority of the full Board of Directors, and, except as provided in the following paragraph, the holders of the Comrnon Stock, voting separately as a class, shall be entitled to elect the remaining directors of the Corporation. The termns of office, as directors, of all persons who may be directors of the Corporation at the time shall terminate upon the election of a majority of the Board of Directors by the holders of the Preferred Stock except that if the holders of the Common Stock shall not have elected the remaining directors of the Corporation, then, and only in that event, the directors of the Corporation in office just prior to the election of a majority of the Board of Directors by the holders of the Preferred Stock shall elect the remaining directors of the Corporation. Thereafter, while such default continues and the majority of the Board of Directors is being elected by the holders of the Preferred Stock, the remaining directors, whether elected by directors, as aforesaid, or whether originally or later elected by holders of the Common Stock shall continue in office until their successors are elected by holders of the Common Stock and shall qualify. If and when all dividends then in default on the Preferred Stock; then outstanding shall be paid (such dividends to be declared and paid out of any funds legally available therefor as soon as reasonably practicable), the holders of the Preferred Stock shall be divested of any special right with respect to the election of directors, and the voting power of the holders of the Preferred Stock and the holders of the Common Stock shall revert to the status existing before the first dividend payment date on which dividends on the Preferred Stock were not paid in full, but always subject to the same provisions for vesting such special rights in the bolders of the Preferred Stock in case of further like defaults in the payment of dividends thereon as described in the immediately foregoing paragraph. Upon termination of any such special voting right upon payment of all accumulated and unpaid dividends on the Preferred Stock, the terms of office of all persons who may have been elected directors of the Corporation by vote of the holders of the Preferred Stock as a class, pursuant to such special voting right shall forthwith terminate, and the resulting vacancies shall be filled by the vote of a majority of the remaining directors. In case of any vacancy in the office of a director occurring among the directors elected by the holders of the Preferred Stock, voting separately as a class, the remaining directors elected by the holders of the Preferred Stock, by affirmative vote of a majority thereof, or the remaining director so elected if there be but one, may elect a successor or successors to hold office for the unexpired term or terms of the director or directors whose place or places shall be vacant. Likewise, in case of any vacancy in the office of a director occurring among the directors not elected by the holders of the Preferred Stock, the remaining directors not elected by the holders of the Preferred Stock, by affirmative vote of a majority thereof, or the remaining director so elected if there be but one, may elect a successor or successors to hold office for the unexpired term or terms of the director or directors whose place or places shall be vacant. Whenever the right shall have accrued to the holders of the Preferred Stock to elect directors, voting separately as a class, it shall be the duty of the President, a Vice- President or the Secretary of the Corporation forthwith to call and cause notice to be given to the shareholders entitled to vote of a meeting to be held at such time as the Corporation's officers may fix, not less than forty-five nor more than sixty days after the accrual of such right, for the purpose of electing directors. The notice so given shall be mailed to each holder of record of preferred stock at his last known address appearing on the books of the Corporation and shall set forth, among other things, (i) that by reason of the fact that dividends payable on preferred stock are in default in an amount equal to four full quarterly payments or more per share, the holders of the Preferred Stock, voting separately as a class, have the right to elect the smallest number of directors necessary to constitute a majority of the full Board of Directors of the Corporation, (ii) that any holder of the Preferred Stock has the right, at any reasonable time, to inspect, and make copies of, the list or lists of holders of the Preferred Stock maintained at the principal office of the Corporation or at the office of any Transfer Agent of the Preferred Stock, and (iii) either the entirety of this paragraph or the substance thereof with respect to the number of shares of the Preferred Stock required to be represented at any meeting, or adjournment thereof, called for the election of directors of the Corporation. At the first meeting of stockholders held for the purpose of electing directors during such time as the holders of the Preferred Stock shall have the special right, voting separately as a class, to elect directors, the presence in person or by proxy of the holders of a majority of the outstanding Common Stock shall be required to constitute a quorum of such class for the election of directors, and the presence in person or by proxy of the holders of a majority of the outstanding Preferred Stock shall be required to constitute a quorum of such class for the election of directors; provided, however, that in the absence of a quorum of the holders of the Preferred Stock, no election of directors shall be held, but a majority of the holders of the Preferred Stock who are present in person or by proxy shall have power to adjourn the election of the directors to a date not less than fifteen nor more than fifty days from the giving of the notice of such adjourned meeting hereinafter provided for; and provided, further, that at such adjourned meeting, the presence in person or by proxy of the holders of 35% of the outstanding Preferred Stock shall be required to constitute a quorum of such class for the election of directors. In the event such first meeting of stockholders shall be so adjourned, it shall be the duty of the President, a Vice-President or the Secretary of the Corporation, within ten days from the date on which such first meeting shall have been adjourned, to cause notice of such adjourned meeting to be given to the shareholders entitled to vote thereat, such adjourned meeting to be held not less than fifteen days nor more than fifty days from the giving of such second notice. Such second notice. shall be given in the form and manner hereinabove provided for with respect to the notice required to be given of such first meeting of stockholders, and shall further set forth that a quorum was not present at such first meeting and that the holders of 35% of the outstanding Preferred Stock shall be required to constitute a quorum of such class for the election of directors at such adjourned meeting. If the requisite quorum of holders of the Preferred Stock shall not be present at said adjourned meeting, then the directors of the Corporation then in office shall remain in office until the next Annual Meeting of the Corporation, or special meeting in lieu thereof and until their successors shall have been elected and shall qualify. Neither such first meeting nor such adjourned meeting shall be held on a date within sixty days of the date of the next Annual Meeting of the Corporation, or special meeting in lieu thereof. At each Annual Meeting of the Corporation, or special meeting in lieu thereof, held during such time as the holders of the Preferred Stock, voting separately as a class. shall have the right to elect a majority of the Board of Directors, the foregoing provisions of this paragraph shall govern each Annual Meeting, or special meeting in lieu thereof, as if said Annual Meeting or special meeting were the first meeting of stockholders held for the purpose of electing directors after the right of the holders of the Preferred Stock, voting separately as a class, to elect a majority of the Board of Directors, should have accrued the exception, that if, at any adjourned annual meeting, or special meeting in lieu thereof, the holders of 35% of the outstanding Preferred Stock are not present in person or by proxy, all the directors shall be elected by a vote of the holders of a majority of the Common Stock of the Corporation present or represented at the meeting. (C) So long as any shares of the Preferred Stock are outstanding, the Corporation shall not, without the consent (given by vote at a meeting called for that purpose) of at least two-thirds of the total number of shares of the Preferred Stock then outstanding: (1) create, authorize or issue any new stock which, after issuance would rank prior to the Preferred Stock as to dividends, in liquidation, dissolution, winding up or distribution, or create, authorize or issue any security convertible into shares of any such stock except for the purpose of providing funds for the redemption of all of the Preferred Stock then outstanding, such new stock or security not to be issued until such redemption shall have been authorized and notice of such redemption given and the aggregate redemption price deposited as provided in paragraph (G) below; provided, however, that any such new stock or security shall be issued within twelve months after the vote of the Preferred Stock herein provided for authorizing the issuance of such new stock or security; or (2) amend, alter, or repeal any of the rights, preferences or powers of the holders of the Preferred Stock so as to affect adversely any such rights, preferences or powers; provided, however, that if such amendment, alteration or repeal affects adversely the rights, preferences or powers of one or more, but not all, series of Preferred Stock at the time outstanding, only the consent of the holders of at least two-thirds of the total number of outstanding shares of all series so affected shall be required; and provided, further, that an amendment to increase or decrease the authorized amount of Preferred Stock or to create or authorize, or increase or decrease the amount of, any class of stock; ranking on a parity with the outstanding shares of the Preferred Stock as to dividends or assets shall not be deemed to affect adversely the rights, preferences or powers of the holders of the Preferred Stock or any series thereof. (D) So long as any shares of the Preferred Stock are outstanding, the Corporation shall not, without the consent (given by vote at a meeting called for that purpose) of the holders of a majority of the total number of shares of the Preferred Stock then outstanding: (1) merge or consolidate with or into any other corporation or corporations or sell or otherwise dispose of all or substantially all of the assets of the Corporation, unless such merger or consolidation or sale or other disposition, or the exchange, issuance or assumption of all securities to be issued or assumed in connection with any such merger or consolidation or sale or other disposition, shall have been ordered, approved or permitted under the Public Utility Holding Company Act of 1935; or (2) issue or assume any unsecured notes, debentures or other securities representing unsecured indebtedness for purposes other than (i) the refunding of outstanding unsecured indebtedness theretofore issued or assumed by the Corporation resulting in equal or longer maturities, or (ii) the reacquisition, redemption or other retirement of all outstanding shares of the Preferred Stock, if immediately after such issue or assumption, the total principal amount of all unsecured notes, debentures or other securities representing unsecured indebtedness issued or assumed by the Corporation, including unsecured indebtedness then to be issued or assumed (but excluding the principal amount then outstanding of any unsecured notes, debentures, or other securities representing unsecured indebtedness having a maturity in excess of ten (10) years and in amount not exceeding 10% of the aggregate of (a) and (b) of this section below) would exceed ten per centum (10%) of the aggregate of (a) the total principal amount of all bonds or other securities representing secured indebtedness issued or assumed by the Corporation and then to be outstanding, and (b) the capital and surplus of the Corporation as then to be stated on the books of account of the Corporation. When unsecured notes, debentures or other securities representing unsecured debt of a maturity in excess of ten (10) years shall become of a maturity of ten (10) years or less, it shall then be regarded as unsecured debt of a maturity of less than ten (10) years and shall be computed with such debt for the purpose of determining the percentage ratio to the sum of (a) and (b) above of unsecured debt of a maturity of less than ten (10) years, and when provision shall have been made, whether through a sinking fund or otherwise, for the retirement, prior to their maturity, of unsecured notes, debentures, or other securities representing unsecured debt of a maturity in excess of ten (10) years, the amount of any such security so required to be retired in less than ten (10) years shall be regarded as unsecured debt of a maturity of less than ten (10) years (and not as unsecured debt of a maturity in excess of ten (10) years) and shall be computed with such debt for the purpose of determining the percentage ratio to the sum of (a) and (b) above of unsecured debt of a maturity of less than ten (10) years, provided, however, that the payment due upon the maturity of unsecured debt having an original single maturity in excess of ten (10) years or the payment due upon the latest maturity of any serial debt which had original maturities in excess of ten (10) years shall not, for purposes of this provision, be regarded as unsecured debt of a maturity of less than ten (10) years until such payment or payments shall be required to be made within three (3) years; furthermore, when unsecured notes, debentures or other securities representing unsecured debt of a maturity of less than ten (10) years shall exceed 10% of the sum of (a) and (b) above, no additional unsecured notes, debentures or other securities representing unsecured debt shall be issued or assumed (except for the purpose set forth in (i) or (ii) above) until such ratio is reduced to 10% of the sum of (a) and (b) above; or (3) issue, sell or otherwise dispose of any shares of the Preferred Stock in addition to the 104,476 shares of the Preferred Stock originally authorized, or of any other class of stock ranking on a parity with the Preferred Stock as to dividends or in liquidation, dissolution, winding up or distribution, unless the gross income of the Corporation and Mississippi Power & Light Company, a Florida corporation, for a period of twelve (12) consecutive calendar months within the fifteen (15) calendar months immediately preceding the issuance, sale or disposition of such stock, determined in accordance with generally acccepted accounting practices (but in any event after deducting all taxes and the greater of (a) the amount for said period charged by the Corporation and Mississippi Power & Light Company, a Florida corporation, on their books to depreciation expense or (b) the largest amount required to be provided therefor by any mortgage indenture of the Corporation) to be available for the payment of interest, shall have been at least one and one-half times the sum of (i) the annual interest charges on all interest bearing indebtedness of the Corporation and (ii) the annual dividend requirements on all outstanding shares of the Preferred Stock and of all other classes of stock ranking prior to, or on a parity with, the Preferred Stock as to dividends or distributions, including the shares proposed to be issued; provided, that there shall be excluded from the foregoing computation interest charges on all indebtedness and dividends on all shares of stock which are to be retired in connection with the issue of such additional shares of the Preferred Stock or other class of stocks ranking prior to, or on a parity with, the Preferred Stock as to dividends or distributions; and provided, further, that in any case where such additional shares of the Preferred Stock, or other class of stock ranking on a parity with the Preferred Stock as to dividends or distributions, are to be issued in connection with the acquisition of additional property, the gross income of the property to be so acquired, computed on the same basis as the gross income of the Corporation, may be included on a pro forma basis in making the foregoing computation; or (4) issue, sell, or otherwise dispose of any shares of the Preferred Stock, in addition to the 104,476 shares of the Preferred Stock originally authorized, or of any other class of stock ranking on a parity with the Preferred Stock as to dividends or distributions, unless the aggregate of the capital of the Corporation applicable to the Common Stock and the surplus of the Corporation shall be not less than the aggregate amount payable on the involuntary liquidation, dissolution, or winding up of the Corporation, in respect of all shares of the Preferred Stock and all shares of stock, if any, ranking prior thereto, or on a parity therewith, as to dividends or distributions, which will be outstanding after the issue of the shares proposed to be issued; provided, that if, for the purposes of meeting the requirements of this subparagraph (4), it becomes necessary to take into consideration any earned surplus of the Corporation, the Corporation shall not thereafter pay any dividends on shares of the Common Stock which would result in reducing the Corporation's Common Stock equity (as in paragraph (H) hereinafter defined) to an amount less than the aggregate amount payable, on involuntary liquidation, dissolution or winding up the Corporation, on all shares of the Preferred Stock and of any stock ranking prior to, or on a parity with, the Preferred Stock, as to dividends or other distributions, at the time outstanding. (E) Each holder of Conunon Stock of the Corporation shall be entitled to one vote, in person or by proxy, for each share of such stock standing in his name on the books of the Corporation. Except as hereinbefore expressly provided in this Section Fourth, the holders of the Preferred Stock shall have no power to vote and shall be entitled to no notice of any meeting of the stockholders of the Corporation. As to matters upon which holders of the Preferred Stock are entitled to vote as hereinbefore expressly provided, each holder of such Preferred Stock shall be entitled to one vote, in person or by proxy, for each share of such Preferred Stock standing in his name on the books of the Corporation. (F) In the event of any voluntary liquidation, dissolution or winding up of the Corporation, the Preferred Stock, pari passu with all shares of preferred stock of any class or series then outstanding, shall have a preference over the Common Stock until an amount equal to the then current redemption price shall have been paid. In the event of any involuntary liquidation, dissolution or winding up of the Corporation, which shall include any such liquidation, dissolution or winding up which may arise out of or result from the condemnation or purchase of all or a major portion of the properties of the Corporation, by (i) the United States Government or any authority, agency or instrumentality thereof, (ii) a state of the United States or any polltical subdivision, authority, agency, or instrumentality thereof, or (iii) a disrict, cooperative or other association or entity not organized for profit, the Preferred Stock, pari passu with all shares of preferred stock of any class or series then outstanding, shall also have a preference over the Common Stock until the full par value thereof and an amount equal to all accumulated and unpaid dividends thereon shall have been paid by dividends or distribution. (G) Upon the affirmative vote of a majority of the shares of the issued and outstanding Common Stock at any annual meeting, or any special meeting called for that purpose, the Corporation may at any time redeem all of any series of said Preferred Stock or may from time to time redeem any part thereof, by paying in cash the redemption price then applicable thereto as stated and expressed with respect to such series in the resolution providing for the issue of such shares adopted by the Board of Directors of the Corporation, or in these Restated Articles of Incorporation or any amendment thereof, plus, in each case, an amount equivalent to the accumulated and unpaid dividends, if any, to the date of redemption. Notice of the intention of the Corporation to redeem all or any part of the Preferred Stock shall be mailed not less than thirty (30) days nor more than sixty (60) days before the date of redemption to each holder of record of Preferred Stock to be redeemed, at his post office address as shown by the Corporation's records, and not less than thirty (30) days' nor more than sixty (60) days' notioe of such redemption may be published in such manner as may be prescribed by resolution of the Board of Directors of the Corporation; and, in the event of such publication, no defect in the mailing of such notice shall affect the validity of the proceedings for the redemption of any shares of Preferred Stock so to be redeemed. Contemporaneously with the mailing or the publication of such notice as aforesaid or at any time thereafter prior to the date of redemption, the Corporation may deposit the aggregate redemption price (or the portion thereof not already paid in the redemption of such Preferred Stock so to be redeemed) with any bank or trust company in the City of New York, New York, or in the City of Jackson, Mississippi, named in such notice, payable to the order of the record holders of the Preferred Stock so to be redeemed, as the case may be, on the endorsement and surrender of their certificates, and thereupon said holders shall cease to be stockholders wlth respect to such shares; and from and after the making of such deposit such holders shall have no interest in or claim against the Corporation with respect to said shares, but shall be enlitled only to receive such moneys from said bank or trust company, with interest, if any, allowed by such bank or trust company on such moneys deposited as in this paragraph provided, on endorsement and surrender of their certificates, as aforesaid. Any moneys so deposited, plus interest thereon, if any, remaining unclaimed at the end of six years from the date fixed for redemption, if thereafter requested by resolution of the Board of Directors, shall be repaid to the Corporation, and in the event of such repayment to the Corporation, such holders of record of the shares so redeemed as shall not have made claim against such moneys prior to such repayment to the Corporation, shall be deemed to be unsecured creditors of the Corporation for an amount, without interest, equivalent to the amount deposited, plus interest thereon, if any, allowed by such bank or trust company, as above stated, for the redemption of such shares and so paid to the Corporation. Shares of the Preferred Stock which have been redeemed shall not be reissued. If less than all of the shares of the Preferred Stock are to be redeemed, the shares thereof to be redeemed shall be selected by lot, in such manner as the Board of Directors of the Corporation shall determine, by an independent bank or trust company selected for that purpose by the Board of Directors of the Corporation. Nothing herein contained shall limit any legal right of the Corporation to purchase or otherwise acquire any shares of the Preferred Stock; provided, however, that, so long as any shares of the Preferred Stock are outstanding, the Corporation shall not redeem, purchase or otherwise acquire less than all of the shares of the Preferred Stock, if, at the time of such redemption, purchase or other acquisition, dividends payable on the Preferred Stock shall be in default in whole or in part, unless, prior to or concurrently with such redemption, purchase or other acquisition, all such defaults shall be cured or unless such redemption, purchase or other acquisition shall have been ordered, approved or permitted under the Public Utility Holding Company Act of 1935; and provided further that, so long as any shares of the Preferred Stock are outstanding, the Corporation shall not make any payment or set aside any funds for payment into any sinking fund for the purchase or redemption of any shares of the Preferred Stock, if, at the time of such payment, or the setting apart of funds for such payment, dividends payable on the Preferred Stock shall be in default in whole or in part, unless, prior to or concurrently with such payment or the setting apart of funds for such payment, all such defaults shall be cured or unless such payment, or the setting apart of funds for such payment, shall bave been ordered, approved or permitted under the Public Utility Holding Company Act of 1935. Any shares of the Preferred Stock so redeemed, purchased or acquired shall retired and cancelled. (H) For the purposes of this paragraph (H) and subparagraph (4) of paragraph (D) the term "Common Stock Equity" shall mean the aggregate of the par value of, or stated capital represented by, the outstanding shares (other than shares owned by the Corporation) of stock ranking junior to the Preferred Stock as to dividends and assets, of the premium on such junior stock and of the surplus (including earned surplus, capital surplus and surplus invested in plant) of the Corporation less (1) any amounts recorded on the books of the Corporation for utility plant and other plant in excess of the original cost thereof, (2) unamortized debt discount and expense, capital stock discount and expense and any other intangible items set forth on the asset side of the balance sheet as a result of accounting convention, (3) the excess, if any, of the aggregate amount payable on involuntary liquidation, dissolution or winding up of the affairs of the Corporation upon all outstanding preferred stock of the Corporation over the aggregate par or stated value thereof and any premiums thereon and (4) the excess, if any, for the period beginning with January 1, 1954, to the end of the month within ninety (90) days preceding the date as of which Common Stock Equity is determined, of the cumulative amount computed under requirements contained in the Corporation's mortgage indentures relating to minimum depreciation provisions (this cumulative amount being the aggregate of the largest amounts separately computed for entire periods of differing coexisting mortgage indenture requirements), over the amount charged by the Corporation and Mississippi Power & Light Company, a Florida corporation, on their books for depreciation during such period, including the final fraction of a year; provided, however, that no deductions shall be required to be made in respect of items referred to in subdivisions (1) and (2) of this paragraph (H) in cases in which such items are being amortized or are provided for, or are being provided for, by reserves. For the purpose of this paragraph (H): (i) the term "total capitalization" shall mean the sum of the Common Stock Equity plus item three (3) in this paragraph (H) and the stated capital applicable to, and any premium on, outstanding stock of the Corporation not included in Common Stock Equity, and the principal amount of all outstanding debt of the Corporation maturing more than twelve months after the date of issue thereof; and (ii) the term "dividends on Common Stock" shall embrace dividends on Common Stock (other than dividends payable only in shares of Common Stock), distributions on, and purchases or other acquisitions for value of, any Common Stock of the Corporation or other stock if any, subordinate to its Preferred Stock. So long as any shares of the Preferred Stock are outstanding, the Corporation shall not declare or pay any dividends on the Common Stock, except as follows: (a) If and so long as the Common Stock Equity at the end of the calendar month immediately preceding the date on which a dividend on Common Stock is declared is, or as a result of such dividend would become, less than 20% of total capitalization, the Corporation shall not declare such dividends in an amount which, together with all other dividends on Common Stock paid within the year ending with and including the date on which such dividend is payable, exceeds 50% of the net income of the Corporation available for dividends on the Common Stock for the twelve full calendar months immediately preceding the month in which such dividends are declared, except in an amount not exceeding the aggregate of dividends on Common Stock which under the restrictions set forth above in this subparagraph (a) could have been, and have not been, declared; and (b) If and so long as the Common Stock Equity at the end of the calendar month immediately preceding the date on which a dividend on Common Stock is declared is, or as a result of such dividend would become, less than 25% but not less than 20% of total capitalization, the Corporation shall not declare dividends on the Common Stock in an amount which, together