10-K 1 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, 1994 OR 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 of Principal Executive Identification No. Offices and Telephone Number 1-11299 ENTERGY CORPORATION 13-5550175 (a Delaware corporation) 639 Loyola Avenue New Orleans, Louisiana 70113 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) 529-5262 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) 529-5262 1-9067 SYSTEM ENERGY RESOURCES, INC. 72-0752777 (an Arkansas corporation) Echelon One 1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 368-5000 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 - 227,410,827 New York Stock Exchange, Inc. Shares outstanding at February 28, 1995 Midwest Stock Exchange Incorporated Pacific Stock Exchange Incorporated Arkansas Power & Light Company $2.40 Preferred Stock, Cumulative, $0.01 Par Value New York Stock Exchange, Inc. ($25 Involuntary Liquidation Value) Gulf States Utilities Company Preferred Stock, Cumulative, $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 (Depository Receipts) New York Stock Exchange, Inc. Preference Stock, Cumulative, without Par Value New York Stock Exchange, Inc. $1.75 Dividend Series Louisiana Power & Light Company 9.68% Preferred Stock, Cumulative, $25 Par Value New York Stock Exchange, Inc. 12.64% Preferred Stock, Cumulative, $25 Par Value New York Stock Exchange, Inc.
Securities registered pursuant to Section 12(g) of the Act: Registrant Title of Class Arkansas Power & Light Company Preferred Stock, Cumulative, $100 Par Value Preferred Stock, Cumulative, $25 Par Value Preferred Stock, Cumulative, $0.01 Par Value Louisiana Power & Light Company Preferred Stock, Cumulative, $100 Par Value Preferred Stock, Cumulative, $25 Par Value Mississippi Power & Light Company Preferred Stock, Cumulative, $100 Par Value New Orleans Public Service Inc. Preferred Stock, Cumulative, $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 $5.1 billion based on the reported last sale price of such stock on the New York Stock Exchange on February 28, 1995. 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 26, 1995, are incorporated by reference into Part III hereof. TABLE OF CONTENTS Page Number Definitions i Part I Item 1. Business 1 Item 2. Properties 53 Item 3. Legal Proceedings 53 Item 4. Submission of Matters to a Vote of Security Holders 53 Part II Item 5. Market for Registrants' Common Equity and Related Stockholder Matters 54 Item 6. Selected Financial Data 55 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 55 Item 8. Financial Statements and Supplementary Data 56 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 341 Part III Item 10. Directors and Executive Officers of the Registrants 341 Item 11. Executive Compensation 350 Item 12. Security Ownership of Certain Beneficial Owners and Management 359 Item 13. Certain Relationships and Related Transactions 363 Part IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 364 Experts 365 Signatures 366 Consents of Experts 373 Reports of Independent Accountants on Financial Statement Schedules 380 Independent Auditors' Report on Financial Statement Schedules 381 Index to Financial Statement Schedules S-1 Exhibit Index E-1 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 Alliance for Affordable Energy, Inc. ANO Arkansas Nuclear One Steam Electric Generating Station (nuclear) 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 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 EPAct 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. 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 (nuclear) Grand Gulf 2 Unit No. 2 of the Grand Gulf Station (nuclear) 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 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 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. RUS Rural Utility Services (formerly the Rural Electrification Administration or "REA") 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, Entergy Corporation merged with and into Entergy-GSU Holdings, Inc., a Delaware corporation, which then changed its name to Entergy Corporation. Entergy Corporation is a holding company registered under the Holding Company Act and does not own or operate any significant 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, 1994, these operating companies provided electric service to approximately 2.4 million customers in the States of Arkansas, Louisiana, Mississippi, Tennessee and Texas. In addition, GSU furnished gas service in the Baton Rouge, Louisiana area, and NOPSI furnished gas service in the New Orleans, Louisiana area. GSU 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 1994, the System's electricity sales as a percentage of total System energy sales were: residential - 26.9%; commercial - 20.6%; and industrial - 42.1%. Electric revenues from these sectors as a percentage of total System electric revenues were: 36.3% - residential; 25.6% - commercial; and 31.3% - industrial. Sales to governmental and municipal sectors and to nonaffiliated utilities accounted for the balance of 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, a Delaware corporation, provides general executive, advisory, administrative, accounting, legal, engineering, and other services to the System companies, generally at cost. Entergy Operations, a Delaware corporation, 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, a Delaware corporation, is an independent power producer that 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 incorporated under Delaware law that investigates and develops energy-related projects and other businesses whose products and activities are or may be of benefit to the System's utility business (see "Corporate Development," below). Entergy Enterprises also markets outside the System technical expertise, products, and services developed by the System companies that have commercial value beyond their use in the System's operations and provides services to certain nonutility companies in the System. Entergy Corporation has formed subsidiaries 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 35%, 33%, 19%, and 13%, respectively, of all the common stock of System Fuels, a non-profit subsidiary incorporated in Louisiana 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. GSG&T, Inc. owns the Lewis Creek Station, a gas- fired generating plant, which is leased to and operated by GSU. Southern Gulf Railway Company owns and will 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, GSU became a wholly-owned subsidiary of Entergy Corporation. As consideration to GSU's shareholders, Entergy Corporation paid $250 million in cash and issued 56,695,724 shares of its common stock, based upon a valuation of $35.8417 per share, in exchange for outstanding shares of GSU common stock. 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. Unless otherwise noted, consolidated financial and statistical information contained in this report for the years ended December 31, 1994 and 1993 (such as assets, liabilities, and property) includes the associated GSU amounts. Consolidated financial and statistical information (such as revenues, sales, and expenses) for the year ended December 31, 1994 includes such GSU amounts, while periods ending before January 1, 1994 do 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); - adaptation to structural changes in the electric utility industry and changes in the regulation of generation and transmission of electricity (see "Competition - General" below); - continued cost management (particularly in the area of operation and maintenance costs at nuclear units) to improve financial results and to minimize or eliminate the need for rate increase requests and, to the extent possible, accommodate rate reductions while maintaining profitability (see "Rate Matters and Regulation - Rate Matters - Retail Rate Matters," below); - achieving cost savings anticipated with the Merger; - 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); - achieving enhanced earnings despite lower authorized returns and slow growth in the domestic utility business (see "Corporate Development," below); - 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), litigation with Cajun relating to its ownership interest in River Bend, and Cajun's bankruptcy proceedings (see "Rate Matters and Regulation - Regulation - Other Regulation and Litigation - GSU," below); and - the implementation of a proposed accounting standard that describes the circumstances in which assets are determined to be impaired, which may eventually be applied to stranded investments as discussed below. (see Entergy Corporation and Subsidiaries' "Management's Financial Discussion and Analysis - Significant Factors and Known Trends"). Corporate Development Entergy Corporation continues to consider opportunities to expand its utility and utility related businesses that are not regulated by state and local regulatory authorities (nonregulated businesses). Entergy Corporation's investment strategy is to invest in nonregulated business opportunities that have the potential to earn a greater rate of return than its regulated utility operations, and Entergy Corporation may invest up to approximately $150 million per year for the next several years in nonregulated businesses. Entergy Corporation's nonregulated businesses currently fall into two broad categories: power development and new technology related to the utility business. Entergy Corporation made investments in Argentina's and Pakistan's electric energy infrastructure, as described below, and is pursuing additional projects in North America, Central America, South America, Europe, and Asia. Entergy Corporation opened an office in Hong Kong in 1994 and expects to open offices in South America and Europe in 1995. Entergy Corporation is negotiating in China to participate in two power generation projects, Datong and Taishan, which are expected to receive final approval in 1995 or 1996. The Datong and Taishan projects involve the expansion of an existing coal- fired plant and construction of additional coal-fired plants. To date, Entergy Corporation has made no investment in these projects; however, Entergy Corporation's share of these projects may total approximately $115 million. In addition, Entergy Corporation is exploring the possibility to provide telecommunications services that allow customers to control energy usage. Current investments in nonregulated businesses include the following: (1) In 1990, Entergy Power purchased from AP&L 100% of Ritchie 2 and 31 1/2% of Independence 2. Entergy Power is currently selling capacity and energy from both plants. Entergy Corporation originally financed Entergy Power principally with a note between itself and Entergy Power. This note is scheduled to expire on June 30, 1995. As of December 31, 1994, this note amounted to $221.5 million. In 1994, Entergy Power requested, but has not yet received, authorization from the SEC to convert amounts outstanding under the note plus accrued interest to a capital contribution. (2) Entergy Corporation's subsidiary, Entergy Power Development Corporation an EWG under the provisions of the EPAct, through its subsidiary, Entergy Richmond Power Corporation (which is also an EWG), 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 (Enron), a developer of independent power projects. The plant has a 25-year contract to sell electricity to Virginia Electric & Power Company (VEPCO). Entergy Corporation's investment in the project totals approximately $13.5 million. Entergy Corporation has been notified by Enron that, prior to 1994, the facility did not met the FERC efficiency test to maintain qualifying facility status as required by the contract with VEPCO. Enron has indicated that the facility has met the test in 1994. The failure to meet the test prior to 1994 could result in a default under the VEPCO contract. However, Entergy Richmond Power Corporation, Enron, and VEPCO are currently involved in negotiations to amend the contract to resolve this issue. (3) Entergy Enterprises has a 7.9% equity interest in First Pacific Networks, Inc. (FPN), a communications company, and has 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 $11.8 million, of which $9.5 million is equity investment. (4) 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. Entergy SASI distributes such products in conjunction with providing various energy management services to its customers. Entergy SASI 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' investment in Entergy SASI is approximately $13.5 million of which $2.3 million is invested in SASI common stock. Entergy Corporation has provided to Entergy SASI $72.3 million in loans, as of December 31, 1994, to fund Entergy SASI's installment sale agreements with its customers. (5) 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 $10.5 million and its maximum financial obligation currently authorized by the SEC in connection with this investment is $22.5 million. (6) Entergy Corporation, through two subsidiaries, Entergy Argentina, S.A., and Entergy Argentina, S.A. Ltd., 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 $58.2 million and its maximum financial obligation currently authorized by the SEC in connection with this investment is $77.5 million. (7) Entergy Corporation, through its 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 Argentina. Entergy Corporation's initial investment in the project totals approximately $20.5 million. Depending upon the consortium's ability to continue its financing of a portion of its investment in the transmission system, Entergy Corporation could be required in 1995 to increase its investment by approximately $9 million. (8) In 1994, Entergy Corporation, through a new subsidiary, Entergy Pakistan, Ltd., acquired a 10% interest in the Hub River steam electric generating facility under development in Pakistan. Entergy Corporation's initial investment to acquire its 10% interest in the consortium was $50.2 million. In 1994, Entergy Corporation's nonregulated investments reduced consolidated net income by approximately $31.7 million. In the near term, these investments are unlikely to have a positive effect on Entergy Corporation's earnings; but management believes that these investments will contribute to future earnings growth. These investments may involve a higher degree of risk than domestic regulated utility enterprises. International operations are subject to the risks 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 1994 are summarized in the following tables: 1994 - Selected Customer Data Customers as of December 31, 1994 Area Served Electric Gas AP&L Portions of Arkansas 599,702 - GSU Portions of Texas and Louisiana 595,348 86,416 LP&L Portions of Louisiana 607,002 - MP&L Portions of Mississippi 367,692 - NOPSI City of New Orleans, except Algiers, which is provided electric service by LP&L 189,836 153,259 --------- ------- System 2,359,580 239,675 ========= ======= 1994 - Selected Electric Energy Sales Data
System Entergy AP&L GSU LP&L MP&L NOPSI Energy System (Millions of KWH) Electric Department: Sales to retail customers 15,841 28,763 29,064 10,480 5,396 - 89,544 Sales for resale: - Affiliates 10,428 2,676 10 1,079 92 8,653 - - Others 5,069 840 776 512 202 - 7,908 ------------------------------------------------------ Total 31,338 32,279 29,850 12,071 5,690 8,653 97,452 Steam Department: - Sales to steam products customer - 1,659 - - - - 1,659 ------------------------------------------------------ TOTAL 31,338 33,938 29,850 12,071 5,690 8,653 99,111 ====================================================== Average use per residential customer (KWH) 10,743 14,220 13,945 12,777 11,076 - 12,793 ======================================================
NOPSI sold 16,982,648 MCF of natural gas to retail customers in 1994. Revenues from natural gas operations for each of the three years in the period ended December 31, 1994 were material for NOPSI, but not material for the System (see "Industry Segments" below for a description of NOPSI's business segments). GSU sold 6,967,018 MCF of natural gas to retail customers in 1994. Revenues from natural gas operations for each of the three years in the period ended December 31, 1994 were not material for GSU. See "Entergy Corporation and Subsidiaries Selected Financial Data - Five-Year Comparison," and "Selected Financial Data - Five-Year Comparison of AP&L, GSU, LP&L, MP&L, NOPSI and System Energy," (which follow each company's notes to financial statements herein) for further information with respect to operating statistics. Employees As of December 31, 1994, Entergy had 16,037 employees as follows: Full-time: Entergy Corporation - AP&L 2,423 GSU 2,656 LP&L 1,539 MP&L 1,186 NOPSI 660 System Energy - Entergy Operations 4,313 Entergy Services 2,631 Other Subsidiaries 494 ------ Total Full-time 15,902 Part-time 135 ------ Total Entergy System 16,037 ====== Competition General. Entergy and the electric utility industry are experiencing increased competitive pressures in both the retail and wholesale markets. The economic, social, and political forces behind these competitive pressures are numerous and complex. These pressures include legislative and regulatory changes, technological advances, consumer demands, greater availability of natural gas, environmental needs, and other factors. These competitive pressures present opportunities to compete for new customers, as well as risks for loss of customers. On October 24, 1992, Congress passed the EPAct. The EPAct 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 EPAct creates exemptions from regulation under the Holding Company Act and creates a class of EWG's consisting of utility affiliates and nonutilities that own and operate facilities for the generation and transmission of power for sales at wholesale. The EPAct 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. This 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 System operating companies jointly filed open access transmission service tariffs with FERC, and subsequent modifications to such tariffs were filed in October 1994 in order to bring the companies into compliance with FERC's evolving "comparability" standard for transmission. For further information, see "Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters," below. Retail wheeling, 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 area of service, is also evolving. Over a dozen states have been or are studying the concept of retail competition. In April 1994, the state of Michigan initiated a five-year experiment that allows limited competition among public utilities. During the same month, the California Public Utilities Commission proposed to deregulate that state's electric power industry, starting on January 1, 1996, to allow the largest industrial customers to select the lowest cost supplier for electricity service. Under the proposal, by the year 2002, smaller companies and residential customers in California would also be able to buy power from any suppliers. The California Public Utilities Commission is currently reviewing its proposal and is expected to make a ruling in the first half of 1995. The retail market for electricity is expected to become more competitive with such moves toward deregulation. In some areas of the country, municipalities (or comparable entities) whose residents are served at retail by an investor-owned utility pursuant to a franchise are exploring the possibility of establishing new or extending existing distribution systems or seeking new delivery points in order to serve retail customers, especially large industrial customers, that currently receive service from an investor-owned utility. These options depend on the terms of a utility's franchise as well as on state law and regulation. In addition, FERC's authority to order utilities to transmit for a new or expanding municipal system is limited in certain respects. Where successful, however, the establishment of a municipal system or the acquisition by a municipal system of a utility's customers could result in the inability to recover costs that the utility has incurred in serving those customers. In mid-1994, FERC issued a notice of proposed rulemaking concerning a regulatory framework for dealing with recovery of stranded costs, such as high cost nuclear generating units, which may be incurred by electric utilities as a result of increased competition. In addition to addressing recovery of stranded costs related to wholesale service, the proposal requested comment as to recovery of retail stranded costs in transmission rates where state regulatory authorities failed to address the issue or were in conflict. Comments and reply comments have been filed, and the matter is pending. The risk of exposure to stranded costs which may result from competition in the industry will depend on the extent and timing of retail competition, the resolution of jurisdictional issues concerning stranded cost recovery, and the extent to which such costs are recovered from departing or remaining customers, among other matters. Wholesale Competition. Entergy, like other utility systems, has generating capacity and energy available from time to time for sale to other utility systems. Entergy Power owns 809 MW of generating capacity, and the first priority of use for this capacity is for wholesale sales. The System operating companies may use energy from Entergy Power's capacity for native load needs if no wholesale transactions have been scheduled. The System is in competition with other utilities to sell capacity and energy. Given this competition, the ability of the System to sell capacity and energy to other utilities is limited. However, in 1994, the System sold 7,908 million KWH of energy (compared to 8,291 million KWH in 1993) to nonaffiliated utilities. The System also sold 1,213 MW of long-term capacity (compared to 1,234 MW in 1993) to nonaffiliated utilities outside of the area served by the System. These capacity sales represent 6% of the System's net capability at year-end 1994. 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 have been 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 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. On July 12, 1994, the D.C. Circuit issued an opinion finding that FERC's failure to conduct an evidentiary hearing with respect to the proposed transmission tariffs and related matters was arbitrary and capricious, and that FERC failed to adequately explain its approval of certain provisions in the tariffs, including a provision allowing Entergy to seek recovery in transmission rates of "stranded investment" costs resulting from the provision of transmission service. The case was remanded to FERC for further proceedings. On October 31, 1994, Entergy Services filed revised transmission tariffs with FERC in response to the D.C. Circuit's remand. These tariffs provide both point-to-point and network transmission services and are intended to provide "comparability of service" over the Entergy transmission network. On January 6, 1995, FERC issued an order accepting the tariffs for filing and making them effective, subject to refund. On January 25, 1995, Entergy Services filed revised transmission tariffs in response to FERC's order. In addition, FERC set Entergy's market pricing authority for investigation, thereby making Entergy's market price rate schedules subject to refund. The market price rate investigation has been deferred by FERC until conclusion of the transmission tariff case, and an order is expected to be issued no later than January 15, 1997. 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 by 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 was formed to compete with other utilities and independent power producers in the bulk power market. As of December 31, 1994, Entergy Power has accumulated total losses from operations of $67.1 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. In 1994, Entergy Power sold 460 million KWH of energy to nonaffiliated utilities, and sold 332 MW of capacity, at the time of the Entergy system peak, to nonaffiliated utilities. Entergy Power actively markets its capacity and energy in the bulk power market. The System operating companies and Entergy Power have separate marketing staffs and may on occasion compete for the same bulk power sale opportunities. (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. Many of Entergy's industrial customers, whose costs of production are energy-sensitive, have energy alternatives such as fuel switching, cogeneration, and production shifting. Entergy is constantly working with these customers to address their needs. 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 flexible pricing 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, there can be no assurance that they will be successful or that future revenues will not be lost to other forms of generation. Since PURPA was enacted in 1978, the System operating companies have been largely successful in retaining industrial load. This competitive challenge will likely increase. Cogeneration is generally defined as the combined production of electricity and some other useful form of heat, typically steam. Cogenerated power may be either sold by its producer to the local utility at its avoided cost under PURPA, and/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 the GSU area of service. Since PURPA was enacted in 1978, 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 and/or customers that have an attractive electrical thermal ratio. Presently, the loss of load to cogeneration and the amount of cogenerated power delivered under PURPA to the System are not significant, except in GSU's area of service. 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 GSU's area of service are estimated to total approximately 2,400 MWs or over 10% of Entergy's total owned and leased generating capability as of December 31, 1994. GSU believes that no significant load will be lost to cogeneration projects during the next several years; however, GSU is currently negotiating with a large industrial customer whose contract is scheduled to expire in 1997. If the contract is not renewed, GSU would lose approximately $40 million in annual base revenues. Although GSU has competed in the past for various retail and wholesale customers, the System is not otherwise generally in direct competition with privately-owned or municipally-owned electric utilities for retail sales. A few municipalities within the area of service of the System operating companies distribute electricity within their corporate limits and some of these municipalities 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 operating companies. Sales of energy by the System to privately- or municipally-owned utilities amounted to approximately 3.3% of total System energy sales in 1994. As noted above, municipalities in other areas of the country are seeking to expand their customers bases, to find alternate sources of electricity, and/or to set up new distribution systems. Legislatures and regulatory commissions in several states have considered, or are considering, retail wheeling. Retail wheeling would permit retail customers to purchase electric capacity and/or energy from the electric utility in whose area of service they are located or from other electric utilities or independent power producers. Retail wheeling is not currently required within the Entergy System's area of service. 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 resulting 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 refined action plan with its respective regulator. Each Least Cost Plan detailed the resources that the System intended to use to provide reasonably priced, reliable electric service to its customers over the next 20 years. Such plans included 925 MW of DSM resources, such as programs for efficient air conditioning and heating, high efficiency lighting, and CCLM. The plans also included significant resource additions, but did not contemplate construction of any new generating facilities. All incremental supply-side resources would come from either delayed retirements or repowering of existing generating units. Each Least Cost Plan included specific actions that the System would undertake pursuant to regulatory approval, including the recovery of costs associated with DSM. In 1994, the System substantially revised the approach to least cost planning that was used to prepare the above December 1, 1992 and July 1, 1993 filings made with the APSC, LPSC, MPSC, and the Council. At MP&L's request, the MPSC dismissed MP&L's Least Cost Plan filing without prejudice. AP&L and LP&L have requested that their respective retail regulators allow the withdrawal of their Least Cost Plans. Furthermore, AP&L, LP&L, MP&L, and NOPSI have requested that their retail regulators allow for significant changes in the integrated planning process and filings. The System remains committed to employing integrated resource planning tools. However, the increasingly competitive nature of the market place for electric services mandates changes in the planning process. First, the System has indicated that it intends to use the Ratepayer Impact Measure (RIM) as the screening criterion for all DSM programs, including those DSM measures targeted at strategic load growth. This criterion was adopted because programs selected under this screen will minimize the rate impacts of any programs on all customers. Second, the System has indicated that it will not seek special rate treatment, such as rate riders, for the costs of programs or to compensate for lost revenues as a result of DSM for programs selected using the RIM criterion. Finally, the System has indicated that it will file with the retail regulators, for informational purposes only, a revised integrated resource plan in the fourth quarter of 1995 (for further information, see "Rate Matters and Regulation - Rate Matters - Retail Rate Matters," below). CAPITAL REQUIREMENTS AND FUTURE FINANCING Construction expenditures by company (including environmental expenditures, which are immaterial, and AFUDC, but excluding nuclear fuel) for the period 1995-1997 are estimated as follows: 1995 1996 1997 Total (In Millions) AP&L $155 $155 $155 $ 465 GSU 177 177 177 531 LP&L 115 115 115 345 MP&L 68 68 68 204 NOPSI 29 29 29 87 System Energy 22 22 19 63 Entergy Power 2 2 2 6 ---- ---- ---- ------ System $568 $568 $565 $1,701 ==== ==== ==== ====== No significant construction 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. In addition to construction expenditure requirements, the estimated amounts required during 1995-1997 to meet scheduled long- term debt and preferred stock maturities and cash sinking fund requirements are: AP&L - $107 million; GSU - $375 million; LP&L - $160 million; MP&L - $253 million; NOPSI - $93 million; and System Energy - $365 million. A substantial portion of these 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 order to achieve cost savings. Entergy Corporation's current primary capital requirements are to invest periodically in, or make loans to, its subsidiaries. Entergy Corporation has SEC authorization to make additional investments in Entergy Power, Entergy S.A., and Entergy Argentina, S.A., and has applied for authorization to make additional investments in Entergy SASI and Entergy Enterprises. Entergy Corporation expects to meet these capital requirements in 1995-1997 with internally generated funds and cash on hand. Entergy receives funds through dividend distributions 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," 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 may invest up to approximately $150 million per year over the next several years in nonregulated business opportunities. Entergy Corporation expects to fund these investments using internally generated funds and cash on hand Also, Entergy Corporation may repurchase, from time to time, shares of its outstanding common stock. Market conditions and board authorization determine the amount of repurchases. Entergy Corporation has requested, but has not yet received, SEC authorization for a $300 million bank line of credit, the proceeds of which may be used for common stock repurchases and other investment activities. In addition, Entergy Corporation's non-regulated businesses may seek external financing, subject to receipt of any necessary regulatory approval. (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." 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.") 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 interests in Grand Gulf 1 (and the costs related thereto) to AP&L (36%), LP&L (14%), MP&L (33%), and NOPSI (17%), respectively. 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 the Availability Agreement were terminated, or if any of the parties thereto withdrew from it, then System Energy would enter into a separate agreement with all 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 the Availability 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 obligations 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 must make those payments directly to the holders of indebtedness secured by such assignment agreements. The payments must 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 the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to FERC for approval with respect to the terms of such sale. No filing with FERC has been made because sales of capacity and energy from the Grand Gulf Station are being made pursuant to 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, whose 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) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments. The amount, if any, that these companies would become liable to pay or advance, over and above amounts they would pay under the Unit Power Sales Agreement for capacity and energy from Grand Gulf 1, would depend on a variety of factors, including, but not limited to, the amount 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 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 among 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. This 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 below under "Sale and Leaseback Arrangements - System Energy" . 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 must make those payments directly to the holders of indebtedness secured by the supplemental agreements. The payments (other than the Specific Payments) must 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 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. LP&L did 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. As a result, LP&L was required to provide collateral to the owner participants for the equity portion of certain amounts payable by LP&L under the lease. Such collateral was in the form of a new series of first mortgage bonds in the aggregate principal amount of $208.2 million issued by LP&L in September 1994 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." ) System Energy. On December 28, 1988, System Energy entered into arrangements for the sale and leaseback of an approximate aggregate 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 (Reimbursement Agreement), 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, in June 1994, System Energy, AP&L, LP&L, MP&L, and NOPSI reached a settlement with the FERC staff and other parties. On November 30, 1994, FERC approved the settlement. In accordance with the settlement, System Energy refunded approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI, which in turn have made or will make refunds or credits to their customers (except for those portions attributable to AP&L's and LP&L's retained share of Grand Gulf 1 costs). Additionally, System Energy will refund a total of approximately $62 million, plus interest, to AP&L, LP&L, MP&L, and NOPSI over the period through June 2004. AP&L, LP&L MP&L, and NOPSI also wrote-off certain related unamortized balances of deferred tax credits. As a result of the charges associated with the settlement, System Energy obtained the consent of certain banks (parties to the Reimbursement Agreement) to waive the fixed charge coverage covenant in the letters of credit and the Reimbursement Agreement related to the Grand Gulf 1 sale and leaseback transaction, until November 30, 1995. System Energy expects that upon expiration of the waiver period, it will be in compliance with the fixed charge coverage covenant. Absent a waiver, failure by System Energy to perform this covenant 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 effects of the settlement on System Energy's financial condition, see Note 2 of System Energy's Notes to Financial Statements, "Rate and Regulatory Matters - FERC Audit," 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." ) 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. In November 1994, FERC approved an agreement settling a long- standing dispute involving income tax allocation procedures of System Energy. In accordance with the agreement, System Energy refunded approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI, which in turn have made or will make refunds or credits to their customers (except for those portions attributable to AP&L's and LP&L's retained share of Grand Gulf 1 costs). Additionally, System Energy will refund a total of approximately $62 million, plus interest, to AP&L, LP&L, MP&L, and NOPSI over the period through June 2004. The settlement also required the write-off of certain related unamortized balances of deferred investment tax credits by AP&L, LP&L, MP&L, and NOPSI. The settlement reduced Entergy Corporation's consolidated net income for the year ended December 31, 1994, by approximately $68.2 million, offset by the write-off of the unamortized balances of related deferred investment tax credits of approximately $69.4 million ($2.9 million for Entergy Corporation; $27.3 million for AP&L; $31.5 million for LP&L; $6 million for MP&L; and $1.7 million for NOPSI). System Energy also reclassified from utility plant to other deferred debits approximately $81 million of other Grand Gulf 1 costs. Although excluded from rate base, System Energy will be permitted to recover such costs over a 10-year period. Interest on the $62 million refund and the loss of the return on the $81 million of other Grand Gulf 1 costs will reduce Entergy's and System Energy's net income by approximately $10 million annually over the next 10 years. For further information, 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 Settlement." 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. The matter is pending before the SEC on remand. 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, and GSU now participates in this System-wide coordination. 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 AP&L, LP&L, MP&L, and NOPSI 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 acquire Cajun's 30% share in River Bend. See "Regulation - Other Regulation and Litigation," for information on appeals of FERC Merger orders and related pending rate schedule changes. In the December 15, 1993, order approving the Merger, FERC also initiated a new proceeding to consider whether the System Agreement permits certain out-of-service generating units to be included in reserve equalization calculations under Service Schedule MSS-1 of that agreement. FERC established March 8, 1994, as the refund effective date. On February 16, 1994, Entergy Corporation filed an Offer of Settlement to amend the System Agreement prospectively to make it explicit that certain out-of-service generating units may be included in reserve equalization calculations under Service Schedule MSS-1. The LPSC and MPSC contested certain provisions in the proposal, and also argued that LP&L and MP&L were entitled to refunds for MSS-1 payments made in the past. Subsequently, the LPSC and MPSC submitted testimony based on estimates, seeking refunds estimated at $22.6 million and $13.2 million, respectively. On March 31, 1994, the ALJ limited the scope of the hearing to exclude any claims for retroactive refunds. On April 5, 1994, the LPSC, Mississippi Attorney General (MAG), and MPSC filed a complaint with FERC claiming that Entergy's past reserve equalization charges under System Agreement Schedule MSS- 1 violated the System Agreement, sought refunds and requested FERC to hold a hearing to consider this claim. Responses by Entergy Corporation and other parties were filed on April 26, 1994. On June 17, 1994, FERC issued an order that clarified the scope of the proceeding to include a review of whether refunds are due for periods prior to the refund effective date. The FERC staff submitted testimony concluding that although Entergy's treatment was reasonable, because it violated the tariff, refunds of approximately $7.2 million should be ordered. Entergy submitted testimony on September 23, 1994, describing the potential impacts (not including interest) on Service Schedule MSS-1 calculations if extended reserve shutdown units were not included in the MSS-1 calculations during the period 1987 through 1993. Under such a theory, LP&L and MP&L would have been overbilled by $10.6 and $8.8 million, respectively, and AP&L and NOPSI would have been underbilled by $6.3 and $13.1 million, respectively. The amounts potentially subject to refund will continue to accrue while the case is pending. Entergy believes that its calculation of MSS-1 charges has been and will continue to be, in compliance with the System Agreement, and that no refunds are due. An initial decision is expected in March 1995. 