with all other dividends on Comrnon Stock paid within the year ending with and including the date on which such dividend is payable, exceeds 75% of the net income of the Corporation and Mississippi Power & Light Company, a Florida corporation, available for dividends on the Common Stock for the twelve full calendar months immediately preceding the month in which such dividends are declared, except in an amount not exceeding the aggregate of dividends on Common Stock which under the restrictions set forth above in subparagraph (a) and in this subparagraph (b) could have been and have not been declared; and (c) If any time when the Common Stock Equity is 25% or more of total capitalization, the Corporation may not declare dividends on shares of the Common Stock which would reduce the Common Stock Equity below 25% of total capitalization, except to the extent provided in subparagraphs (a) and (b) above. At anytime when the aggregate of all amounts credited subsequent to January 1, 1954, to the depreciation reserve account of the Corporation and Mississippi Power & Light Company, a Florida corporation, through charges to operating revenue deductions or otherwise on the books of the Corporation and Mississippi Power & Light Company, a Florida corporation, shall be less than the amount computed as provided in clause (aa) below, under requirements contained in the Corporation's mortgage indentures, then for the purposes of subparagraphs (a) and (b) above, in determining the earnings available for common stock dividends during any twelve-month period, the amount to be provided for depreciation in that period shall be (aa) the greater of the cumulative amount charged to depreciation expense on the books of the Corporation and Mississippi Power & Light Company, a Florida corporation, or the cumulative amount computer under requirements contained in the Corporation's mortgage indentures relating to minimum depreciation provisions (the latter cumulative amount being the aggregate of the largest amounts separately computed for entire periods of differing co-existing mortgage indenture requirements) for the period from January 1, 1954, to and including said twelve- month period, less (bb) the greater of the cumulative amount charged to depreciation expense on the books of the Corporation and Mississippi Power & Light Company, a Florida corporation, or the cumulative amount computed under requirements contained in the Corporation's mortgage indentures relating to minimum depreciation provisions (the latter cumulative amount being the aggregate of the largest amounts separately computed for entire periods of differing coexisting mortgage indenture requirements) from January 1, 1954, up to but excluding said twelve-month period; provided that in the event any company other than Mississippi Power & Light Company, a Florida corporation, is merged into the Corporation the "cumulative amount computed under requirements contained in the Corporation's mortgage indentures relating to minimum depreciation provisions" referred to above shall be computed without regard, for the period perior to the merger, of property acquired in the merger, and the "cumulative amount charged to depreciation expense on the books of the Corporation" shall be exclusive of amounts provided for such property prior to the merger. (I) The Board of Directors are hereby expressly authorized by resolution or resolutions to state and express the series and distinctive serial designation of any authorized and unissued shares of Preferred Stock proposed to be issued, the number of shares to constitute each such series, the annnal rate or rates of dividends payable on shares of each series together with the dates on which such dividends shall be paid in each year, the date from which such dividends shall commence to accumulate, the amount or amounts payable upon redemption and the sinking fund provisions, if any, for the redemption or purchase of shares. (J) Dividends may be paid upon the Common Stock only when (i) dividends have been paid or declared and funds set apart for the payment of dividends as aforesaid on the Preferred Stock from thc date(s) after which dividends thereon became cumulative, to the beginning of the period then current, with respect to which such dividends on the Preferred Stock are usually declared, and (ii) all payments have been made or funds have been set aside for payments then or theretofore due under sinking fund provisions, if any, for the redemption or purchase of shares of any series of the Preferred Stock, but whenever (x) there shall have been paid or declared and funds shall have been set apart for the payment of all such dividends upon the Preferred Stock as aforesaid, and (y) all payments shall have been made or funds shall have been set aside for payments then or theretofore due under sinking fund provisions, if any, for the redemption or purchase of shares of any series of the Preferred Stock, then, subject to the limitations above set forth, dividends upon the Common Stock may be declared payable then or thereafter, out of any net earnings or surplus of assets over liabilities, including capital, then remaining. After the payment of the limited dividends and/or shares in distribution of assets to which the Preferred Stock is expressly entitled in preference to the Common Stock, in accordancc with the provisions hereinabove set forth, the Common Stock alone (subject to the rights of any class of stock hereafter authorized) shall receive all further dividends and shares in distribution. (K) Subject to the limitations hereinabove set forth the Corporation from time to time may resell any of its own stock, purchased or otherwise acquired by it as hereinafter provided for, at such price as may be fixed by its Board of Directors or Executive Committee. (L) Subject to the limitations hereinabove set forth the Corporation in order to acquire funds with which to redeem any outstanding Preferred Stock of any class, may issue and sell stock of any class then authorized but unissued, bonds, notes, evidences of indebtedness, or other securities. (M) Subject to the limitations hereinabove set forth the Board of Directors of the Corporation may at any time authorize the conversion or exchange of the whole or any particular share of the outstanding preferred stock of any class with the consent of the holder thereof, into or for stock of any other class at the time of such consent authorized but unissued and may fix the terms and conditions upon which such conversion or exchange may be made; provided that without the consent of the holders of record of two-thirds of the shares of Common Stock outstanding given at a meeting of the holders of the Common Stock called and held as provided by the By-Laws or given in writing without a meeting, the Board of Directors shall not authorize the conversion or exchange of any preferred stock of any class into or for Common Stock or authorize the conversion or exchange of any preferred stock; of any class into or for preferred stock of any other class, if by such conversion or exchange the amount which the holders of the shares of stock so converted or exchanged would be entitled to receive either as dividends or shares in distribution of assets in preference to the Common Stock would be increased. (N) A consolidation, merger or amalgamation of the Corporation with or into any other corporation or corporations shall not be deemed a distribution of assets of the Corporation within the meaning of any provisions of these Restated Articles of Incorporation. (O) The consideration received by the Corporation from the sale of any additional stock without nominal or par value shall be entered in the Corporation's capital stock account. (P) Subject to the limitations hereinabove set forth upon the vote of a majority of all the Directors of the Corporation and of a majority of the total number of shares of stock then issued and outstanding and entitled to vote, irrespective of class (or if the vote of a larger number or different proportion of shares is required by the laws of the State of Mississippi notwithstanding the above agreement of the stockholders of the Corporation to the contrary, then upon the vote of the larger number or different proportion of shares so required), the Corporation may from time to time create or authorize one or more other classes of stock with such preferences, designations, rights, privileges, powers, restrictions, limitations and qualifications as may be determined by said vote, which may be the same as or different from the preferences, designations, rights, privileges, powers, restrictions, limitations and qualifications of the classes of stock of the Corporation then authorized. Any such vote authorizing the creation of a new class of stock may provide that all moneys payable by the Corporation with respect to any class of stock thereby authorized shall be paid in the money of any foreign country named therein or designated by the Board of Directors, pursuant to authority therein granted, at a fixed rate of exchange with the money of the United States of America therein stated or provided for and all such payments shall be made accordingly. Any such vote may authorize any shares of any class then authorized but unissued to be issued as shares of such new class or classes (Q) Subject to the limitations hereinabove set forth, either the Preferred Stock or the Common Stock or both of said classes of stock, may be increased at any time upon vote of the holders of a majority of the total number of shares of the Corporation then issued and outstanding and entitled to vote thereon, irrespective of class. (R) If any provisions in this Section Fourth shall be in conflict or inconsistent with any other provisions of these Restated Articles of Incorporation of the Corporation the provisions of this Section Fourth shall prevail and govern. FIFTH: The Corporation will not commence business until at least $1,000 has been received by it as consideration for the issuance of shares. SIXTH: Existing provisions limiting or denying to shareholders the preemptive right to acquire additional or treasury shares of the Corporation are: No holder of any stock of the Corporation shall be entitled as of right to purchase or subscribe for any part of any unissued stock of the Corporation, or any additional stock of any class to be issued by reason of any increase of the authorized capital stock of the Corporation or of bonds, certificates of indebtedness, debentures, or other securities convertible into stock of the Corporation, but any such unissued stock or any such additional authorized issue of new stock, or of securities convertible into stock, may be issued and disposed of by the Board of Directors without offering to the stockholders then of record, or to any class of stockholders, any thereof on any terms. SEVENTH: Existing provisions of the Restated Articles of Incorporation for the regulation of the internal affairs of the Corporation are: (a) General authority is hereby conferred upon the Board of Directors to fix the consideration for which shares of stock of the Corporation without nominal or par value may be issued and disposed of, and the shares of stock of the Corporation without nominal or par value, whether authorized by these Restated Articles of Incorporation or by subsequent increase of the authorized number of shares of stock or by amendment of these Restated Articles of Incorporation by consolidation or merger or otherwise, and/or any securities convertible into stock of the Corporation without nominal or par value may be issued and disposed of for such consideration and on such terms and in such manner as may be fixed from time to time by the Board of Directors. (b) The issue of the whole, or any part determined by the Board of Directors, of the shares of stock of the Corporation as partly paid, and subject to calls thereon until the whole thereof shall have been paid, is hereby authorized. (c) The Board of Directors shall have power to authorize the payment of compensation to the directors for services to the Corporation, including fees for attendance at meetings of the Board of Directors or the Executive Committee and all other committees and to determine the amount of such compensation and fees. (d) The Corporation may issue a new certificate of stock in the place of any certificate theretofore issued by it, alleged to have been lost or destroyed and the Board of Directors may, in their discretion, require the owner of the lost or destroyed certificate, or his legal representative, to give bond in such sum as they may direct as indemnity against any claim that may be made against the Corporation, its officers, employees or agents by reason thereof; a new certificate may be issued without requiring any bond when, in the judgment of the directors, it is proper so to do. If the Corporation shall neglect or refuse to issue such a new certificate and it shall appear that the owner thereof has applied to the Corporation for a new certificate in place thereof and has made due proof of the loss or destruction thereof and has given such notice of his application for such new certificate on such newspaper of general circulation, published in the State of Mississippi as reasonably should be approved by the Board of Directors, and in such other newspaper as may be required by the Board of Directors, and has tendered to the Corporation adequate security to indemnify the Corporation, its officers employees, or agents, and any person other than such applicant who shall thereafter appear to be the lawful owner of such alleged lost or destroyed certificate against damage, loss or expense because of the issuance of such new certificate, and the effect thereof as herein provided, then, unless there is adequate cause why such new certificate shall not be issued, the Corporation, upon the receipt of said indemnity, shall issue a new certificate of stock in place of such lost or destroyed certificate. In the event that the Corporation shall nevertheless refuse to issue a new certificate as aforesaid, the applicant may then petition any court of competent jurisdiction for relief against the failure of the Corporation to perform its obligations hereunder. In the event that the Corporation shall issue such new certificate, any person who shall thereafter claim any rights under the certificate in place of which such new certificate is issued, whether such new certificate is issued pursuant to the judgment or decree of such court or voluntarily by the Corporation after the publication of notice and the receipt of proof and indemnity as aforesaid, shall have recourse to such indemnity and the Corporation shall be discharged from all liability to such person by reason of such certificate and the shares represented thereby. (e) No stockholder shall have any right to inspect any account, book or document of the Corporation, except as conferred by statute or authorized by the directors. (f) A director of the Corporation shall not be disqualified by his office from dealing or contracting with the Corporation either as a vendor, purchaser or otherwise, nor shall any transaction or contract of the Corporation be void or voidable by reason of the fact that any director or any firm of which any director is a member or any corporation of which any director is a shareholder, officer or director, is in any way interested in such transaction or contract, provided that such transaction or contract is or shall be authorized, ratified or approved either (1) by a vote of a majority of a quorum of the Board of Directors or the Executive Committee, without counting in such majority or quorum any directors so interested or members of a firm so interested or a shareholder, officer or director of a corporation so interested, or (2) by the written consent, or by vote at a stockholders' meeting of the holders of record of a majority in number of all the outstanding shares of stock of the Corporation entitled to vote; nor shall any director be liable to account to the Corporation for any profits realized by or from or through any such transaction or contract of the Corporation, authorized, ratified or approved as aforesaid by reason of the fact that he or any firm of which he is a member or any corporation of which he is a shareholder, officer or director was interested in such transaction or contract. Nothing herein contained shall create any liability in the events above described or prevent the authorization, ratification or approval of such contract in any other manner provided by law. (g) Any director may be removed, whether cause shall be assigned for his removal or not, and his place filled at any meeting of the stockholders by the vote of a majority of the outstanding stock of the Corporation entitled to vote. Vacancies in the Board of Directors, except vacancies arising from the removal of directors, shall be filed by the directors remaining in office. (h) Any property of the Corporation not essential to the conduct of its corporate business and purposes may be sold, leased, exchanged or otherwise disposed of by authority of its Board of Directors and the Corporation may sell, lease or exchange all of its property and franchises or any of its property, franchises, corporate rights or privileges essential to the conduct of its corporate business and purposes upon the consent of and for such considerations and upon such terms as may be authorized by a majority of the Board of Directors and the holders of a majority of the outstanding shares of stock entitled to vote, expressed in writing or by vote at a meeting called for that purpose in the manner provided by the By-Laws of the Corporation for special meetings of stockholders; and at no time shall any of the plants, properties, easements, franchises (other than corporate franchises) or securities then owned by the Corporation be deemed to be property, franchises, corporate rights or privileges essential to the conduct of the corporate business and purposes of the Corporation. Upon the vote or consent of the stockholders required to dissolve the Corporation, the Corporation shall have power, as the attorney and agent of the holders of all of its outstanding stock, to sell, assign and transfer all such stock to a new corporation organized under the laws of the United States, the State of Mississippi or any other state, and to receive as the consideration therefor shares of stock of such new corporation of the several classes into which the stock of the Corporation is then divided, equal in number to the number of shares of stock of the Corporation of said several classes then outstanding, such shares of said new corporation to have the same preferences, voting powers, restrictions and qualifications thereof as may then attach to the classes of stock of the Corporation then outstanding so far as the same shall be consistent with such laws of the United States or of the State of Mississippi or of such other state, except that the whole or any part of such stock or any class thereof may be stock with or without nominal or par value. In order to make effective such a sale, assignment and transfer, the Corporation shall have the right to transfer all its outstanding stock on its books and to issue and deliver new certificates therefor in such names and amounts as such new corporation may direct without receiving for cancellation the certificates for such stock previously issued and then outstanding. Upon completion of such sale, assignment and transfer, the holders of the stock of the Corporation shall have no rights or interests in or against the Corporation except the right, upon surrender of certificates for stock of the Corporation properly endorsed, if required, to receive from the Corporation certificates for shares of stock of such new corporation of the class corresponding to the class of the shares surrendered, equal in number to the number of shares of the stock of the Corporation so surrendered. (i) Upon the written assent or pursuant to the affirmative vote in person or by proxy of the holders of a majority in number of the shares then outstanding and entitled to vote, irrespective of class, (1) any or every statute of the State of Mississippi hereafter enacted, whereby the rights, powers or privileges of the Corporation are or may be increased, diminished or in any way affected or whereby the rights, powers or privileges of the stockholders of corporations organized under the law under which the Corporation is organized, are increased, diminished or in any way affected or whereby effect is given to the action taken by any part, less than all, of the stockholders of any such corporation, shall, notwithstanding any provisions which may at the time be contained in these Restated Articles of Incorporation or any law, apply to the Corporation, and shall be binding not only upon the Corporation, but upon every stockholder thereof, to the same extent as if such statute had been in force at the date of the making and filing of these Restated Articles of Incorporation and/or (2) amendments of these Restated Articles of Incorporation authorized at the time of the making of such amendments by the laws of the State of Mississippi may be made. EIGHTH: The Restated Articles of Incorporation correctly set forth without change the corresponding provisions of the Articles of Incorporation as heretofore amended and restated, and supersede the original Articles of Incorporation, and all amendments thereto, and prior Restated Articles of Incorporation and all amendments thereto. DATED: December 21, 1983. MISSISSIPPI POWER & LIGHT COMPANY By: D. C. LUTKEN Its President [CORPORATE SEAL] By: F. S. YORK, JR. Its Secretary STATE OF MISSISSIPPI COUNTY OF HINDS I, Bethel Ferguson, a Notary Public, do hereby certify that on this 21st day of December, 1983, personally appeared before me D. C. Lutken. who, being by me first duly sworn, declared that he is the President of Mississippi Power & Light Company, that he signed the foregoing document as President of the Corporation, and that the statements therein contained are true. BETHEL FERGUSON Notary Public My commission expires July 23, 1987. [NOTARY'S SEAL] RESTATED ARTICLES OF INCORPORATION of MISSISSIPPI POWER & LIGHT COMPANY Filing and Recording Data Restated Articles of Incorporation filed with Secretary of State--December 21, 1983 Certificate of Restated Articles of Incorporation issued by Secretary of State--December 21, 1983 Certificate of Restated Articles of Incorporation and Restated Articles of Incorporation filed for record in the office of the Chancery Clerk of the First Judicial District of Hinds County, Mississippi, Book 189, Page 624--December 22, 1983. MISSISSIPPI POWER & LIGHT COMPANY Statement of Resolution Establishing Series of Shares October 25, 1984 Pursuant to the provisions of Section 79-3-29 of the Mississippi Business Corporation Law, the undersigned Corporation submits the following statement for the purpose of establishing and designating a series of shares and fixing and determining the relative rights and preferences thereof: 1. The name of the corporation is Mississippi Power & Light Company. 2. The attached resolution establishing and designating a series of shares and fixing and determining the relative rights and preferences thereof was duly adopted by the Board of Directors of the Corporation on October 24, 1984. Dated this the 25th day of October, 1984. MISSISSIPPI POWER & LIGHT COMPANY By/s/ William Cavanaugh, III William Cavanaugh, III President By /s/ Frank S. York, Jr. Frank S. York, Jr. Senior Vice President, Chief Financial Officer and Secretary STATE OF MISSISSIPPI COUNTY OF MINDS I, Joy L. Spears, a Notary Public, do hereby certify that on this October 25, 1984, personally appeared before me William Cavanaugh, III, who, being by me first duly sworn, declared that he is President of Mississippi Power & Light Company, that he executed the foregoing document as President of the Corporation, and that the statements therein contained are true. /s/ Joy L. Spears Joy L. Spears, Notary Public My Commission Expires: March 30, 1986 STATE OF MISSISSIPPI COUNTY OF MINDS I, Joy L. Spears, a Notary Public, do hereby certify that on this October 25, 1984, personally appeared before me Frank S. York, Jr., who, being by me first duly sworn, declared that he is Senior Vice President, Chief Financial Officer and Secretary of Mississippi Power & Light Company, that he executed the foregoing document as Senior Vice President, Chief Financial Officer and Secretary of the Corporation, and that the statements therein contained are true. /s/ Joy L. Spears Joy L. Spears, Notary Public My Commission Expires: March 30, 1986 RESOLVED That there is hereby established a series of the Preferred Stock of Mississippi Power & Light Company as follows: A series of 150,000 shares of the Preferred Stock shall: (a) be designated "16.16% Preferred Stock, Cumulative, $100 Par Value;" (b) have a dividend rate of $16.16 per share per annum payable quarterly on February 1, May 1, August 1, and November 1 of each year, the first dividend date to be February 1, 1986, and such dividends to be cumulative from the date of issuance; (c) be subject to redemption at the price of $116.16 per share if redeemed on or before November 1, 1989, of $112.12 per share if redeemed after November 1, 1989, and on or before November 1, 1994, of $108.08 per share if redeemed after November 1, 1994, and on or before November 1, 1999, and of $104.04 per share if redeemed after November 1, 1999, in each case plus an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date fixed for redemption; provided, however, that no share of the 16.16% Preferred Stock, Cumulative, $100 Par Value, shall be redeemed prior to November 1, 1989, if such redemption is for the purpose or in anticipation of refunding such share through the use, directly or indirectly, of funds borrowed by the Corporation, or through the use, directly or indirectly, of funds derived through the issuance by the Corporation of stock ranking prior to or on a parity with the 16.16% Preferred Stock, Cumulative, $100 Par Value, as to dividends or assets, if such borrowed funds have an effective interest cost to the Corporation (computed in accordance with generally accepted financial practice) or such stock has an effective dividend cost to the Corporation (so computed) of less than 16.2772% per annum; and (d) be subject to redemption as and for a sinking fund as follows: on November 1, 1989 and on each November 1 thereafter (each such date being hereinafter referred to as a "16.16% Sinking Fund Redemption Date"), for so long as any shares of the 16.16% Preferred Stock, Cumulative, $100 Par Value, shall remain outstanding, the Corporation shall redeem, out of funds legally available therefor, 7,500 shares of the 16.16% Preferred Stock, Cumulative, $100 Par Value, (or the number of shares than outstanding if less than 7,500) at the sinking fund redemption price of $100 per share plus, as to each share so redeemed, an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date of redemption (the obligation of the Corporation so to redeem the shares of the 16.16% Preferred Stock, Cumulative, $100 Par Value, being hereinafter referred to as the "16.16% Sinking Fund Obligation"); the 16.16% Sinking Fund Obligation shall be cumulative; if on any 16.16% Sinking Fund Redemption Date, the Corporation shall not have funds legally available therefor sufficient to redeem the full number of shares required to be redeemed on that date, the 16.16% Sinking Fund Obligation with respect to the shares not redeemed shall carry forward to each successive 16.16% Sinking Fund Redemption Date until such shares shall have been redeemed; whenever on any 16.16% Sinking Fund Redemption Date, the funds of the Corporation legally available for the satisfaction of the 16.16% Sinking Fund Obligation and all other sinking fund and similar obligations than existing with respect to any other class or series of its stock ranking on a parity as to dividends or assets with the 16.16% Preferred Stock, Cumulative, $100 Par Value (such obligation and obligations collectively being hereinafter referred to as the "Total Sinking Fund Obligations"), are insufficient to permit the Corporation to satisfy fully its Total Sinking Fund Obligation on that date, the Corporation shall apply to the satisfaction on its 16.16% Sinking Fund Obligation on that date that proportion of such legally available funds which is equal to the ratio of such 16.16% Sinking Fund Obligation to such Total Sinking Fund Obligation; in addition to the 16.16% Sinking Fund Obligation, the Corporation shall have the option, which shall be noncumulative, to redeem, upon authorization of the Board of Directors, on each 16.16% Sinking Fund Redemption Date, at the aforesaid sinking fund redemption price, up to 7,500 additional shares of the 16.16% Preferred Stock, Cumulative $100 Par Value; the Corporation shall be entitled, at its election, to credit against its 16.16% Sinking Fund Obligation on any 16.16% Sinking Fund Redemption Date any shares of the Preferred Stock, Cumulative, $100 Par Value (including shares of the 16.16% Preferred Stock, Cumulative, $100 Par Value, optionally redeemed at the aforesaid sinking fund price) theretofore redeemed (other than shares of the 16.16% Preferred Stock, Cumulative, $100 Par Value, redeemed pursuant to the 16.16% Sinking Fund Obligation) purchased or otherwise acquired and not previously credited against the 16.16% Sinking Fund Obligation. MISSISSIPPI POWER & LIGHT COMPANY Statement of Resolution Establishing Series of Shares July 24, 1986 Pursuant to the provisions of Section 79-3-29 of the Mississippi Code of 1972, the undersigned Corporation submits the following statement for the purpose of establishing and designating a series of shares and fixing and determining the relative rights and preferences thereof: 1. The name of the corporation is Mississippi Power & Light Company. 2. The attached resolution establishing and designating a series of shares and fixing and determining the relative rights and preferences thereof was duly adopted by the Board of Directors of the Corporation on July 24, 1986. Dated this the 24th day of July, 1986. MISSISSIPPI POWER & LIGHT COMPANY By/s/ William Cavanaugh, III William Cavanaugh, III President By /s/ Frank S. York, Jr. Frank S. York, Jr. Senior Vice President, Chief Financial Officer and Secretary STATE OF MISSISSIPPI COUNTY OF MINDS I, Joseph L. Blount, a Notary Public, do hereby certify that on this July 24, 1986, personally appeared before me William Cavanaugh, III, who, being by me first duly sworn, declared that he is President of Mississippi Power & Light Company, a Mississippi corporation, that he executed the foregoing document as President of the Corporation, and that the statements therein contained are true. /s/ Joseph L. Blount Joseph L. Blount, Notary Public My Commission Expires: January 20, 1990 STATE OF MISSISSIPPI COUNTY OF MINDS I, Joseph L. Blount, a Notary Public, do hereby certify that on this July 24, 1986, personally appeared before me Frank S. York, Jr., who, being by me first duly sworn, declared that he is Senior Vice President, Chief Financial Officer and Secretary of Mississippi Power & Light Company, a Mississippi corporation, that he executed the foregoing document as Senior Vice President, Chief Financial Officer and Secretary of the Corporation, and that the statements therein contained are true. /s/ Joseph L. Blount Joseph L. Blount, Notary Public My Commission Expires: January 20, 1990 RESOLVED That there is hereby established a series of the Preferred Stock of Mississippi Power & Light Company as follows: A series of 350,000 shares of the Preferred Stock shall: (a) be designated "9% Preferred Stock, Cumulative, $100 Par Value;" (b) have a dividend rate of $9.00 per share per annum payable quarterly on February 1, May 1, August 1, and November 1 of each year, the first dividend date to be November 1, 1986, and such dividends to be cumulative from the date of issuance; (c) be subject to redemption at the price of $109.00 per share if redeemed on or before July 1, 1991, of $106.75 per share if redeemed after July 1, 1991, in each case plus an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date fixed for redemption; provided, however, that no share of the 9% Preferred Stock, Cumulative, $100 Par Value, shall be redeemed prior to July 1, 1991, if such redemption is for the purpose or in anticipation of refunding such share through the use, directly or indirectly, of funds borrowed by the Corporation, or through the use, directly or indirectly, of funds derived through the issuance by the Corporation of stock ranking prior to or on a parity with the 9% Preferred Stock, Cumulative, $100 Par Value, as to dividends or assets, if such borrowed funds have an effective interest cost to the Corporation (computed in accordance with generally accepted financial practice) or such stock has an effective dividend cost to the Corporation (so computed) of less than 9.9901% per annum; and (d) be subject to redemption as and for a sinking fund as follows: on July 1, 1991, and on each July 1 thereafter (each such date being hereinafter referred to as a "9% Sinking Fund Redemption Date"), for so long as any shares of the 9% Preferred Stock, Cumulative, $100 Par Value, shall remain outstanding, the Corporation shall redeem, out of funds legally available therefor, 70,000 shares of the 9% Preferred Stock, Cumulative, $100 Par Value, (or the number of shares than outstanding if less than 70,000) at the sinking fund redemption price of $100 per share plus, as to each share so redeemed, an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date of redemption (the obligation of the Corporation so to redeem the shares of the 9% Preferred Stock, Cumulative, $100 Par Value, being hereinafter referred to as the "9% Sinking Fund Obligation"); the 9% Sinking Fund Obligation shall be cumulative; if on any 9.% Sinking Fund Redemption Date, the Corporation shall not have funds legally available therefor sufficient to redeem the full number of shares required to be redeemed on that date, the 9% Sinking Fund Obligation with respect to the shares not redeemed shall carry forward to each successive 9% Sinking Fund Redemption Date until such shares shall have been redeemed; whenever on any 9% Sinking Fund Redemption Date, the funds of the Corporation legally available for the satisfaction of the 9% Sinking Fund Obligation and all other sinking fund and similar obligations than existing with respect to any other class or series of its stock ranking on a parity as to dividends or assets with the 9% Preferred Stock, Cumulative, $100 Par Value (such obligation and obligations collectively being hereinafter referred to as the "Total Sinking Fund Obligations"), are insufficient to permit the Corporation to satisfy fully its Total Sinking Fund Obligation on that date, the Corporation shall apply to the satisfaction on its 9% Sinking Fund Obligation on that date that proportion of such legally available funds which is equal to the ratio of such 9% Sinking Fund Obligation to such Total Sinking Fund Obligation; the Corporation shall be entitled, at its election, to credit against its 9% Sinking Fund Obligation on any 9% Sinking Fund Redemption Date any shares of the Preferred Stock, Cumulative, $100 Par Value, theretofore redeemed (other than shares of the 9% Preferred Stock, Cumulative, $100 Par Value, redeemed pursuant to the 9% Sinking Fund Obligation) purchased or otherwise acquired and not previously credited against the 9% Sinking Fund Obligation. MISSISSIPPI POWER & LIGHT COMPANY Statement of Cancellation of Shares September 1, 1986 Pursuant to the provisions of Section 79-3-133 of the Mississippi Code of 1972, the undersigned Corporation submits the following statement of cancellation of redeemable shares by redemption: 1. The name of the corporation is Mississippi Power & Light Company. 2. The number of redeemable shares cancelled through redemption is 20,000 shares of 17% preferred stock, cumulative, $100 par value. 3. The aggregate number of issued shares, itemized by class and series, after giving effect to such cancellation is as follows: (a) 6,275,000 shares of common stock, without par value; (b) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (c) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (d) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (e) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (f) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (g) 180,000 shares of 17% preferred stock, cumulative, $100 par value; (h) 100,000 shares of 14.75% preferred stock, cumulative, $100 par value; (i) 100,000 shares of 12% preferred stock, cumulative, $100 par value; (j) 150,000 shares of 16.16% preferred stock, cumulative, $100 par value; (k) 350,000 shares of 9% preferred stock, cumulative, $100 par value; 4. The amount, expressed in dollars, of the stated capital of the Corporation, after giving effect to such cancellation is $270,205,800.00. 5. The Restated Articles of Incorporation of the Corporation provide that the cancelled shares shall not be reissued, and the number of shares which the Corporation has authority to issue, itemized by class, after giving effect to such cancellation, is as follows: (a) 15,000,000 shares of common stock, without par value, 6,275,000 of such shares being issued and outstanding at the date hereof; and (b) 1,984,476 shares of preferred stock, 1,258,808 shares of which are issued and outstanding as outlined above. Dated this the 10th day of December, 1986. MISSISSIPPI POWER & LIGHT COMPANY By /s/ Frank S. York, Jr. Frank S. York, Jr. Senior Vice President, Chief Financial Officer and Secretary By /s/ A. H. Mapp A. H. Mapp Assistant Secretary and Assistant Treasurer STATE OF MISSISSIPPI COUNTY OF MINDS I, Joy L. Spears, a Notary Public, do hereby certify that on this 10th day of December, 1986, personally appeared before me Frank S. York, Jr., who, being by me first duly sworn, declared that he is Senior Vice President, Chief Financial Officer and Secretary of Mississippi Power & Light Company, a Mississippi corporation, that he executed the foregoing document as Senior Vice President, Chief Financial Officer and Secretary of the Corporation, and that the statements therein contained are true. /s/ Joy L. Spears Joy L. Spears, Notary Public My Commission Expires: ________________________ STATE OF MISSISSIPPI COUNTY OF MINDS I, Joy L. Spears, a Notary Public, do hereby certify that on this 10th day of December, 1986, personally appeared before me A. H. Mapp, who, being by me first duly sworn, declared that he is Assistant Secretary and Assistant Treasurer of Mississippi Power & Light Company, a Mississippi corporation, that he executed the foregoing document as Senior Vice President, Chief Financial Officer and Secretary of the Corporation, and that the statements therein contained are true. /s/ Joy L. Spears Joy L. Spears, Notary Public My Commission Expires: ________________________ MISSISSIPPI POWER & LIGHT COMPANY Statement of Cancellation of Shares November 1, 1986 Pursuant to the provisions of Section 79-3-133 of the Mississippi Code of 1972, the undersigned Corporation submits the following statement of cancellation of redeemable shares by redemption: 1. The name of the corporation is Mississippi Power & Light Company. 2. The number of redeemable shares cancelled through redemption is 180,000 shares of 17% preferred stock, cumulative, $100 par value. 3. The aggregate number of issued shares, itemized by class and series, after giving effect to such cancellation is as follows: (a) 6,275,000 shares of common stock, without par value; (b) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (c) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (d) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (e) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (f) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (g) 100,000 shares of 14.75% preferred stock, cumulative, $100 par value; (h) 100,000 shares of 12% preferred stock, cumulative, $100 par value; (i) 150,000 shares of 16.16% preferred stock, cumulative, $100 par value; (j) 350,000 shares of 9% preferred stock, cumulative, $100 par value; 4. The amount, expressed in dollars, of the stated capital of the Corporation, after giving effect to such cancellation is $252,205,800.00. 5. The Restated Articles of Incorporation of the Corporation provide that the cancelled shares shall not be reissued, and the number of shares which the Corporation has authority to issue, itemized by class, after giving effect to such cancellation, is as follows: (a) 15,000,000 shares of common stock, without par value, 6,275,000 of such shares being issued and outstanding at the date hereof; and (b) 1,804,476 shares of preferred stock, 1,078,808 shares of which are issued and outstanding as outlined above. Dated this the 10th day of December, 1986. MISSISSIPPI POWER & LIGHT COMPANY By /s/ Frank S. York, Jr. Frank S. York, Jr. Senior Vice President, Chief Financial Officer and Secretary By /s/ A. H. Mapp A. H. Mapp Assistant Secretary and Assistant Treasurer STATE OF MISSISSIPPI COUNTY OF MINDS I, Joy L. Spears, a Notary Public, do hereby certify that on this 10th day of December, 1986, personally appeared before me Frank S. York, Jr., who, being by me first duly sworn, declared that he is Senior Vice President, Chief Financial Officer and Secretary of Mississippi Power & Light Company, a Mississippi corporation, that he executed the foregoing document as Senior Vice President, Chief Financial Officer and Secretary of the Corporation, and that the statements therein contained are true. /s/ Joy L. Spears Joy L. Spears, Notary Public My Commission Expires: ________________________ STATE OF MISSISSIPPI COUNTY OF MINDS I, Joy L. Spears, a Notary Public, do hereby certify that on this 10th day of December, 1986, personally appeared before me A. H. Mapp, who, being by me first duly sworn, declared that he is Assistant Secretary and Assistant Treasurer of Mississippi Power & Light Company, a Mississippi corporation, that he executed the foregoing document as Senior Vice President, Chief Financial Officer and Secretary of the Corporation, and that the statements therein contained are true. /s/ Joy L. Spears Joy L. Spears, Notary Public My Commission Expires: ________________________ MISSISSIPPI POWER & LIGHT COMPANY Statement of Cancellation of Shares November 1, 1986 Pursuant to the provisions of Section 79-3-133 of the Mississippi Code of 1972, the undersigned Corporation submits the following statement of cancellation of redeemable shares by redemption: 1. The name of the corporation is Mississippi Power & Light Company. 2. The number of redeemable shares cancelled through redemption is 100,000 shares of 14.75% preferred stock, cumulative, $100 par value. 3. The aggregate number of issued shares, itemized by class and series, after giving effect to such cancellation is as follows: (a) 6,275,000 shares of common stock, without par value; (b) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (c) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (d) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (e) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (f) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (g) 100,000 shares of 12% preferred stock, cumulative, $100 par value; (h) 150,000 shares of 16.16% preferred stock, cumulative, $100 par value; (i) 350,000 shares of 9% preferred stock, cumulative, $100 par value; 4. The amount, expressed in dollars, of the stated capital of the Corporation, after giving effect to such cancellation is $242,205,800.00. 5. The Restated Articles of Incorporation of the Corporation provide that the cancelled shares shall not be reissued, and the number of shares which the Corporation has authority to issue, itemized by class, after giving effect to such cancellation, is as follows: (a) 15,000,000 shares of common stock, without par value, 6,275,000 of such shares being issued and outstanding at the date hereof; and (b) 1,704,476 shares of preferred stock, 978,808 shares of which are issued and outstanding as outlined above. Dated this the 10th day of December, 1986. MISSISSIPPI POWER & LIGHT COMPANY By /s/ Frank S. York, Jr. Frank S. York, Jr. Senior Vice President, Chief Financial Officer and Secretary By /s/ A. H. Mapp A. H. Mapp Assistant Secretary and Assistant Treasurer STATE OF MISSISSIPPI COUNTY OF MINDS I, Joy L. Spears, a Notary Public, do hereby certify that on this 10th day of December, 1986, personally appeared before me Frank S. York, Jr., who, being by me first duly sworn, declared that he is Senior Vice President, Chief Financial Officer and Secretary of Mississippi Power & Light Company, a Mississippi corporation, that he executed the foregoing document as Senior Vice President, Chief Financial Officer and Secretary of the Corporation, and that the statements therein contained are true. /s/ Joy L. Spears Joy L. Spears, Notary Public My Commission Expires: ________________________ STATE OF MISSISSIPPI COUNTY OF MINDS I, Joy L. Spears, a Notary Public, do hereby certify that on this 10th day of December, 1986, personally appeared before me A. H. Mapp, who, being by me first duly sworn, declared that he is Assistant Secretary and Assistant Treasurer of Mississippi Power & Light Company, a Mississippi corporation, that he executed the foregoing document as Senior Vice President, Chief Financial Officer and Secretary of the Corporation, and that the statements therein contained are true. /s/ Joy L. Spears Joy L. Spears, Notary Public My Commission Expires: ________________________ MISSISSIPPI POWER & LIGHT COMPANY Statement of Resolution Establishing Series of Shares January 13, 1987 Pursuant to the provisions of Section 79-3-29 of the Mississippi Code of 1972, the undersigned Corporation submits the following statement for the purpose of establishing and designating a series of shares and fixing and determining the relative rights and preferences thereof: 1. The name of the corporation is Mississippi Power & Light Company. 2. The attached resolution establishing and designating a series of shares and fixing and determining the relative rights and preferences thereof was duly adopted by the Board of Directors of the Corporation on January 13, 1987. Dated this the 13th day of January, 1987. MISSISSIPPI POWER & LIGHT COMPANY By /s/ D. C. Lutken D. C. Lutken President, Chairman of the Board and Chief Executive Officer By /s/ G. A. Goff G. A. Goff Senior Vice President, Chief Financial Officer and Secretary STATE OF MISSISSIPPI COUNTY OF MINDS I, Joy L. Spears, a Notary Public, do hereby certify that on this January 13, 1987, personally appeared before me D. C. Lutken, who, being by me first duly sworn, declared that he is President, Chairman of the Board and Chief Executive Officer of Mississippi Power & Light Company, a Mississippi corporation, that he executed the foregoing document as President, Chairman of the Board and Chief Executive Officer of the Corporation, and that the statements therein contained are true. /s/ Joy L. Spears Joy L. Spears, Notary Public My Commission Expires: ________________________ STATE OF MISSISSIPPI COUNTY OF MINDS I, Joy L. Spears, a Notary Public, do hereby certify that on this January 13, 1987, personally appeared before me G. A. Goff, who, being by me first duly sworn, declared that he is Senior Vice President, Chief Financial Officer and Secretary of Mississippi Power & Light Company, a Mississippi corporation, that he executed the foregoing document as Senior Vice President, Chief Financial Officer and Secretary of the Corporation, and that the statements therein contained are true. /s/ Joy L. Spears Joy L. Spears, Notary Public My Commission Expires: ________________________ RESOLVED That there is hereby established a series of the Preferred Stock of Mississippi Power & Light Company as follows: A series of 350,000 shares of the Preferred Stock shall: (a) be designated "9.76% Preferred Stock, Cumulative, $100 Par Value;" (b) have a dividend rate of $9.76 per share per annum payable quarterly on February 1, May 1, August 1, and November 1 of each year, the first dividend date to be May 1, 1987, and such dividends to be cumulative from the date of issuance; (c) be subject to redemption at the price of $109.76 per share if redeemed on or before January 1, 1988, of $108.68 per share if redeemed after January 1, 1988, and on or before January 1, 1989, of $107.60 per share if redeemed after January 1, 1989,, and on or before January 1, 1990, of $106.51 per share if redeemed after January 1, 1990, and on or before January 1, 1991, of $105.43 per share if redeemed after January 1, 1991, and on or before January 1, 1992, of $104.34 per share if redeemed after January 1, 1992, and on or before January 1, 1993, of $103.26 per share if redeemed after January 1, 1993, and on or before January 1, 1994, of $102.17 per share if redeemed after January 1, 1994, and on or before January 1, 1995, of $101.09 per share if redeemed after January 1, 1995, and on or before January 1, 1996, and of $100.00 per share if redeemed after January 1, 1996, in each case plus an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date fixed for redemption; provided, however, that no share of the 9.76% Preferred Stock, Cumulative, $100 Par Value, shall be redeemed prior to January 1, 1992, if such redemption is for the purpose or in anticipation of refunding such share through the use, directly or indirectly, of funds borrowed by the Corporation, or through the use, directly or indirectly, of funds derived through the issuance by the Corporation of stock ranking prior to or on a parity with the 9.76% Preferred Stock, Cumulative, $100 Par Value, as to dividends or assets, if such borrowed funds have an effective interest cost to the Corporation (computed in accordance with generally accepted financial practice) or such stock has an effective dividend cost to the Corporation (so computed) of less than 9.9165% per annum; and (d) be subject to redemption as and for a sinking fund as follows: on January 1, 1993, and on each January 1 thereafter (each such date being hereinafter referred to as a "9.76% Sinking Fund Redemption Date"), for so long as any shares of the 9.76% Preferred Stock, Cumulative, $100 Par Value, shall remain outstanding, the Corporation shall redeem, out of funds legally available therefor, 70,000 shares of the 9.76% Preferred Stock, Cumulative, $100 Par Value, (or the number of shares than outstanding if less than 70,000) at the sinking fund redemption price of $100 per share plus, as to each share so redeemed, an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date of redemption (the obligation of the Corporation so to redeem the shares of the 9.76% Preferred Stock, Cumulative, $100 Par Value, being hereinafter referred to as the "9.76% Sinking Fund Obligation"); the 9.76% Sinking Fund Obligation shall be cumulative; if on any 9.76% Sinking Fund Redemption Date, the Corporation shall not have funds legally available therefor sufficient to redeem the full number of shares required to be redeemed on that date, the 9.76% Sinking Fund Obligation with respect to the shares not redeemed shall carry forward to each successive 9.76% Sinking Fund Redemption Date until such shares shall have been redeemed; whenever on any 9.76% Sinking Fund Redemption Date, the funds of the Corporation legally available for the satisfaction of the 9.76% Sinking Fund Obligation and all other sinking fund and similar obligations than existing with respect to any other class or series of its stock ranking on a parity as to dividends or assets with the 9.76% Preferred Stock, Cumulative, $100 Par Value (such obligation and obligations collectively being hereinafter referred to as the "Total Sinking Fund Obligations"), are insufficient to permit the Corporation to satisfy fully its Total Sinking Fund Obligation on that date, the Corporation shall apply to the satisfaction on its 9.76% Sinking Fund Obligation on that date that proportion of such legally available funds which is equal to the ratio of such 9.76% Sinking Fund Obligation to such Total Sinking Fund Obligation; the Corporation shall be entitled, at its election, to credit against its 9.76% Sinking Fund Obligation on any 9.76% Sinking Fund Redemption Date any shares of the Preferred Stock, Cumulative, $100 Par Value, theretofore redeemed (other than shares of the 9.76% Preferred Stock, Cumulative, $100 Par Value, redeemed pursuant to the 9.76% Sinking Fund Obligation) purchased or otherwise acquired and not previously credited against the 9.76% Sinking Fund Obligation. FURTHER RESOLVED That the officers of the Company are hereby authorized and directed to execute, file, publish and record all such statements and other documents, and to do and perform all such other and further acts and things, as in the judgment of the officer or officers taking such action may be necessary or desirable for the purpose of causing the immediately preceding resolution to become fully effective and of causing said resolution to become and constitute an amendment of the Restated Articles of Incorporation of the Company, all in the manner and to the extent required by the Mississippi Business Corporation Law. MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (Supp. 1987) March 8, 1988 The undersigned corporation, pursuant to Section 79-4- 6.31 of the Mississippi Code of 1972, as amended, submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 5,000 shares of 12% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 6,275,000 of such shares being issued and outstanding at the date hereof; and (b) 1,699,476 shares of preferred stock, 1,323,808 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 95,000 shares of 12% preferred stock, cumulative, $100 par value; (vii) 150,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii) 350,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and Dated this the 8th day of March, 1988. MISSISSIPPI POWER & LIGHT COMPANY By /s/ G. A. Goff G. A. Goff Senior Vice President, Chief Financial Officer and Secretary By /s/ J. R. Martin J. R. Martin Treasurer and Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (Supp. 1988) January 19, 1989 The undersigned corporation, pursuant to Section 79-4- 6.31 of the Mississippi Code of 1972, as amended, submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 1,500 shares of 12% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 7,579,400 of such shares being issued and outstanding at the date hereof; and (b) 1,699,476 shares of preferred stock, 1,323,808 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 93,500 shares of 12% preferred stock, cumulative, $100 par value; (vii) 150,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii) 350,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and Dated this the 19th day of January, 1989. MISSISSIPPI POWER & LIGHT COMPANY By /s/ G. A. Goff G. A. Goff Senior Vice President, Chief Financial Officer and Secretary REGISTERED AGENT/OFFICE STATEMENT OF CHANGE (Mark appropriate box) X DOMESTIC X PROFIT FOREIGN NONPROFIT 1. Name of Corporation: Mississippi Power & Light Company Federal Tax ID: 64-0205830 2. Current street address of registered office: 308 East Pearl Street Jackson, Mississippi 39201 3. New street address of registered office: (No change) 4. Name of current registered agent: Donald C. Lutken or Robert C. Grenfell 5. Name of new registered agent: Michael B. Bemis or Robert C. Grenfell 6. (Mark appropriate box) (X) The undersigned hereby accepts designation as registered agent for service of process. /s/ Michael B. Bemis /s/ Robert C. Grenfell ( ) Statement of written consent if attached. 7. ( ) Nonprofit. The street address of the registered office and the street address of the principal office of its registered agent will be identical. (X) Profit. The street address of the registered office and the street address of the business office of its registered agent will be identical. 8. The corporation has been notified of the change of registered office. Mississippi Power & Light Company Corporate Name By: Michael B. Bemis, President and COO /s/ Michael B. Bemis PRINTED NAME/CORPORATE TITLE SIGNATURE MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (Supp. 1988) March 30, 1989 The undersigned corporation, pursuant to Section 79-4- 6.31 of the Mississippi Code of 1972, as amended, submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 8,500 shares of 12% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 7,579,400 of such shares being issued and outstanding at the date hereof; and (b) 1,699,476 shares of preferred stock, 1,323,808 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 85,000 shares of 12% preferred stock, cumulative, $100 par value; (vii) 150,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii) 350,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and Dated this the 30th day of March, 1989. MISSISSIPPI POWER & LIGHT COMPANY By /s/ G. A. Goff G. A. Goff Senior Vice President, Chief Financial Officer and Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (Supp. 1988) March 30, 1989 The undersigned corporation, pursuant to Section 79-4- 6.31 of the Mississippi Code of 1972, as amended, submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 5,800 shares of 12% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 7,579,400 of such shares being issued and outstanding at the date hereof; and (b) 1,692,176 shares of preferred stock, 1,316,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 87,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 150,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii) 350,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and Dated this the 30th day of March, 1989. MISSISSIPPI POWER & LIGHT COMPANY By /s/ G. A. Goff G. A. Goff Senior Vice President, Chief Financial Officer and Secretary ARTICLES OF CORRECTION (Mark appropriate box) X PROFIT NONPROFIT The undersigned corporation, pursuant to Section 79-4-1.24 (if a profit corporation) or Section 79-11-113 (if a nonprofit corporation) of the Mississippi Code of 1972, as amended, hereby executes the following document and sets forth: 1. The name of the corporation is: Mississippi Power & Light Company 2. (Mark appropriate box.) (X) The document to be corrected is Articles of Amendment which became effective on March 31, 1989 (date). ( ) A copy of the document to be corrected is attached. 