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, 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 the FERC ALJ 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 each filed a request for rehearing of this order, which was denied by FERC on February 28, 1994. The Entergy parties and the City each filed an appeal of the FERC's orders with the D.C. Circuit. Various parties have intervened. If FERC's decision were reversed and any refunds were ordered, they would be retroactive to October 19, 1990. On March 15, 1995, the LPSC filed a complaint with FERC alleging that the System Agreement results in unjust and unreasonable rates and requested that FERC order a hearing on this matter. The LPSC contends that the failure of the System Agreement to exclude curtailable load from the determination of a System operating company's responsibility for reserve equalization and transmission equalization costs results in an unjust and unreasonable cost allocation to the companies that do not cause these costs to be incurred, and also results in cross- subsidization among the System operating companies. Further, the LPSC alleges that the mechanism by which the System operating companies purchase energy under the System Agreement results in unjust and unreasonable rates because it does not permit companies that engage in real time pricing to be charged the marginal cost of the energy generated for the real time pricing customer. The System is currently evaluating the merits of the LPSC's complaint. 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 were 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. On July 12, 1994, the D.C. Circuit issued an opinion finding that FERC's failure to conduct an evidentiary hearing with respect to the proposed transmission tariffs and related matters was arbitrary and capricious, and that FERC failed to adequately explain its approval of certain provisions in the tariffs, including a provision allowing Entergy to seek recovery in transmission rates of "stranded investment" costs resulting from the provision of transmission service. The case was remanded to FERC for further proceedings. On October 31, 1994, Entergy Services filed revised transmission tariffs with FERC in response to the D.C. Circuit's remand. These tariffs provide both point-to-point and network transmission services and are intended to provide "comparability of service" over the Entergy transmission network. On January 6, 1995, FERC issued an order accepting the tariffs for filing and making them effective, subject to refund. On January 25, 1995, Entergy Services filed revised transmission tariffs in response to FERC's order. In addition, FERC set Entergy's market pricing authority for investigation, thereby making Entergy's market price rate schedules subject to refund. The market price rate investigation has been deferred by FERC until conclusion of the transmission tariff case, and an order is expected to be issued no later than January 15, 1997. Wholesale Contract. In March 1994, North Little Rock, Arkansas, awarded AP&L a wholesale power contract that will provide estimated revenues of $347 million over 11 years. Under the contract, the price per KWH was reduced 18%, with increases in price through the year 2004. AP&L, which has been serving North Little Rock for over 40 years, was awarded the contract after intense bidding with several competitors. On May 22, 1994, FERC accepted the contract. Rehearings were requested by one of AP&L's competitors and were held in February 1995. The matter is 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 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. Rate proceedings and appeals relating to these issues are ongoing (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. Also, NOPSI reached a settlement with the Council to reduce electric and gas rates and issue credits and refunds to customers. For further information, see "NOPSI" below. The retail regulatory philosophy is shifting in some jurisdictions from traditional cost of service regulation to incentive rate regulation. Incentive and performance-based rate plans encourage efficiencies and productivity while permitting utilities and their customers to share in the results. MP&L implemented an incentive rate plan in 1994 and LP&L filed a performance-based formula rate plan with the LPSC in August 1994. For further information, see "LP&L" and "MP&L" below. 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 remains committed to employing integrated resource planning to minimize the cost of future sources of energy. 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 for, among other things, increases associated with the 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 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, l994, the balance of deferred uncollected costs was $474.1 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. However, in response to an increasingly competitive electric utility environment AP&L filed a motion on July 1, 1994, requesting that the APSC approve the withdrawal of the December 1, 1992, and July 1, 1993, filings and rescind its directive that AP&L file another Least Cost Plan in March 1995. AP&L will file, for informational purposes only, a revised Least Cost Plan in the fourth quarter of 1995. In this plan, AP&L intends to adopt the RIM as the screening criterion for DSM programs including those DSM measures targeted at strategic load growth. This is in place of the total resource cost test that had been used in developing the initial Least Cost Plan. This criterion was adopted because programs selected under this screen will minimize the rate impact of any programs on all customers. AP&L has indicated that it will not seek special rate treatment, such as rate riders, for the cost of programs or loss of revenues due to DSM programs selected using the RIM criterion. On October 5, 1994, the APSC issued an order that suspended the initial Least Cost Plan dockets and established a new docket to consider the need for integrated resource planning standards as required by the EPAct. Hearings are scheduled to begin in April 1995. 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. In 1993, 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 future regulatory filings in November 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. 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 ending in the year 2009, 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, 1994, the unamortized balance of these costs was $321 million. Further, GSU deferred approximately $400.4 million of similar costs pursuant to a 1986 LPSC accounting order. These costs, of which approximately $122 million are unamortized as of December 31, 1994, are being amortized over a 10-year period ending in 1997. In accordance with a phase-in plan approved by the LPSC, GSU deferred $294 million of its River Bend costs related to the period February 1988 through February 1991. GSU has amortized $129 million through December 31, 1994, and the remainder of $165 million will be recovered over approximately 3.2 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 prudence, 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 prudence 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 a Texas 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. The Texas Supreme Court's decision stated that all issues relating to the merits of the original PUCT order, including the prudence of all River Bend-related costs, should be addressed in the Rate Appeal. In October 1991, the Texas 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. The court further stated that the PUCT had 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 1994, the Texas Third District Court of Appeals (the Appellate Court) affirmed the district court's decision that there was substantial evidence to support the PUCT's 1988 decision not to include the abeyed construction costs in GSU's rate base. While acknowledging that the PUCT had exceeded its authority when it attempted to defer a decision on the inclusion of those costs in rate base in order to allow GSU a further opportunity to demonstrate the prudence of those costs in a subsequent proceeding, the Appellate Court found that GSU had suffered no harm or lack of due process as a result of the PUCT's error. Accordingly, the Appellate Court held that the PUCT's action had the effect of disallowing the company-wide $1.4 billion of River Bend construction costs for ratemaking purposes. In its August 1994 opinion, the Appellate Court also held that GSU's deferred operating and maintenance costs associated with the allowed portion of River Bend should be included in rate base and that GSU's deferred River Bend carrying costs included in the Allowed Deferrals should also be included in rate base. The Appellate Court's August 1994 opinion affirmed the PUCT's original order in this case. The Appellate Court's August 1994 opinion was entered by two judges, with a third judge dissenting. The dissenting opinion states that the result of the majority opinion is, among other things, to deprive GSU of due process at the PUCT because the PUCT never reached a finding on the $1.4 billion of construction costs. In October 1994, the Appellate Court denied GSU's motion for rehearing on the August 1994 opinion as to the $1.4 billion in River Bend construction costs and other matters. GSU appealed the Appellate Court's decision to the Texas Supreme Court, where it is pending. As of December 31, 1994, the River Bend plant costs disallowed for retail ratemaking purposes in Texas, the River Bend plant costs held in abeyance, and the related operating and carrying cost deferrals totaled (net of taxes) approximately $13 million, $280 million (both net of depreciation), and $170 million, respectively. Allowed Deferrals were approximately $107 million, net of taxes and amortization, as of December 31, 1994. GSU estimates it has collected approximately $158 million of revenues as of December 31, 1994, as a result of the originally ordered rate treatment by the PUCT of these deferred costs. If recovery of the Allowed Deferrals is not upheld, future revenues based upon those allowed deferrals could also be lost, and no assurance can be given as to whether or not refunds of revenue received based upon such deferred costs previously recorded will be required. 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 or reserves 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, 1994, of up to $293 million could be required based on an ultimate adverse ruling by the PUCT on the abeyed and disallowed costs. 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 two 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 reasonably possible that the Allowed Deferrals will continue to be recovered in rates. Management also 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 deferred costs related to the $1.4 billion of abeyed River Bend plant costs will be recovered in rates to the extent that the $1.4 billion of abeyed River Bend plant is recovered. However, a net of tax write-off of the $170 million of deferred costs related to the $1.4 billion of abeyed River Bend plant costs would be required if they are not allowed to be recovered in rates. Texas Fuel Cost Review. ( December 1, 1986 - September 30, 1991) In January 1992, GSU applied to 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 concluding 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 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. In that proceeding, the PUCT also set GSU's fixed fuel factor in Texas at 1.84 cents per KWH in response to GSU's request that the factor be set at 2.02 cents per KWH. In October 1993, GSU appealed the PUCT's order to the Travis County District Court where the matter is still pending. No assurance can be given as to the timing or outcome of that appeal. In a subsequent proceeding to review GSU's fuel factor, the PUCT approved GSU's request to further reduce its fixed fuel factor in Texas to 1.78 cents per KWH from 1.84 cents per KWH. Texas Fuel Cost Review. (October 1, 1991 - December 31, 1993) On January 9, 1995, GSU and various parties reached an agreement for the reconciliation of over- and under-recovery of fuel and purchased power expenses for the period October 1, 1991, through December 31, 1993. While the settlement still requires PUCT approval, GSU believes it will ultimately be approved and has accordingly recorded a reserve of $7.6 million. Filings with the PUCT and Texas Cities. In March 1994, the Texas Office of Public Utility Counsel and certain cities served by GSU instituted an investigation of the reasonableness of GSU's rates. In June 1994, GSU provided the cities with information that GSU believed supported the current rate level. GSU filed the same information with the PUCT in June 1994, pursuant to provisions of the Merger. In September 1994, certain cities adopted ordinances directing GSU to reduce its Texas retail rates by $45.9 million. GSU appealed the cities' ordinances to the PUCT for a determination of reasonableness of GSU's rates. In November 1994, those cities that intervened in the PUCT appeal filed testimony with the PUCT supporting a $118 million base rate reduction in lieu of the previously proposed $45.9 million reduction. In November 1994, the PUCT staff filed testimony that supported a $38.2 million base rate reduction. GSU filed information with the PUCT that it believed supported the current level of rates. Hearings were held in December 1994 and on March 20, 1995, the PUCT ordered a $72.9 million annual base rate reduction for the period March 31, 1994, through September 1, 1994, decreasing to an annual base rate reduction of $52.9 million after September 1, 1994. In accordance with the Merger agreement, the rate reduction is applied retroactively to March 31, 1994. As a result, GSU recorded a $57 million reserve for rate refund in 1994 which reduced net income after tax by $41.6 million. The rate reduction is being appealed and no assurance can be given as to the timing or outcome of the appeal. Texas Cities Rate Settlement - 1993. 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 provided 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 effective September 1994. Pursuant to the settlement, GSU reduced rates with a $20 million one-time bill credit in December 1993, and refunded approximately $3 million to Texas retail customers on bills rendered in December 1993. The PUCT approved the settlement agreement on July 21, 1994. The cities' rate inquiries were settled earlier on the same terms. LPSC Rate Review Order - 1994. In May 1994, GSU made the required first post-Merger earnings analysis filing with the LPSC. On December 14, 1994, the LPSC ordered a $12.7 million annual rate reduction for GSU effective January 1995. The rate order included, among other things, a reduction in GSU's Louisiana jurisdictional authorized return on equity from 12.75% to 10.95% and the amortization for the benefit of the customers of $8.3 million of previously deferred unbilled revenue, representing one-half of the total resulting from a change in accounting discussed in Note 1 of Entergy Corporation and Subsidiaries' Notes to Consolidated Financial Statements. On December 28, 1994, GSU received a preliminary injunction from the 19th Judicial District Court regarding $8.3 million of the reduction. On January 1, 1995, GSU reduced rates by $4.4 million. The entire $12.7 million reduction is being appealed and no assurance can be given as to the timing or outcome of the appeal. LPSC Fuel Cost Review. In November 1993, the LPSC ordered a review of GSU's fuel costs for the period October 1988 through September 1991 (Phase 1) based on the number of outages at River Bend and the findings in the June 1993 PUCT fuel reconciliation case. In July 1994, the LPSC ruled in the Phase 1 fuel review case and ordered GSU to refund approximately $27 million to its customers. Under the order, a refund of $13.1 million, which was not contested under a Louisiana Supreme Court decision as discussed below, was made through a billing credit on August 1994 bills. In August 1994, GSU appealed the remaining portion of the LPSC ordered refund to the district court. GSU has made no reserve for the remaining portion, pending outcome of the district court appeal, and no assurance can be given as to the timing or outcome of the appeal. On January 18, 1995, GSU met with the Special Counsel of the LPSC to discuss the procedural schedule for the upcoming fuel review (Phase II). The period under investigation was determined to be from October 1991 to December 1994. Hearings are scheduled to begin in July 1995. In February 1990, the LPSC disallowed the pass-through to ratepayers for the portion of GSU's cost to purchase power from NISCO representing the excess of NISCO's purchase price of the units over GSU's depreciated cost of the units. GSU appealed the 1990 order. In March 1994, the Louisiana Supreme Court ruled in favor of the LPSC. GSU recorded an estimated refund provision of $13.1 million, before related income taxes of $5.3 million. 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. GSU intends to adopt the RIM as the screening criterion for DSM measures programs including those DSM measures targeted at strategic load growth. This criterion was adopted because programs selected under this screen will minimize the rate impact of any programs on all customers. GSU has indicated that it will not seek special rate treatment, such as rate riders, for the cost of programs or the loss of revenue due to DSM for programs selected using the RIM criterion. Fuel Recovery. In January 1993, the PUCT adopted a new rule for setting a fixed fuel factor, which 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 Fuel Cost Review," 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, 1994, LP&L's unrecovered deferral balance was $54.0 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 (as of 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. (See Note 2 of LP&L's Notes to Financial Statements, "Rate and Regulatory Matters - Waterford 3 and Grand Gulf 1," 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 expired in mid-1994. LP&L believes that the amortization 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 which expired in March 1994. Performance-Based Formula Rate Plan. In August 1994, LP&L filed a performance-based formula rate plan with the LPSC. The proposed formula rate plan would continue existing LP&L rates at current levels, while providing financial incentive to reduce costs and maintain high levels of customer satisfaction and system reliability. A performance rating adjustment feature of the plan would allow LP&L the opportunity to earn a higher rate of return if it improves performance over time. Conversely, if performance declines, the rate of return LP&L could earn would be lowered. This provides financial incentive for LP&L to maintain continuous improvement in all three performance categories (customer price, customer satisfaction, and customer reliability). Under the proposed plan, if LP&L's earnings fall within a bandwidth around a benchmark rate of return, there would be no adjustment in rates. If LP&L's earnings are above the bandwidth, the proposed plan would automatically reduce LP&L's base rates. Alternatively, if LP&L's earnings are below the bandwidth, the proposed plan would automatically increase LP&L's base rates. 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 2% of LP&L's retail revenues. Hearings were held in March 1995. Least Cost Planning. On December l, l992, and July 1, l993, LP&L filed with the LPSC and the Council the Least Cost Plan and amendments described under "Business of Entergy - Competition - Least Cost Planning," above. In response to an increasingly competitive electric utility environment LP&L intends to adopt the RIM as the screening criterion for DSM programs, including those DSM measures targeted at strategic load growth. This is in place of the total resource cost test that had been used in developing the initial Least Cost Plan. This criterion was adopted because programs selected under this screen will minimize the rate impact of any programs on all customers. LP&L has indicated that it will not seek special rate treatment, such as rate riders, for the cost of programs selected using the RIM criterion. On September 28, 1994, LP&L filed a report with the Council that discussed Entergy's Least Cost Plan activities in other jurisdictions and described the motivations for these activities. LP&L also filed a motion requesting that the Council defer the filing of a new Least Cost Plan, which the existing Least Cost Plan ordinance required on December 1, 1994. On October 6, 1994, the Council approved an amendment to the City Code that rescinded the December 1, 1994 filing requirement and allowed the Council to set a future date for a new filing. The Council's actions also established that there would be a set of hearings to consider a wide range of Least Cost Plan issues, and that a new filing date would be established following these hearings. These rulings do not affect the ongoing DSM programs that LP&L is currently implementing in the City. Regarding the activities of LP&L within the jurisdiction of the LPSC, on June 30, 1994, LP&L filed rebuttal testimony with the LPSC explaining LP&L's new direction for least cost planning. On July 18, 1994, LP&L filed a motion to withdraw its Least Cost Plan and for approval of an experimental time-of-use-rate. LP&L will file, for informational purposes only, a revised Least Cost Plan in the fourth quarter of 1995. The LPSC responded to LP&L's request by placing LP&L's application for approval in abeyance. However, the LPSC did require LP&L to file a set of proposed pilot programs. In December 1994, LP&L filed a set of proposed pilot programs with the LPSC. LP&L has agreed not to seek special treatment of the costs or loss of revenues due to DSM measures associated with these pilot programs. The LPSC has also ordered that a set of generic hearings be held to address integrated resource planning issues for all electric utilities within its jurisdiction. No procedural schedule has been issued for these proceedings. Fuel Adjustment Clause. LP&L's rate schedules include a fuel adjustment clause to reflect the (1) delivered cost of fuel in the second preceding month and (2) 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 MP&L's formulary rate plan 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 for, among other things, increases associated with the 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, 1994, the uncollected balance of MP&L's deferred costs was approximately $492.3 million. MP&L is permitted to recover the carrying charges on all deferred amounts on a current basis. Formula Rate Plan. Under a formulary incentive rate plan (Formula Rate Plan) effective March 25, 1994, MP&L's earned rate of return is calculated automatically every 12 months and compared to and adjusted against a benchmark rate of return (calculated under a separate formula within the Formula Rate Plan). The Formula Rate Plan allows for periodic small adjustments in rates based on a comparison of earned to benchmark returns and upon certain performance factors. In the same proceeding, the MPSC conducted a general review of MP&L's current rates and on March 1, 1994, issued a final order adopting the Formula Rate Plan and previously agreed-upon stipulations of (1) a required return on equity of 11% and (2) certain accounting adjustments that resulted in a 4.3% ($28.1 million) reduction in MP&L's June 30, 1993, test-year base revenues. The MPSC's order required MP&L to file rates designed to provide for this reduction in operating revenues for the test year on or before March 18, 1994, which became effective March 25, 1994. The final order was appealed to the Mississippi Supreme Court on May 17, 1994, by Mississippi Valley Gas Company (MVG) on the grounds that the MPSC issued the final order without having reviewed the cost of MP&L's promotional practices, some of which MVG alleged to be improper. MVG filed a motion to dismiss the appeal, and on October 28, 1994, the Mississippi Supreme Court granted MVG's motion. February 1994 Ice Storm/Rate Rider In early February 1994, an ice storm left more than 80,000 MP&L customers without electric power across the 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. Repair costs totaled approximately $77.2 million, with $64.6 million of these amounts capitalized as plant- related costs. The remaining balances were recorded as a deferred debit. On April 15, 1994, MP&L filed for rate recovery of costs related to the ice storm. MP&L's filing, as subsequently amended, requested recovery of the revenue requirement associated with MP&L's ice storm costs recorded through April 30, 1994, representing approximately 86% of the total estimated ice storm costs. MP&L may make another ice storm rate filing with the MPSC during 1995 to recover ice storm costs recorded by MP&L after April 30, 1994. In August 1994, MP&L and the MPSC's Public Utilities Staff entered into a stipulation with respect to the recovery of ice storm costs recorded through April 30, 1994, and in September 1994, the MPSC approved the stipulation. Under the stipulation, MP&L implemented an ice storm rider schedule, which went into effect on September 29, 1994, that will increase rates approximately $8 million annually for five years. At the end of the five-year period, the revenue requirement associated with the undepreciated ice storm capitalized costs will be included in MP&L's base rates to the extent that this revenue requirement does not result in MP&L's rate of return on rate base being above the benchmark rate of return under MP&L's formula rate plan. 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. In response to an increasingly competitive electric utility environment MP&L filed a motion on June 20, 1994, with the MPSC to lift a currently effective stay order and dismiss without prejudice the proposed Least Cost Plan. On July 28, 1994, the MPSC issued an order that lifted the stay and dismissed, without prejudice, the Least Cost Plan filing. MP&L will file, for informational purposes only, a revised Least Cost Plan in the fourth quarter of 1995. In this plan, MP&L intends to adopt the RIM as the screening criterion for DSM programs including those DSM measures targeted at strategic load growth. This is in place of the total resource cost test that had been used in developing the initial Least Cost Plan. This criterion was adopted because programs selected under this screen will minimize the rate impact of any programs on all customers. MP&L has indicated that it will not seek special rate treatment, such as rate riders, for the cost of programs or loss of revenue due to DSM for programs selected using the RIM criterion. 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 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, 1994, the uncollected balance of NOPSI's deferred costs was $204.7 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. However, this base rate freeze was amended by the 1994 NOPSI Settlement discussed below. See Note 2 of NOPSI's Notes to Financial Statements, "Rate and Regulatory Matters - Prudence Settlement and Finalized Phase- In Plan." 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. 1994 NOPSI Settlement. In a settlement with the Council that was approved on December 29, 1994, NOPSI agreed to reduce electric and gas rates and issue credits and refunds to customers. Effective January 1, 1995, NOPSI implemented a $31.8 million permanent reduction in electric base rates and a $3.1 million permanent reduction in gas base rates. These adjustments resolved issues associated with NOPSI's return on equity exceeding 13.76% for the test year September 30, 1994. Under the 1991 NOPSI Settlement, NOPSI recovers from its retail customers its allocable share of certain costs related to Grand Gulf 1. NOPSI's base rates to recover those costs were derived from estimates of those costs made at that time. Any overrecovery of costs is required to be returned to customers. Grand Gulf 1 experienced lower operating costs than previously estimated, and NOPSI agreed to reduce its base rates in two steps to more accurately match the current costs related to Grand Gulf 1. On January 1, 1995, NOPSI implemented a $10 million permanent reduction in base electric rates to reflect the reduced costs related to Grand Gulf 1, to be followed by an additional $4.4 million rate reduction on October 31, 1995. These Grand Gulf 1 rate reductions, which are expected to be largely offset by lower operating costs, may reduce NOPSI's after-tax net income by approximately $1.4 million per year beginning November 1, 1995. The next scheduled Grand Gulf 1 phase-in rate increase in the amount of $4.4 million on October 31, 1995, will not be affected by the 1994 NOPSI Settlement. The 1994 NOPSI Settlement also requires NOPSI to credit its customers $25 million over a 21-month period, beginning January 1, 1995, in order to resolve disputes with the Council regarding the interpretation of the 1991 NOPSI Settlement. NOPSI reduced its revenues by $25 million and recorded a $15.4 million net-of-tax reserve associated with the credit in the fourth quarter of 1994. The 1994 NOPSI Settlement further required NOPSI to refund, in December 1994, $13.3 million of credits previously scheduled to be made to customers during the period January 1995 through July 1995. These credits were associated with a July 7, 1994, Council resolution that ordered a $24.95 million rate reduction based on NOPSI's overearnings during the test year ended September 30, 1993. Accordingly, NOPSI recorded an $8 million net-of-tax charge in the fourth quarter of 1994. The 1994 NOPSI Settlement also required NOPSI to refund $9.3 million of overcollections associated with Grand Gulf 1 operating costs and $10.5 million of refunds associated with the settlement by System Energy of a FERC tax audit. The settlement of the FERC tax audit by System Energy required refunds to be passed on to NOPSI and to other Entergy subsidiaries and then on to customers. These refunds have no effect on current period net income. 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 agreed to a base rate freeze, except for the scheduled increases and certain other exceptions, through October 31, 1996. However, this was amended by the 1994 NOPSI Settlement discussed above. 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. In response to an increasingly competitive electric utility environment NOPSI intends to adopt RIM as the screening criterion for DSM programs including those DSM measures targeted at strategic load growth. This is in place of the total resource cost test that had been used in developing the initial Least Cost Plan. This criterion was adopted because programs selected under this screen will minimize the rate impact of any programs on all customers. NOPSI has indicated that it will not seek special rate treatment, such as rate riders, for the cost of programs selected using the RIM criterion. NOPSI filed a report on September 28, 1994, with the Council that discussed Entergy's Least Cost Plan activities in other jurisdictions and described the motivations for these activities. NOPSI also filed a motion requesting that the Council defer the filing of a new Least Cost Plan, which the existing Least Cost Plan ordinance required on December 1, 1994. On October 6, 1994, the Council approved an amendment to the City Code that rescinded the December 1, 1994, filing requirement and allowed the Council to set a future date for a new filing. The Council's actions also established that there would be a set of hearings to consider a wide range of Least Cost Plan issues, and that a new filing date would be established following these hearings. These rulings do not affect the ongoing DSM programs that NOPSI is currently implementing in the City. The Council has established a proceeding to consider NOPSI's request for significant changes in the Least Cost Plan Ordinance. NOPSI's initial testimony in that matter was filed on November 17, 1994, and has been the subject of discovery requests from the Council's advisors and intervenors. Initial testimony of the Council's advisors and intervenors was filed February 10, 1995, and rebuttal testimony of all parties was due March 10, 1995. 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 public utility holding company registered 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 EPAct), 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. Entergy Corporation, along with ten other electric utility holding companies, recently asked Congress to repeal the Holding Company Act. The Holding Company Act requires oversight by the SEC of many business practices and activities of utility holding companies and their subsidiaries including, among other things, nonutility activities. Entergy Corporation believes that the Holding Company Act inhibits its ability to compete in the evolving electric energy marketplace, and largely duplicates the oversight activities already performed by FERC and state and local public service commissions. 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 the 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. Currently the DOE projects it will begin to accept spent fuel no earlier than 2010. In the meantime, all System companies are responsible for spent fuel storage. (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, 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.") 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 was required to permit further access to out-of-region generators. The South Carolina legislature failed to take action to permit further access to out-of- region generators; therefore, since July 1994, low-level radioactive waste generators in the Central States Compact, including AP&L, GSU, and LP&L, have been 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. 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 reflect in rates any future changes in projected decommissioning costs. (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.") Uranium Enrichment Decontamination and Decommissioning Fees. The EPAct 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 approximately $3.4 million, $0.9 million, $1.3 million, and $1.4 million, respectively, in 1995 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 limits public liability for a single nuclear incident to approximately $8.92 billion as of December 31, 1994. AP&L, GSU, LP&L, and System Energy have protection with respect to this liability through a combination of private insurance (currently $200 million each) 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.") 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 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. ANO 2 experienced a forced outage for repair of certain steam generator tubes in March 1992. Further inspections and repairs were conducted at subsequent refueling and mid-cycle outages in September 1992, May 1993, April 1994, and January 1995. AP&L's budgeted maintenance expenditures were adequate to cover the cost of such repairs. Unit 2's output has been reduced 15 megawatts or 1.6% due to secondary side fouling, tube plugging, and reduction of primary temperature. Entergy Operations continues to take steps at ANO 2 to reduce the number and severity of future tube cracks. In addition, Entergy Operations continues to meet with the NRC to discuss such steps and results of inspections of the steam generator tubes, as well as the timing of future inspections. Additional inspections are planned for the normal refueling outage scheduled for October 1995. 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 a 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 14, 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. On August 23, 1994, the NRC issued an order disallowing GSU's appeal in the ASLB proceeding and upholding the ASLB's January 27, 1994 order. A hearing on the proceeding before the ASLB is scheduled to begin May 9, 1995. 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. On October 11, 1994, twelve Mississippi cities filed a complaint in state court against MP&L and eight electric power associations seeking a judgment from the court declaring unconstitutional certain Mississippi statutes that establish the procedure that must be followed before a municipality can acquire the facilities and certificate rights of a utility serving in the municipality. Specifically, the suit requests that the court declare unconstitutional certain 1987 amendments to the Mississippi Public Utilities Act that require that the MPSC cancel a utility's certificate to serve in the municipality before a municipality may acquire a utility's facilities located in the municipality. The suit also requests that the court find that Mississippi municipalities can serve any consumer in the boundaries of the municipality and within one mile thereof. Such a finding would be contrary to Mississippi Supreme Court decisions that have held that a municipality cannot serve in another utility's service area even where the municipal boundaries extend into such service area. On January 6, 1995, MP&L and the other defendants filed motions to dismiss. The matter is pending and will be vigorously contested by MP&L. 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 exclusive 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. In Arkansas, franchises are considered to be contracts and therefore are terminable upon breach of the contract. 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 current 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 non-exclusive 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 non-exclusive 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, Entergy's facilities and operations are subject to regulation by various federal, state, and local authorities. Entergy considers itself to be in substantial compliance with those environmental regulations currently applicable to its facilities 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) set up three programs, acid rain for control of sulfur and nitrogen oxides (NOx), ozone nonattainment area for control of NOx and volatile organic compounds, and operating permits for administration and enforcement of these and other Clean Air Act programs. Under the acid rain program, no additional control equipment will be required to control sulfur dioxide. Regarding sulfur dioxide emissions, the Act provides "allowances" to most Entergy generating units based upon past emission levels and operating characteristics. Each 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 generating units. All of Entergy's generating units are classified as "Phase II" units under the Act and are therefore subject to sulfur dioxide allowance requirements beginning in the year 2000. Based on Entergy's operating history, it is considered a "clean" utility and as such has been allocated more allowances than are currently necessary for normal operations. Entergy believes that it will be able to operate its units efficiently without installing scrubbers or purchasing allowances from outside sources, and may have excess allowances available for sale to others. In addition, Entergy has installed additional continuous emission monitoring (CEM) equipment at its base load and cycling generating units to comply with EPA regulations under the Act. Additional CEM equipment will be installed at peaking generating units in 1995 to comply with the regulations at an estimated cost of $3.0 million. Under ozone nonattainment programs in the area served by GSU, control equipment may eventually be required for nitrogen oxide reductions due to the ozone nonattainment status of the Baton Rouge, Louisiana and Beaumont and Houston, Texas, areas. These states are studying the causes of ozone pollution in these areas and will decide during 1995 whether to require controls in these areas. If the states decide to regulate NOx, the cost of such control equipment is estimated at $16.0 million through 1997. Under Title V of the Act, EPA promulgated operating permit regulations in 1994 that may set new operating criteria for the fossil plants relating to fuels, emissions, and equipment maintenance practices. Entergy may also have to install additional CEM equipment as a result of these permits. The extent of the cost will be determined on a state by state basis as plants are granted permits during 1995 and 1996. Any capital and operation and maintenance costs will begin in 1996 and 1997. The authority to impose permit fees under this program 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. Entergy currently estimates that future capital costs of approximately $16.0 million for NOx control and approximately $3.0 million for CEM could be required to comply with the Act. During 1994, Entergy incurred capital costs of approximately $5.7 million for NOx control and approximately $14.7 million for CEM. 