3. The aforesaid articles contain the following incorrect statement: See Attachment "A" 4. a. The reason such statement is incorrect is: The reduction in the number of shares of the class and series referred to in attachment A was incorrectly states as 8,500, and should have been 5,800, which incorrect statement is a component of certain other statements made in the Articles of Amendment, all as reflected in attachment "A". or b. The manner in which the execution of such document was defective was: 5. The correction is as follows: Attachment "B", a new executed form of Articles of Amendment, is substituted in its entirety for the Articles of Amendment referred to above. 6. The certificate of correction shall become effective on March 31, 1989. By: Mississippi Power & Light Company /s/ G. A. Goff printed name/corporation title G. A. Goff Senior Vice President, Chief Financial Officer and Secretary ATTACHMENT "A" The following incorrect statements were included in the Articles of Amendment under Miss. Code Ann. Section 74-4-6.31 (Supp. 1988) dated March 30, 1989: 1. Paragraph 2 thereof provided as follows: "The reduction in the number of authorized shares, itemized by class and series, is 8,500 shares of 12% Preferred Stock, Cumulative, $100 par value." 2. Paragraph 3(b) provided in part as follows: "1,699,476 shares of preferred stock, 1,323,808 shares of which are issued and outstanding in the following series: (vi) 85,000 shares of 12% preferred stock, cumulative, $100 par value; MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (Supp. 1988) November 2, 1989 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (Supp. 1988), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 90,000 shares of 16.16% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 7,579,400 of such shares being issued and outstanding at the date hereof; and (b) 1,602,176 shares of preferred stock, 1,226,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $200 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 87,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 60,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii) 350,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and Dated this the 2nd day of November, 1989. MISSISSIPPI POWER & LIGHT COMPANY By /s/ G. A. Goff G. A. Goff Senior Vice President, Chief Financial Officer and Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1972) March 28, 1990 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (1972), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 10,000 shares of 12.009% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 7,579,400 of such shares being issued and outstanding at the date hereof; and (b) 1,592,176 shares of preferred stock, 1,216,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $200 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 77,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 60,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii) 350,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and Dated this the 30th day of March, 1990. MISSISSIPPI POWER & LIGHT COMPANY By /s/ G. A. Goff G. A. Goff Senior Vice President, Chief Financial Officer and Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1972) November 2, 1990 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (1972), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 15,000 shares of 16.16% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 7,579,400 of such shares being issued and outstanding at the date hereof; and (b) 1,577,176 shares of preferred stock, 1,201,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 77,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 45,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii) 350,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and Dated this the 2nd day of November, 1990. MISSISSIPPI POWER & LIGHT COMPANY By /s/ G. A. Goff G. A. Goff Senior Vice President, Chief Financial Officer and Secretary [Letterhead of Wise Carter Child & Caraway] March 26, 1991 Ms. Sylvia Jacobs Branch Supervisor-Corporations Business Services Secretary of State of State of Mississippi 202 North Congress Street, Suite 601 Jackson, MS 39205 Re: Mississippi Power & Light Company Articles of Amendment Dear Ms. Jacobs: I received your Notice of Return regarding the Articles of Amendment we recently filed for Mississippi Power & Light Company under Section 79-4-6.31 of the Mississippi Code. Your Notice of Return states that we must use Form C-3 provided in the Guide for Domestic Corporations published by the Mississippi Secretary of State. I draw your attention to the fact that the Articles of Amendment we are filing are being filed under Section 79-4- 6.31 (1989) of the Mississippi Code, and not Section 79-4- 10.06. I agree that if we were filing Articles of Amendment under Section 79-4-10.06, the proper form to use would be Form C-3 provided by the Mississippi Secretary of State. However, the Articles of Amendment we are filing are being filed only because stock was redeemed by the corporation and is now being cancelled. We have used the form enclosed with this letter numerous times in the past to file Articles of Amendment pursuant to Section 79-4-6.31, after consultation with Ray Bailey. It is my opinion that the form for the standard Articles of Amendment would not be appropriate for the type of amendment we are filing, and there is no place on the form to provide the information required under Section 79-4-6.31. Accordingly, I am returning our duplicate originals of the Articles of Amendment and request that you file one among the records in your office, and return the conformed copy, marked "Filed," to my attention at the above address. If you have any questions, please feel free to call at the above direct dial number. Very truly yours, /s/ J. Michael Cockrell J. Michael Cockrell DMC/st Enclosure MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) March 18, 1991 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (1989), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is (a) 80 shares of 4.36% preferred stock, cumulative, $100 par value; (b) 588 shares of 4.56% preferred stock, cumulative, $100 par value; and (c) 10,000 shares of 12% preferred stock, cumulative, $100 par value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 7,579,400 of such shares being issued and outstanding at the date hereof; and (b) 1,566,508 shares of preferred stock, 1,191,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 67,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 45,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii) 350,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and Dated this the 18th day of March, 1991. MISSISSIPPI POWER & LIGHT COMPANY By /s/ G. A. Goff G. A. Goff Senior Vice President, Chief Financial Officer and Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) July 12, 1991 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (1989), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 70,000 shares of 9.00% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 7,579,400 of such shares being issued and outstanding at the date hereof; and (b) 1,496,508 shares of preferred stock, 1,121,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 67,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 45,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii) 280,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and Dated this the 12th day of July, 1991. MISSISSIPPI POWER & LIGHT COMPANY By /s/ A. H. Mapp A. H. Mapp Assistant Treasurer and Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) November 19, 1991 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (1989), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 15,000 shares of 16.16% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 7,579,400 of such shares being issued and outstanding at the date hereof; and (b) 1,481,508 shares of preferred stock, 1,106,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 67,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 30,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii) 280,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and Dated this the 19th day of November, 1991. MISSISSIPPI POWER & LIGHT COMPANY By /s/ A. H. Mapp A. H. Mapp Assistant Treasurer and Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) March 13, 1992 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (1989), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 10,000 shares of 12% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 7,579,400 of such shares being issued and outstanding at the date hereof; and (b) 1,471,508 shares of preferred stock, 1,096,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 57,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 30,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii) 280,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and Dated this the 13th day of March, 1992. MISSISSIPPI POWER & LIGHT COMPANY By /s/ A. H. Mapp Title: Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) July 15, 1992 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (1989), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 70,000 shares of 9.00% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 8,666,357 of such shares being issued and outstanding at the date hereof; and (b) 1,401,508 shares of preferred stock, 1,026,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 57,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 30,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii) 210,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and Dated this the 15th day of July, 1992. MISSISSIPPI POWER & LIGHT COMPANY By /s/ A. H. Mapp Title: Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment - Statement of Resolution Establishing Series of Shares October 22, 1992 Pursuant to the provisions of Section 79-4-6.02(d) of the Mississippi Code of 1972 (Supp. 1989), Mississippi Power & Light Company submits the following statement for the purpose of establishing and designating a series of shares and fixing and determining the relative rights and preferences thereof: 1. The name of the corporation is Mississippi Power & Light Company. 2. The attached resolution establishing and designating a series of shares and fixing and determining the relative rights and preferences thereof was duly adopted by the Board of Directors of the Corporation on October 22, 1992. Dated this the 22nd day of October, 1992. MISSISSIPPI POWER & LIGHT COMPANY By /s/ A. H. Mapp Allan H. Mapp Assistant Secretary and Assistant Treasurer MISSISSIPPI POWER & LIGHT COMPANY Excerpts from the minutes of the Meeting of the Board of Directors held on October 22, 1992 RESOLVED That there is hereby established a series of the Preferred Stock of Mississippi Power & Light Company as follows: A series of 200,000 shares of the Preferred Stock shall: (a) be designated as the "8.36% Preferred Stock, Cumulative, $100 Par Value"; (b) have a dividend rate of $8.36 per share per annum payable quarterly on February 1, May 1, August 1, and November 1 of each year, the first dividend date to be February 1, 1993, and such dividends to be cumulative from the date of issuance; and (c) be subject to redemption at the price of $100 par share plus an amount equivalent to the accumulated and unpaid dividends thereon, if any, to the date fixed for redemption (except that no share of the 8.36% Preferred Stock shall be redeemed on or before October 1, 1997). FURTHER RESOLVED That the officers of the Company are hereby authorized and directed to execute, file and publish and record all such statements and other documents, and to do and perform all such other and further acts and things, as in the judgment of the officer and officers taking such action may be necessary or desirable for the purpose of causing the immediately preceding resolution to become fully effective and of causing said resolution to become and constitute an amendment of the Restated Articles of Incorporation of the Company, all in the manner and to the extent required by the Mississippi Business Corporation Law. MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) November 6, 1992 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (1989), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 15,000 shares of 16.16% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 8,666,357 of such shares being issued and outstanding at the date hereof; and (b) 1,386,508 shares of preferred stock, 1,211,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 57,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 15,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii)210,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 350,000 shares of 9.76% preferred stock, cumulative, $100 par value; and (x) 200,000 shares of 8.36% preferred stock, cumulative, $100 par value. Dated this the 6th day of November, 1993. MISSISSIPPI POWER & LIGHT COMPANY By /s/ A. H. Mapp Title: Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) January 12, 1993 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (1989), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 70,000 shares of 9.76% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 8,666,357 of such shares being issued and outstanding at the date hereof; and (b) 1,316,508 shares of preferred stock, 1,141,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 57,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 15,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii)210,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 280,000 shares of 9.76% preferred stock, cumulative, $100 par value; and (x) 200,000 shares of 8.36% preferred stock, cumulative, $100 par value. Dated this the 12th day of January, 1993. MISSISSIPPI POWER & LIGHT COMPANY By /s/ A. H. Mapp Title: Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) March 10, 1993 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (1989), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 10,000 shares of 12.00% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 8,666,357 of such shares being issued and outstanding at the date hereof; and (b) 1,306,508 shares of preferred stock, 1,131,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 47,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 15,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii)210,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 280,000 shares of 9.76% preferred stock, cumulative, $100 par value; and (x) 200,000 shares of 8.36% preferred stock, cumulative, $100 par value. Dated this the 10th day of March, 1993. MISSISSIPPI POWER & LIGHT COMPANY By /s/ A. H. Mapp Title: Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) July 12, 1993 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (1989), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 70,000 shares of 9.00% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 8,666,357 of such shares being issued and outstanding at the date hereof; and (b) 1,236,508 shares of preferred stock, 1,061,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 47,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 15,000 shares of 16.16% preferred stock, cumulative, $100 par value; (viii)140,000 shares of 9% preferred stock, cumulative, $100 par value; (ix) 280,000 shares of 9.76% preferred stock, cumulative, $100 par value; and (x) 200,000 shares of 8.36% preferred stock, cumulative, $100 par value. Dated this the 12th day of July, 1993. MISSISSIPPI POWER & LIGHT COMPANY By /s/ James W. Snider Title: Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) November 15, 1993 The undersigned corporation, pursuant to Miss. Code Ann. Section 79-4-6.31 (1989), submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. The reduction in the number of authorized shares, itemized by class and series, is 15,000 shares of 16.16% Preferred Stock, Cumulative, $100 Par Value. 3. The total number of authorized shares, itemized by class and series, remaining after reduction of the shares is as follows: (a) 15,000,000 shares of common stock, without par value, 8,666,357 of such shares being issued and outstanding at the date hereof; and (b) 1,221,508 shares of preferred stock, 1,046,508 shares of which are issued and outstanding in the following series: (i) 59,920 shares of 4.36% preferred stock, cumulative, $100 par value; (ii) 43,888 shares of 4.56% preferred stock, cumulative, $100 par value; (iii) 100,000 shares of 4.92% preferred stock, cumulative, $100 par value; (iv) 75,000 shares of 9.16% preferred stock, cumulative, $100 par value; (v) 100,000 shares of 7.44% preferred stock, cumulative, $100 par value; (vi) 47,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 140,000 shares of 9% preferred stock, cumulative, $100 par value; (viii)280,000 shares of 9.76% preferred stock, cumulative, $100 par value; and (ix) 200,000 shares of 8.36% preferred stock, cumulative, $100 par value. Dated this the 15th day of November, 1993. MISSISSIPPI POWER & LIGHT COMPANY By /s/ James W. Snider Title: Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-10.06 (1989) February 4, 1994 The undersigned corporation, pursuant to Section 79-4- 10.06 of the Mississippi Code of 1972, as amended, submits the following document and sets forth: 1. The name of the corporation is Mississippi Power & Light Company. 2. As evidenced by the attached Stockholder's Written Approval of Amendment authorizing 1,500,000 additional shares of Preferred Stock of the par value of $100 per share, the following amendment of the Restated Articles of Incorporation, as amended (the "Charter"), was proposed by the Board of Directors of Mississippi Power & Light Company on October 29, 1993, was adopted by the stockholders of the Corporation entitled to vote on the amendment on February 4, 1994, in accordance with and in the manner prescribed by the laws of the State of Mississippi and the Charter of Mississippi Power & Light Company: The first paragraph in Article FOURTH of the Charter is amended to read as follows: FOURTH: The aggregate number of shares which the Corporation shall have authority to issue is 17,721,508 shares, divided into 2,721,508 shares of Preferred Stock of the par value of $100 per share and 15,000,000 shares of Common Stock without par value. 3. Pursuant to the Laws of the State of Mississippi and the Charter of Mississippi Power & Light Company, the holders of Preferred Stock of the par value of $100 per share were not entitled to vote on the amendment as a separate voting group. The holders of the outstanding shares of common stock were the only stockholders entitled to vote on the amendment. 4. The number of shares of common stock of the corporation outstanding at the time of such adoption was 8,666,357; and the number of shares entitled to vote thereon was 8,666,357. Dated this the 4th day of February, 1994. MISSISSIPPI POWER & LIGHT COMPANY By: /s/ Edwin Lupberger Edwin Lupberger Chairman of the Board and Chief Executive Officer By: /s/ Donald E. Meiners Donald E. Meiners President EX-3.(II) 3 MP&L BY-LAWS Exhibit 3(ii)(f) BY-LAWS OF MISSISSIPPI POWER & LIGHT COMPANY AS OF DECEMBER 10, 1993 SECTION 1 - The Annual Meeting of the Stockholders of the Corporation for the election of Directors and such other business as shall property come before such meeting shall be held at the office of the Corporation in the City of Jackson, Mississippi, on the fourth Thursday in May in each year, at ten o'clock in the morning, unless such day is a legal holiday in the State of Mississippi, in which case such meeting shall be held oo the first day thereafter which is not a legal holiday, or at such other place within or without the State of Mississippi and at such other time as the Board of Directors may by resolution designate. SECTION 2 - Special Meetings of the Stockholders may be held at the principal office of the Corporation in the City of Jackson, Mississippi, or at such other place or places as the Board of Directors may from time to time determine. SECTION 3 - Special Meetings of the Stockholders of the Corporation may be held upon the order of the Chairman of the Board, the Board of Directors, the Executive Committee, or of Stockholders of record holding one-tenth of the outstanding stock entitled to vote at such meetings. SECTION 4 - Notice of every meeting of Stockholders shall be given in the manner provided by law to each Stockholder entitled thereto unless waived by such Stockholder. SECTION 5 - The holders of a majority of the outstanding stock of the Corporation entitled to vote upon any matter to be acted upon present in person or by proxy shall constitute a quorum for the transaction of business at any meeting of Stockholders but less than a quorum shall have power to adjourn. SECTION 6 - Certificates of stock shall be signed by the President or a Vice President and the Secretary or an Assistant Secretary, but where any such certificate is signed by a Transfer Agent and by a Registrar, the signature of any such officer or officers and the seal of the Company upon such certificates may be facsimile, engraved or printed. SECTION 7 - The stock of the Corporation shall be transferable or assignable only on the books of the Corporation by the holders in person or by attorney on the surrender of the certificates therefor duly endorsed for transfer. SECTION 8 - The Board of Directors of the Corporation shall consist of fifteen members. Each director shall hold office until the next annual Meeting of Stockholders of the Corporation and until his successor shall have been elected and qualified. Directors need not be residents of the State of Mississippi. Meetings of the Board of Directors may be held within or without the State of Mississippi, at the time fixed by Resolution of the Board or upon the order of the Chairman of the Board, the President, a Vice President, or any two Directors. The Secretary or any other Officer performing his duties shall give at least two days' notice of all meetings of the Board of Directors in the manner provided by law, provided however, a director may waive such notice in the manner provided by law. SECTION 9 - All Officers of the Corporation shall hold their offices until their respective successors are chosen and qualify, but any Officer may be removed from office at any time by the Board of Directors. SECTION 10 - The Officers of the Corporation shall have such duties as usually pertain to their offices, except as modified by the Board of Directors or the Executive Committee, and shall also have such powers and duties as may from time to time be conferred upon them by the Board of Directors or the Executive Committee. The Chairman of the Board shall be the Chief Executive Officer of the Company, unless such title shall be otherwise conferred by the Board, and the Chief Executive Officer shall have supervision of the general management and control of its business and affairs, subject, however, to the orders and directions of the Board of Directors and of the Executive Committee. The Chairman of the Board shall preside at all meetings of the Stockholders, Directors, and Executive Committees. SECTION 11 - EXECUTIVE COMMITTEE - The Board of Directors may elect, each year after their election, an Executive Committee to be comprised of not less than three directors, the Chairman of which shall be the Chairman and CEO of the Company. The Vice Chairman and Chief Operating Officer of the Company shall also be a member and the balance of the membership shall be comprised of non-employee (outside) directors. The Committee, when the Board is not in session, shall have and exercise all of the power of the Board in the management of the business and affairs of the Company within limits set forth in the Executive Committee Charter. SECTION 12 - OTHER COMMITTEES - From time to time the Board of Directors, by the affirmative vote of a majority of the whole Board may appoint other committees for any purpose or purposes, and such committees shall have such powers as shall be conferred by the Resolution of appointment. SECTION 13 - INDEMNIFICATION 13.1 Definitions - In this bv-law: (1) "Director mean an individual who is or was a director of the Corporation or, unless the context requires otherwise, an individual who, while a director of the Corporation, is or was serving at the Corporation's request as a director, officer, partner, trustee, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, including charitable, non-profit or civic organizations. A director is considered to be serving an employee benefit plan at the Corporation's request if his duties to the Corporation also impose duties on, or otherwise involve services by, him to the plan or to participants in or beneficiaries of the plan. "Director" includes unless the context requires otherwise, the estate of personal representative of a director. (2) "Employee" means an individual who is or was an employee of the Corporation, or, unless the context requires otherwise, an individual who, while an employee of the Corporation, is or was serving at the Corporation's request as a director, officer, partner, trustee, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, including charitable, non-profit or civic organizations. An employee is considered to be serving an employee benefit plan at the Corporation's request if his duties to the Corporation also impose duties on, or otherwise involve services by, him to the plan or to participants in or beneficiaries of the plan. "Employee" includes, unless the context requires otherwise, the estate or personal representative of an employee. (3) "Expenses" include counsel fees. (4) "Liability" means the obligation to pay a judgment, settlement, penalty, fine, or reasonable expenses incurred with respect to a proceeding. Without any limitation whatsoever upon the generality thereof, the term "fine" as used in this Section shall include (1) any penalty imposed by the Nuclear Regulatory Commission (the "NRC"), including penalties pursuant to NRC regulations, 10 CFR Part 21, (2) penalties or assessments (including any excise tax assessment) with respect to any employee benefit plan pursuant to the Employee Retirement Income Security Act of 1974, as amended, or otherwise, and (3) penalties pursuant to any Federal, state or local environmental laws or regulations. (5) "Officer" means an individual who is or was an officer of the Corporation, or, unless the context requires otherwise, an individual who, while an officer of the Corporation, is or was serving at the Corporation's request as a director, officer, partner, trustee, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, including charitable, non-profit or civic organizations. An officer is considered to be serving an employee benefit plan at the Corporation's request if his duties to the Corporation also impose duties on, or otherwise involve services by, him to the plan or to participants in or beneficiaries of the plan. "Officer" includes, unless the context requires otherwise, the estate or personal representative of an officer. (6) "Official capacity" means: (i) when usedwith respect to a director, the office of director in the Corporation; and (ii) when used with respect to an individual other than a director as contemplated in Section 13.7, the office in the Corporation held by the officer or the employment undertaken by the employee on behalf of the Corporation. "Official capacity" does not include service for any other foreign or domestic corporation or any partnership, joint venture, trust, employee benefit plan or other enterprise, including charitable, non-profit or civic organizations. (7) "Party" includes an individual who was, is, or is threatened to be made a named defendant or respondent in a proceeding. (8) "Proceeding" means any threatened, pending, or completed action suit or proceeding, whether civil, criminal, administrative or investigative and whether formal or informal. 13.2 Authority to Indemnify (a) Except as provided in subsection (d), the Corporation shall indemnify an individual made a party to a proceeding because he is or was a director aqainst liability incurred in the proceeding if: (1) He conducted himself in good faith; and (2) He reasonably believed: (i) In the case of conduct in his official capacity with the Corporation, that his conduct was in its best interests; and (ii) In all other cases, that his conduct was at least not opposed to its best interests, and (3) In the case of any criminal proceeding, he had no reasonable cause to believe his conduct was unlawful (b) A director's conduct with respect to an employee benefit plan for a purpose he reasonably believed to be in the interest of the participants in and beneficiaries of the plan is conduct that satisfies the requirement of subsection (a)(2)(ii). (c) The termination of a proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent is not, of itself, determinative that the director did not meet the standard of conduct described in this section. (d) The corporation shall not indemnify a director under this section: (1) In connection with a proceeding by or in the right of the Corporation in which the director was adjudged liable to the Corporation; or (2) In connection with any other proceeding charging improper personal benefit to him, whether or not involving action in his official capacity, in which he was adjudged liable on the basis that personal benefit was improperly received by him. (e) Indemnification permitted under this section in connection with a proceeding by or in the right of the Corporation is limited to reasonable expenses incurred in connection with the proceeding. (f) The Corporation shall have power to make any further indemnity, including advance of expenses, to and to enter contracts of indemnity with any director that may be authorized by the articles of incorporation or any bylaw made by the shareholders or any resolution adopted, before or after the event, by the shareholders, except an indemnity against his gross negligence or willful misconduct. Unless the articles of incorporation, or any such bylaw or resolution provide otherwise, any determination as to any further indemnity shall be made in accordance with subsection (b) of Section 13.6. Each such indemnity may continue as to a person who has ceased to have the capacity referred to above and may inure to the benefit of the heirs, executors and administrators of such person. 