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. 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 in effect 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 in 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 (PCBs), 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 PRPs (along with LP&L and GSU) at one Saline County site in Arkansas. The site was contaminated with PCBs and lead. AP&L actively participated with the cleanup of the site, which was completed in 1994. EPA has reviewed and accepted the site remediation and closure report. AP&L to date has expended approximately $1.0 million at the site and does not anticipate any significant additional expenditures. The EPA has discovered an additional site in Saline County that is similar to the site mentioned above and could involve many of the same PRPs. At EPA's request, AP&L voluntarily performed stabilization activities at the site. EPA has indicated that the records associated with the site are inconclusive, therefore no PRPs have been named at this time. AP&L, LP&L and GSU believe their potential liability for this site, if any, 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 PCBs 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 PCBs and pentachlorophenol (a wood preservative chemical). Also, containers and drums that contained PCBs and other hazardous substances were found at the site. AP&L's share of total remediation costs is estimated to range between $3.0 million and $5.0 million. AP&L is attempting to identify and notify other PRPs. 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 PRPs that can be identified (approximately 20 have been identified to date). AP&L has performed the activities necessary to stabilize the site, which to date has cost approximately $348,000. AP&L believes that its potential liability for this site will not be material. 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 has investigated these sites to determine the full extent of the contamination and has stabilized the sites at an aggregate cost of approximately $250,000. AP&L estimates the remediation cost for both sites to be less than $1.0 million. 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 clean-ups and 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 PRPs for the voluntary cleanup of the waste site. A Consent Decree has been signed by all parties. The ultimate costs for the voluntary cleanup are not known because additional wastes have been discovered at the site since the original cleanup costs were estimated, however they are expected to be at least $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 PRPs and the agencies. GSU does not presently believe that its ultimate responsibility with respect to this site will be material after allowance for previously reserved amounts. 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 1994, 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. On February 13, 1995 the EPA published a proposed rule adding the Lake Charles site to 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 after allowance for previously reserved amounts. 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 1995. GSU and LP&L have been named as defendants in a class action lawsuit lodged against a group of PRPs 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 PRPs. The EPA is continuing its investigation of the site and has notified the PRPs 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, along with AP&L and LP&L, was notified in 1990 of its potential liability at a site located in Saline County, Arkansas (see "AP&L" above). GSU believes its responsibility to be de minimus at the one site where the cleanup has been completed and also at the additional site. 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 one or both 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. Because of the type and the large number of PRPs (over 700, including many large utilities and national and international corporations), LP&L and NOPSI do not expect liabilities in excess of this amount. As to the two Saline County, Arkansas, sites (see "AP&L" above), LP&L (along with GSU) believes its responsibilities to be de minimus because of its limited scope of involvement and the number and nature of PRPs . 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 and settled with the EPA that determined LP&L to be a de minimus party with a total liability of approximately $28,000 (see "AP&L," above). As to one 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 PRPs 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 PRPs for this site (including a number of major oil companies), does not expect its share of future costs to be material. NOPSI received notice from the EPA with respect to a second Mississippi site in the fall of 1994. NOPSI has advised the EPA in connection with that site that (1) the natural gas condensate NOPSI sold in 1983 and 1984 is excluded from the definition of "hazardous waste" under Superfund and (2) NOPSI is not aware that such material was ever shipped to the site in question. NOPSI believes it is not liable with regard to the $298,000 which EPA allegedly incurred in conducting operations at the site. With respect to the Livingston Parish, Louisiana, site (involving at least 70 PRPs, 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 PRPs, 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. During 1994, impact assessments were conducted at a power plant owned and operated by LP&L. Initial groundwater information is being collected for submittal to LDEQ. Remediation strategies will be formulated to restore the area to acceptable conditions. LP&L estimates costs to be approximately $135,000. From 1992 to 1994, LP&L performed site assessments and remedial activities at two retired power plants previously owned and operated by two Louisiana municipalities. LP&L purchased the power plants, as part of the acquisition of 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 has completed all remediation work to the LDEQ's satisfaction for these two former generating plants, and follow-up sampling has been completed at one site. Sampling at the other site is expected to be completed in 1996. Because of LDEQ solid waste regulations promulgated in 1993, LP&L in 1994 began to close a surface impoundment at another municipal plant site now owned and operated by LP&L. With regard to hydrocarbons found in some ground water near the impoundment, additional assessment activities pursuant to LDEQ review were completed in January 1995. A report on such activities was filed with the LDEQ in February 1995. 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 either upgrade or close them. The aggregate cost of the upgrades and closures, to be completed by 1996, is estimated to be $16 million. System Energy. In February 1990, System Energy received an EPA notice that it may be a PRP along with numerous other parties 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 PRPs 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). FERC's December 15, 1993, and May 17, 1994, orders approving the Merger were appealed to the United States Court of Appeals for the District of Columbia Circuit by Entergy Services, the City, the Arkansas Electric Energy Consumers (AEEC), the APSC, Cajun, the MPSC, the American Forest and Paper Association, the State of Mississippi, the Cities of Benton and others, and Occidental Chemical Corporation (Occidental). Entergy seeks review of FERC's deletion of 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 decisions on various grounds, including the issues of whether FERC appropriately conditioned the Merger to protect various interested parties from alleged harm and FERC's reliance on Entergy's transmission tariff to mitigate any potential anticompetitive impacts of the Merger. On November 18, 1994, the D. C. Circuit denied motions filed by Cajun, Occidental, and AEEC for a remand to FERC and a partial summary grant of the petitions for review. At the same time, the D.C. Circuit ordered that the cases be held in abeyance pending FERC's issuance of (1) a final order on remand in the proceedings on Entergy's transmission tariff, citing its July 12, 1994, opinion discussed in "Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters - Open Access Transmission," and (2) a final order on competition issues in the proceedings on the Merger. On December 30, 1993, Entergy Services submitted to FERC tariff revisions to comply with FERC's December 15, 1993, order approving the Merger. On February 4, 1994, the APSC and AEEC filed with FERC a joint protest to the compliance filing. They alleged that Entergy must insulate the ratepayers of AP&L, LP&L, MP&L, and NOPSI from all litigation liabilities related to GSU's River Bend nuclear facility. In its May 17, 1994, order on rehearing, FERC addressed Entergy's commitment to insulate the customers of AP&L, LP&L, MP&L, and NOPSI against liability resulting from certain litigation involving River Bend. In response to FERC's clarification of Entergy's commitment, Entergy Services filed a compliance filing on June 16, 1994, which amended certain System Agreement language submitted with the December 30, 1993, filing. APSC and AEEC subsequently filed protests questioning the adequacy of Entergy's June 16, 1994, compliance filing. Entergy filed an answer to the protest reiterating its full compliance with the requirements of FERC's May 17, 1994, order on rehearing. FERC has not yet acted on the compliance filings. On February 14, 1994, Cajun filed with the D. C. Circuit petitions for review of the NRC's issuance of two Merger-related license amendments for River Bend. The D. C. Circuit consolidated the cases and assigned the cases to be heard by the same panel and on the same day as the petitions to review the SEC Merger-related orders. On December 29, 1994, the D. C. Circuit, citing its July 12, 1994, opinion discussed in "Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters - Open Access Transmission," ordered the parties to file motions governing further proceedings within thirty days. Subsequently, the NRC and Entergy requested that the D. C. Circuit hold the case in abeyance; Cajun asked the D. C. Circuit to remand the proceedings to the NRC. On March 14, 1995, the D.C. Circuit denied the NRC's and Entergy's request, ordered the original NRC order be set aside, and remanded the case to the NRC for further consideration. 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. The matter has been remanded by the D.C. Circuit to the SEC for further consideration in light of developments at FERC relating to Entergy's transmission tariffs. 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. On February 9, 1995, the 19th Judicial District Court ruled that there was no duty on the part of the LPSC to consider environmental issues in this matter and, accordingly, dismissed the claim of the Alliance based on those grounds. The Alliance appealed this ruling to the Louisiana Supreme Court. The matter is pending. 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. These plaintiffs failed timely to petition the U.S. Supreme Court to issue a writ of certiorari to permit its review of the Eighth Circuit's decision, thereby concluding this aspect of the litigation. On February 10, 1995, the plaintiffs who had voluntarily dismissed their claims, and as to whom the flowage easements did not apply, petitioned the Arkansas District Court to reopen the proceedings as to their claims. AP&L and Entergy Services will respond to the petition by opposing the reopening of this aspect of the litigation on the basis that the applicable statutes of limitation were not tolled by the order permitting the voluntary dismissal of the claims and that the delay since final resolution of the appeals is unreasonable. 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). On June 23, 1994, the Federal District Court entered into the record its first case management and scheduling order, which order, among other things, set the trial in this matter for September 3, 1996. Such order also stated the intention of the Federal District Court to facilitate, prior to the scheduled trial date, appellate review of any significant decisions. At an April 28, 1994 status conference, the Federal District Court judge stated that he intended to adopt the Federal magistrate's recommendation that the class action not be remanded to the State District Court. On January 26, 1995, the Federal District Court certified the plaintiffs' lawsuit as a Federal class action. A trial date of April 11, 1994, previously set by the State District Court was not 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. Two similar suits also have been filed in the District Courts of Jefferson County, Texas, one on behalf of approximately 210 plaintiffs against about 122 defendants, including GSU, and the other on behalf of about 136 plaintiffs against approximately 63 defendants, including GSU. In these two suits together, possibly 60 to 70 plaintiffs may have worked at GSU. These two suits have not been settled. 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. Settlements of the two largest of the Jefferson County suits (involving about 1660 groups of claimants) and all of the suits in Calcasieu Parish were consummated in the second and third quarters of 1994. GSU was named as one of a number of defendants in nearly all of the suits. GSU's share of the settlements was not material to its financial position or results of operations. 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. Although 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/Cajun - GSU has significant business relationships with Cajun, including co-ownership of River Bend and Big Cajun 2, Unit 3. GSU and Cajun own 70% and 30% undivided interests in River Bend, respectively, and 42% and 58% undivided interests in Big Cajun 2, Unit 3, respectively. Cajun/River Bend Litigation - In June 1989, Cajun filed a civil action against GSU in the United States District Court for the Middle District of Louisiana (District Court). Cajun's complaint seeks to annul, rescind, terminate, and/or dissolve the Joint Ownership Participation and Operating Agreement entered into on August 28, 1979 (Operating Agreement) relating 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 also seeks to recover Cajun's alleged $1.6 billion investment in the unit as damages, plus attorneys' fees, interest, and costs. 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 Operating Agreement between GSU and Cajun is void because an allegedly required approval of the LPSC had not been obtained. This suit was transferred from the Western District to the Middle District. GSU believes the suits are without merit and is contesting them vigorously. A trial without jury on the portion of the suit by Cajun to rescind the Operating Agreement which began in April 1994 has been completed, and an order from the District Court is pending. 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 United States Bankruptcy Code. If GSU prevails in this litigation, there can be no assurance that the United States Bankruptcy Court will allow funding of all required costs of Cajun's ownership in River Bend. Since 1992 Cajun has not paid its full share of operating and maintenance expenses and other costs for repairs and improvements to River Bend. In addition, certain costs and expenses paid by Cajun were paid under protest. These actions were taken by Cajun based on its contention, which GSU disagrees, that River Bend's operating and maintenance expenses were excessive. In a letter dated October 21, 1994, and at a subsequent meeting, Cajun representatives advised Entergy Corporation and GSU that, on October 25, 1994, Cajun would exhaust its 1994 budget for operating and maintenance expenses for River Bend, and did not make any further payments to GSU in 1994 for River Bend operating, maintenance or capital costs. Cajun also advised that the RUS (which provided funding to Cajun for its investment in River Bend) would not permit Cajun to budget funds in 1995 to pay its share of operating and maintenance expenses or capital costs for River Bend. However, Cajun stated that it would continue to fund its share of the nuclear decommissioning trust payments for River Bend, as well as insurance and safety-related expenses. The unpaid portion of Cajun's River Bend operating, maintenance, and capital costs for 1994 was approximately $22.4 million. Cajun's total share of River Bend annual operating (including nuclear fuel) and maintenance expenses and capital costs was approximately $76.1 million in 1994. In view of Cajun's stated expectation that it will fund only a limited portion of its share of River Bend related operating, maintenance, and capital costs, GSU notified Cajun that it would (i) credit GSU's share of expenses for Big Cajun 2, Unit 3 against amounts due from Cajun to GSU and (ii) seek to market Cajun's share of the power from River Bend and apply the proceeds to the amounts due from Cajun to GSU. On November 2, 1994, Cajun discontinued GSU's entitlement of energy from Big Cajun 2, Unit 3. In response, on November 3, 1994, GSU filed pleadings in District Court seeking an order requiring Cajun to provide GSU with the energy from Big Cajun 2, Unit 3 to which GSU is entitled, and holding that GSU is entitled to credit amounts due from GSU to Cajun for Big Cajun 2, Unit 3 against amounts due from Cajun to GSU with respect to River Bend. On December 19, 1994, the District Court issued an injunction prohibiting Cajun from denying its share of energy from Big Cajun 2, Unit 3 and stipulating that GSU must make payments for its portion of expenses for Big Cajun 2, Unit 3 to the registry of the District Court. Cajun Bankruptcy Filing - On December 14, 1994, the LPSC ordered Cajun to decrease the rates charged to its member distribution cooperatives by approximately $30 million per year. The rate decrease is associated with the LPSC's prior finding of imprudence in Cajun's participation in River Bend. On December 21, 1994, Cajun filed a petition in the United States Bankruptcy Court for the Middle District of Louisiana seeking bankruptcy relief under Chapter 11 of the United States Bankruptcy Code. Cajun's bankruptcy could have a material adverse effect on GSU, including the possibility of an NRC action with respect to the operation of River Bend. However, GSU is taking appropriate steps to protect its interests and its claims against Cajun arising from the co- ownership in River Bend and Big Cajun 2, Unit 3. On December 31, 1994, the District Court issued an order lifting an automatic stay as to certain proceedings, with the result that the preliminary injunction granted by the Court on December 19, 1994, remains in effect. Cajun filed a Notice of Appeal on January 18, 1995, to the United States Court of Appeals for the Fifth Circuit seeking a reversal of the District Court's grant of the preliminary injunction. No hearing date has been set on Cajun's appeal. In the bankruptcy proceedings, Cajun filed on January 10, 1995, a motion to reject the Operating Agreement as a burdensome executory contract. GSU responded on January 10, 1995, with a memorandum opposing Cajun's motion filed with the District Court. This memorandum argues that the motion should be denied because (1) the Operating Agreement is not an executory contract that can be rejected under the United States Bankruptcy Code, but an agreement establishing property rights and obligations; (2) Cajun legally cannot have its payment obligations under the Operating Agreement suspended while retaining the benefits from co-ownership in River Bend, as the benefits and obligations are indivisible; (3) Cajun cannot seek to dispose of its property interest in River Bend or reject the Operating Agreement with respect thereto without disposing of all of its property interests and rejecting all of the arrangements under the River Bend package of agreements consisting of the Operating Agreement, Big Cajun 2, Unit 3 facility, certain transmission lines and the buy-back agreement pursuant to when GSU paid Cajun approximately $600 million for River Bend capacity and energy during the early years of operation of River Bend; and (4) a legal determination of Cajun's obligations and interests in River Bend should only be made as part of a plan of reorganization in bankruptcy and such determination should be subject to regulatory approvals by certain agencies with jurisdiction over Cajun, including the NRC. If the court were to grant Cajun's motion to reject the Operating Agreement, Cajun would be relieved of its financial obligations under the contract, while GSU would likely have a substantial damage claim arising from any such rejection. Although GSU believes that Cajun's motion to reject the Operating Agreement is non-meritorious, it is not possible to predict the outcome or ultimate impact of these proceedings. During the period in which Cajun is not paying its share of River Bend costs, GSU intends to fund all costs necessary for the safe, continuing operation of the unit. The responsibilities of Entergy Operations as the licensed operator of River Bend, for safely operating and maintaining the unit are not affected by Cajun's actions. The total resulting from Cajun's failure to fund repair projects, Cajun's funding limitation on refueling outages, and the weekly funding limitation by Cajun was $55.6 million as of December 31, 1994, compared with $33.3 million as of December 31, 1993. These amounts are reflected in long-term receivables with an offsetting reserve in other deferred credits. Cajun's bankruptcy may affect the ultimate collectibility of the amounts owed to GSU, including any amounts that may be awarded in litigation. In September 1994, in connection with Entergy Corporation's analysis of certain preacquisition contingencies, Entergy Corporation increased its acquisition adjustment and GSU recorded a loss provision associated with the River Bend litigation between GSU and Cajun and certain underpayments by Cajun of River Bend costs, in accordance with SFAS 5, "Accounting for Contingencies." See Note 12 of Entergy Corporation's Notes to Financial Statements, "Entergy Corporation - GSU Merger" for additional information on provisions for preacquisition contingencies recorded during 1994. Cajun/Transmission Service - GSU and Cajun are parties to FERC proceedings relating to transmission service charge disputes. In April 1992, FERC issued a final order. In May 1992, GSU and Cajun filed motions for rehearings which are pending at 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 December 1994, FERC held a hearing to address the issues remanded by the Court of Appeals. In February 1995, FERC clarified its order, eliminating an issue that GSU believes the Court of Appeals directed FERC to reconsider. GSU interprets the 1992 FERC order and the United States Court of Appeals' decision to mean that Cajun would owe GSU approximately $93.3 million as of December 31, 1994. However, FERC's February 1995, order indicates that FERC believes an issue, estimated by GSU to constitute approximately $26.2 million of this amount, may not be pursued by GSU in the remand proceedings. GSU further estimates that if it prevails in its May 1992 motion for rehearing, Cajun would owe GSU approximately $129.6 million as of December 31, 1994. 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 $85.6 million as of December 31, 1994. 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 payment. 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 $160.2 million as of December 31, 1994. This amount is reflected in long- term receivables with an offsetting reserve in other deferred credits. 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 seeking an order compelling the conveyance of certain facilities and awarding 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. Cajun/Service Dispute - 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. On March 21, 1994, FERC issued an order affirming the ALJ and dismissing Cajun's complaint, finding that GSU properly exercised its contractual right to refuse to provide the service. On August 3, 1994, FERC denied rehearing. On August 12, 1994, Cajun filed a petition for review of FERC's orders in the United States Court of Appeals for the District of Columbia Circuit. The matter is pending. 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. Cajun/River Bend Repairs - 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. See "Cajun Bankruptcy Filing," above for information regarding Cajun's bankruptcy filing. 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. Cajun/Other - 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 RUS. GSU has failed in its efforts to have the RUS made a party to the Cajun litigation. GSU does not know the purpose of such Office's investigation, but 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. 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), the parish in which Waterford 3 is located, have disputed use taxes paid on nuclear fuel ($4.9 million through 1989) under protest by LP&L. LP&L continues to be successful in lawsuits 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. On October 13, 1994, Parish tax authorities sued LP&L and Entergy Corporation in the Civil District Court of Orleans Parish, Louisiana, claiming that $1.4 million of sales and use and lease taxes paid under protest by LP&L with respect to newly acquired nuclear fuel were not, in fact, paid under protest and should be disposed of by the Parish, and that unspecified additional taxes, interest, and penalties are due. Entergy Corporation was dismissed from the suit and the suit has been transferred back to the Parish where it will form part of the suit by LP&L to recover the $1.4 million of sales and use taxes it paid to the Parish under protest. 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. Entergy Corporation, LP&L, and System Energy. In August 1994, Entergy received an IRS report covering the federal income tax audit of Entergy Corporation and subsidiaries for the years 1988 - 1990. The report asserts an $80 million tax deficiency for the 1990 consolidated federal income tax returns related primarily to the application of accelerated investment tax credits associated with Waterford 3 and Grand Gulf nuclear plants. Entergy Corporation believes there is no material tax deficiency and is vigorously contesting the proposed assessment. 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, 1990 1991 1992 1993 1994 Ratios of Earnings to Fixed Charges(a) AP&L 2.16 2.25 2.28 3.11(f) 2.32 GSU .80(g) 1.56 1.72 1.54 .36(g) LP&L 2.32 2.40 2.79 3.06 2.91 MP&L 2.42 2.36 2.37 3.79(f) 2.12 NOPSI 2.73 5.66(e) 2.66 4.68(f) 1.91 System Energy 2.10 1.74 2.04 1.87 1.23
Years Ended December 31, 1990 1991 1992 1993 1994 Ratios of Earnings to Fixed Charges and Preferred Dividends(a)(b)(c) AP&L 1.81 1.87 1.86 2.54(f) 1.97 GSU(d) .59(g) 1.19 1.37 1.21 .29(g) LP&L 1.87 1.95 2.18 2.39 2.43 MP&L 1.93 1.94 1.97 3.08(f) 1.81 NOPSI 2.36 4.97(e) 2.36 4.12(f) 1.73
____________________ (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, 1991, include the $90 million effect of the 1991 NOPSI Settlement. (f) 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. (g) Earnings for the year ended December 31, 1994 and 1990, for GSU were not adequate to cover fixed charges by $144.8 million and $60.6 million, respectively. Earnings for the year ended December 31, 1994 and 1990, were not adequate to cover fixed charges and preferred dividends by $197.1 million and $165.1 million, respectively. INDUSTRY SEGMENTS NOPSI Narrative Description of NOPSI Industry Segments Electric Service. NOPSI supplied electric service to 189,836 customers as of December 31, 1994. During 1994, 36% of electric operating revenues was derived from residential sales, 41% from commercial sales, 6% from industrial sales, 15% from sales to governmental and municipal customers, and 2% from sales to public utilities and other sources. Natural Gas Service. NOPSI supplied natural gas service to 153,259 customers as of December 31, 1994. During 1994, 57% of gas operating revenues was derived from residential sales, 18% from commercial sales, 10% from industrial sales, and 15% from sales to governmental and municipal customers. (See "Fuel Supply - Natural Gas Purchased for Resale.") 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." Employees by Segment NOPSI's full-time employees by industry segment as of December 31, 1994, were as follows: Electric 527 Natural Gas 133 --- Total 660 === (For further information with respect to NOPSI's segments, see "Property.") GSU For the year ended December 31, 1994, 96% of GSU's operating revenues was derived from the electric utility business. The remainder of operating revenues was 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 the System's owned and leased generating stations as of December 31, 1994, by company and by fuel type, is indicated below: Owned and Leased Capability MW(1) Gas Turbine and Internal Company Total Fossil Nuclear Combustion Hydro AP&L 4,367 (2) 2,373 1,694 230 (8) 70 GSU 6,547 (2) 5,817 655 (5) 75 - LP&L 5,405 (2) 4,311 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 21,320 (3) 16,448 (3)(4) 4,452 350 70 ====== ====== ===== === == _______________________ (1) "Owned and Leased Capability" is the dependable load carrying capability, as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. (2) Excludes the capacity of fossil-fueled generating stations placed on extended reserve as follows: AP&L - 506 MW; GSU - 405 MW; LP&L - 157 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 generating facilities owned by Entergy Power, which owns 809 MW of fossil-fueled capacity (see "Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters - Entergy Power," above). (4) Includes 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 from August 11, 1993 to February 18, 1994, due to an explosion. (5) GSU's nuclear capability represents its 70% undivided ownership interest in River Bend; Cajun owns the remaining 30% undivided interest. (6) LP&L's nuclear capability represents its 90.7% undivided 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 and bulk power availability, the System has no current need to install additional generating capacity. To delay the need for new capacity, the System is purchasing power in the wholesale power market and 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, purchasing power in the wholesale power market and/or removing generating stations from extended reserve shutdown. Under the terms of the System Agreement, certain 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 shall sell such capacity to those parties having deficiencies in generating capacity and that the purchasers shall pay to the sellers a charge sufficient to cover certain of the sellers' 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 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. The System's 1994 peak demand of 18,028 MW occurred on June 28, 1994. The net System capability at the time of peak was 20,884 MW, which reflects a reduction of the System's total 21,196 MW of owned and leased capability by net off-system firm sales of 312 MW. The capacity margin at the time of the peak was approximately 13.7%, not including units placed on extended reserve and capacity owned by Entergy Power. 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. The System 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. Neighboring utilities with which one or more System operating companies are directly interconnected include, 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, 1994, NOPSI distributed and transported natural gas for distribution solely within the limits of the City of New Orleans through a total of 1,419 miles of gas distribution mains and 40 miles of gas transmission lines. NOPSI receives deliveries of natural gas for distribution purposes at 14 separate locations, including deliveries from Koch Gateway Pipeline Company (formerly United Gas Pipe Line Company) at six of these locations. Of the remaining delivery points, two are principally served by interstate suppliers and the remainder are served by intrastate suppliers. As of December 31, 1994, the gas properties of GSU were 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, respectively, are subject to the lien of a 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 also 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 also 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 and 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 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 1994 44 2.24 1 3.99 39 .60 16 1.82 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 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 The following tabulation shows the percentages of generation by fuel type used in generation, excluding that of Entergy Power, for 1994 (actual) and 1995 (projected). The balance of generation, which is immaterial, is provided by hydroelectric power. Natural Gas Fuel Oil Nuclear Fuel Coal 1994 1995 1994 1995 1994 1995 1994 1995 System 44% 47% 1% 0% 39% 35% 16% 18% AP&L 7 2 - - 59 51 33 46 GSU 71 73 - - 13 15 16 12 LP&L 57 62 - - 43 38 - - MP&L 60 67 13 - - - 27 33 NOPSI 100 100 - - - - - - System - - - - 100(a) 100(a) - - Energy _______________________ (a) 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 retain a mix of long-term firm and short-term interruptible gas contracts. Long-term firm supply contracts currently comprise less than 40% of total System requirements but can be called upon, if necessary, to satisfy a significant percentage of the System's needs. Additional gas requirements are satisfied by short-term contracts and spot-market purchases. Furthermore, 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 service to certain generating stations by using such supplier's pipeline and 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 1995. However, pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies may be disrupted, the System operating companies will use alternate fuels, such as oil, or rely on coal and nuclear generation. 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 a 42% undivided interest). 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 nuclear fuel assemblies for use in fueling nuclear reactors, and disposal of the spent fuel. System Fuels is responsible for contracts to acquire nuclear material to be used in fueling 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 currently contracts for the fabrication of its own nuclear fuel and for purchasing the required enriched uranium hexafluoride from System Fuels. The requirements for GSU's River Bend plant are covered by contracts made by GSU. System Fuels sometimes acts as agent for GSU in negotiating and/or administering such contracts. 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 cation Disposal ANO 1 (1) (1) (3) 1997 (4) ANO 2 (1) (1) (3) 1999 (4) River Bend (2) (2) (3) 2000 (4) Waterford 3 (1) (1) (3) 1999 (4) Grand Gulf 1 (1) (1) (3) 2000 (4) __________________________ (1) Current contracts will provide a significant percentage of these materials and services through termination dates ranging from 1995-1998. 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 1996. (3) Current contracts will provide a significant percentage of these materials and services through approximately 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 EPAct to be made by AP&L, GSU, LP&L, and System Energy as a result of their enrichment contracts with the DOE.) (4) The Nuclear Waste Policy Act of 1982 provides for the disposal of spent nuclear fuel or high level waste by the DOE. (See "Rate Matters and Regulation - Regulation - Regulation of the Nuclear Power Industry - Spent Fuel and Other High-Level Radioactive Waste," above for further information). The System will enter into additional arrangements to acquire nuclear fuel 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 have nuclear fuel leasing arrangements that provide for AP&L, GSU, LP&L, and System Energy to lease nuclear fuel and related equipment and services having an aggregate value of up to $125 million, $105 million, $95 million, and $105 million for each company, respectively. As of December 31, 1994, the unrecovered cost base of AP&L's, GSU's, LP&L's, and System Energy's nuclear fuel leases amounted to approximately $94.6 million, $80.0 million, $44.2 million, and $46.7 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 by 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 been extended and now have termination dates of December 1997, January 1998, and February 1998, respectively. The credit agreement for GSU was entered into in December 1993 and has a termination date of December 1997. The intermediate-term notes issued pursuant to these fuel lease arrangements 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 lessee in each case 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 Koch Gas Services, Company (KGS), an interstate gas marketer, and Bridgeline and Pontchartrain, intrastate pipelines. NOPSI has a firm gas purchase contract with KGS. The KGS gas supply is transported to NOPSI pursuant to a "No-Notice" transportation service agreement with Koch Gateway Pipeline Company (KGPC). This service is subject to FERC-approved rates. NOPSI 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. After the implementation of FERC-mandated interstate pipeline restructuring, which occurred on October 31, 1993, curtailments of interstate gas supply could occur if NOPSI's suppliers failed to perform their obligations to deliver gas under their supply agreements. KGPC 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 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 Entergy's needs and available resources. During 1992, 1993 and 1994, the System contributed approximately $16 million, $17 million and $18 million, respectively, for the various research programs in which Entergy was involved. Item 2. Properties Refer to Item 1. "Business - Property," for information regarding the properties of the registrants. Item 3. Legal Proceedings Refer to Item 1. "Business - Rate Matters and Regulation," 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 1994. Item 4. Submission of Matters to a Vote of Security Holders During the fourth quarter of 1994, no matters that would be described in response to this item were submitted to a vote of the security holders of Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, or System Energy. 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, Chicago, and Pacific Stock Exchanges. The high and low prices for each quarterly period in 1994 and 1993, were as follows: 1994 1993 High Low High Low (In Dollars) First 37 3/8 31 1/8 36 1/2 32 1/2 Second 32 1/8 24 5/8 38 1/4 33 1/4 Third 26 1/4 22 5/8 39 7/8 36 1/4 Fourth 24 3/4 21 1/4 39 1/4 35 1/8 Eight consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in 1994 and 1993. Dividends of 45 cents per share were paid in each of the four quarters of 1994. 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. As of February 28, 1995, there were 103,100 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." 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 1993. Cash dividends on common stock paid by AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy to Entergy Corporation during 1994 and 1993, were as follows: 1994 1993 (In Millions) AP&L $80.0 $156.3 GSU 289.1 - LP&L 167.1 167.6 MP&L 45.6 85.8 NOPSI 33.3 43.9 System Energy 148.3 233.1 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, 1994, 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." Item 6. Selected Financial Data Entergy Corporation. Refer to information under the heading "Entergy Corporation and Subsidiaries Selected Financial Data - Five- Year Comparison." AP&L. Refer to information under the heading "Arkansas Power & Light Company Selected Financial Data - Five-Year Comparison." GSU. Refer to information under the heading "Gulf States Utilities Company Selected Financial Data - Five-Year Comparison." LP&L. Refer to information under the heading "Louisiana Power & Light Company Selected Financial Data - Five-Year Comparison." MP&L. Refer to information under the heading "Mississippi Power & Light Company Selected Financial Data - Five-Year Comparison." NOPSI. Refer to information under the heading "New Orleans Public Service Inc. Selected Financial Data - Five-Year Comparison." System Energy. Refer to information under the heading "System Energy Resources, Inc. Selected Financial Data - Five-Year Comparison." 