13.3 Mandatorv Indemnification The Corporation shall indemnify a director who was wholly successful, on the merits or otherwise, in the defense of any proceeding to which he was a party because he is or was a director of the Corporation against reasonable expenses incurred by him in connection with the proceeding. 13.4 Advance for Expenses (a) The Corporation shall pay for or reimburse thereasonable expenses incurred by a director who is a party to a proceeding in advance of final disposition of the proceeding if: (1) The director furnishes the Corporation a written affirmation of his good faith belief that he has met the standard of conduct described in Section 13.2; (2) The director furnishes the Corporation a written undertaking, executed personally or on his behalf, to repay the advance if it is ultimately determined that he did not meet the standard of conduct; and (3) A determination is made that the facts then known to those making the determination would not preclude indemnification under these By-Laws. (b) The undertaking required by subsection (a)(2) must be an unlimited general obligation of the director but need not be secured and may be accepted without reference to financial ability to make repayment. (c) Determinations and authorizations of payments under this section shall be made in the manner specified in Section 13.6. 13.5 Court-Ordered Indemnification A director of the Corporation who is a party to a proceeding may apply for indemnification to the court conducting the proceeding or to another court of competent jurisdiction as provided by law 13.6 Determination and Authorization of Indemnification (a) The Corporation may not indemnify a director under Section 13.2 unless authorized in the specific case after a determination has been made that indemnification of the director is permissible in the circumstances because he has met the standard of conduct set forth in Section 13.2 (b) The determination shalI be made: (1) By the Board of Directors by majority vote of a quorum consisting of directors not at the time parties to the proceeding; (2) If a quorum cannot be obtained under subsection (b) (1), by majority vote of a committee duly designated by the Board of Directors (in which designation directors who are parties may participate), consisting solely of two (2) or more directors not at the time parties to the proceeding; (3) By special legal counsel: (i) Selected by the Board of Directors or ts committee in the manner prescribed in subsection (b) (1) or (b) (2); or (ii) If a quorum of the Board of Directors cannot be obtained under subsection (b) (1) and a committee cannot be designated under subsection (b) (2), selected by a majority vote of the full Board of Directors (in which selection directors who are parties may participate); or (4) By the shareholders, but shares owned by or voted under the control of directors who are at the time parties to the proceeding may not be voted on the determination. (c) Authorization of indemnification and evaluation as to reasonableness of expenses shall be made in the same manner as the determination that indemnification is permissible, except that if the determination is made by special legal counsel, authorization of indemnification and evaluation as to reasonableness of expenses shall be made by those entitled under subsection (b) (3) to select counsel. 13.7 Indemnification of Officers, Employees and Agents (1) An officer of the Corporation who is not a director is entitled to mandatory indemnification under Section 13.3, and is entitled to apply for court-ordered indemnification under Section 13.5, in each case to the same extent as a director; and (2) The Corporation shall indemnify and advance expenses under these By-Laws to an officer or employee of the Corporation who is not a director to the same extent as to a director as provided under Sections 13.2, 13.4 and 13.6. 13.8 Insurance If authorized by the Board of Directors, the Board of Directors of Middle South Utilities. Inc. and/or otherwise property authorized, the Corporation shall purchase and maintain insurance on behalf of an individual who is or was a director, office, or employee of the Corporation against liability asserted against or incurred by him in that capacity or arising from his status as a director, officer or employee, whether or not the Corporation would have power to indemnify him against the same liability under Sections 13.2 or 13.3. If further authorized as provided in this subsection, the Corporation shall purchase and maintain such insurance on behalf of an individual who is or was a director, officer or employee who, while a director, officer or employee of the Corporation, is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, including charitable, non-profit or civic organizations, whether or not the Corporation would have power to indemnify him against the same liability under Sections 13.2 or 13.3. 13.9 Application of By-Law (a) This By-Law does not limit the Corporations power to pay or reimburse expenses incurred by a director, officer or employee in connection with his appearance as a witness in a proceeding at a time when he has not been made a named defendant or respondent to the proceeding. (b) The foregoing rights shall not be exclusive of other rights to which any director, officer or employee may otherwise be entitled. (c) The foregoing shall not limit any right or power of the Corporation to provide indemnification as allowed by statute or otherwise. 13.10 Rights Deemed Contract Rights All rights to indemnification and to advancement of expenses under these By-Laws shall be deemed to be provided by a contract between the Corporation and the director, officer or employee who serves in such capacity at any time while these By-Laws are in effect. Any repeal or modification of this By-Law shall not affect any rights or obligations then existing. SECTION 14 - The Board of Directors may alter or amend these by-laws at any meeting duly held as herein provided. EX-10 4 ENTERGY CORPORATION DEFINED CONTRIBUTION Exhibit 10(a) 81 Entergy Corporation Amend to the Defined Contribution Restoration Plan Mr. Blount then referred to the Defined Contribution Restoration Plan for Entergy Corporation and Subsidiaries (Restoration Plan). He stated that, effective January 1, 1991, the Restoration Plan was amended to terminate virtually all additional accruals under participants' ESOP Restoration Accounts under the Restoration Plan with certain limited exceptions. He further stated that, due to these amendments, participants' ESOP Restoration Accounts are now essentially frozen with the exception of periodic credits based on the Corporation's dividends on common stock. Mr. Blount suggested that, due to relatively small balances held in the majority of the ESOP Restoration Accounts, the cost of maintaining each of these frozen accounts and the fact that no additional substantive accruals will be credited to such accounts, the Restoration Plan should be amended to close such accounts as of May 31, 1992, and all Restoration Plan benefits accrued under such ESOP Restoration Accounts through that date be distributed by the respective employers to appropriate participants as soon as practicable thereafter. After discussion, upon motion duly made, seconded and unanimously adopted, it was RESOLVED, That, effective May 31, 1992, ESOP Restoration Accounts under the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (Restoration Plan) as defined by the terms of the Restoration Plan in effect on December 31, 1990, be closed pursuant to the authority granted to the Corporation under the Restoration Plan and all accrued Restoration Plan benefits credited to such ESOP Restoration Accounts as of May 31, 1992, be distributed by the respective employers to appropriate Restoration Plan participants as soon as practicable thereafter; provided, however, that (i) any benefits attributable to such ESOP Restoration Accounts shall accrue no additional benefits under the Restoration Plan after May 31, 1992, and (ii) any and all Savings Plan Restoration Accounts under the Restoration Plan shall remain subject to terms of the Restoration Plan and shall be unaffected by any distributions from the ESOP Restoration Accounts closed hereunder; and further RESOLVED, That the officers of the Corporation be, and each of them hereby is, authorized and directed on behalf of the Corporation, to make any and all amendments to the Restoration Plan as may be necessary, appropriate or desirable to reflect the distribution of accrued benefits credited to participants' ESOP Restoration Accounts as of May 31, 1992, consistent with the foregoing resolution; and further RESOLVED, That the officers of the Corporation be, and each of them hereby is, authorized and directed on behalf of the Corporation to execute and deliver all such documents, certificates of amendment and other papers, and to perform and do such other acts and things as they, in their judgment, may deem necessary or appropriate to effectuate the purpose and intent of the foregoing resolutions. EX-10 5 SYSTEM EXECUTIVE RETIREMENT PLAN Exhibit 10(a) 82 SYSTEM EXECUTIVE RETIREMENT PLAN OF ENTERGY CORPORATION AND SUBSIDIARIES PURPOSES The System Executive Retirement Plan of Entergy Corporation and Subsidiaries has as its purposes attracting, retaining and motivating certain highly competent eligible employees; and encouraging personal growth and improvement of personal productivity. The Plan is designed primarily to aid eligible employees in providing supplemental post-retirement income for themselves and their families and after death benefits for their beneficiaries. The Plan is also designed to make available to the Employer, subsequent to the Employee's retirement and subject to the Employee's post-retirement time constraints, the Employee's knowledge of, and experience with respect to, the business and operations of the Employer. Article I. DEFINITIONS The following terms shall have the meaning hereinafter indicated unless expressly provided herein to the contrary: 1.01 "Administrator" shall mean the Vice President, Human Resources & Administration of Entergy Services, Inc. or such other person or persons from time to time appointed by the Chairman of the Board of Directors in accordance with Section 7.01. The Administrator shall be the "plan administrator" for the Plan within the meaning of the Employee Retirement Income Security Act of 1974, as amended. 1.02 "Beneficiary" shall mean the Surviving Spouse of the Participant or, if the Participant does not have a Surviving Spouse, the Beneficiary shall mean any individual or entity so designated by the Participant, or, if the Participant does not have a Surviving Spouse and does not designate a beneficiary hereunder, or if the designated beneficiary predeceases the Participant, the Beneficiary shall mean the Participant's estate. 1.03 "Benefit Base" shall mean that amount defined in Section 2.01 which is payable at or after a Participant's Normal Retirement Date. 1.04 "Board of Directors" shall mean the Board of Directors of Entergy Corporation. 1.05 "Deferred Retirement Date" shall mean the first day of the month coincident with or next following the month in which the Participant elects to Retire from Service or Separate from Service but which occurs after the Normal Retirement Date for such Participant. Notwithstanding this definition, such date shall constitute the "Deferred Retirement Date" for purposes of this Plan only to the extent that the Employer has given its prior written consent for the Participant to continue his employment beyond the Normal Retirement Date of such Participant. Such consent may be freely withheld. Any continuation of employment by the Employee beyond his Normal Retirement Date without such prior written consent of the Employer shall be governed by the terms of Section 6.01. 1.06 "Early Retirement Date" shall mean the first day of the month coincident with or next following the date on which the Participant who has attained the requisite age and number of Years of Service required for early retirement under the Entergy Retirement Plan (as in effect as of the date of any such election) elects to Retire from Service or Separate from Service with the prior written consent of the Employer (which consent may be freely withheld) provided that such date precedes the Normal Retirement Date for any such Participant. Any election by the Participant to Retire or Separate from Service on or after his Normal Retirement Date shall not be deemed an Early Retirement Date, but shall be governed, to the extent applicable, by Sections 1.05 and 1.17, respectively. 1.07 "Early Retirement Reduction Factor" shall mean the factor or percentage by which the Benefit Base of a participant under the Entergy Retirement Plan, as from time to time amended, shall be reduced for each month by which such participant's early retirement date precedes his Normal Retirement Date. 1.08 "Entergy Retirement Plan" shall mean the Retirement Income Plan of Entergy Corporation, Entergy Services, Inc., Electec, Inc., System Energy Resources, Inc., System Fuels, Inc., and Entergy Operations, Inc., or any successor to such plan as may from time to time be established by Entergy Corporation for the benefit of non- bargaining employees of Entergy Corporation and other System Companies. In the event that any such Entergy Retirement Plan is terminated as to the non-bargaining employees of Entergy Corporation and System Companies and no successor plan is established with respect thereto, the term "Entergy Retirement Plan" shall mean the qualified defined benefit plan in the form last sponsored by Entergy Corporation on or before the date of any such termination. 1.09 "Employee" shall mean an employee of a System Company who is a member of a select group of management or highly compensated employees. 1.10 "Employer" shall mean the System Company with which the Employee is last employed on or before the Employee's Retirement or Separation from Service. 1.11 "Executive Annual Incentive Plan" shall mean the Executive Annual Incentive Plan sponsored by Entergy Corporation as a cash incentive plan for select members of management of Entergy Corporation and other System Companies (exclusive of Entergy Enterprises, Inc.) as such plan is from time to time amended. 1.12 "Final Annual Compensation" shall mean the sum of (i) the final annual base salary received by or payable to the Participant from the Employer or from any other System Company, exclusive of bonuses and overtime payments, but including the amount, if any, such Participant defers under a cash or deferred arrangement qualified under Section 401(k) of the Code, and under any cafeteria plan under Section 125 of the Code including, without limitation, any deferrals under any flexible spending arrangements permitted by the Code; and (ii) any annual Target Award with respect to the Participant for the performance period under the Executive Annual Incentive Plan during which the Participant's Retirement or Separation from Service occurs. 1.13 "Final Monthly Compensation" shall mean 1/12th of the amount equal to the Participant's Final Annual Compensation as in effect on the Participant's Retirement or Separation from Service. 1.14 "Income Commencement Date" shall mean the first date on which the Participant is entitled under the applicable provisions of Article II to commence receiving a monthly benefit under the Plan based on, or as the result of, such Participant's death, Retirement or Separation from Service. 1.15 "Joint Annuitant" shall mean the legal spouse of a Participant as of the date of the Participant's Retirement or Separation from Service who is eligible to receive a Survivor's Benefit in the event of the Participant's death on or after the Income Commencement Date in accordance with Article III. 1.16 "Know-How Points" shall mean those number of points from time to time established with respect to a position held by a Participant as defined by and determined in accordance with the procedures under the Entergy Corporation Companies Job Evaluation Manual, as from time to time amended. 1.17 "Normal Retirement Date" shall be the first day of the month coincident with or next following an Employee's 65th birthday, or such earlier date as may be established from time to time under the Entergy Retirement Plan as the earliest date on which an unreduced benefit shall become payable under such plan. 1.18 "Other Employer Plans" shall mean all other non-qualified defined benefit retirement income or pension plans, trusts, or other arrangements sponsored by any System Company (including any benefits under Supplemental Credited Service Agreements, the Supplement Retirement Plan, and the Post-Retirement Plan) under which the Participant may have an earned or accrued benefit in effect at the time of his Retirement or Separation from Service. Such term shall not include: any tax qualified employee pension plans; any profit-sharing, stock bonus or other defined contribution plans; the Gulf States Utilities Company Executive Income Security Plan; Gulf States Utilities Company Executive Continuity Plan; Gulf States Utilities Company Nonqualified Deferred Compensation Plan for Officers, Nonemployee Directors and Designated Key Employees; and any other plans, programs, or arrangements that allow for a paid up benefit or a cash lump sum payment in lieu thereof. 1.19 "Participant" shall mean an Employee who is eligible for a Target Award at a level at or above 35% of base salary as from time to time defined in the Executive Annual Incentive Plan and who remains eligible for participation in accordance with the applicable provisions of the Plan including, without limitation, Section 6.01. 1.20 "Personnel Committee" shall mean the Personnel Committee of the Board of Directors. 1.21 "Plan" shall mean this System Executive Retirement Plan of Entergy Corporation and Subsidiaries and any amendments, supplements or modifications from time to time made hereto. 1.22 "Retirement", "Retires", "Retire," or "Retired from Service" shall mean the retirement of a Participant from employment with the Employer in accordance with Article II. 1.23 "Retirement Income" shall mean the monthly benefit payable to a Participant under the Plan in accordance with Article II. 1.24 "Separation from Service", "Separates from Service" or "Separated from Service" shall mean the separation of a Participant from employment with the Employer before attaining his Normal Retirement Date with the prior written consent of the Employer. 1.25 "Separation from Service Date" shall mean the date on which a Participant Separates from Service as defined in Section 1.24. 1.26 "Surviving Spouse" shall mean the person to whom the Participant was legally married as of the date of such Participant's death. 1.27 "Survivor's Benefit" shall mean that monthly benefit described under Section 3.01 which is payable to the Participant's Joint Annuitant in the event his death occurs on or after his Income Commencement Date. To the extent that the Participant has made a timely election for an optional form of Survivor's Benefit in accordance with Section 3.02, the term "Survivor's Benefit" shall mean the monthly benefit described under Section 3.02 rather than Section 3.01. 1.28 "Survivor's Preretirement Death Benefit" shall mean that monthly benefit described under Article IV which is payable to the Participant's Surviving Spouse or other Beneficiary, as applicable, in the event the Participant's death occurs before his Income Commencement Date. 1.29 "System" shall mean Entergy Corporation and all System Companies. 1.30 "System Company" shall mean Entergy Corporation and any corporation 80% or more of whose stock (based on voting power or value) is owned, directly or indirectly, by Entergy Corporation and any partnership or trade or business which is 80% or more controlled, directly or indirectly, by Entergy Corporation. 1.31 "Target Award" shall mean the full, unreduced annual award for which a given Participant hereunder is eligible to receive under the Executive Annual Incentive Plan. For purposes of this Plan, such Target Award is determined as if the Participant: (i) had completed the applicable annual plan year under the Executive Annual Incentive Plan, and (ii) had met all performance criteria thereunder for the then current year at a Superior Level established under that plan or under such other terms as the Board of Directors may from time to time determine. 1.32 "Ten-Year Certain Period" shall mean that period referred to in Section 2.01 which commences on the Participant's Income Commencement Date and continues thereafter for a period of ten Years. For purposes of Section 4.01, if the Participant dies after the earliest date on which he is eligible for early retirement under the Entergy Retirement Plan (as in effect on the date of his death), but before his Income Commencement Date, the term "Ten- Year Certain Period" shall mean the ten Year period commencing on his date of death. 1.33 "Year" shall mean any period of twelve consecutive months. 1.34 "Year of Service" shall mean each Year of employment within the System. If a Participant becomes permanently disabled and qualifies for monthly benefits under any long term disability plan sponsored by a System Company, the term "Year of Service" shall include any Year preceding the date on which such Participant elects Retirement under this Plan and for which the Participant received monthly disability benefit payments under such long term disability plan. Additionally, the term "Year of Service" shall include any Years of imputed service or employment that the Employer may, in its discretion, grant to a given Participant. 1.35 The masculine pronoun whenever used in the Plan shall include the feminine. Similarly, the feminine pronoun whenever used in the Plan shall include the masculine as the context or facts may require. Whenever any words are used herein in the singular, they shall be construed as if they were also used in the plural in all cases where the context so applies. Article II. BENEFITS 2.01 Benefit Base (a) A Participant's Retirement Income shall be payable in a form described in Article III below. Except as otherwise provided in the Plan, such Retirement Income shall be determined based on a Participant's Benefit Base which shall be in the form of equal monthly installments payable on a ten-year continuous and certain basis described in Article III commencing at a Participant's Normal Retirement Date. Such monthly Benefit Base shall be equal to: (i) a percentage of his Final Monthly Compensation, based on the percentages described in Appendix A attached hereto and made a part hereof, which percentages, as determined from the Appendix A, shall vary depending on (A) the number of Years of Service the Participant has completed through the date of Retirement or Separation from Service, as applicable, and (B) the number of Know-How Points established with respect to the position held by such Participant as of the date of his Retirement or Separation from Service; less (ii) the amount of any benefit (in the form described below) which such Participant earned (A) under any other qualified or non-qualified defined benefit retirement income or pension plan, trust, or other arrangement sponsored by any System Company (including, without limitation, Gulf States Utilities Company Employees' Trusteed Retirement Plan and Gulf States Utilities Company Executive Income Security Plan) or (B) under any such qualified or non-qualified defined benefit retirement income or pension plans sponsored by any previous employer or any other person, persons or entities for whom the Participant may have been employed on or before the date of his Retirement or Separation from Service, regardless of whether the Participant received a paid up benefit or a cash payment under such plans in lieu thereof. The benefits described in this Subsection (ii) shall exclude any and all benefits earned under the following plans: any stock bonus plans, profit sharing plans, employee stock ownership plans, or other defined contribution plans; and, except as provided in Section 2.06(b), any Other Employer Plans as to which the Participant has completely waived all rights. For purposes of this Subsection (ii), with respect to an unmarried Participant, such benefits shall be expressed as a single life annuity commencing at the Participant's Normal Retirement Date and, as to Participants who are married as of the date of their Retirement or Separation from Service, such benefits shall be expressed as a single life annuity adjusted for a 50% joint and survivors annuity benefit or the equivalent thereof commencing at the Participant's Normal Retirement Date. 2.02 Normal Retirement Benefit A Participant who elects to Retire from the Employer as of his Normal Retirement Date shall be entitled to a monthly Retirement Income in a form described under Article III of the Plan, commencing on his Normal Retirement Date (which shall be his Income Commencement Date). Such Participant's Benefit Base shall be computed as described in Section 2.01, and, unless the Participant elects an optional form of benefit under Section 3.02, his Retirement Income shall be equal to that amount. If the Participant elects an optional form of benefit under Section 3.02, such Benefit Base shall be subject to adjustment in accordance with the terms of that provision. 2.03 Deferred Retirement Benefit A Participant who elects to Retire from the Employer as of his Deferred Retirement Date shall be entitled to a monthly Retirement Income in a form described under Article III of the Plan, commencing on his Deferred Retirement Date (which shall be his Income Commencement Date). Such Participant's Benefit Base shall be computed as described in Section 2.01, and, unless the Participant elects an optional form of benefit under Section 3.02, his Retirement Income shall be equal to that amount. If the Participant elects an optional form of benefit under Section 3.02, such Benefit Base shall be subject to adjustment in accordance with the terms of that provision. 2.04 Early Retirement Benefit A Participant who elects to Retire as of his Early Retirement Date shall be entitled to a monthly Retirement Income in a form described under Article III of the Plan, commencing on his Early Retirement Date (which shall be his Income Commencement Date). Such Participant's Benefit Base shall be computed as described in Section 2.01, but such Benefit Base shall be reduced by the Early Retirement Reduction Factor for each month by which the Early Retirement Date precedes his Normal Retirement Date and, unless the Participant elects an optional form of benefit under Section 3.02, his Retirement Income shall be equal to that reduced amount. If the Participant elects an optional form of benefit under Section 3.02, such Benefit Base shall be subject to further adjustment in accordance with the terms of that provision. A Participant who Separates from Service and, on or after such Separation from Service Date, attains or has attained the earliest age and Years of Service required for early retirement under the Entergy Retirement Plan is not required to elect early retirement under the terms of this Section 2.04, but such Participant may, at any time on or after such Separation from Service Date (but no later than his Normal Retirement Date), elect to commence his Retirement Income hereunder in accordance with the terms of Section 2.05(b). 