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." AP&L. Refer to information under the heading "ARKANSAS POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS." GSU. Refer to information under the heading "GULF STATES UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS." LP&L. Refer to information under the heading "LOUISIANA POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS." MP&L. Refer to information under the heading "MISSISSIPPI POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS." NOPSI. Refer to information under the heading "NEW ORLEANS PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS." System Energy. Refer to information under the heading "SYSTEM ENERGY RESOURCES, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS." Item 8. Financial Statements and Supplementary Data. INDEX TO FINANCIAL STATEMENTS Entergy Corporation and Subsidiaries: Definitions 61 Report of Management 64 Audit Committee Chairman's Letter 65 Reports of Independent Accountants 66 Independent Auditors' Report 67 Consolidated Balance Sheets, December 31, 1994 and 1993 68 Statements of Consolidated Cash Flows For the Years Ended December 31, 1994, 1993 and 1992 70 Management's Financial Discussion and Analysis 72 Statements of Consolidated Income For the Years Ended December 31, 1994, 1993 and 1992 75 Statements of Consolidated Retained Earnings and Paid-In Capital for the Years Ended December 31, 1994, 1993 and 1992 76 Management's Financial Discussion and Analysis (continued) 77 Notes to Consolidated Financial Statements 86 Selected Financial Data - Five-Year Comparison 120 AP&L: Definitions 122 Report of Management 124 Audit Committee Chairman's Letter 125 Reports of Independent Accountants 126 Independent Auditors' Report 127 Balance Sheets, December 31, 1994 and 1993 128 Statements of Cash Flows For the Years Ended December 31, 1994, 1993 and 1992 130 Management's Financial Discussion and Analysis 131 Statements of Income For the Years Ended December 31, 1994, 1993 and 1992 132 Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 133 Management's Financial Discussion and Analysis (continued) 134 Notes to Financial Statements 139 Selected Financial Data - Five-Year Comparison 156 GSU: Definitions 158 Report of Management 160 Audit Committee Chairman's Letter 161 Report of Independent Accountants 163 Balance Sheets, December 31, 1994 and 1993 164 Statements of Cash Flows For the Years Ended December 31, 1994, 1993 and 1992 166 Management's Financial Discussion and Analysis 167 Statements of Income (Loss) For the Years Ended December 31, 1994, 1993 and 1992 168 Statements of Retained Earnings and Paid-In Capital for the Years Ended December 31, 1994, 1993 and 1992 169 Management's Financial Discussion and Analysis (continued) 170 Notes to Financial Statements 176 Selected Financial Data - Five-Year Comparison 203 LP&L: Definitions 206 Report of Management 208 Audit Committee Chairman's Letter 209 Reports of Independent Accountants 210 Independent Auditors' Report 211 Balance Sheets, December 31, 1994 and 1993 212 Statements of Cash Flows For the Years Ended December 31, 1994, 1993 and 1992 214 Management's Financial Discussion and Analysis 215 Statements of Income For the Years Ended December 31, 1994, 1993 and 1992 216 Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 217 Management's Financial Discussion and Analysis (continued) 218 Notes to Financial Statements 222 Selected Financial Data - Five-Year Comparison 239 MP&L: Definitions 242 Report of Management 244 Audit Committee Chairman's Letter 245 Reports of Independent Accountants 246 Independent Auditors' Report 247 Balance Sheets, December 31, 1994 and 1993 248 Statements of Cash Flows For the Years Ended December 31, 1994, 1993 and 1992 250 Management's Financial Discussion and Analysis 251 Statements of Income For the Years Ended December 31, 1994, 1993 and 1992 252 Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 253 Management's Financial Discussion and Analysis (continued) 254 Notes to Financial Statements 259 Selected Financial Data - Five-Year Comparison 274 NOPSI: Definitions 276 Report of Management 278 Audit Committee Chairman's Letter 279 Reports of Independent Accountants 280 Independent Auditors' Report 281 Balance Sheets, December 31, 1994 and 1993 282 Statements of Cash Flows For the Years Ended December 31, 1994, 1993 and 1992 284 Management's Financial Discussion and Analysis 285 Statements of Income For the Years Ended December 31, 1994, 1993 and 1992 286 Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 287 Management's Financial Discussion and Analysis (continued) 288 Notes to Financial Statements 293 Selected Financial Data - Five-Year Comparison 308 System Energy: Definitions 310 Report of Management 312 Audit Committee Chairman's Letter 313 Reports of Independent Accountants 314 Independent Auditors' Report 315 Balance Sheets, December 31, 1994 and 1993 316 Statements of Cash Flows For the Years Ended December 31, 1994, 1993 and 1992 318 Management's Financial Discussion and Analysis 319 Statements of Income For the Years Ended December 31, 1994, 1993 and 1992 320 Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 321 Management's Financial Discussion and Analysis (continued) 322 Notes to Financial Statements 325 Selected Financial Data - Five-Year Comparison 340 Entergy Corporation and Subsidiaries 1994 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 Cajun Cajun Electric Power Cooperative, Inc. 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. 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 Services Entergy Services, Inc. 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 EPAct The Energy Policy Act of 1992 FASB Financial Accounting Standards Board 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 (nuclear) Grand Gulf 2 Unit No. 2 of the Grand Gulf Steam Electric Generating Station (nuclear) 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 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 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 RUS Rural Utility Services (formerly the Rural Electrification Administration or "REA") SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the FASB SFAS 106 SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS 109, "Accounting for Income Taxes" System Agreement Agreement, effective January 1, 1983, as subsequently modified by the FERC, 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 (nuclear) 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 four directors, who are not officers of Entergy Corporation: H. Duke Shackelford (Chairman), Lucie J. Fjeldstad, Dr. Norman C. Francis, and James R. Nichols. The committee held four meetings during 1994. 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 (Coopers & Lybrand L.L.P.). 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 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Entergy Corporation We have audited the accompanying consolidated balance sheet of Entergy Corporation and Subsidiaries as of December 31, 1994, and the related statements of consolidated income, retained earnings and paid-in capital and cash flows for the year then ended. 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 audit. The consolidated financial statements of Entergy Corporation and Subsidiaries as of December 31, 1993 and for the years ended December 31, 1993 and 1992, were audited by other auditors, whose report, dated February 11, 1994, included explanatory paragraphs that (i) described changes in 1993 in methods of accounting for revenues, income taxes and postretirement benefits other than pensions (Notes 1, 3 and 10, respectively); (ii) uncertainties regarding costs capitalized by Gulf States Utilities Company for its River Bend Unit I Nuclear Generating Plant (River Bend) and other rate-related contingencies which may result in a refund of revenues previously collected (Note 2); and, (iii) an uncertainty regarding civil actions against Gulf States Utilities Company (Note 8). We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Entergy Corporation and Subsidiaries as of December 31, 1994, and the result of their operations and their cash flows for the year then ended in conformity with generally accepted accounting principles. 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, 1994, approximately $685 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 refunds of revenues previously collected. The extent of such write-off of capitalized River Bend costs or refunds 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 or provision for write-off or refund 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 River Bend Joint Ownership Participation and Operating Agreement. The ultimate outcome of these proceedings cannot presently be determined. /s/ Coopers & Lybrand L.L.P. COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 21, 1995, except for the last paragraph of "Filings with the PUCT and Texas Cities" in Note 2, as to which the date is March 20, 1995 INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directors of Entergy Corporation We have audited the accompanying consolidated balance sheet of Entergy Corporation and subsidiaries as of December 31, 1993, and the related statements of consolidated income, retained earnings and paid-in capital, and cash flows for each of the two 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 the results of their operations and their cash flows for each of the two 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 1993 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 1993 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 LLP DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994 ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS
December 31, 1994 1993 (In Thousands) Utility Plant: Electric $21,184,013 $20,848,844 Plant acquisition adjustment - GSU 487,955 380,117 Electric plant under leases 668,846 663,024 Property under capital leases - electric 161,950 175,276 Natural gas 164,013 156,452 Steam products 77,307 75,689 Construction work in progress 476,816 533,112 Nuclear fuel under capital leases 265,520 329,433 Nuclear fuel 70,147 17,760 ----------- ----------- Total 23,556,567 23,179,707 Less - accumulated depreciation and amortization 7,639,549 7,157,981 ----------- ----------- Utility plant - net 15,917,018 16,021,726 ----------- ----------- Other Property and Investments: Decommissioning trust funds 207,395 172,960 Other 240,745 183,597 ----------- ----------- Total 448,140 356,557 ----------- ----------- Current Assets: Cash and cash equivalents: Cash 87,700 27,345 Temporary cash investments - at cost, which approximates market 526,207 536,404 ----------- ----------- Total cash and cash equivalents 613,907 563,749 Special deposits 8,074 36,612 Notes receivable 19,190 17,710 Accounts receivable: Customer (less allowance for doubtful accounts of $6.7 million in 1994 and $8.8 million in 1993) 325,410 315,796 Other 66,651 81,931 Accrued unbilled revenues 240,610 257,321 Fuel inventory 93,211 110,204 Materials and supplies - at average cost 365,956 360,353 Rate deferrals 380,612 333,311 Prepayments and other 98,811 98,144 ----------- ----------- Total 2,212,432 2,175,131 ----------- ----------- Deferred Debits and Other Assets: Regulatory Assets: Rate deferrals 1,451,926 1,876,051 SFAS 109 regulatory asset - net 1,417,646 1,385,824 Unamortized loss on reacquired debt 232,420 210,698 Other regulatory assets 316,878 283,846 Long-term receivables 277,830 228,030 Other 339,201 338,834 ----------- ----------- Total 4,035,901 4,323,283 ----------- ----------- TOTAL $22,613,491 $22,876,697 =========== =========== See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 1994 1993 (In Thousands) Capitalization: Common stock, $0.01 par value, authorized 500,000,000 shares; issued 230,017,485 shares in 1994 and 231,219,737 shares in 1993 $2,300 $2,312 Paid-in capital 4,202,134 4,223,682 Retained earnings 2,223,739 2,310,082 Less - treasury stock (2,608,908 shares in 1994) 77,378 - ----------- ----------- Total common shareholders' equity 6,350,795 6,536,076 Subsidiaries' preference stock 150,000 150,000 Subsidiaries' preferred stock: Without sinking fund 550,955 550,955 With sinking fund 299,946 349,053 Long-term debt 7,093,473 7,355,962 ----------- ----------- Total 14,445,169 14,942,046 ----------- ----------- Other Noncurrent Liabilities: Obligations under capital leases 273,947 322,867 Other 310,977 296,572 ----------- ----------- Total 584,924 619,439 ----------- ----------- Current Liabilities: Currently maturing long-term debt 349,085 322,010 Notes payable 171,867 43,667 Accounts payable 471,120 413,727 Customer deposits 134,478 127,524 Taxes accrued 92,578 118,267 Accumulated deferred income taxes 40,313 73,933 Interest accrued 195,639 210,894 Dividends declared 13,599 13,404 Deferred revenue - gas supplier judgment proceeds - 14,632 Deferred fuel cost 27,066 4,528 Obligations under capital leases 151,904 194,015 Reserve for rate fefund 56,972 - Other 327,330 233,313 ----------- ----------- Total 2,031,951 1,769,914 ----------- ----------- Deferred Credits: Accumulated deferred income taxes 3,915,138 3,829,041 Accumulated deferred investment tax credits 649,898 793,375 Other 986,411 922,882 ----------- ----------- Total 5,551,447 5,545,298 ----------- ----------- Commitments and Contingencies (Notes 2, 8, and 9) TOTAL $22,613,491 $22,876,697 =========== =========== See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Operating Activities: Net income $341,841 $551,930 $437,637 Noncash items included in net income: Cumulative effect of a change in accounting principle - (93,841) - Change in rate deferrals/excess capacity-net 394,344 200,532 109,153 Depreciation and decommissioning 656,896 443,550 424,958 Deferred income taxes and investment tax credits (123,503) 17,669 118,562 Allowance for equity funds used during construction (11,903) (8,049) (7,355) Amortization of deferred revenues (14,632) (42,470) (38,646) Gain on sale of property - net - - (19,612) Changes in working capital: Receivables 22,377 (40,682) (19,150) Fuel inventory 16,993 (1,161) 20,008 Accounts payable 57,393 (9,167) (54,559) Taxes accrued (25,689) (32,761) 28,561 Interest accrued (15,255) (758) (10,845) Reserve for rate refund 56,972 - Other working capital accounts 144,297 51,100 (12,428) Refunds to customers - gas contract settlement - (56,027) (56,066) Decommissioning trust contributions (24,755) (20,402) (20,896) Provision for estimated losses and reserves 22,522 20,832 (24,911) Other 39,869 94,092 (43,185) ---------- ---------- -------- Net cash flow provided by operating activities 1,537,767 1,074,387 831,226 ---------- ---------- -------- Investing Activities: Merger with GSU - cash paid - (250,000) - Merger with GSU - cash acquired - 261,349 - Construction / capital expenditures (676,180) (512,235) (438,845) Allowance for equity funds used during construction 11,903 8,049 7,355 Nuclear fuel purchases (179,932) (118,216) (60,359) Proceeds from sale/leaseback of nuclear fuel 128,675 121,526 62,332 Investment in nonregulated/nonutility properties (49,859) (76,870) (35,189) Proceeds received from sale of property 26,000 - 67,985 Decrease in other temporary investments - 17,012 114,651 ---------- ---------- -------- Net cash flow used in investing activities (739,393) (549,385) (282,070) ---------- ---------- -------- Financing Activities: Proceeds from the issuance of: First mortgage bonds 59,410 605,000 637,114 General and refunding mortgage bonds 24,534 350,000 65,000 Preferred stock - - 120,999 Other long-term debt 164,699 106,070 48,067 Premium and expense on refinancing sale/leaseback bonds (48,497) - - Retirement of: First mortgage bonds (303,800) (911,692) (1,009,320) General and refunding mortgage bonds (45,000) (99,400) - Other long-term debt (148,962) (69,982) (17,412) Repurchase of common stock (119,486) (20,558) (105,673) Redemption of preferred stock (49,091) (56,000) (109,369) Common stock dividends paid (410,223) (287,483) (256,117) Changes in short-term borrowings 128,200 43,000 - ---------- ---------- -------- Net cash flow used in financing activities (748,216) (341,045) (626,711) ---------- ---------- -------- Net increase (decrease) in cash and cash equivalents 50,158 183,957 (77,555) Cash and cash equivalents at beginning of period 563,749 379,792 457,347 ---------- ---------- -------- Cash and cash equivalents at end of period $613,907 $563,749 $379,792 ========== ========== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $660,150 $485,876 $570,199 Income taxes $218,667 $159,659 $125,079 Noncash investing and financing activities: Capital lease obligations incurred $88,574 $126,812 $75,040 Deficiency of fair value of decommissioning trust assets over amount invested ($2,198) - - 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 its business, which requires large investments in long-lived assets. While large capital expenditures for the construction of new generating capacity are not currently planned, the System does require significant capital resources for the periodic maturity of certain series of debt and preferred stock and ongoing construction expenditures. Net cash flow from operations totaled $1,538 million, $1,074 million, and $831 million in 1994, 1993, and 1992, 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 continued efforts to streamline operations and reduce costs as well as collections under Grand Gulf 1 and River Bend 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.) These phase-in plans will continue to contribute to Entergy's cash position for the next several years. 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 for additional information on the System's capital and refinancing requirements in 1995 - 1997. Also, to the extent current market interest and dividend rates allow, the System operating companies and System Energy may continue to refinance high-cost debt and preferred stock prior to maturity. Productive investment by Entergy Corporation of excess funds is necessary to enhance the long-term value of its common stock. In 1994, Entergy Corporation invested in the Hub River Company which is constructing a generating station near Karachi, Pakistan. In 1993, Entergy Corporation invested in an electric distribution company and a high-voltage transmission system in Argentina. In 1992, Entergy Corporation invested in a generating facility in Argentina, an independent power plant in Virginia, a lighting efficiency services company, and a company that develops energy management and other technology applications. Entergy Corporation may invest up to $150 million per year for the next several years in nonregulated business opportunities. 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, 1994, and an assumed annual interest or dividend rate of 9.25%, the System operating companies could have issued bonds or preferred stock in the following amounts, respectively: AP&L - $253 million and $468 million; GSU - $0 million and $0 million; LP&L - $107 million and $784 million; MP&L - $246 million and $95 million; and NOPSI - $89 million and $17 million. System Energy could also have issued $241 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. Although GSU was precluded from issuing first mortgage bonds under its earnings coverage test as of December 31, 1994, GSU has the ability to issue $578 million of first mortgage bonds against the retirement of first mortgage bonds without meeting such 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 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 1995 - 1997 with internally generated funds and cash on hand. Further, Entergy Corporation paid $410.2 million of dividends on its common stock in 1994. Declarations of dividends on common stock are made at the discretion of Entergy Corporation's Board of Directors (Board). It is anticipated that management will not recommend future dividend increases to the Board unless such increases are justified by sustained earnings growth of Entergy Corporation and its subsidiaries. Entergy Corporation receives funds through dividend payments from its subsidiaries. During 1994, these common stock dividend payments totaled $763.4 million. Certain restrictions may limit the amount of these distributions. See Note 7 for additional information. See Notes 2 and 8 for information regarding litigation with Cajun and River Bend rate appeals. Substantial write-offs or charges resulting from adverse rulings in these matters could result in substantial additional net losses being reported by Entergy and GSU in 1995 and subsequent periods, with resulting substantial adverse adjustments to common shareholder's equity. Also, adverse resolution of these matters could adversely affect GSU's ability to continue to pay dividends and obtain financing, which could in turn affect GSU's liquidity. Entergy Corporation has a program to repurchase shares of its outstanding common stock. The timing and amount of such repurchases depend upon market conditions and Board authorization. Entergy Corporation has requested, but not yet received, SEC authorization for a $300 million bank line of credit, the proceeds of which are expected to be used for common stock repurchases, investments in nonregulated and nonutility businesses, and other optional activities. Certain parties have intervened in this proceeding, and the application is pending. See Notes 4 and 5 for additional information. Increasing competition in the utility industry brings an increased need to stabilize costs and reduce retail rates. See "Significant Factors and Known Trends - Competition" for additional information on rate issues affecting the System. On March 20, 1995, the PUCT ordered GSU to implement a $72.9 million annual base rate reduction for the period March 31, 1994, through September 1, 1994, decreasing to an annual base rate reduction of $52.9 million after September 1, 1994. In accordance with the Merger agreement, the rate reduction is applied retroactively to March 31, 1994. As a result, GSU recorded a $57 million reserve for rate refund in 1994. See Note 2 for additional information. In March 1994, the MPSC issued a final order adopting a formulary incentive rate plan. The order also adopted previously agreed-upon stipulations of a required return on equity of 11% and certain accounting adjustments that resulted in a 4.3% ($28.1 million) reduction in MP&L's June 30, 1993, test-year base revenues effective March 25, 1994. The plan allows for periodic small adjustments in rates based on an annual comparison of earned to benchmark rates of return and upon certain other performance factors. See Note 2 for additional information. As discussed in Note 2, NOPSI agreed to reduce electric and gas rates and issue credits and refunds to customers pursuant to the 1994 NOPSI Settlement. Under the terms of the settlement, NOPSI implemented rate reductions totaling $44.9 million effective January 1, 1995. NOPSI will implement an additional $4.4 million rate reduction on October 31, 1995. In addition, the 1994 NOPSI Settlement requires NOPSI to credit its customers $25 million over a 21-month period, beginning January 1, 1995, in order to resolve disputes with the Council regarding the interpretation of the 1991 NOPSI Settlement. The 1994 NOPSI Settlement also required NOPSI to refund $9.3 million of overcollections associated with Grand Gulf 1 operating costs and $10.5 million of refunds associated with the settlement by System Energy of a FERC tax audit. See Note 2 for additional information on the 1994 NOPSI Settlement. As discussed in Note 2, in November 1994, FERC approved an agreement settling a long-standing dispute involving income tax allocation procedures of System Energy. In connection with this settlement, System Energy refunded approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI, which in turn have made or will make refunds or credits to their customers (except for those portions attributable to AP&L's and LP&L's retained share of Grand Gulf 1 costs). Additionally, System Energy will refund a total of approximately $62 million, plus interest, to AP&L, LP&L, MP&L, and NOPSI over the period through June 2004. AP&L, LP&L, MP&L, and NOPSI also wrote off certain related unamortized balances of deferred investment tax credits. See Note 2 for further information on the FERC Settlement. 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. 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. See Note 8 for additional information. ENTERGY CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME
For the Years Ended December 31, 1994 1993 1992 (In Thousands, Except Share Data) Operating Revenues: Electric $5,797,769 $4,394,346 $4,043,555 Natural gas 118,962 90,991 72,944 Steam products 46,559 - - ---------- ---------- ---------- Total 5,963,290 4,485,337 4,116,499 ---------- ---------- ---------- Operating Expenses: Operation and maintenance: Fuel, fuel-related expenses, and gas purchased for resale 1,446,397 912,233 802,682 Purchased power 350,903 278,070 228,679 Nuclear refueling outage expenses 63,979 76,383 87,885 Other operation and maintenance 1,568,810 1,043,838 1,020,894 Depreciation and decommissioning 656,896 443,550 424,958 Taxes other than income taxes 284,234 199,151 197,895 Income taxes 131,965 251,163 210,081 Rate deferrals: Rate deferrals - (1,651) (24,176) Amortization of rate deferrals 391,365 289,259 209,015 ---------- ---------- ---------- Total 4,894,549 3,491,996 3,157,913 ---------- ---------- ---------- Operating Income 1,068,741 993,341 958,586 ---------- ---------- ---------- Other Income (Deductions): Allowance for equity funds used during construction 11,903 8,049 7,355 Miscellaneous - net 20,631 50,957 135,475 Income taxes 241 (33,640) (46,382) ---------- ---------- ---------- Total 32,775 25,366 96,448 ---------- ---------- ---------- Interest Charges: Interest on long-term debt 665,541 503,797 546,805 Other interest - net 22,354 5,740 12,549 Allowance for borrowed funds used during construction (9,938) (5,478) (5,094) Preferred dividend requirements of subsidiaries and other 81,718 56,559 63,137 ---------- ---------- ---------- Total 759,675 560,618 617,397 ---------- ---------- ---------- Income before Cumulative Effect of a Change in Accounting Principle 341,841 458,089 437,637 Cumulative effect to January 1, 1993, of Accruing Unbilled Revenues (net of income taxes of $57,188) - 93,841 - ---------- ---------- ---------- Net Income $341,841 $551,930 $437,637 ========== ========== ========== Earnings per average common share before cumulative effect of a change in accounting principle $1.49 $2.62 $2.48 Earnings per average common share $1.49 $3.16 $2.48 Dividends declared per common share $1.80 $1.65 $1.45 Average number of common shares outstanding 228,734,843 174,887,556 176,573,778 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, 1994 1993 1992 (In Thousands) Retained Earnings, January 1 $2,310,082 $2,062,188 $1,943,298 Add: Net income 341,841 551,930 437,637 ---------- ---------- ---------- Total 2,651,923 2,614,118 2,380,935 ---------- ---------- ---------- Deduct: Dividends declared on common stock 411,806 288,342 255,479 Common stock retirements 13,940 13,906 59,187 Capital stock and other expenses 2,438 1,788 4,081 ---------- ---------- ---------- Total 428,184 304,036 318,747 ---------- ---------- ---------- Retained Earnings, December 31 $2,223,739 $2,310,082 $2,062,188 ========== ========== ========== Paid-in Capital, January 1 $4,223,682 $1,327,589 $1,357,883 Add: Loss on reacquisition of subsidiaries' preferred stock (23) (20) (1,323) Issuance of 56,695,724 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 4,223,659 4,225,909 1,356,560 ---------- ---------- ---------- Deduct: Common stock retirements 22,468 4,389 28,127 Capital stock discounts and other expenses (943) (2,162) 844 ---------- ---------- ---------- Total 21,525 2,227 28,971 ---------- ---------- ---------- Paid-in Capital, December 31 $4,202,134 $4,223,682 $1,327,589 ========== ========== ==========
See Notes to Consolidated Financial Statements ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS On December 31, 1993, GSU became a subsidiary of Entergy Corporation. In accordance with the purchase method of accounting, the results of operations for the 12 months ended December 31, 1993, of Entergy Corporation and subsidiaries reported in its Statements of Consolidated Income and Cash Flows do not include GSU's results of operations. However, the following discussion between the years 1994 and 1993 is presented with GSU's 1993 results of operations included for comparative purposes. The discussion between the years 1993 and 1992 reflects reported results which do not include GSU. In the second half of 1994, Entergy recorded certain charges that significantly affected results of operations as discussed below. These charges included, among other things, the FERC Settlement refund, NOPSI rate reductions and credits, Merger-related costs, and restructuring costs (see Notes 2, 11, and 12). Net Income Consolidated net income decreased $253.4 million in 1994 due primarily to the one-time recording in 1993 of the cumulative effect of the change in accounting principle for unbilled revenues for AP&L, GSU, MP&L, and NOPSI and a base rate reduction ordered by the PUCT applied retroactively to March 31, 1994 (see Note 2). In addition, net income was impacted by a decrease in revenues, increased Merger-related costs, certain restructuring costs, and decreased miscellaneous income - net, partially offset by a decrease in interest on long- term debt and preferred dividend requirements. 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 for AP&L, MP&L, and NOPSI. This increase was partially offset by the effects of implementing SFAS 109 and SFAS 106, and the impact in March 1992 of an after-tax gain from the sale of AP&L's Missouri properties. Significant factors affecting the results of operations and causing variances between the years 1994 and 1993, and 1993 and 1992, are discussed under "Revenues and Sales," "Expenses," and "Other" below. Revenues and Sales See "Selected Financial Data - Five-Year Comparison," following the notes, for information on operating revenues by source and KWH sales. Electric operating revenues decreased in 1994 due primarily to rate reductions/credits at GSU, MP&L, and NOPSI, the effects of the 1994 NOPSI Settlement and the FERC Settlement, and decreased fuel adjustment revenues, partially offset by increased retail energy sales and increased collections of previously deferred Grand Gulf 1-related costs. Electric operating revenues were higher in 1993 due primarily to increased residential and commercial energy sales resulting from favorable weather conditions, increased industrial sales due to improving market conditions 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, partially offset by the impact of a System Energy rate reduction settlement. Expenses Purchased power decreased in 1994 due primarily to decreased power purchases from nonassociated utilities due to changes in generation requirements for the System operating companies. Purchased power increased in 1993 due to increased power purchases from non-associated utilities, resulting from changes in fuel-related costs and increased energy sales. Nuclear refueling outage expenses decreased in 1994 due primarily to Grand Gulf 1 outage expenses incurred in 1993. Nuclear refueling outage expenses decreased in 1993 due primarily to a decrease in the number of scheduled and unscheduled refueling outages. Total income taxes decreased in 1994 due primarily to lower pre-tax book income and the effects of the FERC Settlement. 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. The amortization of rate deferrals increased in 1994 and 1993 due primarily to collection of more Grand Gulf 1-related costs from customers. Interest expense decreased in 1994 due primarily to the refinancing of high-cost debt partially offset by interest recorded on the FERC Settlement. Interest expense decreased in 1993 due primarily to the refinancing of high-cost debt and debt reduction activities. Preferred dividend requirements decreased in 1994 and 1993 due primarily to stock redemption activities. Other Miscellaneous income - net decreased in 1994 due primarily to amortization of plant acquisition adjustment related to the Merger, the adoption of SFAS 116, "Accounting for Contributions Made and Contributions Received" and reduced Grand Gulf 1 carrying charges at AP&L. Miscellaneous income - net decreased in 1993 due primarily to the 1992 pretax gain of approximately $33.7 million from the sale of AP&L's Missouri properties. ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Competition The electric utility industry, including Entergy, is experiencing increased competitive pressures. Entergy is seeking to become a leading competitor in the changing electric energy business. Competition presents Entergy with many challenges. The following have been identified by Entergy as its 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 philosophy is shifting in some jurisdictions from traditional cost-of-service regulation to incentive- rate regulation. Incentive and performance-based rate plans encourage efficiencies and productivity while permitting utilities and their customers to share in the results. MP&L implemented an incentive-rate plan in 1994 and LP&L filed a performance-based formula rate plan with the LPSC in August 1994. GSU agreed to shared-savings plans as part of the Merger. Recognizing that many industrial customers have energy alternatives, Entergy continues to work with these customers to address their needs. In certain cases, competitive prices are negotiated, using variable-rate designs. In a settlement with the Council that was approved on December 29, 1994, NOPSI agreed to reduce electric and gas rates and issue credits and refunds to customers. Effective January 1, 1995, NOPSI implemented a $31.8 million permanent reduction in electric base rates and a $3.1 million permanent reduction in gas base rates. These adjustments resolved issues associated with NOPSI's return on equity exceeding 13.76% for the test year ended September 30, 1994. Under the 1991 NOPSI Settlement, NOPSI is recovering from its retail customers its allocable share of certain costs related to Grand Gulf 1. NOPSI's base rates to recover those costs were derived from estimates of those costs made at that time. Any overrecovery of costs is required to be returned to customers. Grand Gulf 1 has experienced lower operating costs than previously estimated, and NOPSI accordingly is reducing its base rates in two steps to more accurately match the current costs related to Grand Gulf 1. On January 1, 1995, NOPSI implemented a $10 million permanent reduction in base electric rates to reflect the reduced costs related to Grand Gulf 1, to be followed by an additional $4.4 million rate reduction on October 31, 1995. These Grand Gulf 1 rate reductions, which are expected to be largely offset by lower operating costs, may reduce NOPSI's after-tax net income by approximately $1.4 million per year beginning November 1, 1995. The next scheduled Grand Gulf 1 phase-in rate increase in the amount of $4.4 million on October 31, 1995, will not be affected by the 1994 NOPSI Settlement. The 1994 NOPSI Settlement also requires NOPSI to credit its customers $25 million over a 21-month period, beginning January 1, 1995, in order to resolve disputes with the Council regarding the interpretation of the 1991 NOPSI Settlement. NOPSI recorded a $15.4 million net-of-tax reserve associated with the credit in the fourth quarter of 1994. The 1994 NOPSI Settlement further required NOPSI to refund, in December 1994, $13.3 million of credits previously scheduled to be made to customers during the period January 1995 through July 1995. These credits were associated with a July 7, 1994, Council resolution that ordered a $24.95 million rate reduction based on NOPSI's overearnings during the test year ended September 30, 1993. Accordingly, NOPSI recorded an $8 million net-of-tax charge in the fourth quarter of 1994. MP&L's formulary incentive rate plan allows for periodic small adjustments in rates based on a comparison of earned to benchmark returns and upon certain performance factors. In addition, certain previously agreed-upon stipulations of a required return on equity of 11% and certain accounting adjustments resulted in a 4.3% ($28.1 million) reduction in MP&L's revenues effective March 25, 1994. See Note 2 for further information. LP&L's five-year rate freeze expired in March 1994. In August 1994, LP&L filed a performance-based formula rate plan with the LPSC. The proposed formula rate plan would continue existing LP&L rates at current levels, while providing financial incentive to reduce costs and maintain high levels of customer satisfaction and system reliability. Hearings were held in March 1995. See Note 2 for additional information. In connection with the Merger, AP&L and MP&L agreed with their respective retail regulators not to request any general retail rate increases that would take effect before November 1998, with certain exceptions. MP&L also agreed that during this period retail base rates under its formula rate plan would not be increased above the level of rates in effect on November 1, 1993. 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. 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. Under the terms of their respective Merger agreements, the LPSC and PUCT have reviewed GSU's base rates during the first post-Merger earnings analysis. The LPSC ordered a $12.7 million annual rate reduction effective January 1, 1995. GSU received an injunction delaying implementation of $8.3 million of the reduction and on January 1, 1995, reduced rates by $4.4 million. The entire $12.7 million is being appealed. On March 20, 1995, the PUCT ordered a $72.9 million annual base rate reduction for the period March 31, 1994, through September 1, 1994, decreasing to an annual base rate reduction of $52.9 million after September 1, 1994. In accordance with the Merger agreement, the rate reduction is applied retroactively to March 31, 1994. The rate reduction is being appealed and no assurance can be given as to the timing or outcome of the appeal. See Note 2 for further information. Retail wheeling, 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 area of service, is also evolving. Over a dozen states have been or are studying the concept of retail competition. In April 1994, the state of Michigan initiated a five-year experiment that allows limited competition among public utilities. During the same month, the California Public Utilities Commission proposed to deregulate that state's electric power industry, starting on January 1, 1996, to allow the largest industrial customers to select the lowest cost supplier for electricity service. Under the proposal, by the year 2002, smaller companies and residential customers in California would also be able to buy power from any suppliers. The California Public Utilities Commission is currently reviewing its proposal and is expected to make a ruling in the first half of 1995. The retail market for electricity is expected to become more competitive with such moves toward deregulation. In some areas of the country, municipalities (or comparable entities) whose residents are served at retail by an investor-owned utility pursuant to a franchise are exploring the possibility of establishing new or extending existing distribution systems or seeking new delivery points in order to serve retail customers, especially large industrial customers, that currently receive service from an investor-owned utility. These options depend on the terms of a utility's franchise as well as on state law and regulation. In addition, FERC's authority to order utilities to transmit for a new or expanding municipal system is limited in certain respects. Where successful, however, the establishment of a municipal system or the acquisition by a municipal system of a utility's customers could result in the inability to recover costs that the utility has incurred in serving those customers. In mid-1994, FERC issued a notice of proposed rulemaking concerning a regulatory framework for dealing with recovery of stranded costs, such as high- cost nuclear generating units, which may be incurred by electric utilities as a result of increased competition. In addition to addressing recovery of stranded costs related to wholesale service, the proposal requested comment as to recovery of retail stranded costs in transmission rates where state regulatory authorities failed to address the issue or were in conflict. Comments and reply comments have been filed, and the matter is pending. The risk of exposure to stranded costs which may result from competition in the industry will depend on the extent and timing of retail competition, the resolution of jurisdictional issues concerning stranded cost recovery, and the extent to which such costs are recovered from departing or remaining customers, among other matters. Cogeneration projects developed or considered by certain of GSU's 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. In 1994, KWH sales to GSU's industrial customers at non-full cost of service rates, which make up approximately 28% of GSU's total industrial class, increased 13%. Sales to the remaining GSU industrial customers increased 2%. See Note 2 for information with respect to a settlement between System Energy and FERC in which System Energy refunded approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI, which in turn have made or will make refunds or credits to their customers (except for those portions attributable to AP&L's and LP&L's retained share of Grand Gulf 1 costs). Additionally, System Energy will refund a total of approximately $62 million, plus interest, to AP&L, LP&L, MP&L, and NOPSI over the period through June 2004. AP&L, LP&L, MP&L, and NOPSI also wrote off certain related unamortized balances of deferred investment tax credits. 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. On October 31, 1994, as amended on January 25, 1995, Entergy Services filed with FERC revised transmission tariffs intended to provide access to transmission service on the same or comparable basis, terms, and conditions as the System operating companies, and the matter is pending. Open access and market pricing, 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 March 1994, North Little Rock, Arkansas, awarded AP&L a wholesale power contract that will provide estimated revenues of $347 million over 11 years. Under the contract, the price per KWH was reduced 18%, with increases in price through the year 2004. AP&L, which has been serving North Little Rock for over 40 years, was awarded the contract after intense bidding with several competitors. On May 22, 1994, FERC accepted the contract. Rehearings were requested by one of AP&L's competitors and were held in February 1995. The matter is pending. 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. In 1994, Entergy announced a restructuring program related to certain of its operating units. This program is designed to reduce costs and improve operating efficiencies. See Note 12 for further information. Also, in response to an increasingly competitive environment, AP&L, LP&L, MP&L, and NOPSI have announced intentions to revise their initial least-cost planning activities and GSU is continuing to work with the PUCT regarding integrated resource planning. The Energy Policy Act of 1992 The EPAct addresses a wide range of energy issues and is altering the way Entergy and the rest of the electric utility industry operate. The EPAct encourages competition and affords utilities the opportunities and the risks, associated with an open and more competitive market environment. The EPAct creates exemptions from regulation under the Public Utility Holding Company Act of 1935 (Holding Company Act) and creates a class of exempt wholesale generators consisting of utility affiliates and nonutilities that are owners and operators of facilities for the generation and transmission of power for sales at wholesale. The EPAct 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. Both the System operating companies and Entergy Power expect to compete in this market. In addition, the EPAct allows utilities to own and operate foreign generation, transmission, and distribution facilities. See "Nonregulated Investments" below for further information. Public Utility Holding Company Act of 1935 Entergy Corporation, along with 10 other electric utility holding companies, recently asked Congress to repeal the Holding Company Act. The Holding Company Act requires oversight by the SEC of many business practices and activities of utility holding companies and their subsidiaries including, among other things, nonutility activities. Entergy Corporation believes that the Holding Company Act inhibits its ability to compete in the evolving electric energy marketplace, and largely duplicates the oversight activities already performed by FERC and state and local public service commissions. Litigation and Regulatory Proceedings See Note 2 for information on the possible material adverse effects on GSU's financial condition and results of operations 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 ($170 million net of tax) of Texas retail jurisdiction deferred River Bend operating and carrying costs. See Note 8 for information on the bankruptcy proceedings of Cajun and litigation with Cajun concerning Cajun's ownership interest in River Bend and the related possible material adverse effects on GSU's financial condition. Entergy Corporation-GSU Merger The acquisition of GSU by Entergy Corporation was the largest electric utility merger in United States history. Entergy expects to achieve $850 million in fuel cost savings and $670 million in operation and maintenance expense savings over 10 years as a result of the Merger. In 1994, GSU recorded charges associated with certain preacquisition contingencies, severance and augmented retirement costs, and restructuring costs. See Notes 12 and 11 for further information. Although common shareholders experienced some dilution in earnings as a result of the Merger, Entergy believes that the Merger will ultimately be beneficial to common shareholders in terms of strategic benefits as well as economies and efficiencies produced. For further information, see Note 2. Nonregulated Investments Entergy Corporation continues to consider opportunities to expand its utility and utility-related businesses that are not regulated by state and local regulatory authorities (nonregulated businesses). Entergy Corporation's investment strategy is to invest in nonregulated business opportunities that have the potential to earn a greater rate of return than its regulated utility operations, and Entergy Corporation may invest up to approximately $150 million per year for the next several years in nonregulated businesses. Entergy Corporation's nonregulated businesses currently fall into two broad categories: power development and new technology related to the utility business. Entergy Corporation made investments in Argentina's and Pakistan's electric energy infrastructures and is also pursuing additional projects in Central America, South America, Europe, and Asia. Entergy Corporation opened an office in Hong Kong during 1994 and expects to open offices in South America and Europe in 1995. Entergy Corporation is negotiating in China to participate in two power generation projects, Datong and Taishan, which are expected to receive final approval in 1995 or 1996. To date, Entergy Corporation has made no investment in the China projects; however, Entergy Corporation's share of these projects may total approximately $115 million. In addition, Entergy Corporation is exploring the possibility to provide telecommunications services that allow customers to control energy usage. In 1994, Entergy Corporation's nonregulated investments reduced consolidated net income by approximately $31.7 million. In the near term, these investments are unlikely to have a positive effect on earnings; but management believes that these investments will contribute to future earnings growth. ANO Matters ANO 2 experienced a forced outage for repair of certain steam generator tubes in March 1992. Further inspections and repairs were conducted at subsequent refueling and mid-cycle outages in September 1992, May 1993, April 1994, and January 1995. AP&L's budgeted maintenance expenditures were adequate to cover the cost of such repairs. ANO 2's output has been reduced 15 megawatts or 1.6% due to secondary side fouling, tube plugging, and reduction of primary temperature. Entergy Operations continues to take steps at ANO 2 to reduce the number and severity of future tube cracks. In addition, Entergy Operations continues to meet with the NRC to discuss such steps and results of inspections of the generator tubes, as well as the timing of future inspections. Additional inspections are planned for the normal refueling outage scheduled for October 1995. Deregulated Portion of River Bend As of December 31, 1994, GSU had not recovered a significant amount of its investment in, 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 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, 1994, GSU recorded revenues resulting from the sale of electricity from the deregulated asset plan of approximately $34.1 million. Operation and maintenance expenses, including fuel, were approximately $30 million, and depreciation expense associated with the deregulated asset plan investment was approximately $16.7 million for the year ended December 31, 1994. For the year ended December 31, 1994, GSU recorded nonfuel revenue of $32.5 million (included in the $34.1 million of total deregulated asset plan revenue discussed above) which, absent the deregulated asset plan, would not have been realized. The operation and maintenance expenses and depreciation expense allocated to the deregulated asset plan as detailed above would have been incurred at River Bend with or without the deregulated asset plan. The 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. Based on current estimates of the factors discussed above, GSU anticipates that future revenues from the deregulated asset plan will fully recover all related costs. Property Tax Exemptions Exemptions from the payment of Louisiana local property taxes on Waterford 3 and River Bend, which have been in effect for 10 years for each of the plants, will expire in December 1995 and December 1996, respectively. LP&L and GSU are working with taxing authorities to determine the method for calculating the amount of the property taxes to be paid when the exemptions expire. LP&L believes that assessed property taxes will be recovered from its customers through rates. GSU believes that assessed property taxes allocated to its retail jurisdictions will be recovered from those customers through rates. Environmental Issues GSU has been notified by the United States 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 material 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 allegedly resulting from exposure on GSU premises. While the amounts at issue in the cleanup efforts and suits may be substantial, GSU believes that its results of operations and financial condition will not be materially affected by the outcome of the suits. During 1993, the Louisiana Department of Environmental Quality 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 either upgrade or close them. The aggregate cost of the upgrades and closures, to be completed by 1996, is estimated to be $16 million. Accounting Issues Proposed Accounting Standards - The FASB has proposed a SFAS on "Accounting for the Impairment of Long-Lived Assets," effective January 1, 1996. The proposed standard describes circumstances which may result in assets (including goodwill such as the Merger acquisition adjustment, see Note 1) being impaired and provides criteria for recognition and measurement of asset impairment. Note 2 describes regulatory assets of $170 million (net of tax) related to Texas retail deferred River Bend operating and carrying costs. Management believes these deferred costs will be required to be written off under the provisions of the new standard unless there are favorable regulatory or court actions related to these costs prior to the adoption of the new standard by Entergy. Certain other operations of Entergy are potentially affected by this standard, and any resulting write-offs will depend on future operating costs, generating units' efficiency and availability, and the future market for energy over the remaining life of the units. Based on current estimates, Entergy anticipates that future revenues will fully recover the costs of such operations. Continued Application of SFAS 71 - Entergy's financial statements currently reflect, for the most part, assets and costs based on current cost-based ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." As discussed above, the electric utility industry is changing and these changes could possibly result in the discontinuance of the application of SFAS 71, which would result in the elimination of regulatory assets and liabilities. See Note 1 for further information. Accounting for Decommissioning Costs - The FASB is currently reviewing the accounting for decommissioning of nuclear plants. This project could possibly change the System's, as well as the entire utility industry's, accounting for such costs. For further information, see Note 8. 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 Pakistan, Ltd., Entergy Power, Entergy Power Development Corporation, Entergy Richmond Power Corporation, Entergy Services, System Fuels, Entergy Enterprises, Entergy SASI, Entergy S.A., Entergy Argentina S.A, Entergy Transener S.A., Entergy Power Asia, Ltd., Entergy Yacyreta I, Inc., and Entergy Edegel, Inc. 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. GSU is included in all of the consolidated financial statements for 1994. All references made to Entergy or the 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 a LPSC rate order, GSU recorded a deferred credit of $16.6 million for the January 1, 1993, amount of unbilled revenues. See Note 2 regarding recent LPSC rate actions regarding the deferred unbilled revenues. The System operating companies' rate schedules (except GSU's Texas retail 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 in effect until changed as part of a general rate case, fuel reconciliation, or a fixed fuel factor filing. 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. 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. Total System net electric utility plant in service of $14.5 billion as of December 31, 1994, (excluding approximately $0.5 billion of plant acquisition adjustment related to the Merger) includes $9.8 billion of production plant, $1.4 billion of transmission plant, $2.8 billion of distribution plant, and $0.5 billion of other plant. 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 1994 and 1993, and 3.1% in 1992. 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 9.5% for 1994, 10.6% for 1993, and 10.8% for 1992. 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 generating stations to the extent of their respective ownership interests. As of December 31, 1994, 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% (1) $3,366,471 $751,717 River Bend Unit 1 Nuclear 936 70.00% (2) $3,080,019 $617,002 Independence Units 1 and 2 Coal 1,678 56.50% $ 541,893 $170,837 White Bluff Units 1 and 2 Coal 1,660 57.00% $ 400,918 $151,830 Roy S. Nelson Unit 6 Coal 550 70.00% $ 390,033 $145,897 Big Cajun 2 Unit 3 Coal 540 42.00% $ 219,788 $ 74,442
(1) Includes System Energy's ownership and leasehold interests in Grand Gulf 1. (2) See Note 8 regarding the current status of Cajun's 30% undivided ownership interest in River Bend. Income Taxes Entergy Corporation and its subsidiaries file a consolidated federal income tax return. Income taxes are allocated to the System companies in proportion to their contribution to consolidated taxable income. SEC regulations require that no Entergy Corporation subsidiary 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, in 1993 Entergy changed its accounting for income taxes to conform with SFAS 109. Acquisition Adjustment Entergy Corporation, upon completion of the Merger in December 1993 (see Note 12 for additional details), 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. During 1994, the System recorded an additional $115 million of acquisition adjustment related to the resolution of certain preacquisition contingencies and appropriate allocation of purchase price, which combined with the amortization of the acquisition adjustment of $16 million in 1994, resulted in an unamortized balance of $479 million of acquisition adjustment as of December 31, 1994. The acquisition adjustment is being amortized on a straight-line basis over a 31-year period beginning January 1, 1994, which approximates the remaining average book life of the plant acquired as a result of the Merger. The System anticipates that its future net cash flows will be sufficient to recover such amortization. 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. Continued Application of SFAS 71 As a result of the EPAct and actions of regulatory commissions, the electric utility industry is moving toward a combination of competition and a modified regulatory environment. The System's financial statements currently reflect, for the most part, assets and costs based on current cost-based ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Continued applicability of SFAS 71 to the System's financial statements requires that rates set by an independent regulator on a cost-of-service basis (including a reasonable rate of return on invested capital) can actually be charged to and collected from customers. In the event that either all or a portion of a utility's operations cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation or a change in the competitive environment for the utility's regulated services, the utility should discontinue application of SFAS 71 for the relevant portion. That discontinuation should be reported by elimination from the balance sheet of the effects of any actions of regulators recorded as regulatory assets and liabilities. As of December 31, 1994, and for the foreseeable future, the System's financial statements continue to follow SFAS 71, with the exceptions noted below. SFAS 101 SFAS 101, "Accounting for the Discontinuation of Application of FASB 71," specifies how an enterprise that ceases to meet the criteria for application of SFAS 71 to all or part of its operations should report that event in its financial statements. GSU discontinued regulatory accounting principles for its 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 of financial instruments has 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. Entergy adopted the provisions of SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," effective January 1, 1994. As a result, at December 31, 1994, Entergy recorded on the balance sheet a reduction of $2.2 million in decommissioning trust funds, representing the amount by which the fair value of the securities held in such funds is less than amounts for decommissioning recovered in rates and deposited in the funds and the related earnings on the amounts deposited. Due to the regulatory treatment for decommissioning trust funds, the System recorded an offsetting amount in unrealized losses on investment securities as a regulatory asset. 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 prudence, 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 prudence 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 a Texas 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. The Texas Supreme Court's decision stated that all issues relating to the merits of the original PUCT order, including the prudence of all River Bend-related costs, should be addressed in the Rate Appeal. In October 1991, the Texas 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. The court further stated that the PUCT had 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 1994, the Texas Third District Court of Appeals (the Appellate Court) affirmed the district court's decision that there was substantial evidence to support the PUCT's 1988 decision not to include the abeyed construction costs in GSU's rate base. While acknowledging that the PUCT had exceeded its authority when it attempted to defer a decision on the inclusion of those costs in rate base in order to allow GSU a further opportunity to demonstrate the prudence of those costs in a subsequent proceeding, the Appellate Court found that GSU had suffered no harm or lack of due process as a result of the PUCT's error. Accordingly, the Appellate Court held that the PUCT's action had the effect of disallowing the company-wide $1.4 billion of River Bend construction costs for ratemaking purposes. In its August 1994 opinion, the Appellate Court also held that GSU's deferred operating and maintenance costs associated with the allowed portion of River Bend should be included in rate base and that GSU's deferred River Bend carrying costs included in the Allowed Deferrals should also be included in rate base. The Appellate Court's August 1994 opinion affirmed the PUCT's original order in this case. The Appellate Court's August 1994 opinion was entered by two judges, with a third judge dissenting. The dissenting opinion states that the result of the majority opinion is, among other things, to deprive GSU of due process at the PUCT because the PUCT never reached a finding on the $1.4 billion of construction costs. In October 1994, the Appellate Court denied GSU's motion for rehearing on the August 1994 opinion as to the $1.4 billion in River Bend construction costs and other matters. GSU appealed the Appellate Court's decision to the Texas Supreme Court, where it is pending. As of December 31, 1994, the River Bend plant costs disallowed for retail ratemaking purposes in Texas, the River Bend plant costs held in abeyance, and the related operating and carrying cost deferrals totaled (net of taxes) approximately $13 million, $280 million (both net of depreciation), and $170 million, respectively. Allowed Deferrals were approximately $107 million, net of taxes and amortization, as of December 31, 1994. GSU estimates it has collected approximately $158 million of revenues as of December 31, 1994, as a result of the originally ordered rate treatment by the PUCT of these deferred costs. If recovery of the Allowed Deferrals is not upheld, future revenues based upon those allowed deferrals could also be lost, and no assurance can be given as to whether or not refunds of revenue received based upon such deferred costs previously recorded will be required. 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 or reserves 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, 1994, of up to $293 million could be required based on an ultimate adverse ruling by the PUCT on the abeyed and disallowed costs. 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 two 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 reasonably possible that the Allowed Deferrals will continue to be recovered in rates. Management also 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 deferred costs related to the $1.4 billion of abeyed River Bend plant costs will be recovered in rates to the extent that the $1.4 billion of abeyed River Bend plant is recovered. However, a net of tax write-off of the $170 million of deferred costs related to the $1.4 billion of abeyed River Bend plant costs would be required if they are not allowed to be recovered in rates. A proposed accounting standard, "Accounting for the Impairment of Long- Lived Assets," which is expected to become effective January 1, 1996, may require the write-off of the $170 million of rate deferrals discussed above, upon adoption of the standard, unless there are favorable regulatory or court actions related to these costs prior to adoption. 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 AP&L, MP&L, and NOPSI agreed, among other things, 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 for, among other things, increases associated with the 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 the formula rate plan would not be increased above November 1, 1993, levels for a period of five years beginning November 9, 1993 (described below). In 1993, 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 future regulatory filings in November 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 System 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 acquire Cajun's 30% share in River Bend (see Note 8). Formula Rate Plan Under a formulary incentive rate plan (Formula Rate Plan) effective March 25, 1994, MP&L's earned rate of return is calculated automatically every 12 months and compared to and adjusted against a benchmark rate of return (calculated under a separate formula within the Formula Rate Plan). The Formula Rate Plan allows for periodic small adjustments in rates based on a comparison of earned to benchmark returns and upon certain performance factors. In the same proceeding, the MPSC conducted a general review of MP&L's current rates and on March 1, 1994, issued a final order adopting the Formula Rate Plan and previously agreed-upon stipulations of (1) a required return on equity of 11% and (2) certain accounting adjustments that resulted in a 4.3% ($28.1 million) reduction in MP&L's June 30, 1993, test-year base revenues. The MPSC's order required MP&L to file rates designed to provide for this reduction in operating revenues for the test year on or before March 18, 1994, which became effective March 25, 1994. The final order was appealed to the Mississippi Supreme Court on May 17, 1994, by Mississippi Valley Gas Company (MVG) on the grounds that the MPSC issued the final order without having reviewed the cost of MP&L's promotional practices, some of which MVG alleged to be improper. MVG filed a motion to dismiss the appeal, and on October 28, 1994, the Mississippi Supreme Court granted MVG's motion. FERC Settlement In November 1994, FERC approved an agreement settling a long-standing dispute involving income tax allocation procedures of System Energy. In accordance with the agreement, System Energy refunded approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI, which in turn have made or will make refunds or credits to their customers (except for those portions attributable to AP&L's and LP&L's retained share of Grand Gulf 1 costs). Additionally, System Energy will refund a total of approximately $62 million, plus interest, to AP&L, LP&L, MP&L, and NOPSI over the period through June 2004. The settlement also required the write-off of certain related unamortized balances of deferred investment tax credits by AP&L, LP&L, MP&L, and NOPSI. The settlement reduced Entergy Corporation's consolidated net income for the year ended December 31, 1994, by approximately $68.2 million, offset by the write-off of the unamortized balances of related deferred investment tax credits of approximately $69.4 million ($2.9 million for Entergy Corporation; $27.3 million for AP&L; $31.5 million for LP&L; $6 million for MP&L; and $1.7 million for NOPSI). System Energy also reclassified from utility plant to other deferred debits approximately $81 million of other Grand Gulf 1 costs. Although excluded from rate base, System Energy will be permitted to recover such costs over a 10-year period. Interest on the $62 million refund and the loss of the return on the $81 million of other Grand Gulf 1 costs will reduce Entergy's and System Energy's net income by approximately $10 million annually over the next 10 years. As a result of the charges associated with the settlement, System Energy obtained the consent of certain banks (parties to the Reimbursement Agreement) to waive temporarily the fixed charge coverage covenant in the letters of credit and Reimbursement Agreement related to the Grand Gulf 1 sale and leaseback transaction until November 30, 1995. System Energy expects that upon expiration of the waiver period, it will be in compliance with the fixed charge coverage covenant. Absent a waiver, System Energy's failure to perform this covenant 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. 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 were either deferred or recovered currently from customers. 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, 1994, the unamortized balance of these costs was $321 million. Further, GSU deferred approximately $400.4 million of similar costs pursuant to a 1986 LPSC accounting order. These costs, of which approximately $122 million were unamortized as of December 31, 1994, are being amortized over a 10-year period ending in 1997. In accordance with a phase-in plan approved by the LPSC, GSU deferred $294 million of its River Bend costs related to the period February 1988 through February 1991. GSU has amortized $129 million through December 31, 1994, and the remainder of $165 million will be recovered over approximately 3.2 years. AP&L's permanently retained share of Grand Gulf 1 costs is 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 (as of 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, 1994, System Energy's billings for Grand Gulf 1-related costs totaled approximately $475 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. Based on current estimates, Entergy anticipates that future revenues will fully recover all related costs. Filings with the PUCT and Texas Cities In March 1994, the Texas Office of Public Utility Counsel and certain cities served by GSU instituted an investigation of the reasonableness of GSU's rates. In June 1994, GSU provided the cities with information that GSU believed supported the current rate level. GSU filed the same information with the PUCT in June 1994, pursuant to provisions of the Merger. In September 1994, various cities adopted ordinances directing GSU to reduce its Texas retail rates by $45.9 million. GSU appealed the cities' ordinances to the PUCT for a determination of reasonableness of GSU's rates. In November 1994, those cities that intervened in the PUCT appeal filed testimony with the PUCT supporting a $118 million base rate reduction in lieu of the previously proposed $45.9 million reduction. In November 1994, the PUCT staff filed testimony that supported a $38.2 million base rate reduction. GSU filed information with the PUCT that it believed supported the current level of rates. Hearings were held in December 1994 and on March 20, 1995, the PUCT ordered a $72.9 million annual base rate reduction for the period March 31, 1994, through September 1, 1994, decreasing to an annual base rate reduction of $52.9 million after September 1, 1994. In accordance with the Merger agreement, the rate reduction is applied retroactively to March 31, 1994. As a result, GSU recorded a $57 million reserve for rate refund in 1994. The rate reduction is being appealed and no assurance can be given as to the timing or outcome of the appeal. Texas Cities Rate Settlement - 1993 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 provided 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 effective September 1994. Pursuant to the settlement, GSU reduced rates with a $20 million one-time bill credit in December 1993, and refunded approximately $3 million to Texas retail customers on bills rendered in December 1993. The PUCT approved the settlement agreement on July 21, 1994. The cities' rate inquiries were settled earlier on the same terms. LPSC Rate Reviews In May 1994, GSU made the required first post-Merger earnings analysis filing with the LPSC. On December 14, 1994, the LPSC ordered a $12.7 million annual rate reduction for GSU effective January 1995. The rate order included, among other things, a reduction in GSU's Louisiana jurisdictional authorized return on equity from 12.75% to 10.95% and the amortization for the benefit of the customer of $8.3 million of previously deferred unbilled revenue, representing one-half of the total resulting from a change in accounting as discussed in Note 1. On December 28, 1994, GSU received a preliminary injunction from the 19th Judicial District Court regarding $8.3 million of the reduction. On January 1, 1995, GSU reduced rates by $4.4 million. The entire $12.7 million reduction is being appealed and no assurance can be given as to the timing or outcome of the appeal. In August 1994, LP&L filed a performance-based formula rate plan with the LPSC. The proposed formula rate plan would continue existing LP&L rates at current levels, while providing financial incentive to reduce costs and maintain high levels of customer satisfaction and system reliability. A performance rating adjustment feature of the plan would allow LP&L the opportunity to earn a higher rate of return if it improves performance over time. Conversely, if performance declines, the rate of return LP&L could earn would be lowered. This provides financial incentive for LP&L to maintain continuous improvement in all three performance categories (customer price, customer satisfaction, and customer reliability). Under the proposed plan, if LP&L's earnings fall within a bandwidth around a benchmark rate of return, there would be no adjustment in rates. If LP&L's earnings are above the bandwidth, the proposed plan would automatically reduce LP&L's base rates. Alternatively, if LP&L's earnings are below the bandwidth, the proposed plan would automatically increase LP&L's base rates. 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 2% of LP&L's retail revenues. Hearings were held in March 1995. No assurance can be given that the LPSC will accept the performance-based formula rate plan, or that the current rate review will not result in a rate decrease. February 1994 Ice Storm/Rate Rider 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. Repair costs totaled approximately $116.2 million, $30.8 million, and $77.2 million for the System, AP&L, and MP&L, respectively, with $85 million, $18.7 million, and $64.6 million of these amounts capitalized as plant-related costs. The remaining balances have been charged against the respective companies' regulatory storm damage reserves, except for MP&L which recorded a deferred debit. On April 15, 1994, MP&L filed for rate recovery of costs related to the ice storm. MP&L's filing, as subsequently amended, requested recovery of the revenue requirement associated with MP&L's ice storm costs recorded through April 30, 1994, representing approximately 86% of the total estimated ice storm costs. MP&L may make another ice storm rate filing with the MPSC during 1995 to recover ice storm costs recorded by MP&L after April 30, 1994. In August 1994, MP&L and the MPSC's Public Utilities Staff entered into a stipulation with respect to the recovery of ice storm costs recorded through April 30, 1994, and in September 1994, the MPSC approved the stipulation. Under the stipulation, MP&L implemented an ice storm rider schedule, which went into effect on September 29, 1994, that will increase rates approximately $8 million annually for five years. At the end of the five-year period, the revenue requirement associated with the undepreciated ice storm capitalized costs will be included in MP&L's base rates to the extent that this revenue requirement does not result in MP&L's rate of return on rate base being above the benchmark rate of return under MP&L's formula rate plan. PUCT Fuel Cost Review (December 1, 1986 - September 30, 1991) In January 1992, GSU applied to 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 12-month period. In April 1993, the presiding PUCT administrative law judge (ALJ) issued a report concluding 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 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. In that proceeding, the PUCT also set GSU's fixed fuel factor in Texas at 1.84 cents per KWH in response to GSU's request that the factor be set at 2.02 cents per KWH. In October 1993, GSU appealed the PUCT's order to the Travis County District Court where the matter is still pending. No assurance can be given as to the timing or outcome of that appeal. In a subsequent proceeding to review GSU's fuel factor, the PUCT approved GSU's request to further reduce its fixed fuel factor in Texas to 1.78 cents per KWH from 1.84 cents per KWH. PUCT Fuel Cost Review (October 1, 1991 - December 31, 1993) On January 9, 1995, GSU and various parties reached an agreement for the reconciliation of over- and under-recovery of fuel and purchased power expenses for the period October 1, 1991, through December 31, 1993. While the settlement still requires PUCT approval, GSU believes it will ultimately be approved and has accordingly recorded a reserve of $7.6 million. LPSC Fuel Cost Review In November 1993, the LPSC ordered a review of GSU's fuel costs for the period October 1988 through September 1991 (Phase 1) based on the number of outages at River Bend and the findings in the June 1993 PUCT fuel reconciliation case. In July 1994, the LPSC ruled in the Phase 1 fuel review case and ordered GSU to refund approximately $27 million to its customers. Under the order, a refund of $13.1 million, which was not contested under a Louisiana Supreme Court decision as discussed below, was made through a billing credit on August 1994 bills. In August 1994, GSU appealed the remaining portion of the LPSC-ordered refund to the district court. GSU has made no reserve for the remaining portion, pending outcome of the district court appeal, and no assurance can be given as to the timing or outcome of the appeal. On January 18, 1995, GSU met with the special counsel of the LPSC to discuss the procedural schedule for the upcoming fuel review (Phase II). The period under investigation was determined to be from October 1991 to December 1994. Hearings are scheduled to begin in July 1995. In February 1990, the LPSC disallowed the pass-through to ratepayers for the portion of GSU's cost to purchase power from NISCO representing the excess of NISCO's purchase price of the units over GSU's depreciated cost of the units. GSU appealed the 1990 order. In March 1994, the Louisiana Supreme Court ruled in favor of the LPSC. In 1994, GSU recorded an estimated refund provision of $13.1 million, before related income taxes of $5.3 million. 1994 NOPSI Settlement In a settlement with the Council that was approved on December 29, 1994, NOPSI agreed to reduce electric and gas rates and issue credits and refunds to customers. Effective January 1, 1995, NOPSI implemented a $31.8 million permanent reduction in electric base rates and a $3.1 million permanent reduction in gas base rates. These adjustments resolved issues associated with NOPSI's return on equity exceeding 13.76% for the test year ended September 30, 1994. Under the 1991 NOPSI Settlement, NOPSI is recovering from its retail customers its allocable share of certain costs related to Grand Gulf 1. NOPSI's base rates to recover those costs were derived from estimates of those costs made at that time. Any overrecovery of costs is required to be returned to customers. Grand Gulf 1 has experienced lower operating costs than previously estimated, and NOPSI accordingly is reducing its base rates in two steps to more accurately match the current costs related to Grand Gulf 1. On January 1, 1995, NOPSI implemented a $10 million permanent reduction in base electric rates to reflect the reduced costs related to Grand Gulf 1, to be followed by an additional $4.4 million rate reduction on October 31, 1995. These Grand Gulf 1 rate reductions, which are expected to be largely offset by lower operating costs, may reduce NOPSI's after-tax net income by approximately $1.4 million per year beginning November 1, 1995. The next scheduled Grand Gulf 1 phase-in rate increase in the amount of $4.4 million on October 31, 1995, will not be affected by the 1994 NOPSI Settlement. The 1994 NOPSI Settlement also requires NOPSI to credit its customers $25 million over a 21-month period, beginning January 1, 1995, in order to resolve disputes with the Council regarding the interpretation of the 1991 NOPSI Settlement. NOPSI reduced its revenues by $25 million and recorded a $15.4 million net-of-tax reserve associated with the credit in the fourth quarter of 1994. The 1994 NOPSI Settlement further required NOPSI to refund, in December 1994, $13.3 million of credits previously scheduled to be made to customers during the period January 1995 through July 1995. These credits were associated with a July 7, 1994, Council resolution that ordered a $24.95 million rate reduction based on NOPSI's overearnings during the test year ended September 30, 1993. Accordingly, NOPSI recorded an $8 million net-of-tax charge in the fourth quarter of 1994. The 1994 NOPSI Settlement also required NOPSI to refund $9.3 million of overcollections associated with Grand Gulf 1 operating costs, and $10.5 million of refunds associated with the settlement by System Energy of a FERC tax audit. The settlement of the FERC tax audit by System Energy required refunds to be passed on to NOPSI and to other Entergy subsidiaries and then on to customers. These refunds have no effect on current period net income. NOTE 3. INCOME TAXES Income tax expense consisted of the following:
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Current: Federal $227,046 $236,513 $ 99,898 State 50,300 30,618 23,596 -------- -------- -------- Total 277,346 267,131 123,494 -------- -------- -------- Deferred - net: Reclassification due to net operating loss carryforward 48,482 (17,131) 35,969 Rate deferrals - net (137,376) (88,651) (54,079) Gas contract settlement 5,483 9,513 15,180 Liberalized depreciation 127,881 116,513 107,976 Unbilled revenue 7,246 56,315 (18,902) Alternative minimum tax (614) (10,270) 6,577 Bond reacquisition cost (4,481) 17,958 11,496 Nuclear refueling and maintenance 552 (7,929) 9,740 Decontamination and decommissioning fund 2,366 27,303 - Provision for rate refunds (31,739) - - FERC Settlement (23,098) - - Adjustment to Grand Gulf 2 tax basis (14,037) - - Other (35,094) 15,035 (1,595) -------- -------- -------- Total (54,429) 118,656 112,362 -------- -------- -------- Investment tax credit adjustments - net (24,739) (43,796) 20,607 Investment tax credit amortization - FERC settlement (66,454) - - -------- -------- -------- Recorded income tax expense $131,724 $341,991 $256,463 ======== ======== ======== Charged to operations $131,965 $251,163 $210,081 Charged to other income (241) 33,640 46,382 Charged to cumulative effect - 57,188 - -------- -------- -------- Recorded income tax expense 131,724 341,991 256,463 Income taxes applied against the debt component of AFUDC - - 696 -------- -------- -------- Total income taxes $131,724 $341,991 $257,159 ======== ======== ========