2.05 Separation Retirement Benefit (a) Except as provided in Subsection (b) below, a Participant who Separates from Service shall be entitled to a monthly Retirement Income in a form described under Article III of the Plan, commencing on his Normal Retirement Date (which shall be his Income Commencement Date). Such Participant's Benefit Base shall be computed as described in Section 2.01, and, unless the Participant elects an optional form of benefit under Section 3.02, his Retirement Income shall be equal to that amount. If the Participant elects an optional form of benefit under Section 3.02, such Benefit Base shall be subject to adjustment in accordance with the terms of that provision. (b) Early Commencement. Subject to consent from the Employer, any Participant who Separates from Service may elect to commence such monthly Retirement Income on the first day of the month coincident with or any month following the date on which such Participant, on or after such Separation from Service Date, attains or has attained the earliest age and requisite number of Years of Service required for early retirement under the Entergy Retirement Plan as in effect on his Separation from Service Date (which commencement date shall be his Income Commencement Date). Any such election must be made in accordance with rules and regulations as established from time to time by the Administrator, and shall be made no later than his Normal Retirement Date; provided that, if such Participant elects to receive such monthly benefit prior to his Normal Retirement Date with the consent of his Employer, his Benefit Base shall be reduced by the Early Retirement Reduction Factor for each month by which the Early Retirement Date precedes his Normal Retirement Date. 2.06 Election of Benefits on Other Employer Sponsored Benefits (a) Waiver Required. Notwithstanding any provision stated herein to the contrary, in order for a Participant or Beneficiary to receive any benefit under this Plan, such Participant must expressly waive, revoke, forgive or otherwise relinquish any and all rights to any benefits under all Other Employer Plans. As a condition for any benefits under this Plan, the Participant must further provide the Administrator with written evidence of any such waiver, revocation, forgiveness or otherwise relinquishment of any and all such other rights or benefits under such Other Employer Plans in such form as the Administrator may require. (b) Effect If No Waiver Possible. Subject to the prior written consent from the Employer, but only to the extent that any such other rights or benefits under any such Other Employer Plans cannot be effectively waived, revoked, forgiven or relinquished by the Participant, the Employer may, in its sole and complete discretion, allow any and all benefits payable hereunder nonetheless to be payable at such times and in such amounts as described above except that any such monthly Retirement Income hereunder shall be reduced or offset by the amount of any such other rights or benefits that the Participant may otherwise receive on a monthly basis from such Other Employer Plans. (c) Actions Inconsistent With Waiver. If, for any reason, the Participant makes any claim for benefits under both this Plan and any of such Other Employer Plans as to which such Participant has executed a waiver, revocation, forgiveness or relinquishment of rights and benefits, any and all benefits hereunder shall thereupon immediately terminate except to the extent agreed to in writing by the Employer, and the Employer shall thereafter have the full and complete right to recover from the Participant any and all benefits paid under the terms of this Plan through the date of any such forfeiture together with interest and reasonable attorneys fees. 2.07 Vesting. Notwithstanding the foregoing, and except as provided in Article VIII, a Participant shall not vest in any benefits under the Plan until the date immediately preceding the Participant's Retirement or Separation from Service. Article III. AMOUNT AND FORM OF BENEFITS 3.01 Normal Form of Retirement Income (a) Ten Year Continuous and Certain Benefit. Unless the Participant makes an election under Section 3.02 below, his Retirement Income shall be a ten year continuous and certain benefit which means that such Retirement Income shall be paid in equal monthly installments in the form of an annuity for the life of the Participant with a minimum of 120 monthly payments to the Participant or, in the event of his death, his Joint Annuitant. Subject to any reduction required under Section 2.04 (or Section 2.05(b), as applicable) for early retirement, the amount of such monthly payments shall be equal to the Participant's Benefit Base as determined under Section 2.01. In the event that there is a Joint Annuitant and such Joint Annuitant should survive the Participant, the unpaid guaranteed monthly payments remaining payable after the Participant's death during the Ten Year Certain Period shall be paid to such Joint Annuitant. If, at the time of the Participant's death, there is no Joint Annuitant (e.g., the Participant was not legally married as of his Retirement or Separation from Service) or if the Joint Annuitant predeceases the Participant, the remaining unpaid guaranteed monthly payments payable during the Ten Year Certain Period shall be paid to the Participant's Beneficiary. If the Joint Annuitant (or the Participant's Beneficiary who is eligible in the absence of a Joint Annuitant to receive the remaining unpaid guaranteed monthly payments payable during the Ten Year Certain Period, as applicable) should die before the end of the Ten Year Certain Period, the remaining unpaid guaranteed monthly payments payable during the Ten Year Certain Period shall be paid to such person or persons as the Joint Annuitant (or, if there was no Joint Annuitant or in the instance where the Joint Annuitant predeceased the Participant, the Beneficiary) may have designated in writing to the Administrator prior to the Joint Annuitant's (or, as applicable, the Beneficiary's) death or, in the absence of any such beneficiary designation, to the Joint Annuitant's (or, as applicable, the Beneficiary's) estate. No such beneficiary designation shall be binding or valid unless filed with and received by the Administrator on or before the Joint Annuitant's (or, as applicable, Beneficiary's) death. There shall be no reduction in the Participant's Benefit Base as a result of the extension of such Retirement Income on a ten-year continuous and certain basis. Except as provided in Article IV, no benefits shall be paid under the Plan if the Participant dies before his Income Commencement Date. (b) Survivor's Benefit. If the Participant dies on or after such Income Commencement Date, his Joint Annuitant will be provided a monthly Survivor's Benefit for the life of such Joint Annuitant equal to one-half of the Benefit Base described under Section 2.01 (as reduced under Sections 2.04 or Section 2.05(b), respectively, based on the Participant's early retirement as applicable). Notwithstanding the foregoing, if the Participant timely elects an optional form of benefit under Section 3.02, such optional form of benefit, including Survivor's Benefit, shall be paid in lieu of any amounts otherwise payable under this Section 3.01. The monthly Survivor's Benefit shall commence as of the first day of the month coincident with or next following the later of (i) the date on which the Participant dies, or (ii) the end of the Ten-Year Certain Period. (c) Without limiting the breadth of Article IV, if the Joint Annuitant predeceases the Participant, there shall be no Survivor's Benefit under Section 3.01(b) except that the monthly guaranteed payments shall be continued in such instance to the Participant's Beneficiary for the remainder of the Ten Year Certain Period as described in Subsection (a) above to the extent applicable. 3.02 Optional Survivor's Benefit Option (a) In lieu of the normal Survivor's Benefit described in Section 3.01 above, a Participant who is legally married as of his Income Commencement Date may elect to increase the amount of the monthly Survivor's Benefit payable to the Joint Annuitant, if any, on and after his death subject to the following conditions: (i) Such election must be made on or before the earlier of (A) the date on which such Participant attains age 64, or (B) the date occurring forty- five (45) days immediately preceding the Participant's Retirement or Separation from Service; (ii) Under this optional form of Survivor's Benefit, the Survivor's Benefit payable to the Joint Annuitant shall be a percentage designated by the Participant in an amount equal to 66 2/3%, 75%, 90%, or 100% of the amount of the Participant's Benefit Base (as adjusted for early retirement, as applicable); (iii) At the time the Participant elects this optional form of Survivor's Benefit, he shall furnish to the Administrator satisfactory proof of the age of the Joint Annuitant; (iv) The Participant may cancel his election for such optional form of Survivor's Benefit at any time prior to the deadline for making such elections as described in Subsection (i) above after which date any such election(s) shall become irrevocable; (v) Any failure by the Participant to make an affirmative written election hereunder on or before the deadline established in Subsection (i) above shall constitute a waiver of any right to elect an optional form of benefit, including an adjusted Survivor's Benefit, in which case the terms of Section 3.01 shall govern to the extent applicable; (vi) The Survivor's Benefit under any such optional form of benefit elected under this Section 3.02 shall terminate on the death of the Joint Annuitant at any time after the Income Commencement Date and all rights to a Survivor's Benefit hereunder shall thereafter cease; and (vii) Except as otherwise provided in this Section 3.02, the terms and conditions for the payment of the adjusted Retirement Income to the Participant (or his Joint Annuitant or Beneficiary, as applicable) including, without limitation, the payment of any minimum guaranteed payments during the Ten Year Certain Period, shall be governed by the terms described in Section 3.01 above. (b) Any election under this Section 3.02 shall cause the Participant's Benefit Base (as adjusted for early retirement, as applicable) to be adjusted based on the relative ages of the Participant and his Joint Annuitant at the time of his Income Commencement Date which adjustment shall be in accordance with the applicable adjustment tables attached hereto and made a part hereof as Appendix B. If the Joint Annuitant should predecease the Participant on or after the Income Commencement Date, the Participant shall not thereafter be entitled to any readjustment to his Retirement Income. (c) Any Survivor's Benefit payable under this optional form of benefit shall be a monthly benefit payable over the life of the Joint Annuitant commencing as of the first day of the month coincident with or next following the later of (i) the date on which the Participant dies, or (ii) the end of the Ten-Year Certain Period. Except as provided in Article IV, no benefits shall be paid under the Plan if the Participant dies before his Income Commencement Date. Without limiting the breadth of Article IV, if the Joint Annuitant predeceases the Participant, there shall be no Survivor's Benefit under Section 3.02 except that the monthly guaranteed payments as adjusted hereunder shall be continued in such instance to the Participant's Beneficiary for the remainder of the Ten Year Certain Period as described in Section 3.01(a) above to the extent applicable. Article IV PRE-RETIREMENT DEATH BENEFITS 4.01 Pre-Retirement Death Benefit if Participant is Eligible for Retirement. (a) Upon the death of a Participant on or after the date on which he attained age 55 and ten (10) Years of Service (or such earlier date as the Entergy Retirement Plan may, at the time of the Participant's death, permit for early retirement), but prior to his Income Commencement Date, his Beneficiary shall be entitled to receive 120 monthly payments under the Plan, commencing as of the first day of the month next following the Participant's death. The amount of each such monthly benefit shall be equal to the Participant's Benefit Base calculated as if he had not died on his actual date of death but instead had: (i) Retired on his Normal Retirement Date, with the same Years of Service and Final Monthly Compensation as of his date of death (or, in the case of a Participant who continues his employment beyond his Normal Retirement Date with the consent of his Employer, but dies before his Income Commencement Date, such Participant shall be treated for purposes of this Section 4.01 as having Retired as of his date of death); (ii) Elected the normal form of benefit described in Section 3.01 without additional adjustments pursuant to Section 3.02; and (iii) Then died immediately thereafter. The Survivor's Preretirement Death Benefit described hereunder shall not be reduced by the Early Retirement Reduction Factor even if such benefits commence on or before the Participant's Normal Retirement Date determined as if he had lived. (b) In the event that the Beneficiary should die before the end of the Ten Year Certain Period, the remaining unpaid monthly installments of the total 120 initial monthly payments payable during the Ten Year Certain Period shall be paid in the same installments to such person or persons as the Beneficiary may have designated in writing to the Administrator prior to such Beneficiary's death or, in the absence of any such beneficiary designation, to such Beneficiary's estate. No such beneficiary designation shall be binding or valid unless filed with and received by the Administrator on or before the Beneficiary's death. (c) In the event that the Beneficiary is the Participant's Surviving Spouse and such Surviving Spouse is still living following the date on which the last of the initial 120 payments is made, such Beneficiary shall thereafter be entitled to receive monthly payments in an amount equal to one-half of the Benefit Base determined under Subsection (a) above. Such additional payments to the Surviving Spouse shall commence on the first day of the month next following the last of the initial 120 payments and shall continue for the remaining life of such Surviving Spouse. 4.02 Pre-retirement Death Benefit if Participant is Not Eligible for Retirement Upon the death of a Participant prior to the date on which he attained age 55 and ten (10) Years of Service (or such earlier date as the Entergy Retirement Plan may, at the time of the Participant's death, permit for early retirement), his Beneficiary shall be entitled to receive, for her life, monthly payments under the Plan commencing as of the first day of the month next following the date on which the Participant would have attained age 55 had he lived. Such monthly payments shall be in an amount equal to one-half of the Participant's Benefit Base calculated as if he had not died on his actual date of death but instead had: (i) Retired on his Normal Retirement Date, with the same Years of Service and Final Monthly Compensation as of his date of death; (ii) Elected the normal form of benefit described under Section 3.01 without additional adjustments pursuant to Section 3.02; and (iii) Then died immediately thereafter. The Survivor's Preretirement Death Benefit described hereunder shall not be reduced by the Early Retirement Reduction Factor even if such benefits commence on or before the Participant's Normal Retirement Date determined as if he had lived. Article V SOURCE OF PAYMENTS 5.01 Unfunded Plan. It is a condition of the Plan that neither the Participant nor any other person or entity shall look to any other person or entity other than the Employer for the payment of benefits under the Plan. The Participant or any other person or entity having or claiming a right to payments hereunder shall rely solely on the unsecured obligation of the Employer set forth herein. Nothing in this Plan shall be construed to give the Participant or any such person or entity any right, title, interest, or claim in or to any specific asset, fund, reserve, account or property of any kind whatsoever, owned by the Employer or in which the Employer may have any right, title or interest now or in the future. However, the Participant or any such person or entity shall have the right to enforce his claim against the Employer in the same manner as any other unsecured creditor of the Employer. 5.02 Employer Liability. At its own discretion, the Employer may purchase such insurance or annuity contracts or other types of investments as it deems desirable in order to accumulate the necessary funds to provide for the future benefit payments under the Plan. Notwithstanding anything to the contrary herein, (1) the Employer shall be under no obligation to fund the benefits provided under this Plan; (2) the investment of Employer funds credited to a special account established hereunder shall not be restricted in any way; and (3) such funds may be available for any purpose the Employer may choose. Article VI. FORFEITURES 6.01 Forfeitures. The Participant shall cease to be a Participant hereunder and no benefits under the Plan shall be payable hereunder on and after any of the following events: (1) if the Participant continues his employment with the Employer after his Normal Retirement Date without the prior written consent of the Employer which consent may be freely withheld; (2) if the Participant voluntarily terminates his employment with the Employer prior to his Normal Retirement Date without the prior written consent of his Employer, which consent may be freely withheld; (3) if the Participant is involuntarily terminated by the Employer for cause. For purposes of the Plan, termination for cause shall include: (a) a material violation by the Participant of any agreement with the Employer to which he is a party; (b) a material violation of the employer-employee relationship existing between the Participant and the Employer at the time, including, without limi tation, breach of confidentiality, moral turpitude, theft or defalcation; and (c) a material failure by the Participant to perform the services required by him by any agreement with the Employer to which he is a party, or, if there is no such agreement, a material failure by the Participant to perform the reasonable customary services of an employee holding the type of position he holds at the time; (4) if the Participant loses his status as an officer of the Employer (otherwise than for the purpose of assuming an officer position with another System Company) or otherwise has the Know-How Points for his position reduced to a level less than 1,451 ("Demotion"); (5) except as otherwise provided in Section 2.06, if the Participant (i) fails to expressly waive, revoke, forgive or otherwise relinquish any and all rights to any benefits under all Other Employer Plans in such form and in accordance with such procedures as the Administrator may from time to time establish, or (ii) files a claim under such Other Employer Plans inconsistent with the waiver filed with the Administrator; (6) if the Participant engages in any employment (without the prior written consent from the Employer) either individually or with any person, corporation, governmental agency or body, or other entity in competition with, or similar in nature to, any business conducted by any System Company at any time within the ten Year period commencing at Retirement or Separation from Service, as applicable; (7) if the Participant shall divulge, communicate or use to the detriment of the Employer or any System Company, or use for the benefit of any other person or entity, or misuse in any way, any confidential or proprietary information or trade secrets of the Employer or any System Company, or engage in any activities that are contrary to the best interests of the Employer or any System Company; or (8) if the Participant voluntarily terminates his employment or his employment is terminated with the Employer prior to his completion of five (5) actual Years of service or employment with the System. 6.02 Advisory Services. As a condition for benefits under this Plan, the Participant must hold himself available to render advisory services, with his consent, if so requested by the Employer, during the period beginning with his Retirement or Separation from Service, as applicable, and continuing for a period of ten Years thereafter. The Participant shall control the manner in which he renders services hereunder and may, at his discretion, decline to render any such services requested by the Employer if the Participant's time constraints are such that the rendering of such services would result in an undue burden upon the Participant. Article VII. PLAN ADMINISTRATION 7.01 Administration of Plan. Subject to periodic review by the Personnel Committee, the Administrator shall have the exclusive right to interpret the provisions of the Plan and to resolve any questions arising hereunder or in connection with the administration hereof. Any decision or action of the Administrator shall be conclusive and binding upon the Participant, any Joint Annuitant, and any beneficiaries. The Chairman of the Board of Directors shall from time to time appoint and, as the Chairman may determine appropriate, remove the Administrator who shall operate and administer the Plan. The Administrator shall discharge his duties for the exclusive benefit of the Participants and their beneficiaries. The Administrator shall administer the Plan in accordance with its terms and shall have such powers necessary for such purpose including, without limitation: (a) to adopt such rules and regulations as he shall deem desirable or necessary for the administration of the Plan on a consistent and uniform basis; (b) to interpret the Plan including, without limitation, the power to use his sole and exclusive discretion to construe and interpret (i) the Plan, (ii) the intent of the Plan, and (iii) any ambiguous, disputed or doubtful provisions of the Plan; (c) to resolve any questions concerning eligibility for benefits under the Plan subject to the terms herein stated, and to require such information as he may reasonably request as a condition for receiving any benefit under the Plan; (d) to compute the amount of the benefit payable hereunder to Participants, any Joint Annuitants, or any beneficiaries; (e) to execute or deliver any instrument or make any payment on behalf of the Plan; (f) to employ one or more persons to render advice with respect to any of the Administrator's responsibilities under the Plan; and (g) to direct the Employer concerning all payments that shall be made pursuant to the terms of the Plan. All decisions of the Administrator of any type, including the interpretation or construction of the Plan, shall be final and binding on all parties and shall not be disturbed unless the Administrator's decisions are arbitrary and capricious. The Administrator shall by rule or regulation establish a claims procedure under which a claimant shall receive notice in writing in the event any claim for benefits with respect to the Participant's participation in the Plan has been denied; such notice shall set forth the specific reasons for such denial. Such claims procedures shall also provide an opportunity for full and fair review by the Administrator of any denial of a claim. 7.02 Reliance on Reports and Certificates. The Board of Directors, the Personnel Committee, the Administrator and the Employer may rely conclusively upon all tables, valuations, certificates, opinions and reports furnished by an actuary, accountant, counsel or other person who may from time to time be employed or engaged for such purposes. Article VIII. AMENDMENT AND TERMINATION 8.01 General. The Board of Directors may at any time amend, supplement, modify or terminate the Plan, subject to the provisions of Section 8.02 hereof. 8.02 Restrictions on Amendment or Termination. Any amendment, supplement or modification to, or the termination of, the Plan shall be subject to the following restrictions: (a) The Employer shall continue, subject to the provisions of Article II and Section 6.01, to make payments to any retired or separated Participant or Beneficiary then entitled to payments as if the Plan had not been amended, supplemented, modified or terminated; and (b) As to any Participant who has not yet begun receiving monthly benefits under the Plan, the Employer, subject to any provisions of Article II to the contrary, shall remain obligated to provide a benefit upon the earlier of the Participant's Early Retirement Date or death that is actuarially equivalent to (and payable for the term of) the accrued benefit under Article II earned by the Participant at the time the Plan is amended, supple mented, modified or terminated. 8.03 Successors to Business of Employer. The Employer shall not sell all or substantially all of its assets or participate in any merger, consolidation or similar reorganization as to which it is not the surviving entity unless the successor to the business of the Employer or other surviving entity, by whatever form or manner resulting, shall continue the Plan. Thereupon such successor or surviving entity shall succeed to all the rights, powers and duties of the Employer and the Board of Directors hereunder. The employment of the Participant who has continued in the employ of such successor or surviving entity shall not be deemed to have been terminated or severed for any purpose hereunder. 8.04 Dissolution of the Employer. In the event that the Employer is dissolved or liquidated by reason of bankrupt cy, insolvency or otherwise prior to the Employee's death or Retirement from Service, without any provision being made for the continuance of the Plan by a successor to the business of the Employer or unless another System Company shall have assumed the obligations of the Employer under the Plan, the date on which such dissolution or liquidation occurs shall be deemed to be the non-retired Participant's Early Retirement Date and the Participant's Retirement from Service shall be deemed to have occurred on his Early Retirement Date. At the option of the person entitled thereto, the actuarial equivalent of such benefits shall be paid immediately in one lump sum. Upon the date of such liquidation or dissolution in the case of a retired Participant or Beneficiary who is receiving benefit payments under the Plan, the actuarial equivalent of the benefits then remaining to be paid under the Plan to the Participant, Joint Annuitant, or Beneficiary, as applicable, shall be paid immediately in one lump sum at the option of the person entitled thereto. Article IX. ALIENATION 9.01 No Alienation. The benefits provided hereunder shall not be subject to alienation, assignment, pledge, anticipation, attachment, garnishment, receivership, execution or levy of any kind, including liability for alimony or support payments, and any attempt to cause such benefits to be so subjected shall not be recognized, except to the extent as may be required by law. APPENDIX A DESIGNED TARGET PAY REPLACEMENT RATIOS FOR THE PROPOSED SYSTEM EXECUTIVE RETIREMENT PLAN (SERP) OF ENTERGY CORPORATION AND SUBSIDIARIES Target Pay Replacement Level For Executives With Know-How Points: Years Of Chairman & CEO Above 1,901** Between 1,451 & 1,900*** Service* 55% 50% 45% 1 3.3% 3.0% 2.7% 2 6.6% 6.0% 5.4% 3 9.9% 9.0% 8.1% 4 13.2% 12.0% 10.8% 5 16.5% 15.0% 13.5% 6 19.8% 18.0% 16.2% 7 23.1% 21.0% 18.9% 8 26.4% 24.0% 21.6% 9 29.7% 27.0% 24.3% 10 33.0% 30.0% 27.0% 11 36.3% 33.0% 29.7% 12 39.6% 36.0% 32.4% 13 42.9% 39.0% 35.1% 14 46.2% 42.0% 37.8% 15 49.5% 45.0% 40.5% 16 50.6% 46.0% 41.4% 17 51.7% 47.0% 42.3% 18 52.8% 48.0% 43.2% 19 53.9% 49.0% 44.1% 20 55.0% 50.0% 45.0% 21 56.0% 51.0% 46.0% 22 57.0% 52.0% 47.0% 23 58.0% 53.0% 48.0% 24 59.0% 54.0% 49.0% 25 60.0% 55.0% 50.0% 26 61.0% 56.0% 51.0% 27 62.0% 57.0% 52.0% 28 63.0% 58.0% 53.0% 29 64.0% 59.0% 54.0% 30 65.0% 60.0% 55.0% * Replacement Ratio for fractional years will be determined by interpolating the difference between the ratio corresponding to completed years of service and the ratio corresponding to the next higher year of service. APPENDIX B-1--100%J&S Joint and 100% Survivor Pension Factors If The Participant Is " O L D E R " Than The Joint Annuitant And The Age Difference Is: If Participant's Less Than Age Is Greater Or Less Than: 58 61 64 100 Than but Equal To Greater Than or 0 58 61 64 Equal to: 40 100 89% 88% 86% 84% 30 40 89% 88% 86% 84% 20 30 90% 88% 87% 85% 17 20 90% 89% 88% 86% 14 17 90% 89% 88% 87% 11 14 91% 89% 88% 87% 8 11 91% 90% 89% 87% 5 8 92% 90% 90% 88% 2 5 92% 91% 91% 89% 0 2 93% 91% 91% 90% If The Participant Is " Y O U N G E R " Than The Joint Annuitant And The Age Difference Is: If Participant's Less Than Age Is Greater Or Less Than: 58 61 64 100 Than but Equal To Greater Than or 0 58 61 64 Equal to: 0 2 93% 92% 92% 90% 2 5 93% 93% 92% 92% 5 8 94% 94% 94% 93% 8 11 95% 95% 95% 94% 11 14 95% 96% 95% 95% 14 17 96% 97% 96% 96% 17 20 98% 97% 97% 97% 20 100 98% 98% 98% 97% APPENDIX B-2--90%J&S Joint and 90% Survivor Pension Factors If The Participant Is " O L D E R " Than The Joint Annuitant And The Age Difference Is: Less If Participant's Than Age Is Greater Or Less Than: 58 61 64 100 Than but Equal To Greater Than or 0 58 61 64 Equal to: 40 100 91% 90% 89% 87% 30 40 91% 90% 89% 87% 20 30 92% 90% 90% 88% 17 20 92% 91% 90% 89% 14 17 92% 91% 90% 90% 11 14 93% 91% 90% 89% 8 11 93% 92% 91% 90% 5 8 94% 92% 92% 90% 2 5 94% 93% 93% 91% 0 2 94% 93% 93% 92% If The Participant Is " Y O U N G E R " Than The Joint Annuitant And The Age Difference Is: Less If Participant's Than Age Is Greater Or Less Than: 58 61 64 100 Than but Equal To Greater Than or 0 58 61 64 Equal to: 0 2 94% 94% 94% 92% 2 5 94% 94% 94% 94% 5 8 95% 95% 95% 94% 8 11 96% 96% 96% 95% 11 14 96% 97% 96% 96% 14 17 97% 98% 97% 97% 17 20 98% 98% 98% 98% 20 100 98% 98% 98% 98% APPENDIX B-3--75%J&S Joint and 75% Survivor Pension Factors If The Participant Is " O L D E R " Than The Joint Annuitant And The Age Difference Is: Less If Participant's Than Age Is Greater Or Less Than: 58 61 64 100 Than but Equal To Greater Than or 0 58 61 64 Equal to: 40 100 95% 94% 93% 92% 30 40 95% 94% 93% 92% 20 30 95% 94% 94% 93% 17 20 95% 95% 94% 93% 14 17 95% 95% 94% 94% 11 14 96% 95% 94% 93% 8 11 96% 95% 95% 94% 5 8 96% 95% 95% 94% 2 5 96% 96% 96% 95% 0 2 97% 96% 96% 95% If The Participant Is " Y O U N G E R " Than The Joint Annuitant And The Age Difference Is: Less If Participant's Than Age Is Greater Or Less Than: 58 61 64 100 Than but Equal To Greater Than or 0 58 61 64 Equal to: 0 2 97% 96% 96% 95% 2 5 97% 97% 96% 96% 5 8 97% 97% 97% 97% 8 11 98% 98% 98% 97% 11 14 98% 98% 98% 98% 14 17 98% 99% 98% 98% 17 20 99% 99% 99% 99% 20 100 99% 99% 99% 99% APPENDIX B-4--66&2/3%J&S Joint W/66 & 2/3% Survivor Pension Factors If The Participant Is " O L D E R " Than The Joint Annuitant And The Age Difference Is: Less If Participant's Than Age Is Greater Or Less Than: 58 61 64 100 Than but Equal To Greater Than or 0 58 61 64 Equal to: 40 100 96% 96% 95% 95% 30 40 96% 96% 95% 95% 20 30 97% 96% 96% 95% 17 20 97% 96% 96% 95% 14 17 97% 96% 96% 96% 11 14 97% 96% 96% 95% 8 11 97% 97% 96% 96% 5 8 97% 97% 97% 96% 2 5 97% 97% 97% 96% 0 2 98% 97% 97% 97% If The Participant Is " Y O U N G E R " Than The Joint Annuitant And The Age Difference Is: Less If Participant's Than Age Is Greater Or Less Than: 58 61 64 100 Than but Equal To Greater Than or 0 58 61 64 Equal to: 0 2 98% 97% 97% 97% 2 5 98% 98% 97% 97% 5 8 98% 98% 98% 98% 8 11 98% 98% 98% 98% 11 14 98% 99% 98% 98% 14 17 99% 99% 99% 99% 17 20 99% 99% 99% 99% 20 100 99% 99% 99% 99% EX-10 6 EMPLOYMENT AGREEMENT - J. L. DONNELLY Exhibit 10(d) 57 ADDENDUM TO EMPLOYMENT AGREEMENT FOR J. L. DONNELLY, CHAIRMAN OF THE BOARD, GULF STATES UTILITIES COMPANY There presently exists an Employment Agreement by and between Gulf States Utilities Company (Gulf States) and Joseph L. Donnelly (Donnelly) effective as of February 12, 1992. Upon the retirement or termination of employment by prior Chief Executive Officers of Gulf States it has been the practice to enter into agreements stipulating the understanding of the parties regarding the application of their respective employment agreements. Consistent with such past practice and in anticipation of the retirement of Donnelly, Gulf States and Donnelly hereby stipulate and agree as follows: I. It is presently expected that the business combination between Gulf States and Entergy Corporation will be consummated on December 31, 1993 or as soon thereafter as practicable. Gulf States and Donnelly agree that Donnelly shall resign as Chairman of the Board of Directors, President, Chief Executive Officer and Director of Gulf States on the third business day following the consummation of such business combination. By doing so, Donnelly does not waive his entitlement under the Agreement and Plan of Reorganization dated as of June 5, 1992 between Entergy Corporation and Gulf States (Reorganization Agreement) to become Vice Chairman and Director of Entergy Corporation. Further, resignation from such Gulf States' offices prior to April 1, 1994, shall not constitute retirement as an employee of Gulf States. If the business combination is consummated prior to April 1, 1994, which is Donnelly's normal retirement date, Donnelly shall retire as of April 1, 1994. Until such retirement, if the business combination has been consummated he shall be on leave of absence from and after the date of consummation and will continue to be paid at the salary rate of $37,500.00 per month until April 1, 1994. Upon retirement he shall also be entitled to receive compensation for one month's unused vacation. If the business combination is not consummated prior to April 1, 1994, then Donnelly's continued position as Chairman, President, CEO, Director and employee of Gulf States shall be at the pleasure of the Board of Directors of Gulf States. II. Pursuant to Paragraph 3. of the Employment Agreement, Gulf States hereby sets Donnelly's annual base salary as $450,000.00 effective December 15, 1993. III. For purposes of stipulating the level of annual retirement benefit which Gulf States is obligated to assure Donnelly under Paragraph 5 of the Employment Agreement, Gulf States and Donnelly hereby agree that the annual retirement benefit so assured under such Paragraph 5 shall be $248,868.00, and his widow's pension benefit as survivor under Paragraph 5 shall be 50% of such amount. Such assured benefit shall be offset by Social Security retirement benefits only if and to the extent he is eligible to draw such benefits at the time. IV. The Employment Agreement has assured Donnelly personal financial planning services up to $15,000.00 of fees per year. Having previously agreed that the $15,000.00 annual allowance for 1992 could be carried over and agreement hereby that the 1993 allowance may be carried over, Gulf States agrees that an aggregate of $45,000.00 of reimbursement of such personal financial planning service fees shall be paid by the Company for Donnelly as incurred from and after September 1, 1993. In addition, Gulf States agrees to provide up to an additional $5,000 per year for a period of five years commencing with tax year 1994 to reimburse Donnelly for income tax preparation services. V. Gulf States has previously provided Donnelly with an alarm and security lighting system service in his home and a portable emergency cellular phone. In recognition of his continued exposure to risks, Gulf States hereby agrees to continue to provide such services at its expense for a period of four (4) years from and after the consummation of the business combination with Entergy Corporation. Gulf States releases any and all claims and interests in and to such security system and phone effective as of the end of such four (4) years. VI. Paragraph 7 of the Employment Agreement provides for a death benefit. Donnelly hereby elects and Gulf States agrees to have such benefit provided in the form of a life insurance policy if available at a standard rated premium. VII. It has been customary with previous retiring CEO's for Gulf States to provide them an appropriate office and, on an "as available basis", secretarial assistance. In lieu thereof, Gulf States agrees to make a lump sum payment to Donnelly of $28,125.00 on the first to occur of the consummation of the business combination or April 1, 1994. VIII. As provided in the Employment Agreement, Donnelly shall be entitled to all other benefits to which he is entitled under other plans and programs of Gulf States. Without in anyway limiting such entitlements, Gulf States acknowledges and agrees that it is obligated to pay Donnelly the sum of $31,203.00 per year commencing January 1, 1995 and each January 1st thereafter through January 1, 2009 under the Nonemployee Directors and Designated Key Employees plan (Clark/Bardes). Further Gulf States acknowledges and agrees that it is obligated to provide Donnelly with post-retirement health benefits-for himself and his wife during his lifetime in accordance with the post-retirement health benefit program for retired Gulf States employees in effect during 1993. If he elects coverage for dependents other than his wife, he shall bear the additional premium cost thereof. IX. This addendum is not intended to supersede or replace Donnelly's Employment Agreement dated February 12, 1992, and is merely intended to clarify and supplement the provisions thereof, which shall remain in full force and effect. Dated: December 22, 1993 GULF STATES UTILITIES CO. By: /s/ Paul W. Murrill Chairman of the Executive Committee of the Board of Directors By: /s/ Sam F. Segner Chairman of Compensation Committee of the Board of Directors /s/ Joseph L. Donnelly Joseph L. Donnelly EX-10 7 LETTER OF CREDIT - GSU Exhibit 10(d) 58 AGREEMENT ASSIGNMENT, ASSUMPTION AND AMENDMENT AGREEMENT, dated as of September 8, 1993 (this "Agreement") among GULF STATES UTILITIES COMPANY, a Texas corporation (the "Company"), CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY ("CIBC") and WESTPAC BANKING CORPORATION, CHICAGO BRANCH ("Westpac"). W I T N E S S E T H: WHEREAS, the Company and Westpac are parties to that certain Letter of Credit and Reimbursement Agreement dated December 27, 1985, as amended as of October 20, 1992 (the "Reimbursement Agreement") which provides for, among other things, the issuance by Westpac of a letter of credit in favor of The Bank of New York, as Trustee (the "Trustee"), in connection with the Parish of West Feliciana, State of Louisiana Variable Rate Demand Pollution Control Revenue Bonds (Gulf States Utilities Company Project) Series 1985-D in the aggregate principal amount of $28,400,000 (the "Bonds"); WHEREAS, subject to the terms and conditions hereof, Westpac wishes to assign and transfer to CIBC, and CIBC wishes to accept and assume, in each case as hereinafter provided, the rights and obligations of Westpac under the Reimbursement Agreement; WHEREAS, subject to the terms and conditions hereof, the Company and CIBC wish to amend the terms of the Reimbursement Agreement in accordance with the provisions hereof; NOW, THEREFORE, in consideration of the foregoing and of the mutual agreements herein contained, the parties hereto agree as follows: SECTION I DEFINITIONS SECTION 1.1 Terms Defined in Reimbursement Agreement. As used herein, unless otherwise defined herein, capitalized terms defined in the Reimbursement Agreement shall have the respective meaning set forth therein. SECTION 1.2 Other Defined Terms. As used herein: (a) Terms defined in the preamble and the recitals hereto have the meanings set forth therein; and (b) The following terms have the following meanings: "Effective Date" shall be the day on which all the conditions precedent listed in Section V shall be satisfied. "New Letter of Credit" has meaning set forth in Section 2.2. "Original Letter of Credit" means Irrevocable Letter of Credit No. CH468680 dated December 27, 1985, as amended, and issued by Westpac to the Trustee pursuant to the Reimbursement Agreement. SECTION II ASSIGNMENT AND ASSUMPTION SECTION 2.1 Assignment and Assumption. On the Effective Date, subject to the terms and conditions of this Agreement, including, without limitation, Section V, (a) Except as provided in Section 2.4, Westpac hereby sells, assigns, conveys and transfers to CIBC, without recourse, warranty or (except as expressly provided in Section 4.3) representation, all of its right, title and interest in, to and under the Reimbursement Agreement and transfers to CIBC all of Westpac's obligations under the Reimbursement Agreement; (b) CIBC hereby purchases and accepts Westpac's rights under the Reimbursement Agreement and accepts and assumes its obligations thereunder and agrees to be bound by and perform the terms of the Reimbursement Agreement, as amended, substituted or otherwise modified pursuant to this Agreement, as if it were the Bank originally party thereto. SECTION 2.2 Delivery of Letter of Credit. On the Effective Date, subject to the applicable conditions precedent set forth in Section V, (a) CIBC will execute and deliver to the Trustee a replacement Letter of Credit, dated the Effective Date, in the stated maximum amount equal to $28,978,894 substantially in the form of Annex I (the "New Letter of Credit"); and (b) simultaneously therewith, the Trustee will surrender for cancellation to Westpac the Original Letter of Credit. SECTION 2.3 Consent to Assignment and Assumption; Release of Westpac. Subject to the terms and conditions hereof, including, without limitation, Section 2.2 and Section V, the Company hereby (a) consents to and approves the transactions contemplated by Sections 2.1, 2.2 and 2.4; and (b) agrees that, upon the Effective Date, Westpac shall be released from all its obligations under the Reimbursement Agreement other than those arising thereunder prior to the Effective Date; and (c) agrees that upon the Effective Date, Westpac shall be released from all its obligations under the Original Letter of Credit and that the Company shall cause the Trustee to surrender the Original Letter of Credit to Westpac on such date. SECTION 2.4 Reservation of Certain Rights. Notwithstanding Section 2.1 and Section 2.3, (a) Westpac does not sell, assign, convey or transfer to CIBC and reserves to itself any right of indemnification which runs to Westpac pursuant to the terms of the Reimbursement Agreement and (b) CIBC does not accept or assume, and shall not be bound by or liable in respect of, any claim, loss or liability of any person to the extent arising from any failure by Westpac to perform any of its obligations arising under the Reimbursement Agreement prior to the Effective Date or the Original Letter of Credit prior to its surrender by the Trustee pursuant to Section 2.3(c). SECTION III AMENDMENTS TO REIMBURSEMENT AGREEMENT SECTION 3.1 Amendments. Effective on and as of the Effective Date, the Reimbursement Agreement is hereby amended as follows: (a) Section 1.01 of the Reimbursement Agreement is amended as follows: (i) A definition of "Bank" is added in the appropriate alphabetical position reading as follows: "Bank" means Canadian Imperial Bank of Commerce acting through its New York Agency. (ii) The definition of "Disclosure Documents" is amended to read in its entirety as follows: "Disclosure Documents" means the following documents, each in the form distributed to the Bank prior to September 8, 1993: (a) The Company's Annual Report on Form 10-K for the year ended December 31, 1992. (b) The Company's Quarterly Reports on Form 10-Q for the quarters ended March 31, 1993 and June 30, 1993. (c) The Company's Current Reports on Form 8- K dated March 22, 1993, April 27, 1993, June 21, 1993, July 22, 1993 and August 23, 1993. (d) The Company's definitive Proxy Statement for its Annual Meeting of Shareholders Held May 6, 1993. (e) The Prospectus dated March 23, 1993 relating to the offering of $50,000,000 of the Company's First Mortgage Bonds, 6.75% Series A due 2003. (f) The Prospectus Supplement dated May 27, 1993 relating to the offering of 6,000,000 shares of the Company's $1.75 Dividend Preference Stock. (g) The Prospectus Supplement dated July 28, 1993 relating to the offering of $290,000,000 of the Company's First Mortgage Bonds, Medium Term Note Series, consisting of $170,000,000 6.41% Sub- series A due 2001 and $120,000,000 6.77% Sub- series B due 2005. (iii) The definitions of "Domestic Lending Office" and "Euro-Dollar Lending Office" are amended to read in their entirety as follows: "Domestic Lending Office" means the office of the Bank located at Two Paces West, 2727 Paces Ferry Road, Atlanta, Georgia 30339, or such other branch (or affiliate) as the Bank may hereafter designate as its Domestic Lending Office. "Euro-Dollar Lending Office" means the office of the Bank located at Two Paces West, 2727 Paces Ferry Road, Atlanta, Georgia 30339, or such other branch (or affiliate) as the Bank may hereafter designate as its Euro-Dollar Lending Office. (iv) The definition of "Fee Agreement" is deleted. (v) The definition of "Prime Rate" is amended to read in its entirety as follows: "Prime Rate" for any day shall mean the United States "Prime Rate" of the Bank as announced by the Bank from time to time (said rate to change on the date of each change of such prime rate). The Prime Rate is not necessarily intended to be the lowest rate of interest charged by the Bank in connection with extensions of credit. (b) Section 2.02 of the Reimbursement Agreement is deleted and the following is substituted in its place: SECTION 2.02 [Intentionally deleted.] (c) Section 2.03 of the Reimbursement Agreement is amended to read in its entirety as follows: SECTION 2.03 Commission. (a) The Company hereby agrees to pay to the Bank a letter of credit commission on the Commission Amount in effect from time to time from the date of issuance of the Letter of Credit to and including the Credit Termination Date, payable quarterly in arrears on the first day of October, 1993 and on the first day of each July, October, January and April thereafter until the Credit Termination Date, and on the Credit Termination Date, at the rate of 0.65% per annum (computed for actual days elapsed on the basis of a 360-day year). (b) The Company hereby agrees to pay to the Bank, upon each transfer of the Letter of Credit in accordance with its terms, the Banks then customary transfer fees. (c) The Company hereby agrees to pay to the Bank on the date of each draw under the Letter of Credit, a drawing fee in the amount of $100. (d) Section 2.05(d) of the Reimbursement Agreement is amended by deleting the phrase "to the Continental Illinois National Bank and Trust Company of Chicago, Illinois, for credit to the account of the Bank, Account No. 6012795" and substituting in its place the following "to the Domestic Lending Office of the Bank". (e) Section 4.01(e) and (o) of the Reimbursement Agreement are amended by replacing the date "December 31, 1984" with the date "December 31, 1992" wherever it occurs therein and by deleting from Section 4.01(o) of the Reimbursement Agreement the phrase "the parity obligation contained in Section 6.02 of the Debenture Indenture". (f) Section 4.01(i) of the Reimbursement Agreement is amended by substituting "1992 annual report" for "1984 annual report". (g) Section 4.01(k) of the Reimbursement Agreement is amended by replacing "and Gulf States Overseas Finance N.V." with "GSG & T Inc., and Southern Gulf Railway Company". (h) Section 7.02 of the Reimbursement Agreement is amended by deleting the address for the Bank therein and substituting the following therefor: "Two Paces West, 2727 Paces Ferry Road, Atlanta, Georgia 30339, telephone no. (404) 319-4836, facsimile no. (404) 319-4950, telex no. 54-2413 (Answerback: CANBANK ATL), Attention: Claire C. Coyne, Credit Operations, with a copy to: CIBC Inc., 200 West Madison Street, Suite 2300, Chicago, Illinois 60606, telephone no. (312) 855-3123, facsimile no. (312) 750-0927, Attention: Utilities Group". (i) The Reimbursement Agreement is further amended by deleting Exhibit A thereto in its entirety and substituting therefor a new Exhibit A in the form of Annex I to this Agreement. SECTION IV REPRESENTATIONS AND WARRANTIES SECTION 4.1 Representations and Warranties of the Company. The Company hereby represents and warrants that the execution, delivery and performance by the Company of this Agreement are within the Company's corporate powers, have been duly authorized by all necessary corporate action and do not contravene or conflict with any law, rule or regulation applicable to the Company or require any action by or any filing with any governmental or public body or authority or result in a breach of or constitute a default under its charter or by-laws or any agreement, indenture or instrument binding upon it including, without limitation, the Related Documents; this Agreement and the Reimbursement Agreement as amended hereby constitute the legal, valid and binding obligation of the Company enforceable against the Company in accordance with their respective terms except as enforceability may be limited by applicable reorganization, insolvency, liquidation, readjustment of debt, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general principles of equity; the representations and warranties set forth in Article IV of the Reimbursement Agreement as amended hereby are true and correct in all material respects as of the Effective Date; and no Event of Default or event which with the giving of notice or passage of time or both would become an Event of Default has occurred and is continuing. The Company further represents and warrants that, except as provided in the Reimbursement Agreement, the Company has not granted any collateral to CIBC to secure the Company's obligations under the Reimbursement Agreement and no other person has provided a guaranty or collateral with respect thereto. SECTION 4.2 Representations and Warranties of CIBC. (a) CIBC hereby represents and warrants that the execution and delivery by CIBC of this Agreement, the acceptance and assumption of the rights and obligations assigned hereunder, the issuance pursuant hereto of the New Letter of Credit and the performance by CIBC of its obligations under the Reimbursement Agreement are within its powers, have been duly authorized by all necessary action, if any, do not contravene or conflict with any law, rule or regulation applicable to CIBC or require any action by or filing with any governmental or public body or authority or result in a breach of or constitute a default under its charter or by-laws or any agreement, indenture or instrument binding upon it; this Agreement constitutes, and on the Effective Date, the Reimbursement Agreement, as amended hereby and the New Letter of Credit will constitute, the legal, valid and binding obligations of CIBC, enforceable against CIBC in accordance with their respective terms except as enforceability may be limited by applicable reorganization, insolvency, liquidation, readjustment of debt, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general principles of equity. (b) CIBC hereby represents and warrants that, except to the extent it has rights under the Reimbursement Agreement, it has not received any collateral from the Company to secure the Company's obligations under the Reimbursement Agreement and that no other person has guaranteed the obligations of the Company under the Reimbursement Agreement or provided collateral with respect thereto. (c) CIBC hereby confirms to Westpac that it has entered into this Agreement and the Reimbursement Agreement, as amended hereby, on the basis of its own credit evaluation of the Company and that Westpac has not made any representations or warranties to CIBC (other than as set forth in Section 4.3). SECTION 4.3 Representations and Warranties of Westpac. (a) Westpac hereby represents and warrants on and as of the date hereof and on as of the Effective Date that the execution, delivery and performance by Westpac of this Agreement are within its powers, have been duly authorized by all necessary action, if any, do not contravene or conflict with any law, rule or regulation applicable to Westpac or require any action by or filing with any governmental or public body or authority or result in a breach of or constitute a default under its charter or by-laws; this Agreement constitutes, and on the Effective Date will constitute, the legal, valid and binding obligation of Westpac, enforceable against Westpac in accordance with its terms except as enforceability may be limited by applicable reorganization, insolvency, liquidation, readjustment of debt, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general principles of equity. (b) Westpac represents and warrants that it owns all of the right, title and interest of the Bank under the Reimbursement Agreement free and clear of any adverse claims and that to the best of its knowledge, having made no independent investigation, no Event of Default or event which with the passage of time or giving of notice or both would become an Event of Default has occurred and is continuing. SECTION V CONDITIONS PRECEDENT SECTION 5.1 Conditions Precedent. The effectiveness of the transactions contemplated by Section II and the amendments provided in Section III of this Agreement shall be subject to the fulfillment of the following conditions precedent: (a) The Company, CIBC and Westpac as the case may be, shall have received counterparts of this Agreement executed by each of the other parties hereto. (b) CIBC shall have received: (i) the original executed Reimbursement Agreement, including, without limitation, all amendments thereto, certified as complete by the Company and Westpac; (ii) copies of all of the Related Documents (other than the Original Letter of Credit, the Bonds, the Fee Agreement and the Reimbursement Agreement), including, without limitation, all amendments thereto, certified as complete by the Company; (iii) a certificate of the Secretary or an Assistant Secretary of the Company as to authorizing resolutions of the Company's board of directors, the incumbency and signatures of officers and such other matters as the Bank may reasonably request; and (iv) an opinion of Orgain, Bell & Tucker, L.L.P., counsel for the Company, in substantially the form of Exhibit A hereto and as to such other matters as the Bank may reasonably request. (c) Westpac shall have received: (i) the Original Letter of Credit; and (ii) payment in full of all fees payable by the Company pursuant to Section 2.03 of the Reimbursement Agreement accrued through the Effective Date. (d) The Trustee shall have received: (i) an opinion of Mayer, Brown & Platt, counsel to CIBC, and an opinion of Canadian counsel to CIBC, as to the enforceability of the New Letter of Credit; (ii) an opinion of Foley & Judell, Bond Counsel, stating that the delivery of the New Letter of Credit to the Trustee is authorized under the Indenture and complies with the terms thereof; (iii) an opinion of Morgan, Lewis & Bockius as to certain bankruptcy law matters; (iv) written evidence from each of Moody's Investors Service Inc. and Standard & Poor's Corporation to the effect that such rating agency has reviewed the proposed New Letter of Credit and that the substitution of the proposed New Letter of Credit will not, by itself, result in either a withdrawal of its rating of the Bonds or the then current rating of the Bonds being reduced; and (v) the New Letter of Credit. SECTION VI MISCELLANEOUS SECTION 6.1 Effective Amendment; Ratification. Except as expressly amended and modified by this Agreement, the Reimbursement Agreement is and shall continue to be in full force and effect in accordance with the terms thereof and are hereby ratified and confirmed by the parties thereto. From and after the Effective Date (i) each reference to the Reimbursement Agreement in any other instrument or document shall be deemed to be a reference to the Reimbursement Agreement as amended hereby, (ii) the Reimbursement Agreement, as amended hereby shall be deemed to be the "Reimbursement Agreement" for purposes of the Indenture and (iii) CIBC shall be the "Bank" for purposes of the Indenture. SECTION 6.2 Change of Address for Notices. Each party hereto agrees that this Agreement shall constitute a change of address for purposes of notice to the Bank and/or the "Bank" (as defined in the Indenture) and that from and after the Effective Date notices to the Bank and/or the "Bank" shall be sent to the addresses set forth in Section 3.1(a), provided, however, that drawings under the New Letter of Credit shall be sent in accordance with the terms thereof. SECTION 6.3 Further Assurances. Each party hereto agrees that, from time to time, it will promptly execute and deliver all further instruments and documents, and take all further action, that may be necessary or desirable, as requested by any other party hereto, in order to implement the transactions contemplated hereby. SECTION 6.4 Binding Effect. This Agreement shall be binding upon and inure to the benefit of the parties hereto and the respective successors and assigns. SECTION 6.5 Counterparts. This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which when taken together shall constitute one and the same agreement. SECTION 6.6 Governing Law. This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of New York. IN WITNESS WHEREOF, the parties have caused this Agreement to be executed by the respective officers thereunto duly authorized as of the day first above written. GULF STATES UTILITIES COMPANY By: Its: CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY By: Its: WESTPAC BANKING CORPORATION By: Its: EX-12 8 AP&L RATIOS Exhibit 12(a) Arkansas Power and Light Company Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Fixed Charges and Preferred Dividends
Years Ended -------------------------------------------------------- December 31, 1989 1990 1991 1992 1993 -------------------------------------------------------- (In Thousands, Except for Ratios) Fixed charges, as defined: Interest on long-term debt $89,027 $101,412 $100,533 $ 89,317 $ 77,980 Interest on long-term debt - other 31,138 31,195 33,321 31,000 29,791 Interest on notes payable 828 1,027 --- 117 349 Amortization of expense and premium on debt-net(cr) 1,557 1,792 1,112 1,359 2,702 Other interest (6,295) 1,567 1,303 2,308 8,769 Interest applicable to rentals 22,349 24,233 21,969 17,657 16,860 -------------------------------------------------------- Total fixed charges, as defined 138,604 161,226 158,238 141,758 136,451 Preferred dividends, as defined (a) 31,298 30,851 31,458 32,195 30,334 -------------------------------------------------------- Fixed charges and preferred dividends, as defined $169,902 $192,077 $189,696 $173,953 $166,785 ======================================================== Earnings as defined: Net Income $131,979 $129,765 $143,451 $130,529 $205,297 Add: Provision for income taxes: Federal & State 8,440 50,921 44,418 57,089 58,162 Deferred - net 37,268 17,943 11,048 3,490 34,748 Investment tax credit adjustment - net 3,543 (12,022) (1,600) (9,989) (10,573) Fixed charges as above 138,604 161,226 158,238 141,758 136,451 -------------------------------------------------------- Total earnings, as defined $319,834 $347,833 $355,555 $322,877 $424,085 ======================================================== Ratio of earnings to fixed charges, as defined 2.31 2.16 2.25 2.28 3.11 ======================================================== Ratio of earnings to fixed charges and preferred dividends, as defined 1.88 1.81 1.87 1.86 2.54 ======================================================== - ------------------------ (a) "Preferred dividends," as defined by SEC regulation S-K, are computed by dividing the preferred dividend requirement by one hundred percent (100%) minus the income tax rate.