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 1994 1993 1992 % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income (Dollars in Thousands) Computed at statutory rate $194,448 35.0 $332,555 35.0 $257,461 34.0 Increases (reductions) in tax resulting from: Amortization of excess deferred income taxes (5,845) (1.1) (7,063) (0.7) (6,537) (0.9) State income taxes net of federal income tax effect 13,766 2.5 30,160 3.2 26,057 3.5 Amortization of investment tax credits (27,337) (4.9) (25,911) (2.7) (26,885) (3.6) Investment tax credit amortization - FERC Settlement (66,454) (12.0) - - - - Depreciation 9,995 1.8 5,925 0.6 4,527 0.6 SFAS 109 adjustment - - 9,547 1.0 - - Other - net 13,151 2.4 (3,222) (0.4) 1,840 0.3 -------- ---- -------- ---- -------- ---- Recorded income tax expense 131,724 23.7 341,991 36.0 256,463 33.9 Income taxes applied against debt component of AFUDC - - - - 696 0.1 -------- ---- -------- ---- -------- ---- Total income taxes $131,724 23.7 $341,991 36.0 $257,159 34.0 ======== ==== ======== ==== ======== ====
Significant components of net deferred tax liabilities as of December 31, 1994 and 1993, were: 1994 1993 Deferred tax liabilities: (In Thousands) Net regulatory assets $(1,645,119) $(1,676,161) Plant-related basis differences (3,092,889) (2,945,933) Rate deferrals (617,699) (767,124) Other (181,743) (167,478) ----------- ----------- Total $(5,537,450) $(5,556,696) =========== =========== Deferred tax assets: Sale and leaseback $ 247,842 $ 241,391 Accumulated deferred investment tax credit 227,473 330,852 Alternative minimum tax credit 137,387 138,063 Removal cost 88,052 92,618 Standard coal plant 29,275 30,165 NOL carryforwards 251,000 307,737 Pension-related items 30,040 24,879 Unbilled revenues 25,328 23,587 Provision for rate refunds 37,838 - Investment tax credit carryforwards 190,987 314,862 Other 316,777 149,568 ----------- ----------- Total $ 1,581,999 $ 1,653,722 =========== =========== Net deferred tax liabilities $(3,955,451) $(3,902,974) =========== =========== As of December 31, 1994, Entergy had federal net operating loss (NOL) carryforwards of $666.7 million and state NOL carryforwards of $498.2 million related to GSU operations. Investment tax credit (ITC) and other credit carryforwards, as of December 31, 1994, amounted to $282.6 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 between 1995 and 2005. It is currently anticipated that approximately $64.4 million will expire unutilized. A valuation allowance has been provided for deferred tax assets relating to that amount. The alternative minimum tax (AMT) credit carryforwards as of December 31, 1994, were $137.4 million. This AMT credit can be carried forward indefinitely and will reduce the System's federal income tax liability in the future. In accordance with the System Energy FERC Settlement, the System wrote off $66.5 million of unamortized deferred investment tax credits in 1994. In 1993, the System adopted SFAS 109. SFAS 109 required 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 required 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. 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. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. In August 1994, Entergy received an Internal Revenue Service report covering the federal income tax audit of Entergy Corporation and subsidiaries for the years 1988 - 1990. The report asserts an $80 million tax deficiency for the 1990 consolidated federal income tax returns related primarily to the application of accelerated investment tax credits associated with Waterford 3 and Grand Gulf nuclear plants. Entergy believes there is no material tax deficiency and is vigorously contesting the proposed assessment. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy to effect short-term borrowings up to an aggregate of $664 million, which may be increased to as much as $1.216 billion (subject to individual authorizations for each company) after further SEC approval. These authorizations are effective through November 30, 1996. As of December 31, 1994, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy had total outstanding borrowings of $91.8 million (including $8 million under the Money Pool arrangement). 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, 1994, GSU had unused lines of credit for short-term borrowings of $5 million from banks within its service territories. Entergy Services has bank lines of credit permitting it to borrow up to $70 million, of which $65 million in borrowings was outstanding as of December 31, 1994. Interest rates associated with AP&L, Entergy Services, GSU, LP&L, and MP&L's lines of credit generally are based on the prime rate, the EURO dollar rate, a certificate of deposit rate, the London interbank offered rate, or a bid rate. Commitment fees on these lines of credit are 0.125% of the amount of available credit. In addition, AP&L, GSU, LP&L, MP&L, NOPSI, System Energy, Entergy Operations, Entergy Services, and System Fuels can borrow from each other and from Entergy Corporation through the Money Pool, an intra-System borrowing arrangement designed to reduce the System's dependence on external short-term borrowings. Entergy Corporation has requested, but not yet received, SEC approval for a $300 million three-year bank line of credit. System Fuels has financing agreements with banks permitting it to borrow up to $65 million, of which $23 million in borrowings was outstanding as of December 31, 1994. Borrowings under System Fuels' financing agreements 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' preferred and preference stock were:
As of December 31, Shares Call Price Per Authorized and Total Share as of Outstanding Dollar Value December 31, 1994 1993 1994 1993 1994 (Dollars in Thousands) Preference Stock Cumulative, without par value 7% Series (1)(2) 6,000,000 6,000,000 $150,000 $150,000 - ========= ========= ======== ======== Preferred Stock Without sinking fund: Cumulative, $100 par value 4.16% - 5.56% Series 1,201,715 1,201,715 $120,172 $120,172 $102.50 to $108.00 6.08% - 8.56% Series 2,262,829 2,262,829 226,283 226,283 $101.80 to $103.78 9.16% - 11.48% Series 425,000 425,000 42,500 42,500 $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 10,369,544 $550,955 $550,955 ========== ========== ======== ======== With sinking fund: Cumulative, $100 par value 7.00% - 9.76% Series 1,935,372 2,126,539 $193,537 $212,654 $100.00 to $106.75 12.00% - 15.44% Series 72,195 117,195 7,219 11,720 $106.00 to $107.72 Adjustable, 7.10% - 7.15% as of December 31, 1993 519,000 553,500 51,900 55,350 $100.00 to $103.00 Cumulative, $25 par value 9.92% - 12.64% Series 1,691,666 2,311,666 42,290 57,791 $25.67 to $27.37 13.28% Series 200,000 461,537 5,000 11,538 $28.22 ---------- ---------- -------- -------- Total with sinking fund 4,418,233 5,570,437 $299,946 $349,053 ========== ========== ======== ========
(1) The total dollar value represents the involuntary liquidation value of $25 per share. (2) These series are not redeemable as of December 31, 1994. The fair value of the System operating companies' preferred and preference stock with sinking fund was estimated to be approximately $437.4 million and $526.2 million as of December 31, 1994 and 1993, respectively. The fair values were 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 of AP&L, GSU, LP&L, MP&L, and NOPSI with and without sinking fund during the last three years were (excluding GSU in 1992): Number of Shares 1994 1993 1992 Preferred Stock Issuances: $100 par value - - 700,000 $25 par value - - 1,480,000 $0.01 par value - - 600,000 Preferred Stock Retirements: $100 par value (270,667) (265,000) (589,940) $25 par value (881,537) (1,180,000) (1,895,160) Cash sinking fund requirements for the next five years for preferred stock outstanding as of December 31, 1994, are (in millions): 1995 - $38.8, 1996 - $23.3, 1997 - $22.6, 1998 - $15.3, and 1999 - $64.8. On December 31, 1993, Entergy Corporation issued 56,695,724 shares of common stock in connection with the Merger. In addition, Entergy Corporation redeemed 174,552,011 shares of $5 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 a program to repurchase shares of its outstanding common stock. The timing and amount of such repurchases depend upon market conditions and authorization from the Board of Directors of Entergy Corporation (Board). Under this program, Entergy Corporation repurchased and retired (returned to authorized but unissued status) 1,230,000 shares at a cost of $30.7 million in 1994, and 3,671,900 shares at a cost of $161.6 million in 1992. No shares were repurchased under the program in 1993. In addition, 2,805,000 shares, 627,000 shares, and 1,943 shares of treasury stock were purchased for cash during 1994, 1993, and 1992, respectively, at a cost of $88.8 million, $20.6 million, and $0.1 million, respectively. A portion of the treasury shares purchased in 1993 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. On December 9, 1994, the Board approved the repurchase of common shares for an aggregate consideration of not in excess of $300 million during the period through January 1996. Entergy Corporation has SEC authorization to acquire 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 18,757, 12,550 and 14,904 during 1994, 1993, and 1992, 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 1994 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 nor more than 10 years after the date of grant. Nonstatutory stock options transactions are summarized as follows: Option Number Price of Options Options granted during 1992 29.625 50,000 Options exercised during 1992 29.625 (5,000) Options granted during 1993: 34.75 70,000 39.75* 6,107 Options exercised during 1993: 29.625 (13,198) 34.75 (5,000) Options granted during 1994 37.00 67,500 Options exercised during 1994 - - ------- Options remaining as of December 31, 1994 170,409 ======= * Options are not currently exercisable at December 31, 1994. Entergy Corporation received SEC authorization in 1994 to issue new shares for the Employee Stock Investment Plan (ESIP) or to acquire, through March 31, 1997, up to 2,000,000 shares of its common stock to be held as treasury shares and reissued to meet the requirements of the ESIP. Under the ESIP, employees may be granted the opportunity to purchase, (for up to 10% of their regular annual salary, (but not more than $25,000)), 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 runs from April 1, 1994, to March 31, 1995. NOTE 6. LONG -TERM DEBT The long-term debt of Entergy Corporation's subsidiaries as of December 31, 1994 and 1993, was:
Maturities Interest Rates From To From To 1994 1993 (In Thousands) First Mortgage Bonds 1995 1999 4-5/8% 14% $1,290,210 $1,354,810 2000 2004 6% 11% 1,282,320 1,143,520 2005 2009 6.65% 10% 335,000 635,000 2015 2019 9-5/8% 11-3/8% 90,319 90,319 2020 2024 7% 10-3/8% 1,083,818 1,083,818 G&R Bonds 1995 1999 5.95% 14.95%* 221,200 284,200 2000 2023 6-5/8% 8.65% 375,000 350,000 Governmental Obligations ** 1992 2008 6.125% 10% 142,622 139,009 2009 2023 5.95% 12.5% 1,499,768 1,481,678 Debentures - Due 1998, 9.72% 200,000 200,000 Long-Term DOE Obligation (Note 8) 105,163 101,029 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 6,879 Unamortized Premium and Discount - Net (43,341) (45,890) ---------- ---------- Total Long-Term Debt 7,442,558 7,677,972 Less Amount Due Within One Year 349,085 322,010 ---------- ---------- Long-Term Debt Excluding Amount Due Within One Year $7,093,473 $7,355,962 ========== ==========
* $20 million of the 14.95% Series G&R Bonds and $9.2 million of the 13.9% Series G&R Bonds were due 2/1/95. All other series are at interest rates within the range of 5.95% - 11.2%. ** Consists of pollution control 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 lease obligations and long-term DOE obligations, as of December 31, 1994 and 1993, was estimated to be $6.293 billion and $7.207 billion, respectively. The fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. For the years 1995, 1996, 1997, 1998, and 1999, Entergy Corporation's subsidiaries have long-term debt maturities (excluding lease obligations) and cash sinking fund requirements aggregating (in millions) $349.1, $558.0, $361.3, $314.9, and $172.4, 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 $20.9 million for each of the years 1995 through 1999. 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 Holding Company Act prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. As of December 31, 1994, Entergy Corporation's subsidiaries had restricted common equity of approximately $4.495 billion, including $497 million of restricted retained earnings, which were unavailable for distribution to Entergy Corporation. In February 1995, Entergy Corporation received common stock dividend payments from its subsidiaries totaling $96.8 million. NOTE 8. COMMITMENTS AND CONTINGENCIES Cajun - River Bend GSU has significant business relationships with Cajun, including co- ownership of River Bend and Big Cajun 2, Unit 3. GSU and Cajun own 70% and 30% undivided interests in River Bend, respectively, and 42% and 58% undivided interests in Big Cajun 2, Unit 3, respectively. In June 1989, Cajun filed a civil action against GSU in the United States District Court for the Middle District of Louisiana (District Court). Cajun's complaint seeks to annul, rescind, terminate, and/or dissolve the Joint Ownership Participation and Operating Agreement entered into on August 28, 1979 (Operating Agreement) relating 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 also seeks to recover Cajun's alleged $1.6 billion investment in the unit as damages, plus attorneys' fees, interest, and costs. Two member cooperatives of Cajun have brought an independent action to declare the 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. A trial without jury on the portion of the suit by Cajun to rescind the Operating Agreement which began in April 1994 has been completed, and an order from the District Court is pending. 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 United States Bankruptcy Code. If GSU prevails in this litigation, there can be no assurance that the Bankruptcy Court will allow funding of all required costs of Cajun's ownership in River Bend. Since 1992 Cajun has not paid its full share of operating and maintenance expenses and other costs for repairs and improvements to River Bend. In addition, certain costs and expenses paid by Cajun were paid under protest. These actions were taken by Cajun based on its contention, which GSU disagrees, that River Bend's operating and maintenance expenses were excessive. In a letter dated October 21, 1994, and at a subsequent meeting, Cajun representatives advised Entergy Corporation and GSU that, on October 25, 1994, Cajun would exhaust its 1994 budget for operating and maintenance expenses for River Bend, and did not make any further payments to GSU in 1994 for River Bend operating, maintenance, or capital costs. Cajun also advised that the RUS (which provided funding to Cajun for its investment in River Bend) would not permit Cajun to budget funds in 1995 to pay its share of operating and maintenance expenses or capital costs for River Bend. However, Cajun stated that it would continue to fund its share of the nuclear decommissioning trust payments for River Bend, as well as insurance and safety-related expenses. The unpaid portion of Cajun's River Bend operating, maintenance, and capital costs for 1994 (which has been fully reserved) was approximately $22.4 million. Cajun's total share of River Bend annual operating (including nuclear fuel) and maintenance expenses and capital costs was approximately $76.1 million in 1994. In view of Cajun's stated expectation that it will fund only a limited portion of its share of River Bend related operating, maintenance, and capital costs, GSU notified Cajun that it would (i) credit GSU's share of expenses for Big Cajun 2, Unit 3 against amounts due from Cajun to GSU and (ii) seek to market Cajun's share of the power from River Bend and apply the proceeds to the amounts due from Cajun to GSU. On November 2, 1994, Cajun discontinued GSU's entitlement of energy from Big Cajun 2, Unit 3. In response, on November 3, 1994, GSU filed pleadings in District Court seeking an order requiring Cajun to provide GSU with the energy from Big Cajun 2, Unit 3 to which GSU is entitled, and holding that GSU is entitled to credit amounts due from GSU to Cajun for Big Cajun 2, Unit 3 against amounts due from Cajun to GSU with respect to River Bend. On December 19, 1994, the District Court issued an injunction prohibiting Cajun from denying its share of energy from Big Cajun 2, Unit 3 and stipulating that GSU must make payments for its portion of expenses for Big Cajun 2, Unit 3 to the registry of the District Court. On December 14, 1994, the LPSC ordered Cajun to decrease the rates charged to its member distribution cooperatives by approximately $30 million per year. The rate decrease is associated with the LPSC's prior finding of imprudence in Cajun's participation in River Bend. On December 21, 1994, Cajun filed a petition in the United States Bankruptcy Court for the Middle District of Louisiana seeking bankruptcy relief under Chapter 11 of the United States Bankruptcy Code. Cajun's bankruptcy could have a material adverse effect on GSU, including the possibility of an NRC action with respect to the operation of River Bend. However, GSU is taking appropriate steps to protect its interests and its claims against Cajun arising from the co-ownership in River Bend and Big Cajun 2, Unit 3. On December 31, 1994, the District Court issued an order lifting an automatic stay as to certain proceedings, with the result that the preliminary injunction granted by the Court on December 19, 1994, remains in effect. Cajun filed a Notice of Appeal on January 18, 1995, to the United States Court of Appeals for the Fifth Circuit seeking a reversal of the District Court's grant of the preliminary injunction. No hearing date has been set on Cajun's appeal. In the bankruptcy proceedings, Cajun filed on January 10, 1995, a motion to reject the River Bend Operating Agreement as a burdensome executory contract. GSU responded on January 10, 1995, with a memorandum opposing Cajun's motion filed with the District Court. This memorandum argues that the motion should be denied because (1) the Operating Agreement is not an executory contract that can be rejected under the United States Bankruptcy Code, but an agreement establishing property rights and obligations; (2) Cajun legally cannot have its payment obligations under the Operating Agreement suspended while retaining the benefits from co-ownership in River Bend, as the benefits and obligations are indivisible; (3) Cajun cannot seek to dispose of its property interest in River Bend or reject the Operating Agreement with respect thereto without disposing of all of its property interests and rejecting all of the arrangements under the River Bend package of agreements consisting of the Operating Agreement, Big Cajun 2, Unit 3 facility, certain transmission lines and the buy-back agreement pursuant to when GSU paid Cajun approximately $600 million for River Bend capacity and energy during the early years of operation of River Bend; and (4) a legal determination of Cajun's obligations and interests in River Bend should only be made as part of a plan of reorganization in bankruptcy and such determination should be subject to regulatory approvals by certain agencies with jurisdiction over Cajun, including the NRC. If the court were to grant Cajun's motion to reject the Operating Agreement, Cajun would be relieved of its financial obligations under the contract, while GSU would likely have a substantial damage claim arising from any such rejection. Although GSU believes that Cajun's motion to reject the Operating Agreement is non-meritorious, it is not possible to predict the outcome or ultimate impact of these proceedings. During the period in which Cajun is not paying its share of River Bend costs, GSU intends to fund all costs necessary for the safe, continuing operation of the unit. The responsibilities of Entergy Operations as the licensed operator of River Bend, for safely operating and maintaining the unit are not affected by Cajun's actions. The total resulting from Cajun's failure to fund repair projects, Cajun's funding limitation on refueling outages, and the weekly funding limitation by Cajun was $55.6 million as of December 31, 1994, compared with $33.3 million as of December 31, 1993. These amounts are reflected in long-term receivables with an offsetting reserve in other deferred credits. Cajun's bankruptcy may affect the ultimate collectibility of the amounts owed to GSU, including any amounts that may be awarded in litigation. In September 1994, in connection with Entergy Corporation's analysis of certain preacquisition contingencies, Entergy Corporation increased its acquisition adjustment and GSU recorded a loss provision associated with the River Bend litigation between GSU and Cajun and certain underpayments by Cajun of River Bend costs, in accordance with SFAS 5, "Accounting for Contingencies." See Note 12 for additional information on provisions for preacquisition contingencies recorded during 1994. Cajun - Transmission Service GSU and Cajun are parties to FERC proceedings relating to transmission service charge disputes. In April 1992, FERC issued a final order. In May 1992, GSU and Cajun filed motions for rehearings which are pending at 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 December 1994, FERC held a hearing to address the issues remanded by the Court of Appeals. In February 1995, FERC clarified its order, eliminating an issue that GSU believes the Court of Appeals directed FERC to reconsider. GSU interprets the 1992 FERC order and the United States Court of Appeals' decision to mean that Cajun would owe GSU approximately $93.3 million as of December 31, 1994. However, FERC's February 1995, order indicates that FERC believes an issue, estimated by GSU to constitute approximately $26.2 million of this amount, may not be pursued by GSU in the remand proceedings. GSU further estimates that if it prevails in its May 1992 motion for rehearing, Cajun would owe GSU approximately $129.6 million as of December 31, 1994. 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 $85.6 million as of December 31, 1994. 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 payment. 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 $160.2 million as of December 31, 1994. This amount is reflected in long-term receivables with an offsetting reserve in other deferred credits. Capital Requirements and Financing Construction expenditures (excluding nuclear fuel) for the years 1995, 1996, and 1997 are estimated to total $568 million, $568 million, and $565 million, respectively. The System will also require $1.4 billion during the period 1995-1997 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. Capital Funds and Availability Agreements 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. 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, 1994, 1993, and 1992, the purchases of electricity from the joint venture totaled $58.3 million, $62.6 million, and $37.8 million, respectively. Nuclear Insurance The Price-Anderson Act limits public liability for a single nuclear incident to approximately $8.92 billion as of December 31, 1994. The System has protection for this liability through a combination of private insurance (currently $200 million each) 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 $79.3 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 allocated in accordance with the respective ownership interests of 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 $16 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, 1994, AP&L, GSU, LP&L, and System Energy each were insured against such losses up to $2.75 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, 1994, the maximum amounts of such possible assessments were: AP&L - $37.2 million; GSU - $22.6 million; LP&L - $34.7 million; MP&L - $0.9 million; NOPSI - $0.5 million; and System Energy - $29.7 million. Under its agreement with System Energy, SMEPA would share in System Energy's obligation. Cajun shares approximately $4.4 million of GSU's obligation. The amount of property insurance presently 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, 1994, of approximately $105 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. Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. In a statement released February 17, 1993, the DOE asserted that it does not have a legal obligation to accept spent nuclear fuel without an operational repository for which it has not yet arranged. Currently the DOE projects it will begin to accept spent fuel no earlier than 2010. In the meantime, all System companies are responsible for spent fuel storage. Current on-site spent fuel storage capacity at River Bend, Waterford 3, and Grand Gulf 1 is estimated to be sufficient until 2003, 2000, and 2004, respectively. Thereafter, the affected companies will provide additional storage. Current on-site spent fuel storage capacity at ANO is estimated to be sufficient until mid-1995, at which time an ANO storage facility using dry casks will begin operation. This facility is estimated to provide sufficient storage until 2000, with the capability of being expanded further as required. 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 expected to be 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. Entergy Operations and System Fuels joined in lawsuits against the DOE, seeking clarification of the DOE's responsibility to receive spent nuclear fuel beginning in 1998. The original suits, filed June 20, 1994, asked for a ruling stating that the Nuclear Waste Policy Act require the DOE to begin taking title to the spent fuel and to start removing it from nuclear power plants in 1998, a mandate for the DOE's nuclear waste management program to begin accepting fuel in 1998 and court monitoring of the program, and the potential for escrow of payments to a nuclear waste fund instead of directly to the DOE. Decommissioning costs for ANO, River Bend (excluding Cajun's 30% share), Waterford 3, and Grand Gulf 1 (excluding Southern Mississippi Electric Power Association's 10% share) were estimated to be approximately $806.3 million (based on a 1994 interim update to the 1992 cost study), $267.8 million (based on a 1991 cost study reflecting 1990 dollars), $320.1 million (based on a 1994 updated study in 1993 dollars), and $365.9 million (based on a 1994 cost study using 1993 dollars), respectively. AP&L is 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. GSU is currently recovering in rates decommissioning costs based on the 1985 original cost study of $141 million. GSU filed a 1991 study with the PUCT requesting a rate adjustment for decommissioning expense. As discussed in Note 2, on March 20, 1995, the PUCT ruled in the current rate case. The PUCT order included recovery of River Bend decommissioning costs totaling $204.9 million. GSU plans to include the 1991 study in its next LPSC rate review scheduled for mid-1995. LP&L currently is recovering in rates decommissioning costs based on a 1988 study update reflecting a cost of $203 million. LP&L filed with the LPSC a request for a rate adjustment for decommissioning expense based on a 1994 cost study update and the matter is under review. System Energy is currently recovering in rates amounts sufficient to fund $198 million (in 1989 dollars) of its decommissioning costs. A filing with FERC to request the updated decommissioning costs in rates is under consideration by System Energy. 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 and reported at market value. 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 $137.4 million, $22.2 million, $28.2 million, and $31.9 million, respectively, as of December 31, 1994. Decommissioning expense amounting to $25.1 million was recorded in 1994. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. Management believes that actual decommissioning costs are likely to be higher than the amounts presented above. The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry, regarding the recognition, measurement, and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. In response to these questions, the FASB is currently reviewing the accounting for decommissioning. If current electric utility industry accounting practices for such decommissioning are changed, annual provisions for decommissioning could increase, the estimated cost for decommissioning could be recorded as a liability rather than as accumulated depreciation, and trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense. The EPAct 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 $3.4 million, $0.9 million, $1.3 million, and $1.4 million (in 1995 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 $75.9 million as of December 31, 1994, is recorded in other current liabilities and other noncurrent liabilities and is offset in the consolidated financial statements by a regulatory asset. ANO Matters ANO 2 experienced a forced outage for repair of certain steam generator tubes in March 1992. Further inspections and repairs were conducted at subsequent refueling and mid-cycle outages in September 1992, May 1993, April 1994, and January 1995. AP&L's budgeted maintenance expenditures were adequate to cover the cost of such repairs. ANO 2's output has been reduced 15 megawatts or 1.6% due to secondary side fouling, tube plugging, and reduction of primary temperature. Entergy Operations continues to take steps at ANO 2 to reduce the number and severity of future tube cracks. In addition, Entergy Operations continues to meet with the NRC to discuss such steps and results of inspections of the steam generator tubes, as well as the timing of future inspections. Additional inspections are planned for the normal refueling outage scheduled for October 1995. Sales/Use Tax Issues In September 1994, the Louisiana Supreme Court (Court) issued an opinion (in a case in which none of the System companies was a party) holding, in part, that the Louisiana state legislature's suspension of state sales and use tax exemptions also had the effect of suspending exemptions from local sales and use taxes. On January 27, 1995 the Court, after rehearing, reversed its opinion. Because of the Court's most recent ruling, sales of electricity and gas, fuels and other items used by GSU, LP&L, and NOPSI to generate electricity in Louisiana, as well as other items exempt from sales and use taxes, continue to be exempt from local sales and use taxes, even though the state exemptions for sales and use tax have been suspended. NOTE 9. LEASES General As of December 31, 1994, 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) 1995 $ 33,008 $65,429 1996 29,054 57,133 1997 24,653 48,861 1998 24,634 47,446 1999 24,610 43,128 Years thereafter 136,294 246,303 --------- -------- Minimum lease payments 272,253 $508,300 ======== Less: Amount representing interest 103,596 -------- Present value of net minimum lease payments $168,657 ======== Rental expense for capital and operating leases (excluding nuclear fuel leases and the sale and leaseback transactions) amounted to approximately $64.8 million, $62.7 million, and $75.5 million in 1994, 1993, and 1992, respectively. Nuclear Fuel Leases AP&L, GSU, LP&L, and System Energy have arrangements to lease nuclear fuel in an aggregate amount up to $430 million as of December 31, 1994. 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, GSU, LP&L, and System Energy of $163.4 million (including interest of $27.3 million) was charged to operations in 1994. Excluding GSU, nuclear fuel expense of $145.8 million and $158.4 million (including interest of $20.5 million and $25.6 million) was charged to operations in 1993 and 1992, 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 1/2-year 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 18, 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. LP&L did 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. As a result, LP&L was required to provide collateral to the Owner Participants for the equity portion of certain amounts payable by LP&L under the lease. Such collateral was in the form of a new series of non-interest bearing first mortgage bonds in the aggregate principal amount of $208.2 million issued by LP&L in September 1994 under its first mortgage bond indenture. As of December 31, 1994, 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) 1995 $ 42,464 $ 32,569 1996 42,753 35,165 1997 42,753 39,805 1998 42,753 41,447 1999 42,753 50,530 Years thereafter 802,820 676,214 ---------- -------- Total $1,016,296 $875,730 ========== ======== 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 1994, 1993, and 1992 pension cost of Entergy Corporation and its subsidiaries (excluding GSU for 1993 and 1992), including amounts capitalized, included the following components:
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Service cost - benefits earned during the period $35,712 $21,760 $18,784 Interest cost on projected benefit obligation 77,943 53,371 50,225 Actual return on plan assets 10,381 (81,708) (43,772) Net amortization and deferral (96,893) 27,261 (8,243) Other 17,963 - - ------- ------- ------- Net pension cost $45,106 $20,684 $16,994 ======= ======= =======
The funded status of Entergy's various pension plans as of December 31, 1994 and 1993 was:
1994 1993 (In Thousands) Actuarial present value of accumulated pension plan obligation: Vested $ 851,194 $ 851,726 Nonvested 6,479 17,867 ---------- ---------- Accumulated benefit obligation $ 857,673 $ 869,593 ========== ========== Plan assets at fair value $1,014,430 $1,059,715 Projected benefit obligation 999,153 1,064,364 ---------- ---------- Plan assets in excess of (less than) projected benefit obligation 15,277 (4,649) Unrecognized prior service cost 25,501 20,288 Unrecognized transition asset (54,209) (61,561) Unrecognized net loss (gain) (9,332) 32,634 ---------- ---------- Accrued pension liability $ (22,763) $ (13,288) ========== ==========
The pension liability for 1993 has been restated in order to make GSU's presentation of certain Early Retirement Plan liabilities consistent with the other System companies. The significant actuarial assumptions used in computing the information above for 1994, 1993, and 1992 (only 1994 and 1993 with respect to GSU's plan), were as follows: weighted average discount rate, 8.5% for 1994, 7.5% for 1993, and 8.25% for 1992; weighted average rate of increase in future compensation levels, 5.1% for 1994 and 5.6% (5% for GSU) for 1993 and 1992; and expected long-term rate of return on plan assets, 8.5% . 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 (excluding GSU) was approximately $13 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, other than MP&L and NOPSI, continue to fund these benefits on a pay-as-you-go basis. During 1994, pursuant to regulatory directives, MP&L and NOSPI began to fund their postretirement benefit obligation. 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 million for Entergy (other than GSU) 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 are 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. Total 1994 and 1993 postretirement benefit cost of Entergy Corporation and its subsidiaries (excluding GSU for 1993), including amounts capitalized and deferred, included the following components: 1994 1993 (In Thousands) Service cost - benefits earned during the period $11,863 $7,751 Interest cost on APBO 23,312 19,394 Return on plan assets - (71) Net amortization and deferral 9,891 12,071 ------- ------- Net periodic postretirement benefit cost $45,066 $39,145 ======= ======= The funded status of Entergy's postretirement plans as of December 31, 1994 and 1993, was: 1994 1993 (In Thousands) Accumulated postretirement benefit obligation: Retirees $ 186,570 $ 221,562 Other fully eligible participants 58,330 68,283 Other active participants 52,324 95,854 --------- --------- 297,224 385,699 Plan assets at fair value 9,733 354 --------- --------- Plan assets less than APBO (287,491) (385,345) Unrecognized transition obligation 217,275 229,346 Unrecognized net loss (gain) (58,178) 28,529 --------- --------- Accrued postretirement benefit liability $(128,394) $(127,470) ========= ========= The assumed health care cost trend rate used in measuring the APBO of the System companies was 9.4% for 1995, gradually decreasing each successive year until it reaches 5.0% in 2011. 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, as of December 31, 1994, by 8.9%, and the sum of the service cost and interest cost by approximately 11.3% . The assumed discount rate and rate of increase in future compensation used in determining the APBO were 8.5% for 1994 and 7.5% for 1993 and 5.1% for 1994 and 5.5% (5% for GSU) for 1993, respectively. NOTE 11. RESTRUCTURING COSTS During the third quarter of 1994, Entergy announced a restructuring program related to certain of its operating units. The program is designed to reduce costs, improve operating efficiencies, and increase shareholder value in order to enable Entergy to become a low-cost producer. The program includes reductions in the number of employees and the consolidation of offices and facilities. In 1994, AP&L, GSU, LP&L, MP&L, and NOPSI recorded restructuring charges of $12.5 million, $6.5 million, $6.8 million, $6.2 million, and $3.4 million, respectively. These charges primarily include employee severance costs related to the expected termination of approximately 1,850 employees. As of December 31, 1994, 35 AP&L employees were terminated under the program at a severance cost of approximately $0.3 million. 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 FERC, the PUCT, and the LPSC. As consideration to GSU's shareholders, Entergy Corporation paid $250 million and issued 56,695,724 shares of its common stock in exchange for the 114,055,065 outstanding shares of GSU common stock. In addition, $33.5 million of transaction costs were capitalized in connection with the Merger. 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. Additionally, GSU recorded $23.8 million in 1994 for remaining severance and augmented retirement benefits related to the Merger. See Note 2 for information regarding Merger-related rate agreements. In 1993, 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. During the allocation period (which expired on December 31, 1994), Entergy Corporation completed its analyses with respect to preacquisition contingencies and revised the allocation of the purchase price for a number of preacquisition contingencies. In 1994, GSU wrote off assets or recorded liabilities totaling approximately $137 million net of tax for the Cajun-River Bend litigation, unfunded Cajun-River Bend costs, environmental cleanup costs, obsolete spare parts, Louisiana River Bend rate deferrals previously disallowed by the LPSC, plant held for future use, and a PUCT fuel reconciliation settlement. Any items recorded in 1995 or later will result in write-offs and/or losses charged to operations on GSU's financial statements and Entergy Corporation's consolidated financial statements. 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 prior to January 1, 1994, as a result of the Merger. The pro forma combined revenues, net income, earnings per common share before extraordinary items, 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 unaudited pro forma information is not necessarily indicative of the results of operations 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 changes $ 2.10 $ 2.26 Earnings per average common share $ 2.57 $ 2.24 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 1994 and 1993 were: Net Earnings Operating Operating Income (Loss) Revenue Income (Loss) per Share (In Thousands, Except Per Share Amounts) 1994: First Quarter $1,406,039 $253,870 $ 70,735 $ 0.31 Second Quarter $1,586,298 $325,935 $144,337 $ 0.63 Third Quarter $1,805,524 $336,611 $143,198 $ 0.63 Fourth Quarter $1,165,429 $152,325 $(16,429) $(0.07) 1993: First Quarter $ 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 See Note 1 for information regarding the recording of the cumulative effect of the change in accounting principle for unbilled revenues in January 1993. ENTERGY CORPORATION AND SUBSIDIARIES SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1994 1993 1992 1991 1990 (In Thousands, Except Per Share Amounts) Operating revenues $ 5,963,290 $ 4,485,337 $ 4,116,499 $ 4,051,429 $ 3,982,062 Income before cumulative effect of a change in accounting principle $ 341,841 $ 458,089 $ 437,637 $ 482,032 $ 478,318 Earnings per share before cumulative effect of a change in accounting principle $ 1.49 $ 2.62 $ 2.48 $ 2.64 $ 2.44 Dividends declared per share $ 1.80 $ 1.65 $ 1.45 $ 1.25 $ 1.05 Return on average common equity 5.31% 12.58% 10.31% 11.57% 11.47% Book value per share, year-end (2) $ 27.93 $ 28.27 $ 24.35 $ 23.46 $ 22.18 Total assets (2) $22,613,491 $22,876,697 $14,239,537 $14,383,102 $14,831,394 Long-term obligations (1)(2) $ 7,817,366 $ 8,177,882 $ 5,630,505 $ 5,801,364 $ 6,395,951
(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).