EX-12 9 GSU RATIOS Exhibit 12(b)
Gulf States Utilities Company Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Fixed Charges and Preferred and Preference Dividends Years Ended -------------------------------------------------------- December 31, 1989 1990 1991 1992 1993 -------------------------------------------------------- (In Thousands, Except for Ratios) Fixed charges, as defined: Interest on long-term debt $231,170 $218,462 $201,335 $197,218 $172,494 Interest on long-term debt - other 19,495 12,668 19,507 21,155 19,440 Interest on notes payable 33,185 24,295 8,446 - - Amortization of expense and premium on debt-net(cr) 2,280 2,192 1,999 3,479 8,104 Other interest 13,331 18,380 29,169 26,564 10,561 Interest applicable to rentals 23,244 23,761 24,049 23,759 23,455 -------------------------------------------------------- Total fixed charges, as defined 322,705 299,758 284,505 272,175 234,054 Preferred and preference dividends, as defined (a) 241,829 104,484 90,146 69,617 65,299 -------------------------------------------------------- Fixed charges and preferred and preference dividends, as defined $564,534 $404,242 $374,651 $341,792 $299,353 ======================================================== Earnings as defined: Net Income (loss) before extraordinary items and cumulative effect of accounting changes $ 13,251 $(36,399) $112,391 $139,413 $ 69,462 Add: Provision for income taxes: Federal & State 1,140 4,538 5,657 10,775 16,679 Deferred - net 41,028 (24,469) 46,901 47,285 40,244 Investment tax credit adjustment - net (4,424) (4,285) (4,308) (2,200) 1,093 Fixed charges as above 322,705 299,758 284,505 272,175 234,054 -------------------------------------------------------- Total earnings, as defined $373,700 $239,143 $445,146 $467,448 $361,532 ======================================================== Ratio of earnings to fixed charges, as defined 1.16 0.80 1.56 1.72 1.54 ======================================================== Ratio of earnings to fixed charges and preferred and preference dividends, as defined 0.66 0.59 1.19 1.37 1.21 ======================================================== - ------------------------ (a) "Preferred dividends," as defined by SEC regulation S-K, are computed by dividing the preferred dividend requirement by one hundred percent (100%) minus the income tax rate. (b) Earnings for the year ended December 31, 1990, for GSU were not adequate to cover fixed charges by $60.6 million. Earnings for the years December 31, 1990 and 1989, were not adequate to cover fixed charges and preferred and preference dividends by $165.1 million and $190.8 million, respectively. Earnings in 1990 include a $205 million charge for the settlement of a purchased power dispute.
EX-12 10 LP&L RATIOS Exhibit 12(c)
Louisiana Power and Light Company Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Fixed Charges and Preferred Dividends Years Ended ------------------------------------------------------ December 31, 1989 1990 1991 1992 1993 ------------------------------------------------------ (In Thousands, Except for Ratios) Fixed charges, as defined: Interest on mortgage bonds $155,640 $101,996 $ 97,324 $ 68,247 $ 60,939 Interest on long-term debt - other 25,400 52,361 61,492 60,425 63,694 Interest on notes payable --- 87 --- 150 898 Interest on lease (nuclear) 9,475 8,756 7,086 5,092 4,574 Other interest charges 11,300 6,378 5,924 5,591 5,706 Amortization of expense and premium on debt - net(cr) 2,260 3,397 3,282 7,100 5,720 Interest applicable to rentals 4,415 4,150 4,295 4,271 3,945 ------------------------------------------------------- Total fixed charges, as defined 208,490 177,125 179,403 150,876 145,476 Preferred dividends, as defined (a) 59,009 42,365 41,212 42,026 40,779 ------------------------------------------------------- Fixed charges and preferred dividends, as defined $267,499 $219,490 $220,615 $192,902 $186,255 ======================================================= Earnings as defined: Net Income $106,613 $155,049 $166,572 $182,989 $188,808 Add: Provision for income taxes: Federal and State 29,069 62,236 8,684 36,465 70,552 Deferred Federal and State - net 7,840 (9,655) 67,792 51,889 43,017 Investment tax credit adjustment - net 20,822 26,646 8,244 (1,317) (2,756) Fixed charges as above 208,490 177,125 179,403 150,876 145,476 ------------------------------------------------------- Total earnings, as defined $372,834 $411,401 $430,695 $420,902 $445,097 ======================================================= Ratio of earnings to fixed charges, as defined 1.79 2.32 2.40 2.79 3.06 ======================================================= Ratio of earnings to fixed charges and preferred dividends, as defined 1.39 1.87 1.95 2.18 2.39 ======================================================= - ------------------------ (a) "Preferred dividends," as defined by SEC regulation S-K, are computed by dividing the preferred dividend requirement by one hundred percent (100%) minus the income tax rate.
EX-12 11 MP&L RATIOS Exhibit 12(d)
Mississippi Power and Light Company Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Fixed Charges and Preferred Dividends Years Ended ----------------------------------------------- December 31, 1989 1990 1991 1992 1993 ----------------------------------------------- (In Thousands, Except for Ratios) Fixed charges, as defined: Interest on long-term debt $60,995 $ 59,675 $ 59,440 $ 56,646 $ 48,029 Interest on long-term debt - other 4,325 4,300 4,188 4,063 4,070 Interest on notes payable 1,031 1,512 953 36 7 Other interest charges 1,591 1,494 1,444 1,636 1,795 Amortization of expense and premium on debt-net(cr) 1,548 1,737 1,617 1,685 1,458 Interest applicable to rentals 533 596 574 521 1,264 ----------------------------------------------- Total fixed charges, as defined 70,023 69,314 68,216 64,587 56,623 Preferred dividends, as defined (a) 2,584 17,584 14,962 12,823 12,990 ----------------------------------------------- Fixed charges and preferred dividends, as defined $72,607 $ 86,898 $ 83,178 $ 77,410 $ 69,613 =============================================== Earnings as defined: Net Income $12,419 $ 60,830 $ 63,088 $ 65,036 $101,743 Add: Provision for income taxes: Federal and State 370 4,027 (1,001) 4,463 54,418 Deferred Federal and State - net (8,636) 35,721 32,491 20,430 539 Investment tax credit adjustment - net (1,523) (1,835) (1,634) (1,746) 1,036 Fixed charges as above 70,023 69,314 68,216 64,587 56,623 ----------------------------------------------- Total earnings, as defined $72,653 $168,057 $161,160 $152,770 $214,359 =============================================== Ratio of earnings to fixed charges, as defined 1.04 2.42 2.36 2.37 3.79 ============================================== Ratio of earnings to fixed charges and preferred dividends, as defined 1.00 1.93 1.94 1.97 3.08 ============================================== - ------------------------ (a) "Preferred dividends," as defined by SEC regulation S-K, are computed by dividing the preferred dividend requirement by one hundred percent (100%) minus the income tax rate. (b) Earnings for the twelve months ended December 31, 1989 include the impact of the write-off of $60 million of deferred Grand Gulf 1 - related costs pursuant to an agreement between MP&L and the MPSC.
EX-12 12 NOPSI RATIOS Exhibit 12(e)
New Orleans Public Service Inc. Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Fixed Charges and Preferred Dividends Years Ended ----------------------------------------------------- December 31, 1989 1990 1991 1992 1993 ----------------------------------------------------- (In Thousands, Except for Ratios) Fixed charges, as defined: Interest on mortgage bonds $24,472 $24,472 $23,865 $22,934 $19,478 Interest on notes payable --- --- --- -- -- Other interest charges 2,422 831 793 1,714 1,016 Amortization of expense and premium on debt-net(cr) 579 579 565 576 598 Interest applicable to rentals 603 160 517 444 544 ------------------------------------------------------ Total fixed charges, as defined 28,076 26,042 25,740 25,668 21,636 Preferred dividends, as defined (a) 4,633 4,020 3,582 3,214 2,952 ------------------------------------------------------ Fixed charges and preferred dividends, as defined $32,709 $30,062 $29,322 $28,882 $24,588 ====================================================== Earnings as defined: Net Income $14,464 $27,542 $74,699 $26,424 $47,709 Add: Provision for income taxes: Federal and State 848 134 8,885 16,575 27,479 Deferred Federal and State - net 9,296 17,370 36,947 (340) 5,203 Investment tax credit adjustment - net 444 (75) (591) (170) (744) Fixed charges as above 28,076 26,042 25,740 25,668 21,636 ------------------------------------------------------ Total earnings, as defined $53,128 $71,013 $145,680 $68,157 $101,283 ====================================================== Ratio of earnings to fixed charges, as defined 1.89 2.73 5.66 2.66 4.68 ====================================================== Ratio of earnings to fixed charges and preferred dividends, as defined 1.62 2.36 4.97 2.36 4.12 ====================================================== - ------------------------ (a) "Preferred dividends," as defined by SEC regulation S-K, are computed by dividing the preferred dividend requirement by one hundred percent (100%) minus the income tax rate. (b) Earnings for the twelve months ended December 31, 1991 include the $90 million effect of the 1991 NOPSI Settlement.
EX-12 13 SYSTEM ENERGY RATIOS Exhibit 12(f)
System Energy Resources, Inc. Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Fixed Charges and Preferred Dividends Years Ended -------------------------------------------------------- December 31, 1989 1990 1991 1992 1993 -------------------------------------------------------- (In Thousands, Except for Ratios) Fixed charges, as defined: Interest on mortgage bonds $148,402 $138,689 $126,351 $104,429 $ 91,472 Interest on other long-term debt 91,295 91,955 92,187 92,189 93,346 Interest on lease nuclear 18,298 13,830 10,007 6,265 6,790 Amortization of expense and premium on debt-net 7,326 10,532 7,495 6,417 4,520 Other interest charges 2,790 1,460 3,617 1,506 1,600 -------------------------------------------------------- Total fixed charges, as defined $268,111 $256,466 $239,657 $210,806 $197,728 ======================================================== Earnings as defined: Net Income $(655,524) $168,677 $104,622 $130,141 $ 93,927 Add: Provision for income taxes: Federal and State (168,440) 4,620 (26,848) 35,082 48,314 Deferred Federal and State - net 93,048 52,962 37,168 23,648 60,690 Investment tax credit adjustment - net (14,321) 56,320 63,256 30,123 (30,452) Fixed charges as above 268,111 256,466 239,657 210,806 197,728 --------------------------------------------------------- Total earnings, as defined $(477,126) $539,045 $417,855 $429,800 $370,207 ========================================================= Ratio of earnings to fixed charges, as defined (a) 2.10 1.74 2.04 1.87 ======================================================== - ------------------------ (a) Earnings for the twelve months ended December 31, 1989 were inadequate to cover fixed charges due to System Energy's cancellation and write-off of its investment in Grand Gulf 2 in September 1989. The amount of the coverage deficiency for fixed charges was $745.2 million.
EX-21 14 SUBSIDIARIES OF THE REGISTRANT Exhibit 21 The seven registrants, Entergy Corporation, System Energy Resources, Inc., Arkansas Power & Light Company, Gulf States Utilities Company, Louisiana Power & Light Company, Mississippi Power & Light Company and New Orleans Public Service Inc., and their active subsidiaries, are listed below: State or Other Jurisdiction of Incorporation Entergy Corporation Delaware System Energy Resources, Inc. (a) Arkansas Arkansas Power & Light Company (a) Arkansas The Arklahoma Corporation (b) Arkansas Gulf States Utilities Company (a) Texas Varibus Corporation (c) Texas GSG&T, Inc. (c) Texas Southern Gulf Railway Company (c) Texas Prudential Oil & Gas, Inc.(c) Texas Louisiana Power & Light Company (a) Louisiana Mississippi Power & Light Company (a) Mississippi New Orleans Public Service Inc. (a) Louisiana System Fuels, Inc.(d) Louisiana Entergy Services, Inc. (a) Delaware Entergy Power, Inc. (a) Delaware Entergy Operations, Inc. (a) Delaware Entergy Enterprises, Inc. (a) Louisiana Entergy, S.A. (a) Argentina Entergy Argentina, S.A. (a) Argentina Entergy Transener, S.A. (a) Argentina Entergy Power Development Corporation (a) Delaware Entergy Richmond Power Corporation (e) Delaware Entergy Systems and Service, Inc. (f) Delaware _______________________ (a) Entergy Corporation owns all of the Common Stock of System Energy Resources, Inc., Arkansas Power & Light Company, Gulf States Utilities Company, Louisiana Power & Light Company, Mississippi Power & Light Company, New Orleans Public Service Inc., Entergy Services, Inc., Entergy Power, Inc., Entergy Operations, Inc., Entergy Enterprises, Inc., Entergy, S.A., Entergy Argentina, S.A., Entergy Transener, S.A., and Entergy Power Development Corporation. (b) Arkansas Power & Light Company owns 34% of the Common Stock of The Arklahoma Corporation. (c) Gulf States Utilities Company owns all of the Common Stock of Varibus Corporation, GSG&T, Inc., Southern Gulf Railway Company, and Prudential Oil & Gas, Inc. (d) The capital stock of System Fuels, Inc. is owned in proportions of 35%, 33%, 19% and 13% by Arkansas Power & Light Company, Louisiana Power & Light Company, Mississippi Power & Light Company and New Orleans Public Service Inc., respectively. (e) Entergy Power Development Corporation owns all of the Common Stock of Entergy Richmond Power Corporation. (f) Entergy Enterprises, Inc. owns all of the Common Stock of Entergy Systems and Service, Inc. EX-24 15 POWER OF ATTORNEY Exhibit 24 DATE: January 28, 1994 TO: Lee W. Randall Laurence M. Hamric FROM: Edwin Lupberger, et. al. SUBJECT: Power of Attorney Entergy Corporation, Arkansas Power & Light Company, Gulf States Utilities Company, Louisiana Power & Light Company, Mississippi Power & Light Company, New Orleans Public Service Inc., and System Energy Resources, Inc., collectively referred to herein as the Companies, will file with the Securities and Exchange Commission their annual reports on Form 10-K for the year ended December 31, 1993 pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. The Companies and the undersigned, in their respective capacities as directors and/or officers of said Companies as specified in Attachment I, do each hereby make, constitute and appoint Lee W. Randall and Laurence M. Hamric, and each of them, their true and lawful Attorneys (with full power of substitution) for each of them and in their names, places and steads to sign and cause to be filed with the Securities and Exchange Commission the foregoing annual report on Form 10-K and any amendments thereto. The Companies and the undersigned, in their respective capacities as directors and/or officers of the respective Companies as per Attachment I, hereby authorize Lee W. Randall and Laurence M. Hamric to sign said Form 10-K on their behalf as attorney-in-fact and to amend, or remedy any deficiencies with respect to, said Form 10-K by appropriate amendments and to file the same as aforesaid. Yours very truly, /s/ Edwin Lupgerger /s/ Gerald D.McInvale Edwin Lupberger Gerald D. McInvale /s/ Robert H. Barrow /s/ Michael B. Bemis Robert H. Barrow Michael B. Bemis /s/ W. Frank Blount /s/ James M. Cain W. Frank Blount James M. Cain /s/ John A. Cooper, Jr. /s/ John J. Cordaro John A. Cooper, Jr. John J. Cordaro /s/ Cathy Cunningham /s/ Frank R. Day Cathy Cunningham Frank R. Day /s/ Brooke H. Duncan /s/ John O. Emmerich, Jr. Brooke H. Duncan John O. Emmerich, Jr. /s/ Lucie J. Fjeldstad /s/ Norman C. Francis Lucie J. Fjeldstad Norman C. Francis /s/ Frank F. Gallaher /s/ Norman B. Gillis, Jr. Frank F. Gallaher Norman B. Gillis, Jr. /s/ Frank W. Harrison, Jr. /s/ Richard P. Herget, Jr. Frank W. Harrison, Jr. Richard P. Herget, Jr. /s/ Tommy H. Hillman /s/ Donald C. Hintz Tommy H. Hillman Donald C. Hintz /s/ Kaneaster Hodges, Jr. /s/ William K. Hood Kaneaster Hodges, Jr. William K. Hood /s/ Jerry D. Jackson /s/ R. Drake Keith Jerry D. Jackson R. Drake Keith /s/ Robert E. Kennington, II /s/ Tex R. Kilpatrick Robert E. Kennington, II Tex R. Kilpatrick ________________________ /s/ Joseph J. Krebs, Jr. William F. Klausing Joseph J. Krebs, Jr. /s/ Robert v.d. Luft /s/ Jerry L. Maulden Robert v.d. Luft Jerry L. Maulden /s/ Kinnaird R. McKee /s/ Donald E. Meiners Kinnaird R. McKee Donald E. Meiners /s/ Raymond P. Miller, Sr. /s/ Anne M. Milling Raymond P. Miller, Sr. Anne M. Milling /s/ Roy L. Murphy /s/ Paul W. Murrill Roy L. Murphy Paul W. Murrill /s/ James R. Nichols /s/ William C. Nolan, Jr. James R. Nichols William C. Nolan, Jr. /s/ Eugene H. Owen /s/ John N. Palmer, Sr. Eugene H. Owen John N. Palmer, Sr. /s/ M. Bookman Peters /s/ Robert D. Pugh M. Bookman Peters Robert D. Pugh /s/ Lee W. Randall /s/ Monroe J. Rathbone, Jr. Lee W. Randall Monroe J. Rathbone, Jr. /s/ Clyda S. Rent ________________________ Clyda S. Rent E. B. Robinson, Jr. /s/ Sam F. Segnar /s/ H. Duke Shackelford Sam F. Segnar H. Duke Shackelford /s/ John B. Smallpage /s/ Wm. Clifford Smith John B. Smallpage Wm. Clifford Smith /s/ Bismark A. Steinhagen /s/ James E. Taussig, II Bismark A. Steinhagen James E. Taussig, II /s/ Charles C. Teamer, Sr. /s/ Woodson D. Walker Charles C. Teamer, Sr. Woodson D. Walker /s/ Gus B. Walton, Jr. /s/ Walter Washington Gus B. Walton, Jr. Walter Washington /s/ Robert M. Williams, Jr. /s/ Michael E. Wilson Robert M. Williams, Jr. Michael E. Wilson Entergy Corporation By: /s/ Edwin Lupberger Arkansas Power & Light Company By: /s/ Edwin Lupberger Gulf States Utilities Company By: /s/ Edwin Lupberger Louisiana Power & Light Company By: /s/ Edwin Lupberger Mississippi Power & Light Company By: /s/ Edwin Lupberger New Orleans Public Service Inc. By: /s/ Edwin Lupberger System Energy Resources, Inc. By: /s/ Donald C. Hintz Entergy Corporation Chairman of the Board, Chief Executive Officer and Director - - Edwin Lupberger Senior Vice President and Chief Financial Officer - Gerald D. McInvale Vice President and Chief Accounting Officer - Lee W. Randall Directors - W. Frank Blount, John A. Cooper, Jr., Brooke H. Duncan, Lucie J. Fjeldstad, Kaneaster Hodges, Jr., Robert v.d. Luft, Kinnaird R. McKee, Paul W. Murrill, James R. Nichols, Eugene H. Owen, John N. Palmer, Sr., Robert D. Pugh, H. Duke Shackelford, Wm. Clifford Smith, Bismark A. Steinhagen, Walter Washington. Arkansas Power & Light Company Chairman of the Board, Chief Executive Officer and Director - - Edwin Lupberger Senior Vice President and Chief Financial Officer - Gerald D. McInvale Vice President and Chief Accounting Officer - Lee W. Randall Directors - Michael B. Bemis, John A. Cooper, Jr., Cathy Cunningham, Richard P. Herget, Jr., Tommy H. Hillman, Donald C. Hintz, Kaneaster Hodges, Jr., Jerry D. Jackson, R. Drake Keith, Jerry L. Maulden, Raymond P. Miller, Sr., Roy L. Murphy, William C. Nolan, Jr., Robert D. Pugh, Woodson D. Walker, Gus B. Walton, Jr., Michael E. Wilson. Gulf States Utilities Company Chairman of the Board, Chief Executive Officer and Director - - Edwin Lupberger Senior Vice President and Chief Financial Officer - Gerald D. McInvale Vice President and Chief Accounting Officer - Lee W. Randall Directors - Robert H. Barrow, Frank F. Gallaher, Frank W. Harrison, Jr., Donald C. Hintz, William F. Klausing, Jerry L. Maulden, Paul W. Murrill, Eugene H. Owen, M. Bookman Peters, Monroe J. Rathbone, Jr., Sam F. Segnar, Bismark A. Steinhagen, James E. Taussig, II. Louisiana Power & Light Company Chairman of the Board, Chief Executive Officer and Director - - Edwin Lupberger Senior Vice President and Chief Financial Officer - Gerald D. McInvale Vice President and Chief Accounting Officer - Lee W. Randall Directors - Michael B. Bemis, John J. Cordaro, Donald C. Hintz, William K. Hood, Jerry D. Jackson, Tex R. Kilpatrick, Joseph J. Krebs, Jr., Jerry L. Maulden, H. Duke Shackelford, Wm. Clifford Smith. Mississippi Power & Light Company Chairman of the Board, Chief Executive Officer and Director - - Edwin Lupberger Senior Vice President and Chief Financial Officer - Gerald D. McInvale Vice President and Chief Accounting Officer - Lee W. Randall Directors - Michael B. Bemis, Frank R. Day, John O. Emmerich, Jr., Norman B. Gillis, Jr., Donald C. Hintz, Jerry D. Jackson, Robert E. Kennington, II, Jerry L. Maulden, Donald E. Meiners, John N. Palmer, Sr., Clyda S. Rent, E. B. Robinson, Jr., Walter Washington, Robert M. Williams, Jr. New Orleans Public Service Inc. Chairman of the Board, Chief Executive Officer and Director - - Edwin Lupberger Senior Vice President and Chief Financial Officer - Gerald D. McInvale Vice President and Chief Accounting Officer - Lee W. Randall Directors - Michael B. Bemis, James M. Cain, John J. Cordaro, Brooke H. Duncan, Norman C. Francis, Donald C. Hintz, Jerry D. Jackson, Jerry L. Maulden, Anne M. Milling, John B. Smallpage, Charles C. Teamer, Sr. System Energy Resources, Inc. President, Chief Executive Officer and Director - Donald C. Hintz Senior Vice President and Chief Financial Officer - Gerald D. McInvale Directors - Edwin Lupberger, Jerry D. Jackson, Jerry L. Maulden. EX-99 16 LETTER OF CLARK THOMAS & WINTERS Exhibit 99(a)3 [LETTERHEAD OF CLARK, THOMAS, WINTERS & NEWTON] March 9, 1994 Gulf States Utilities Company 639 Loyola Avenue New Orleans, LA 70112 Attn: Scott Forbes Re: SEC Form 10-K of Gulf States Utilities Company (the "Company") for the fiscal year ending December 31, 1993 Dear Mr. Forbes: Our firm has rendered to the Company two opinion letters dated September 30, 1992, concerning certain issues presented in the appeal of PUCT Docket No. 7195 now pending in the Texas Third District Court of Appeals. In connection with the above-referenced Form 10-K, we confirm to you as of the date hereof that we continue to hold the opinions set forth in those two letters.<1> CLARK, THOMAS & WINTERS A Professional Corporation /s/ Clark, Thomas & Winters, A Professional Corporation _______________________________ <1> The opinion letters dated September 30, 1992 indicate that the amount of River Bend plant costs held in abeyance was $1.45 billion. The more correct amount, as indicated by the Company in its securities filings to which those opinions related, is $1.4 billion. -----END PRIVACY-ENHANCED MESSAGE-----