1994 1993 1992 1991 1990 (Dollars in Thousands) Electric Operating Revenues: Residential $2,126,260 $1,596,480 $1,440,360 $1,463,281 $1,449,768 Commercial 1,499,206 1,072,583 1,007,420 996,619 988,409 Industrial 1,832,916 1,199,172 1,097,023 1,068,802 1,051,796 Governmental 159,694 136,649 127,753 128,762 124,597 ---------- ---------- ---------- ----------- ---------- Total retail 5,618,076 4,004,884 3,672,556 3,657,464 3,614,570 Sales for resale 311,018 293,894 252,288 220,347 212,504 Other (1) (131,325) 95,568 118,711 96,667 67,045 ---------- ---------- ---------- ----------- ---------- Total $5,797,769 $4,394,346 $4,043,555 $3,974,478 $3,894,119 ========== ========== ========== ========== ========== Billed Electric Energy Sales (Millions of KWH): Residential 26,231 18,946 17,549 18,329 18,174 Commercial 20,050 13,420 12,928 13,164 12,977 Industrial 41,030 24,889 23,610 23,466 22,795 Governmental 2,233 1,887 1,839 1,903 1,831 ---------- ---------- ---------- ----------- ---------- Total retail 89,544 59,142 55,926 56,862 55,777 Sales for resale 7,908 8,291 7,979 7,346 6,292 ---------- ---------- ---------- ----------- ---------- Total 97,452 67,433 63,905 64,208 62,069 ========== ========== ========== =========== ==========
(1) 1994 includes the effects of the FERC Settlement, the 1994 NOPSI Settlement, and a GSU reserve for rate refund. Arkansas Power & Light Company 1994 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 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 Services Entergy Services, Inc. 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 EPAct The Energy Policy Act of 1992 FASB Financial Accounting Standards Board 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 (nuclear) Grand Gulf 2 Unit No. 2 of the Grand Gulf Station (nuclear) 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-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 92, "Regulated Enterprises - Accounting for Phase-in Plans" SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the FASB SFAS 106 SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS 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 Entergy Corporation Board of Directors' Audit Committee functions as the Audit Committee for Arkansas Power & Light Company. The Audit Committee is comprised of four directors, who are not officers of AP&L: H. Duke Shackelford (Chairman), Lucie J. Fjeldstad, Dr. Norman C. Francis, and James R. Nichols. The committee held four meetings during 1994. 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 (Coopers & Lybrand L.L.P.) 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/ H. Duke Shackelford H. DUKE SHACKELFORD Chairman, Audit Committee REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Arkansas Power & Light Company We have audited the accompanying balance sheet of Arkansas Power & Light Company as of December 31, 1994, and the related statements of income, retained earnings and cash flows for the year then ended. 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 audit. The financial statements of the Company as of December 31, 1993 and for the years ended December 31, 1993 and 1992, were audited by other auditors, whose report, dated February 11, 1994, included an explanatory paragraph that described changes in methods of accounting for revenues, income taxes and postretirement benefits other than pensions which are discussed in Notes 1, 3 and 10 respectively, to these financial statements. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1994, and the result of its operations and its cash flows for the year then ended in conformity with generally accepted accounting principles. /s/ Coopers & Lybrand L.L.P. COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 21, 1995 INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directors of Arkansas Power & Light Company We have audited the accompanying balance sheet of Arkansas Power & Light Company (AP&L) as of December 31, 1993, and the related statements of income, retained earnings, and cash flows for each of the two 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 the results of its operations and its cash flows for each of the two 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 LLP DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994
ARKANSAS POWER & LIGHT COMPANY BALANCE SHEETS ASSETS December 31, 1994 1993 (In Thousands) Utility Plant: Electric $4,293,097 $4,098,355 Property under capital leases 56,135 62,139 Construction work in progress 136,701 197,005 Nuclear fuel under capital lease 94,628 93,606 ---------- ---------- Total 4,580,561 4,451,105 Less - accumulated depreciation and amortization 1,710,216 1,604,318 ---------- ---------- Utility plant - net 2,870,345 2,846,787 ---------- ---------- Other Property and Investments: Investment in subsidiary companies - at equity 11,215 11,232 Decommissioning trust fund 127,136 108,192 Other - at cost (less accumulated depreciation) 4,628 4,257 ---------- ---------- Total 142,979 123,681 ---------- ---------- Current Assets: Cash and cash equivalents: Cash 3,737 1,825 Temporary cash investments - at cost, which approximates market: Associated companies 4,713 - Other 72,306 - ---------- ---------- Total cash and cash equivalents 80,756 1,825 Accounts receivable: Customer (less allowance for doubtful accounts of $2.0 million in 1994 and $2.1 million in 1993) 53,781 65,641 Associated companies 28,506 18,312 Other 11,181 20,817 Accrued unbilled revenues 83,863 83,378 Fuel inventory - at average cost 34,561 51,920 Materials and supplies - at average cost 79,886 81,398 Rate deferrals 113,630 92,592 Deferred excess capacity 8,414 9,115 Prepayments and other 23,867 28,303 ---------- ---------- Total 518,445 453,301 ---------- ---------- Deferred Debits and Other Assets: Regulatory Assets: Rate deferrals 360,496 475,387 Deferred excess capacity 20,060 28,465 SFAS 109 regulatory asset - net 227,068 234,015 Unamortized loss on reacquired debt 57,344 60,169 Other regulatory assets 68,813 72,360 Other 26,665 39,940 ---------- ---------- Total 760,446 910,336 ---------- ---------- TOTAL $4,292,215 $4,334,105 ========== ========== See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 1994 1993 (In Thousands) Capitalization: Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 1994 and 1993 $470 $470 Paid-in capital 590,844 590,844 Retained earnings 491,799 448,811 ---------- ---------- Total common shareholder's equity 1,083,113 1,040,125 Preferred stock: Without sinking fund 176,350 176,350 With sinking fund 58,527 70,027 Long-term debt 1,293,879 1,313,315 ---------- ---------- Total 2,611,869 2,599,817 ---------- ---------- Other Noncurrent Liabilities: Obligations under capital leases 94,534 94,861 Other 68,235 66,575 ---------- ---------- Total 162,769 161,436 ---------- ---------- Current Liabilities: Currently maturing long-term debt 28,175 3,020 Notes payable: Associated companies - 21,395 Other 34,667 667 Accounts payable: Associated companies 17,345 45,177 Other 89,329 93,611 Customer deposits 17,113 15,241 Taxes accrued 45,239 43,013 Accumulated deferred income taxes 25,043 32,367 Interest accrued 31,064 31,410 Dividends declared 4,727 5,049 Co-owner advances 20,639 39,435 Deferred fuel cost 20,254 16,130 Nuclear refueling reserve 37,954 30,677 Obligations under capital leases 56,154 60,883 Other 45,632 26,034 ---------- ---------- Total 473,335 464,109 ---------- ---------- Deferred Credits: Accumulated deferred income taxes 859,558 876,618 Accumulated deferred investment tax credits 118,548 154,723 Other 66,136 77,402 ---------- ---------- Total 1,044,242 1,108,743 ---------- ---------- Commitments and Contingencies (Notes 2, 8, and 9) TOTAL $4,292,215 $4,334,105 ========== ========== See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1994 1993 1992 (In Thousands) Operating Activities: Net income $142,263 $205,297 $130,529 Noncash items included in net income: Cumulative effect of a change in accounting principle - (50,187) - Change in rate deferrals/excess capacity-net 102,959 84,712 60,344 Depreciation and decommissioning 149,878 135,530 132,459 Deferred income taxes and investment tax credits (54,080) (6,965) (820) Allowance for equity funds used during construction (4,001) (3,627) (4,173) Gain on sale of property - net - - (19,612) Changes in working capital: Receivables 10,817 7,385 (22,281) Fuel inventory 17,359 173 17,039 Accounts payable (32,114) 20,608 (5,393) Taxes accrued 2,226 (21,983) (23,492) Interest accrued (346) 201 (8,041) Other working capital accounts 20,324 26,486 5,249 Decommissioning trust contributions (11,581) (11,491) (13,255) Provision for estimated losses and reserves 16,617 1,963 (21,670) Other (4,744) (41,826) (2,736) -------- -------- -------- Net cash flow provided by operating activities 355,577 346,276 224,147 -------- -------- -------- Investing Activities: Construction expenditures (179,116) (176,540) (179,320) Proceeds from sale of property - - 67,985 Allowance for equity funds used during construction 4,001 3,627 4,173 Nuclear fuel purchases (40,074) (29,156) (34,238) Proceeds from sale/leaseback of nuclear fuel 40,074 29,156 34,238 -------- -------- -------- Net cash flow used in investing activities (175,115) (172,913) (107,162) -------- -------- -------- Financing Activities: Proceeds from issuance of: First mortgage bonds - 445,000 148,114 Preferred Stock - - 14,222 Other long-term debt 27,992 48,070 3,973 Retirement of: First mortgage bonds (800) (441,141) (329,019) Other long-term debt (30,231) (47,700) (1,225) Redemption of preferred stock (11,500) (15,500) (34,388) Changes in short-term borrowings 12,605 17,395 4,000 Dividends paid: Common stock (80,000) (156,300) (75,000) Preferred stock (19,597) (21,362) (23,730) -------- -------- -------- Net cash flow used in financing activities (101,531) (171,538) (293,053) -------- -------- -------- Net increase (decrease) cash and cash equivalents 78,931 1,825 (176,068) Cash and cash equivalents at beginning of period 1,825 - 176,068 -------- -------- -------- Cash and cash equivalents at end of period $80,756 $1,825 - ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $98,787 $103,826 $114,791 Income taxes $79,553 $66,366 $60,987 Noncash investing and financing activities: Capital lease obligations incurred $47,719 $48,513 $37,351 Excess of fair value of decommissioning trust assets over amount invested $1,361 - - 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 its business, which requires large investments in long-lived assets. While large capital expenditures for the construction of new generating capacity are not currently planned, AP&L does require significant capital resources for the periodic maturity of certain series of debt and preferred stock and ongoing construction. Net cash flow from operations totaled $356 million, $346 million, and $224 million in 1994, 1993, and 1992, respectively. Net cash flow from operations increased in 1993 due primarily to increased electric sales and increased collections under the phase-in plan, as discussed below. In recent years, this cash flow, supplemented by issuances of debt, 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 its continued efforts to streamline operations and reduce costs, as well as collections under its 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.) AP&L's Grand Gulf 1 phase-in plan will continue to contribute to AP&L's cash position through 1998. See Note 2 for additional information on AP&L's rate phase-in plan. See Note 8 for additional information on AP&L's capital and refinancing requirements in 1995 - 1997. Also, to the extent current market interest and dividend rates allow, AP&L may continue to refinance high-cost debt and preferred stock prior to maturity. Earnings coverage tests 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, 1994, and an assumed annual interest or dividend rate of 9.25%, AP&L could have issued $253 million of additional first mortgage bonds or $468 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 for information on AP&L's financing activities and Note 4, 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, 1994 1993 1992 (In Thousands) Operating Revenues $1,590,742 $1,591,568 $1,521,129 ---------- ---------- ---------- Operating Expenses: Operation and maintenance: Fuel and fuel-related expenses 261,932 257,983 242,040 Purchased power 328,379 349,718 417,099 Nuclear refueling outage expenses 33,107 30,069 40,512 Other operation and maintenance 390,472 373,758 363,768 Depreciation and decommissioning 149,878 135,530 132,459 Taxes other than income taxes 33,610 28,626 26,709 Income taxes 9,938 18,746 4,058 Amortization of rate deferrals 166,793 160,916 114,711 ---------- ---------- ---------- Total 1,374,109 1,355,346 1,341,356 ---------- ---------- ---------- Operating Income 216,633 236,222 179,773 ---------- ---------- ---------- Other Income (Deductions): Allowance for equity funds used during construction 4,001 3,627 4,173 Miscellaneous - net 48,049 64,884 113,842 Income taxes (19,282) (32,451) (46,531) ---------- ---------- ---------- Total 32,768 36,060 71,484 ---------- ---------- ---------- Interest Charges: Interest on long-term debt 106,001 110,472 121,676 Other interest - net 4,811 9,118 2,308 Allowance for borrowed funds used during construction (3,674) (2,418) (3,256) ---------- ---------- ---------- Total 107,138 117,172 120,728 ---------- ---------- ---------- Income before Cumulative Effect of a Change in Accounting Principle 142,263 155,110 130,529 Cumulative Effect to January 1, 1993 of Accruing Unbilled Revenues (net of income taxes of $31,140) - 50,187 - ---------- ---------- ---------- Net Income 142,263 205,297 130,529 Preferred Stock Dividend Requirements and Other 19,275 20,877 23,202 ---------- ---------- ---------- Earnings Applicable to Common Stock $122,988 $184,420 $107,327 ========== ========== ========== See Notes to Financial Statements. ARKANSAS POWER & LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1994 1993 1992 (In Thousands) Retained Earnings, January 1 $448,811 $420,691 $388,364 Add: Net income 142,263 205,297 130,529 -------- -------- -------- Total 591,074 625,988 518,893 -------- -------- -------- Deduct: Dividends declared: Preferred stock 19,275 20,877 23,202 Common stock 80,000 156,300 75,000 -------- -------- -------- Total 99,275 177,177 98,202 -------- -------- -------- Retained Earnings, December 31 (Note 7) $491,799 $448,811 $420,691 ======== ======== ======== See Notes to Financial Statements. ARKANSAS POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income decreased in 1994 due primarily to the one-time recording in the first quarter of 1993 of the cumulative effect of the change in accounting principle for unbilled revenues and its ongoing effects, and to increased operation and maintenance expenses as a result of restructuring costs and storm damage activity during 1994. 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), and its ongoing effects, partially offset by the effect of the implementation of SFAS 109 (see Note 3) 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. Significant factors affecting the results of operations and causing variances between the years 1994 and 1993, and 1993 and 1992, are discussed under "Revenues and Sales," "Expenses," and "Other" below. Revenues and Sales See "Selected Financial Data - Five-Year Comparison," following the notes, for information on operating revenues by source and KWH sales. Total revenues remained relatively unchanged in 1994. Retail revenue decreased primarily due to lower fuel recovery revenue during the year offset by increased sales for resale to associated companies in 1994, caused by changes in generation availability and requirements among the System operating companies. 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 do not impact net income. Expenses Operating expenses increased in 1994 due primarily to increased other operation and maintenance expenses and increased amortization of rate deferrals partially offset by lower purchased power expenses. Operating expenses increased in 1993 due primarily to higher fuel expense, income tax expense and increased amortization of rate deferrals. Other operation and maintenance expenses increased in 1994 primarily due to the storm damage costs and restructuring costs as discussed in Note 12. The decrease in 1994 purchased power expenses is primarily due to the decrease in the price of purchased power. 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. Total income taxes decreased during 1994 primarily due to the write-off of unamortized deferred investment tax credit of $27.3 million due to a FERC settlement and due to lower pretax income in 1994. This decrease was partially offset by an increase in tax expense due to the true-up of actual income tax expense for 1993 determined during 1994. 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. The amortization of rate deferrals increased in 1993 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. Other Miscellaneous other income - net decreased in 1994 due primarily to reduced Grand Gulf 1 carrying charges. Miscellaneous other income - net decreased in 1993 due primarily to the impact of the pretax gain on the 1992 sale of AP&L's retail properties in Missouri. Other income taxes decreased in 1994 primarily due to a lower pretax income as discussed above. Interest on long-term debt decreased in 1994 and 1993 due primarily to the continued refinancing of high-cost debt. ARKANSAS POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Competition The electric utility industry is becoming increasingly competitive and AP&L is seeking to become a leading competitor in the changing electric energy business. Competition presents AP&L with many challenges. The following have been identified by AP&L as its 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 retail rate increases that would take effect before November 1998, with certain exceptions. See Note 2 for further information. Recognizing that many industrial customers have energy alternatives, AP&L continues to work with these customers to address their needs. In certain cases, competitive prices are negotiated, using variable rate designs. Retail wheeling, 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, is evolving. Over a dozen states have been studying the concept of retail competition. In April 1994, the state of Michigan agreed to a five-year experiment that allows limited competition among public utilities. During the same month, the California Public Utilities Commission proposed to deregulate that state's electric power industry, starting on January 1, 1996, to allow the largest industrial customers to select the lowest cost supplier for electricity service. Under the proposal, by the year 2002, smaller companies and residential customers in California would also be able to buy power from any suppliers. The California Public Utilities Commission is currently reviewing its decision and is expected to make a ruling in the first half of 1995. The retail market for electricity is expected to become more competitive with such moves toward deregulation. In some areas of the country, municipalities (or comparable entities) whose residents are served at retail by an investor-owned utility pursuant to a franchise are exploring the possibility of establishing new or extending existing distribution systems or seeking new delivery points in order to serve retail customers, especially large industrial customers, that currently receive service from an investor-owned utility. These options depend on the terms of a utility's franchise as well as on state law and regulation. In addition, FERC's authority to order utilities to transmit for a new or expanding municipal system is limited in certain respects. Where successful, however, the establishment of a municipal system or the acquisition by a municipal system of a utility's customers could result in the inability to recover costs that the utility has incurred in serving those customers. In mid-1994, the FERC issued a notice of proposed rulemaking concerning a regulatory framework for dealing with recovery of stranded costs, such as high cost nuclear generating units, which may be incurred by electric utilities as a result of increased competition. In addition to addressing recovery of stranded costs related to wholesale service, the proposal requested comment as to recovery of retail stranded costs in transmission rates where state regulatory authorities failed to address the issue or were in conflict. Comments and reply comments have been filed, and the matter is pending. The risk of exposure to stranded costs which may result from competition in the industry will depend on the extent and timing of retail competition, the resolution of jurisdictional issues concerning stranded cost recovery, and the extent to which such costs are recovered from departing or remaining customers, among other matters. 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. On October 31, 1994, as amended on January 25, 1995, Entergy Services filed with FERC revised transmission tariffs intended to provide access to transmission service on the same or comparable basis, terms, and conditions as the System operating companies, and the matter is pending. Open access and market pricing, once in 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 March 1994, North Little Rock, Arkansas, awarded AP&L a wholesale power contract that will provide estimated revenues of $347 million over 11 years. Under the contract, the price per KWH was reduced 18%, with increases in price through the year 2004. AP&L, which has been serving North Little Rock for over 40 years, was awarded the contract after intense bidding with several competitors. On May 22, 1994, FERC accepted the contract. Rehearings were requested by one of AP&L's competitors and were held in February 1995. The matter is pending. 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 become more competitive. In 1994, AP&L announced a restructuring program related to certain of its operating units. This program is designed to reduce costs and improve operating efficiencies. See Note 12 for further information. Also, in response to an increasingly competitive environment, AP&L announced intentions to revise its initial least cost planning activities. The Energy Policy Act of 1992 The EPAct addresses a wide range of energy issues and is altering the way Entergy and the rest of the electric utility industry operate. The EPAct encourages competition and affords utilities the opportunities, and the risks, associated with an open and more competitive market environment. The EPAct creates exemptions from regulation under the Holding Company Act and creates a class of exempt wholesale generators consisting of utility affiliates and nonutilities that are owners and operators of facilities for the generation and transmission of power for sales at wholesale. The EPAct also gives FERC the authority to order investor-owned utilities, including AP&L, 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. Both AP&L and Entergy Power expect to compete in this market. Litigation and Regulatory Proceedings In November 1994, FERC approved an agreement settling a long- standing dispute involving income tax allocation procedures of System Energy. In accordance with the agreement, System Energy refunded approximately $22.2 million to AP&L, which will in turn make refunds or credits to its customers (except for those portions attributable to its retained share of Grand Gulf 1 costs). Additionally, System Energy will refund a total of approximately $22.3 million, plus interest, to AP&L over the period through June 2004. The settlement also required the write-off of approximately $27.3 million of certain related unamortized balances of deferred investment tax credits by AP&L. ANO Matters ANO 2 experienced a forced outage for repair of certain steam generator tubes in March 1992. Further inspections and repairs were conducted at subsequent refueling and mid-cycle outages in September 1992, May 1993, April 1994, and January 1995. AP&L's budgeted maintenance expenditures were adequate to cover the cost of such repairs. ANO 2's output has been reduced 15 megawatts or 1.6% due to secondary side fouling, tube plugging, and reduction of primary temperature. Entergy Operations continues to take steps at ANO 2 to reduce the number and severity of future tube cracks. In addition, Entergy Operations continues to meet with the NRC to discuss such steps and results of inspections of the generator tubes, as well as the timing of future inspections. Additional inspections are planned for the normal refueling outage scheduled for October 1995. Accounting Issues Proposed Accounting Standards - The FASB has proposed a SFAS on "Accounting for the Impairment of Long-Lived Assets," effective January 1, 1996. The proposed standard describes circumstances which may result in assets being impaired and provides criteria for recognition and measurement of asset impairment. Certain operations of AP&L are potentially affected by this standard, and any resulting write-offs will depend on future operating costs, generating units' efficiency and availability, and the future market for energy over the remaining life of the units. Based on current estimates, AP&L anticipates that future revenues will fully recover the costs of such operations. Continued Application of SFAS 71 - AP&L's financial statements currently reflect assets and costs based on current cost-based ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." As discussed above, the electric utility industry is changing and these changes could possibly result in the discontinuance of the application of SFAS 71, which would result in the elimination of regulatory assets and liabilities. See Note 1 for further information. Accounting for Decommissioning Costs - The FASB is currently reviewing the accounting for decommissioning of nuclear plants. This project could possibly change AP&L's, as well as the entire utility industry's, accounting for such costs. For further information, see Note 8. 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. Total AP&L net utility plant in service of $2.64 billion as of December 31, 1994 includes $1.23 billion of production plant, $.43 billion of transmission plant, $.82 billion of distribution plant, and $.16 billion of other plant. 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 1994, 1993 and 1992. 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 9.2%, 10.3%, and 10.5% for 1994, 1993, and 1992, respectively. Jointly-Owned Generating Stations AP&L is a co-owner of 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 the investment and expenses associated with these generating stations to the extent of its ownership interests. As of December 31, 1994, 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 1,660 57.00% $400,918 $151,830 Independence: Unit 1 836 31.50% $116,555 $ 38,594 Common Facilities 15.75% $ 29,331 $ 8,758 Income Taxes AP&L, its parent, and affiliates 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 Entergy Corporation subsidiary 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, in 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. Continued Application of SFAS 71 As a result of the EPAct and actions of regulatory commissions, the electric utility industry is moving toward a combination of competition and a modified regulatory environment. AP&L's financial statements currently reflect assets and costs based on current cost- based ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Continued applicability of SFAS 71 to AP&L's financial statements requires that rates set by an independent regulator on a cost of service basis (including a reasonable rate of return on invested capital) can actually be charged to and collected from customers. In the event that either all or a portion of a utility's operations cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation or a change in the competitive environment for the utility's regulated services, the utility should discontinue application of SFAS 71 for the relevant portion. That discontinuation should be reported by elimination from the balance sheet of the effects of any actions of regulators recorded as regulatory assets and liabilities. As of December 31, 1994, and for the foreseeable future, AP&L's financial statements continue to follow SFAS 71. Fair Value Disclosure The estimated fair value of financial instruments has 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. AP&L adopted the provisions of SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," effective January 1, 1994. As a result, at December 31, 1994, AP&L recorded on the balance sheet an additional $1.4 million in decommissioning trust funds, representing the amount by which the fair value of the securities held in such funds exceeds the amounts for decommissioning recovered in rates and deposited in the funds and the related earnings on the amounts deposited. Due to the regulatory treatment for decommissioning trust funds, AP&L recorded an offsetting amount in unrealized gains on investment securities as a regulatory liability. NOTE 2. RATE AND REGULATORY MATTERS Merger - Related 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 for, among other things, increases associated with the 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 7.92% (stated as a percentage of System Energy's share of Grand Gulf 1) of its Grand Gulf 1-related costs (Retained Share) for 1994 and all succeeding years of commercial operation of the unit; (2) recovers currently 28.08% of such costs 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, 1994, $170 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 prior to January 1, 1996 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 to Union Electric for approximately $68 million. 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. In addition, AP&L 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. February 1994 Ice Storm In early February 1994, an ice storm left more than 97,000 AP&L customers without electric power across the 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. Repair costs totaled approximately $30.8 million with $18.7 million of these amounts capitalized as plant-related costs. The remaining balance has been charged against regulatory storm damage reserves. NOTE 3. INCOME TAXES Income tax expense consisted of the following:
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Current: Federal $64,238 $47,326 $45,932 State 19,062 10,836 11,156 ------- ------- ------- Total 83,300 58,162 57,088 ------- ------- ------- Deferred - net: Liberalized depreciation 9,314 7,074 4,929 Alternative minimum tax 30,601 (2,227) 6,577 Nuclear refueling and maintenance (2,855) (2,161) 7,751 Deferred purchased power costs (42,529) (35,896) (14,375) Deferred excess capacity costs (3,487) (4,044) (3,190) Unbilled revenue 1,330 26,847 (2,474) Bond reacquisition costs (1,108) 14,706 5,184 TCBY Tower (CADC) 44 8,743 - Decontamination and decommissioning fund 676 16,429 - Nuclear reserve (1,537) (37) 1,747 Other (8,388) 5,314 (2,659) ------- ------- ------- Total (17,939) 34,748 3,490 ------- ------- ------- Investment tax credit adjustments - net (8,814) (10,573) (9,989) Investment tax credit amortization - FERC settlement (27,327) - - ------- ------- ------- Recorded income tax expense $29,220 $82,337 $50,589 ======= ======= ======= Charged to operations $9,938 $18,746 $4,058 Charged to other income 19,282 32,451 46,531 Charged to cumulative effect - 31,140 - ------- ------- ------- Recorded income tax expense 29,220 82,337 50,589 Income taxes applied against the debt component of AFUDC - - 1 ------- ------- ------- Total income taxes $29,220 $82,337 $50,590 ======= ======= =======
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, 1994 1993 1992 % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income (Dollars in Thousands) Computed at statutory rate $60,017 35.0 $100,673 35.0 $61,580 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 7,821 4.6 12,119 4.2 7,963 4.4 Amortization of investment tax credits (10,220) (6.0) (11,702) (4.1) (13,285) (7.4) Investment tax credit amortization - FERC settlement (27,327) (15.9) - - - - Depreciation (921) (0.5) (3,156) (1.1) (6,755) (3.7) Reversal of tax contingency - - (3,771) (1.3) - - Flow-through/permanent differences (208) (0.1) (7,669) (2.7) (1,407) (0.8) Other - net 58 - (4,157) (1.4) 2,493 1.4 ------- ---- ------- ---- ------- ---- Recorded income tax expense 29,220 17.1 82,337 28.6 50,589 27.9 Income taxes applied against debt component of AFUDC - - - - 1 - ------- ---- ------- ---- ------- ---- Total income taxes $29,220 17.1 $82,337 28.6 $50,590 27.9 ======= ==== ======= ==== ======= ====
Significant components of AP&L's net deferred tax liabilities as of December 31, 1994 and 1993, were (in thousands): 1994 1993 Deferred tax liabilities: Net regulatory assets $(273,574) $ (294,713) Plant related basis differences (465,787) (458,023) Rate deferrals (183,700) (229,714) Bond reacquisition (22,496) (23,604) Decontamination and decommissioning fund (17,104) (16,429) Other (20,317) (21,414) --------- ----------- Total $(982,978) $(1,043,897) ========= =========== Deferred tax assets: Accumulated deferred investment tax credit $ 46,506 $ 60,698 Nuclear refueling and maintenance 14,889 12,035 Alternative minimum tax credit 3,536 34,137 Standard coal plant 9,214 9,552 Other 24,232 18,490 --------- ----------- Total $ 98,377 $ 134,912 ========= =========== Net deferred tax liabilities $(884,601) $ (908,985) ========= =========== The alternative minimum tax (AMT) credit as of December 31, 1994, was $3.5 million. This AMT credit can be carried forward indefinitely and will reduce AP&L's federal income tax liability in future years. In accordance with a System Energy FERC settlement, AP&L wrote off $27.3 million of unamortized deferred investment tax credits in 1994. In 1993, AP&L adopted SFAS 109. SFAS 109 required 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 required 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. 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. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized AP&L to effect short-term borrowings up to $125 million, which may be increased to as much as $243 million after further SEC approval. This authorization is effective through November 30, 1996. As of December 31, 1994, AP&L had outstanding short-term lines of credit of $34 million from banks within its service territory. Interest rates associated with these lines of credit generally are based on the prime rate, the London interbank offered rate, or a bid rate. Commitment fees on these lines of credit are .125% of the amount of available credit. 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 no outstanding borrowings under the Money Pool arrangement as of December 31, 1994. NOTE 5. PREFERRED STOCK The number of shares and dollar value of AP&L's preferred stock were:
As of December 31, Shares Call Price Per Authorized and Total Share as of Outstanding Dollar Value December 31, 1994 1993 1994 1993 1994 (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 - $ 2,000 - 8.52% Series 375,000 40,000 $37,500 40,000 $106.390 Cumulative, $25 par value: 9.92% Series 641,085 721,085 16,027 18,027 $26.320 13.28% Series 200,000 400,000 5,000 10,000 $28.220 --------- --------- ------- ------- Total with sinking fund 1,216,085 1,541,085 $58,527 $70,027 ========= ========= ======= =======
(1) The total dollar value represents the involuntary liquidation value of $25 per share. (2) These series are not redeemable as of December 31, 1994. The fair value of AP&L's preferred stock with sinking fund was estimated to be approximately $60.6 million and $74.7 million as of December 31, 1994 and 1993, respectively. The fair values were 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, with and without sinking fund, during the last three years were: Number of Shares 1994 1993 1992 Preferred stock issuances: $0.01 par value - - 600,000 Preferred stock retirements: $100 par value (45,000) (85,000) (109,940) $25 par value (280,000) (280,000) (880,000) Cash sinking fund requirements for the next five years for preferred stock outstanding as of December 31, 1994 are (in millions): 1995 - $9.5; 1996 - $4.5; 1997 - $4.5; 1998 - $4.5; and 1999 - $4.5. AP&L has the annual non-cumulative option to redeem, at par, additional amounts of certain series of its outstanding preferred stock. NOTE 6. LONG-TERM DEBT The long-term debt of AP&L as of December 31, 1994 and 1993, was: Maturities Interest Rates From To From To 1994 1993 (In Thousands) First Mortgage Bonds 1995 1999 4-5/8% 9-3/4% $100,960 $100,560 2000 2004 6% 9-3/4% 180,800 182,000 2005 2009 6.25% 7-1/2% 215,000 215,000 2019 2023 7% 10-3/8% 448,818 448,818 Governmental Obligations* 1995 2008 6.125% 10% 53,120 83,290 2009 2021 6.25% 11% 234,004 202,193 Long-Term DOE Obligation (Note 8) 105,163 101,029 Unamortized Premium and Discount - Net (15,811) (16,555) ---------- ---------- Total Long-Term Debt 1,322,054 1,316,335 Less Amount Due Within One Year 28,175 3,020 ---------- ---------- Long-Term Debt Excluding Amount Due $1,293,879 $1,313,315 Within 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, 1994 and 1993 was estimated to be $1,133.6 million and $1,250.8 million, respectively. The fair values were 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 1995, 1996, 1997, 1998 and 1999, AP&L has long-term debt maturities and cash sinking fund requirements (in millions) of $28.2, $28.0, $33.1, $18.7, and $1.2, 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. NOTE 7. DIVIDEND RESTRICTIONS The indenture relating to AP&L's long-term debt and provisions of its 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, 1994, $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, 1995, AP&L paid Entergy Corporation a $32.8 million cash dividend on common stock. NOTE 8. COMMITMENTS AND CONTINGENCIES Capital Requirements and Financing Construction expenditures (excluding nuclear fuel) for the years 1995, 1996, and 1997 are estimated to total $154.9 million each year. AP&L will also require $107 million during the period 1995-1997 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. 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 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 $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. 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. 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, 1994, 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 for supply of coal from a mine in Wyoming and owns certain coal mining equipment and facilities at the mine. Based on estimated reserves, the mine is expected to provide the projected requirements of the Independence Station through at least 2011. 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 64 million have been purchased as of December 31, 1994. Nuclear Insurance The Price-Anderson Act limits public liability for a single nuclear incident to approximately $8.92 billion as of December 31, 1994. 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 $79.3 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, AP&L 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 $6.4 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, 1994, AP&L was insured against such losses up to $2.75 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, 1994, the maximum amount of such possible assessments to AP&L was $37.2 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, 1994, of approximately $105 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. Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. In a statement released February 17, 1993, the DOE asserted that it does not have a legal obligation to accept spent nuclear fuel without an operational repository for which it has not yet arranged. Currently the DOE projects it will begin to accept spent fuel no earlier than 2010. 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 mid-1995, at which time an ANO storage facility using dry casks will begin operation. This facility is estimated to provide sufficient storage until 2000, with the capability of being expanded further as required. The initial cost of providing the additional on- site spent fuel storage capability required at ANO is $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 begins accepting ANO's spent fuel. Entergy Operations and System Fuels joined in lawsuits against the DOE, seeking clarification of the DOE's responsibility to receive spent nuclear fuel beginning in 1998. The original suits, filed June 20, 1994, asked for a ruling stating that the Nuclear Waste Policy Act require the DOE to begin taking title to the spent fuel and to start removing it from nuclear power plants in 1998, a mandate for the DOE's nuclear waste management program to begin accepting fuel in 1998 and court monitoring of the program, and the potential for escrow of payments to the Nuclear Waste Fund instead of directly to the DOE. AP&L is recovering in rates amounts sufficient to fund decommissioning costs for ANO, based on a 1994 interim update to the 1992 decommissioning cost study (in 1992 dollars), of approximately $806.3 million. The 1994 interim update adjusted the 1992 study only for increased cost of low level radioactive waste disposal. The amounts recovered in rates are deposited in external trust funds and reported at market value. The accumulated decommissioning liability of $137.4 million as of December 31, 1994, has been recorded in accumulated depreciation. Decommissioning expense in the amount of $12.2 million was recorded in 1994. 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 estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. Management believes that actual decommissioning costs are likely to be higher than the amounts presented above. The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry regarding the recognition, measurement, and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. In response to these questions, the FASB is currently reviewing the accounting for decommissioning. If current electric utility industry accounting practices for such decommissioning are changed, annual provisions for decommissioning could increase, the estimated cost for decommissioning could be recorded as a liability rather than as accumulated depreciation, and trust fund income from the external decommissioning trusts could be reported as investment income. The EPAct 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 $3.4 million (in 1995 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 $38.9 million as of December 31, 1994, is recorded in other current liabilities and other noncurrent liabilities, and is offset in the financial statements by a regulatory asset. ANO Matters ANO 2 experienced a forced outage for repair of certain steam generator tubes in March 1992. Further inspections and repairs were conducted at subsequent refueling and mid-cycle outages in September 1992, May 1993, April 1994, and January 1995. AP&L's budgeted maintenance expenditures were adequate to cover the cost of such repairs. ANO 2's output has been reduced 15 megawatts or 1.6% due to secondary side fouling, tube plugging, and reduction of primary temperature. Entergy Operations continues to take steps at ANO 2 to reduce the number and severity of future tube cracks. In addition, Entergy Operations continues to meet with the NRC to discuss such steps and results of inspections of the steam generator tubes, as well as the timing of future inspections. Additional inspections are planned for the normal refueling outage scheduled for October 1995. NOTE 9. LEASES As of December 31, 1994, 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) 1995 $13,539 $28,303 1996 11,126 24,217 1997 8,293 15,566 1998 8,293 15,144 1999 8,294 11,552 Years thereafter 48,695 50,685 ------- -------- Minimum lease payments 98,240 $145,467 Less: Amount representing interest 40,587 ======== ------- Present value of net minimum lease payments $57,653 ======= Rental expense for capital and operating leases (excluding the nuclear fuel lease) amounted to approximately $26.4 million, $23.2 million, and $27.4 million in 1994, 1993, and 1992, respectively. Nuclear Fuel Lease AP&L has an arrangement to lease nuclear fuel in an amount 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 1997 and the notes have varying remaining maturities of up to 3 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 $56.2 million, $69.7 million, and $65.5 million (including interest of $7.5 million, $10.6 million, and $11.6 million) was charged to operations in 1994, 1993, and 1992, 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, generally during the last five years before retirement. 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 1994, 1993, and 1992 pension cost, including amounts capitalized, included the following components:
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Service cost - benefits earned during the period $8,854 $7,940 $6,906 Interest cost on projected benefit obligation 22,651 21,744 20,512 Actual return on plan assets 365 (31,984) (16,765) Net amortization and deferral (24,474) 10,531 (3,531) Other - - - ------ ------ ------ Net pension cost $7,396 $8,231 $7,122 ====== ====== ======
The funded status of AP&L's pension plan as of December 31, 1994 and 1993, was:
1994 1993 (In Thousands) Actuarial present value of accumulated pension plan benefits: Vested $238,769 $255,955 Nonvested 1,797 1,724 -------- -------- Accumulated benefit obligation $240,566 $257,679 ======== ======== Plan assets at fair value $283,437 $288,418 Projected benefit obligation 283,256 316,255 -------- -------- Plan assets greater (less than) projected benefit obligation 181 (27,837) Unrecognized prior service cost 6,568 5,841 Unrecognized transition asset (16,350) (18,686) Unrecognized net loss (gain) (12,453) 13,242 -------- -------- Accrued pension liability $(22,054) $(27,440) ======== ========
The significant actuarial assumptions used in computing the information above for 1994, 1993, and 1992 were as follows: weighted average discount rate, 8.5% for 1994, 7.5% for 1993 and 8.25% for 1992; weighted average rate of increase in future compensation levels, 5.1% for 1994 and 5.6% for 1993 and 1992 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. Effective January 1, 1993, AP&L adopted SFAS 106. This standard required 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 1994 and 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components: 1994 1993 (In Thousands) Service cost - benefits earned during the period $3,080 $2,366 Interest cost on APBO 5,510 6,427 Actual return on plan assets - (71) Net amortization and deferral 3,833 3,954 ------- -------- Net postretirement benefit cost $12,423 $ 12,676 ======= ======== The funded status of AP&L's pension plan as of December 31, 1994 and 1993, was: 1994 1993 (In Thousands) Accumulated postretirement benefit obligation: Retirees $49,291 $59,906 Other fully eligible participants 9,876 8,366 Other active participants 12,204 25,038 -------- ------- 71,371 93,310 Plan assets at fair value - 354 -------- ------- Plan assets less than APBO (71,371) (92,956) Unrecognized transition obligation 71,160 75,114 Unrecognized net loss (gain) (16,272) 8,360 -------- ------- Accrued postretirement benefit liability $(16,483) $(9,482) ======== ======= The assumed health care cost trend rate used in measuring the APBO was 9.4% for 1995, gradually decreasing each successive year until it reaches 5.0% in 2011. 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, 1994, by 8.2% and the sum of the service cost and interest cost by approximately 10.8%. The assumed discount rate and rate of increase in future compensation used in determining the APBO were 8.5% for 1994 and 7.5% for 1993 and 5.1% for 1994 and 5.5% for 1993, respectively. NOTE 11. TRANSACTIONS WITH AFFILIATES AP&L buys electricity from and/or sells electricity to the other System operating companies, 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, and receives management and operating services from Entergy Operations. Operating revenues include revenues from sales to affiliates amounting to $238.7 million in 1994, $181.8 million in 1993, and $211.4 million in 1992. Operating expenses include charges from affiliates for fuel costs, purchased power and related charges, management services, and technical and advisory services totaling $310.7 million in 1994, $323.2 million in 1993, and $573.4 million in 1992. Operating expenses also include $25.7 million in 1994, $16.8 million in 1993, and $47.4 million in 1992, 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 $221.2 million in 1994, $226.3 million in 1993, and $292.3 million in 1992. NOTE 12. RESTRUCTURING COSTS During the third quarter of 1994, AP&L announced a restructuring program related to certain of its operating units. The program is designed to reduce costs, improve operating efficiencies, and increase shareholder value in order to enable AP&L to become a low-cost producer. The program includes reductions in the number of employees and the consolidation of offices and facilities. In 1994, AP&L recorded restructuring charges of $12.5 million. These charges primarily include employee severance costs related to the expected termination of approximately 696 employees. As of December 31, 1994, 35 AP&L employees were terminated under the program at a severance cost of $0.3 million. 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 1994 and 1993 were: Operating Operating Net Revenues Income Income (In Thousands) 1994: First Quarter $371,091 $ 44,674 $26,388 Second Quarter $414,901 $ 59,581 $41,763 Third Quarter $470,770 $ 56,163 $36,630 Fourth Quarter $333,980 $ 56,215 $37,482 1993: First Quarter $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 See Note 1 for information regarding the recording of the cumulative effect of the change in accounting principle for unbilled revenues in January 1993.
ARKANSAS POWER & LIGHT COMPANY SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1994 1993 1992 1991 1990 (In Thousands) Operating revenues $1,590,742 $1,591,568 $1,521,129 $1,528,270 $1,481,408 Income before cumulative effect of a change in accounting principle $ 142,263 $ 155,110 $ 130,529 $ 143,451 $ 129,765 Total assets $4,292,215 $4,334,105 $4,038,811 $4,192,020 $4,137,938 Long-term obligations (1) $1,446,940 $1,478,203 $1,453,588 $1,670,678 $1,731,212
(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. 1994 1993 1992 1991 1990 (Dollars in Thousands) Operating Revenues: Residential $506,160 $528,734 $476,090 $494,375 $484,359 Commercial 307,296 306,742 291,367 289,291 283,971 Industrial 338,988 336,856 325,569 324,632 331,929 Governmental 16,698 16,670 17,700 19,731 19,599 ---------- ---------- ---------- ---------- ---------- Total retail 1,169,142 1,189,002 1,110,726 1,128,029 1,119,858 Sales for resale 395,234 379,480 385,028 373,735 339,366 Other 26,366 23,086 25,375 26,506 22,184 ---------- ---------- ---------- ---------- ---------- Total $1,590,742 $1,591,568 $1,521,129 $1,528,270 $1,481,408 ========== ========== ========== ========== ========== Billed Electric Energy Sales (Millions of KWH): Residential 5,522 5,680 5,102 5,564 5,401 Commercial 4,147 4,067 3,841 3,967 3,821 Industrial 5,941 5,690 5,509 5,565 5,532 Governmental 231 230 248 290 285 ------ ------ ------ ------ ------ Total retail 15,841 15,667 14,700 15,386 15,039 Sales for resale 15,497 13,950 15,413 16,087 13,618 ------ ------ ------ ------ ------ Total 31,338 29,617 30,113 31,473 28,657 ====== ====== ====== ====== ====== Gulf States Utilities Company 1994 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 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 Entergy Services Entergy Services, Inc. EPAct The Energy Policy Act of 1992 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 RUS Rural Utility Services (formerly the Rural Electrification Administration or "REA") SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the FASB SFAS 106 SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS 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 Entergy Corporation Board of Directors' Audit Committee functions as the Audit Committee for Gulf States Utilities Company. The Audit Committee is comprised of four directors, who are not officers of GSU: H. Duke Shackelford (Chairman), Lucie J. Fjeldstad, Dr. Norman C. Francis, and James R. Nichols. The committee held four meetings during 1994. 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 Entergy's internal auditors and the independent public accountants (Coopers & Lybrand L.L.P.) 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 Entergy'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/ H. Duke Shackelford H. DUKE SHACKELFORD Chairman, Audit Committee REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Gulf States Utilities Company We have audited the accompanying balance sheets of Gulf States Utilities Company as of December 31, 1994 and 1993 and the related statements of income (loss), retained earnings and paid-in-capital and cash flows for each of the three years in the period ended December 31, 1994. 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 13 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 the Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. As discussed in Note 2 to the financial statements, the net amount of capitalized costs for River Bend Unit I Nuclear Generating Plant (River Bend) exceed those costs currently being recovered through rates. At December 31, 1994, approximately $685 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 refunds of revenues previously collected. The extent of such write-off of capitalized River Bend costs or refunds of revenues previously collected, if any, will not be determined until appropriate rate proceedings and court appeals have been concluded. Accordingly, the accompanying financial statements do not include any adjustments or provision for write-off or refund that might result from the outcome of these uncertainties. 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. 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". 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 L.L.P. COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 21, 1995, except for the last paragraph of "Filings with the PUCT and Texas Cities" in Note 2, as to which the date is March 20, 1995 GULF STATES UTILITIES COMPANY BALANCE SHEETS ASSETS December 31, 1994 1993 (In Thousands) Utility Plant: Electric $6,842,726 $6,825,989 Natural gas 44,505 42,786 Steam products 77,307 75,689 Property under capital leases 82,914 86,039 Construction work in progress 96,176 50,080 Nuclear fuel under capital leases 80,042 94,828 ---------- --------- Total 7,223,670 7,175,411 Less - accumulated depreciation and amortization 2,504,826 2,323,804 ---------- --------- Utility plant - net 4,718,844 4,851,607 ---------- --------- Other Property and Investments: Decommissioning trust fund 21,309 17,873 Other - at cost (less accumulated depreciation) 29,315 29,360 ---------- --------- Total 50,624 47,233 ---------- --------- Current Assets: Cash and cash equivalents: Cash 8,063 3,012 Temporary cash investments - at cost, which approximates market Associated companies 5,085 - Other 91,496 258,337 ---------- --------- Total cash and cash equivalents 104,644 261,349 Accounts receivable: Customer (less allowance for doubtful accounts of $0.7 million in 1994 and $2.4 million in 1993) 167,745 117,369 Associated companies 12,732 - Other 20,706 18,371 Accrued unbilled revenues 39,470 32,572 Deferred fuel costs 6,314 5,883 Accumulated deferred income taxes 49,457 - Fuel inventory 25,784 23,448 Materials and supplies - at average cost 90,054 86,831 Rate deferrals 100,478 90,775 Prepayments and other 13,754 48,948 ---------- ---------- Total 631,138 685,546 ---------- ---------- Deferred Debits and Other Assets: Regulatory Assets: Rate deferrals 506,974 638,015 SFAS 109 regulatory asset - net 426,358 432,411 Unamortized loss on reacquired debt 63,994 70,970 Other regulatory assets 35,168 40,690 Long-term receivables 264,752 218,079 Other 145,609 152,800 ---------- ---------- Total 1,442,855 1,552,965 ---------- ---------- TOTAL $6,843,461 $7,137,351 ========== ========== See Notes to Financial Statements. GULF STATES UTILITIES COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 1994 1993 (In Thousands) Capitalization: Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 100 shares in 1994 and 1993 $114,055 $114,055 Paid-in capital 1,152,336 1,152,304 Retained earnings 264,626 666,401 ---------- --------- Total common shareholder's equity 1,531,017 1,932,760 Preference stock 150,000 150,000 Preferred stock: Without sinking fund 136,444 136,444 With sinking fund 94,934 101,004 Long-term debt 2,318,417 2,368,639 ---------- --------- Total 4,230,812 4,688,847 ---------- --------- Other Noncurrent Liabilities: Obligations under capital leases 125,691 152,359 Other 68,753 65,259 ---------- --------- Total 194,444 217,618 ---------- --------- Current Liabilities: Currently maturing long-term debt 50,425 425 Accounts payable: Associated companies 31,722 2,745 Other 140,975 109,840 Customer deposits 22,216 21,958 Taxes accrued 12,478 22,856 Interest accrued 55,327 59,516 Nuclear refueling reserve 10,117 22,356 Obligations under capital leases 37,265 41,713 Reserve for rate refund 56,972 - Other 111,963 97,741 ---------- --------- Total 529,460 379,150 ---------- --------- Deferred Credits: Accumulated deferred income taxes 1,100,396 1,062,180 Accumulated deferred investment tax credits 199,428 255,274 Deferred River Bend finance charges 82,406 106,765 Other 506,515 427,517 ---------- --------- Total 1,888,745 1,851,736 ---------- --------- Commitments and Contingencies (Notes 2, 8, and 9) TOTAL $6,843,461 $7,137,351 ========== ========== See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1994 1993 1992 (In Thousands) Operating Activities: Net income (loss) ($82,755) $78,862 $133,848 Noncash items included in net income (loss): Extraordinary items - 1,259 9,597 Cumulative effect of a change in accounting principle - (10,660) (4,032) Change in rate deferrals 96,979 61,115 52,946 Depreciation and decommissioning 197,151 190,405 188,393 Deferred income taxes and investment tax credits (62,171) 41,302 50,238 Allowance for equity funds used during construction (1,334) (726) (1,226) Write-off of plant held for future use 85,476 - - Changes in working capital: Receivables (72,341) 6,879 4,373 Fuel inventory (2,336) (2,289) (4,152) Accounts payable 60,112 11,072 (1,171) Taxes accrued (10,378) 3,764 (2,634) Interest accrued (4,189) (2,497) (15,276) Reserve for rate refund 56,972 - - Other working capital accounts 33,781 (9,915) (13,675) Decommissioning trust contributions (3,202) (2,710) (5,912) Purchased power settlement - (169,300) (20,797) Other 34,594 58,874 (22,992) -------- -------- ---------- Net cash flow provided by operating activities 326,359 255,435 347,528 -------- -------- ---------- Investing Activities: Construction expenditures (155,989) (115,481) (97,377) Proceeds received from sale of property - - 12,460 Allowance for equity funds used during construction 1,334 726 1,226 Nuclear fuel purchases (31,178) (2,118) - Proceeds from sale/leaseback of nuclear fuel 29,386 2,118 - Refund of escrow account and other property - 5,921 13,091 -------- -------- ---------- Net cash flow used in investing activities (156,447) (108,834) (70,600) -------- -------- ---------- Financing Activities: Proceeds from the issuance of: First mortgage bonds - 338,379 1,185,260 Other long-term debt 101,109 21,440 48,965 Preference stock - 146,625 - Retirement of: First mortgage bonds - (360,199) (1,067,717) Other long-term debt (102,425) (18,398) (127,161) Redemption of preferred and preference stock (6,070) (174,841) (174,226) Dividends paid: Common stock (289,100) - - Preferred and preference stock (30,131) (35,999) (237,369) -------- -------- ---------- Net cash flow used in financing activities (326,617) (82,993) (372,248) -------- -------- ---------- Net increase (decrease) in cash and cash equivalents (156,705) 63,608 (95,320) Cash and cash equivalents at beginning of period 261,349 197,741 293,061 -------- -------- ---------- Cash and cash equivalents at end of period $104,644 $261,349 $197,741 ======== ======== ========== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $191,850 $197,058 $239,607 Income taxes $251 $15,600 $8,000 Noncash investing and financing activities: Capital lease obligations incurred $31,178 $17,143 $87,022 Deficiency of fair value of decommissioning trust assets over amount invested ($915) - - 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 its business, which requires large investments in long-lived assets. While large capital expenditures for the construction of new generating capacity are not currently planned, GSU does require significant capital resources for the periodic maturity of certain series of debt and preferred stock and ongoing construction expenditures. Net cash flow from operations totaled $326 million, $255 million, and $348 million in 1994, 1993, and 1992, 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, dividends, and debt/preferred stock maturities. GSU's ability to fund these capital requirements with cash from operations, results in part from continued efforts to reduce costs as well as collections under 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.) The River Bend rate phase-in plan will continue to contribute to GSU's cash position through 1998. See Note 2 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 for additional information on GSU's capital and refinancing requirements in 1995 - 1997. Also, to the extent current market interest and dividend rates allow, GSU may continue to refinance high-cost debt and preferred stock prior to maturity. In 1994, GSU paid to Entergy Corporation approximately $289.1 million of cash dividends on its common stock. Prior to 1994, GSU had not paid any cash dividends on its common stock since June 1986. On March 20, 1995, the PUCT ordered GSU to implement a $72.9 million annual base rate reduction for the period March 31, 1994, through September 1, 1994, decreasing to an annual base rate reduction of $52.9 million after September 1, 1994. In accordance with the Merger agreement, the rate reduction is applied retroactively to March 31, 1994. As a result, GSU recorded a $57 million reserve for reserve for rate refund in 1994. See Note 2 for additional information. Earnings coverage tests and bondable property additions limit the amount of first mortgage bonds and preferred stock that GSU can issue. As a result of the charges recorded in 1994 as discussed in Notes 12 and 13, GSU was precluded from issuing first mortgage bonds under its earnings coverage test as of December 31, 1994. As of December 31, 1994, GSU was unable to issue any additional preferred stock. There are no limitations on the issuance of preference stock. However, GSU has the ability to issue approximately $578 million of first mortgage bonds against the retirement of first mortgage bonds without satisfying an earnings coverage test. See Notes 5 and 6 for information on GSU's financing activities and Note 4 for information on GSU's short-term borrowings and lines of credit. See Notes 2 and 8 for information regarding litigation with Cajun, and River Bend rate appeals. Substantial write-offs or charges resulting from adverse rulings in these matters could result in substantial additional net losses being reported by GSU in 1995 and subsequent periods, with resulting substantial adverse adjustments to common shareholder's equity. Also, adverse resolution of 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 (LOSS) For the Years Ended December 31, 1994 1993 1992 (In Thousands) Operating Revenues: Electric $1,719,201 $1,747,961 $1,694,536 Natural gas 31,605 32,466 28,523 Steam products 46,559 47,193 50,315 ---------- ---------- ---------- Total 1,797,365 1,827,620 1,773,374 ---------- ---------- ---------- Operating Expenses: Operation and maintenance: Fuel, fuel-related expenses and gas purchased for resale 517,177 559,416 488,436 Purchased power 203,773 134,936 136,716 Nuclear refueling outage expenses 12,684 10,706 29,087 Other operation and maintenance 494,865 458,677 409,378 Depreciation and amortization 197,151 190,405 188,393 Taxes other than income taxes 98,096 95,742 91,740 Income taxes (6,448) 46,007 38,058 Amortization of rate deferrals 66,416 61,115 52,946 ---------- ---------- ---------- Total 1,583,714 1,557,004 1,434,754 ---------- ---------- ---------- Operating Income 213,651 270,616 338,620 ---------- ---------- ---------- Other Income (Deductions): Allowance for equity funds used during construction 1,334 726 1,226 Write-off of plant held for future use (85,476) - - Miscellaneous - net (64,843) 19,996 64,837 Income taxes 55,638 (12,009) (17,801) ---------- ---------- ---------- Total (93,347) 8,713 48,262 ---------- ---------- ---------- Interest Charges: Interest on long-term debt 195,414 202,235 239,341 Other interest - net 8,720 8,364 9,075 Allowance for borrowed funds used during construction (1,075) (731) (947) ---------- ---------- ---------- Total 203,059 209,868 247,469 ---------- ---------- ---------- Income (Loss) before Extraordinary Items and the Cumulative Effect of Accounting Changes (82,755) 69,461 139,413 Extraordinary Items (net of income taxes) - (1,259) (9,597) Cumulative Effect of Accounting Changes (net of income taxes) (Note 1) - 10,660 4,032 ---------- ---------- ---------- Net Income (Loss) (82,755) 78,862 133,848 Preferred and Preference Stock Dividend Requirements and Other 29,919 35,581 49,702 ---------- ---------- ---------- Earnings (Loss) Applicable to Common Stock ($112,674) $43,281 $84,146 ========== ========== ========== See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Retained Earnings, January 1 $ 666,401 $ 631,462 $ 667,893 Add: Net income (loss) (82,755) 78,862 133,848 ---------- ---------- ---------- Total 583,646 710,324 801,741 ---------- ---------- ---------- Deduct: Dividends declared: Preferred and preference stock 29,831 35,581 158,547 Common stock 289,100 - - Preferred and preference stock redemption 89 8,342 11,732 ---------- ---------- ---------- Total 319,020 43,923 170,279 ---------- ---------- ---------- Retained Earnings, December 31 (Note 7) $264,626 $ 666,401 $631,462 ========== ========== ========== Paid-in Capital, January 1 $1,152,304 $67,316 $73,993 Add: 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 - 1,086,868 - Gain (loss) on reacquisition of preferred and preference stock 32 (1,880) (6,677) ---------- ---------- ---------- Paid-in Capital, December 31 $1,152,336 $1,152,304 $67,316 ========== ========== ==========
See Notes to Financial Statements. GULF STATES UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income GSU incurred a net loss for the year 1994 due primarily to write- offs and charges associated with the resolution of certain contingencies and additional Merger-related costs aggregating $137 million (see Note 13), a base rate reduction ordered by the PUCT applied retroactively to March 1994 (see Note 2), and restructuring costs (see Note 12). 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, the effect of implementing SFAS 106, 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 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, an increase of $29.6 million which is due primarily to increased retail energy sales and decreased interest expense. Significant factors affecting the results of operations and causing variances between the years 1994 and 1993, and 1993 and 1992 are discussed under "Revenues and Sales," "Expenses," and "Other" below. Revenues and Sales Operating revenues decreased in 1994 due primarily to a base rate reduction ordered by the PUCT applied retroactively to March 1994 (see Note 2) and lower retail fuel revenues partially offset by increased wholesale revenues associated with higher sales for resale and increased retail base revenue. The decrease in retail revenues is primarily due to a decrease in fuel recovery revenue and a November 1993 rate reduction in Texas. Energy sales increased due primarily to higher sales for resale as a result of GSU's participation in the System power pool. 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. See "Selected Financial Data - Five-Year Comparison," following the notes, for information on operating revenues by source and KWH sales. Expenses Operating expenses increased in 1994 due primarily to higher purchased power and other operation and maintenance expenses, partially offset by lower fuel for electric generation and fuel- related expense and lower income tax expense. Purchased power increased in 1994 due to GSU's participation in joint dispatching through the System power pool resulting from increased energy sales as discussed above. In addition, the increase in purchased power expense in 1994 was also due to the recording of a provision for refund of disallowed purchased power costs resulting from a Louisiana Supreme Court ruling (see Note 2). Fuel, fuel-related expenses and gas purchased for resale decreased in 1994 primarily due to lower gas prices. 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 at River Bend. Other operation and maintenance expenses increased in 1994 due primarily to charges associated with certain contingencies as discussed in Note 13, additional Merger-related costs and restructuring costs as discussed in Note 12. Other operation and maintenance 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. Amortization of amounts in accordance with the River Bend phase-in plan also increased. Income taxes decreased in 1994 due primarily to lower pretax income resulting from the charges discussed above. Other Other miscellaneous income decreased due to the write-off of plant held for future use in 1994 (see Note 13), establishment of a reserve related to the Cajun River Bend litigation (see Note 8), the write-off of previously disallowed rate deferrals, and obsolete spare parts, partially offset by lower interest expense as a result of the continued refinancing of high-cost debt. Income taxes decreased in 1994 due primarily to the charges discussed above. Other miscellaneous income decreased in 1993 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 as a result of the continued refinancing of high-cost debt. GULF STATES UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Competition The electric utility industry is becoming increasingly competitive and GSU is seeking to become a leading competitor in the changing electric energy business. Competition presents GSU with many challenges. The following have been identified by GSU as its major competitive challenges. Retail and Wholesale Rate Issues Increasing competition in the utility industry brings an increased need to stabilize or reduce retail rates. GSU implemented shared-savings plans as part of the Merger. Recognizing that many industrial customers have energy alternatives, GSU continues to work with these customers to address their needs. In certain cases, competitive prices are negotiated, using variable rate designs. 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. Under the terms of their respective Merger agreements, the LPSC and PUCT have reviewed GSU's base rates during the first post-Merger earnings analysis for reasonableness of its return on equity. The LPSC ordered a $12.7 million annual rate reduction effective January 1, 1995. GSU received an injunction delaying implementation of $8.3 million of the reduction and on January 1, 1995, reduced rates by $4.4 million. The entire $12.7 million is being appealed. On March 20, 1995, the PUCT ordered a $72.9 million annual base rate reduction for the period March 31, 1994, through September 1, 1994, decreasing to an annual base rate reduction of $52.9 million after September 1, 1994. In accordance with the Merger agreement, the rate reduction is applied retroactively to March 31, 1994. The rate reduction is being appealed and no assurance can be given as to the timing or outcome of the appeal. See Note 2 for further information. See Note 2 for information on the settlement of several PUCT fuel cost reviews and the continuing likelihood of future reviews. Retail wheeling, 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, is evolving. Over a dozen states have been studying the concept of retail competition. In April 1994, the state of Michigan agreed to a five-year experiment that allows limited competition among public utilities. During the same month, the California Public Utilities Commission proposed to deregulate that state's electric power industry, starting on January 1, 1996, to allow the largest industrial customers to select the lowest cost supplier for electricity service. Under the proposal, by the year 2002, smaller companies and residential customers in California would also be able to buy power from any suppliers. The California Public Utilities Commission is currently reviewing its decision and is expected to make a ruling in the first half of 1995. The retail market for electricity is expected to become more competitive with such moves toward deregulation. In some areas of the country, municipalities (or comparable entities) whose residents are served at retail by an investor-owned utility pursuant to a franchise are exploring the possibility of establishing new or extending existing distribution systems or seeking new delivery points in order to serve retail customers, especially large industrial customers, that currently receive service from an investor-owned utility. These options depend on the terms of a utility's franchise as well as on state law and regulation. In addition, FERC's authority to order utilities to transmit for a new or expanding municipal system is limited in certain respects. Where successful, however, the establishment of a municipal system or the acquisition by a municipal system of a utility's customers could result in the inability to recover costs that the utility has incurred in serving those customers. In mid-1994, the FERC issued a notice of proposed rulemaking concerning a regulatory framework for dealing with recovery of stranded costs, such as high cost nuclear generating units, which may be incurred by electric utilities as a result of increased competition. In addition to addressing recovery of stranded costs related to wholesale service, the proposal requested comment as to recovery of retail stranded costs in transmission rates where state regulatory authorities failed to address the issue or were in conflict. Comments and reply comments have been filed, and the matter is pending. The risk of exposure to stranded costs which may result from competition in the industry will depend on the extent and timing of retail competition, the resolution of jurisdictional issues concerning stranded cost recovery, and the extent to which such costs are recovered from departing or remaining customers, among other matters. Cogeneration projects developed or considered by certain of GSU's 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. In 1994, KWH sales to GSU's industrial customers at non-full cost of service rates, which make up approximately 28% of the total industrial class, increased 13%. Sales to the remaining industrial customers increased 2%. 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. On October 31, 1994, as amended on January 25, 1995, Entergy Services filed with FERC revised transmission tariffs intended to provide access to transmission service on the same or comparable basis, terms, and conditions as the Entergy operating companies, and the matter is pending. Open access and market pricing, once in 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 the rate issues discussed above, GSU is aggressively reducing costs to avoid potential earnings erosions that might result as well as to become more competitive. In 1994, GSU announced a restructuring program related to certain of its operating units. This program is designed to reduce costs and improve operating efficiencies. See Note 12 for further information. Also, in response to an increasingly competitive environment, GSU is continuing to work with the PUCT regarding integrated resource planning. The Energy Policy Act of 1992 The EPAct addresses a wide range of energy issues and is altering the way Entergy and the rest of the electric utility industry operate. The EPAct encourages competition and affords utilities the opportunities, and the risks, associated with an open and more competitive market environment. The EPAct creates exemptions from regulation under the Holding Company Act and creates a class of exempt wholesale generators consisting of utility affiliates and nonutilities that are owners and operators of facilities for the generation and transmission of power for sales at wholesale. The EPAct also gives FERC the authority to order investor-owned utilities, including GSU, 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. Both GSU and Entergy Power expect to compete in this market. Litigation and Regulatory Proceedings See Note 2 for information on the possible material adverse effects on GSU's financial condition and results of operations 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 ($170 million net of tax) of Texas retail jurisdiction deferred River Bend operating and carrying costs. Entergy Corporation-GSU Merger The acquisition of GSU by Entergy Corporation was the largest electric utility merger in United States history. Entergy expects to achieve $850 million in fuel cost savings and $670 million in operation and maintenance expense savings over ten years as a result of the Merger. For further information, see Note 2. See Note 8 for information on the bankruptcy proceedings of Cajun and litigation with Cajun concerning Cajun's ownership interest in River Bend and the related possible material adverse effects on GSU's financial condition. Deregulated Portion of River Bend As of December 31, 1994, GSU had not recovered a significant amount of its investment in, 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 for further information. Future earnings will continue to be limited as long as the limited recovery of the investment and lack of return continue. For the year ended December 31, 1994, GSU recorded revenues resulting from the sale of electricity from the deregulated asset plan of approximately $34.1 million. Operation and maintenance expenses, including fuel, were approximately $30 million, and depreciation expense associated with the deregulated asset plan investment was approximately $16.7 million for the year ended December 31, 1994. For the year ended December 31, 1994, GSU recorded nonfuel revenue of $32.5 million (included in the $34.1 million of total deregulated asset plan revenue discussed above) which, absent the deregulated asset plan, would not have been realized. The operation and maintenance expenses and depreciation expense allocated to the deregulated asset plan as detailed above would have been incurred at River Bend with or without the deregulated asset plan. The 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. Based on current estimates of the factors discussed above, GSU anticipates that future revenues from the deregulated asset plan will fully recover all related costs. Property Tax Exemptions Exemption from the payment of property taxes on River Bend, which has been in effect for 10 years, will expire in December 1996. GSU is working with Louisiana local taxing authorities to determine the method for calculating the amount of the property taxes to be paid when the exemption expires. GSU believes that any property taxes allocated to its retail jurisdictions will be recovered from those customers in rates. 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 material 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 allegedly resulting from exposure on GSU premises. While the amounts at issue in the cleanup efforts and suits may be substantial, GSU believes that its results of operations and financial condition will not be materially affected by the outcome of the suits. See Note 8 for further information. Accounting Issues Proposed Accounting Standards - The FASB has proposed a SFAS on "Accounting for the Impairment of Long-Lived Assets," effective January 1, 1996. The proposed standard describes circumstances which may result in assets being impaired and provides criteria for recognition and measurement of asset impairment. Note 2 describes regulatory assets of $170 million (net of tax) related to Texas retail deferred River Bend operating and carrying costs. Management believes these deferred costs will be required to be written off under the provisions of the new standard unless there are favorable regulatory or court actions related to these costs prior to the adoption of the new standard by GSU. Certain other operations of GSU are potentially affected by this standard, and any resulting write-offs will depend on future operating costs, generating units' efficiency and availability, and the future market for energy over the remaining life of the units. Based on current estimates, GSU anticipates that future revenues will fully recover the costs of such operations. Continued Application of SFAS 71 - GSU's financial statements currently reflect, for the most part, assets and costs based on current cost-based ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." As discussed above, the electric utility industry is changing and these changes could possibly result in the discontinuance of the application of SFAS 71, which would result in the elimination of regulatory assets and liabilities. See Note 1 for further information. Accounting for Decommissioning Costs - The FASB is currently reviewing the accounting for decommissioning of nuclear plants. This project could possibly change GSU's, as well as the entire utility industry's, accounting for such costs. For further information, see Note 8. 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 retail 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. See Note 2 regarding recent LPSC rate actions regarding the deferred unbilled revenues. 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. Although deferred fuel accounting is also practiced in Texas, the Texas retail rate schedules include a fixed fuel factor approved by the PUCT, which remains in effect until changed as part of a general rate case, fuel reconciliation, or a fixed fuel factor filing. 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. Total GSU net electric utility plant in service of $4.50 billion as of December 31, 1994 includes $3.22 billion of production plant, $.44 billion of transmission plant, $.69 billion of distribution plant and $.15 billion of other plant. 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 1994, 1993, and 1992. 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. GSU's AFUDC rates were as follows: January 1, 1992 - March 31, 1992 11.75% April 1, 1992 - March 31, 1993 10.75% April 1, 1993 - December 31, 1993 10.50% 1994 effective composite rate 10.20% Jointly-Owned Facilities GSU owns undivided interests in three jointly-owned electric generating stations and records the investment and expenses associated with these generating stations to the extent of its ownership interest. As of December 31, 1994, GSU's investment and accumulated depreciation in these generating stations were as follows: Total Fuel Megawatt Accumulated Generating Stations Type Capability Ownership Investment Depreciation (In Thousands) River Bend Unit 1 Nuclear 936 70% $3,080,019 $617,002 Roy S. Nelson Unit 6 Coal 550 70% $ 390,033 $145,897 Big Cajun 2, Unit 3 Coal 540 42% $ 219,788 $ 74,442 See Note 8 for information regarding the current status of Cajun's 30% undivided ownership interest in River Bend. Income Taxes GSU, its parent, and affiliates file a consolidated federal income tax return. Income taxes are allocated to GSU in proportion to its contribution to the consolidated taxable income. SEC regulations require that no Entergy Corporation subsidiary 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, in 1993 GSU changed its accounting for income taxes to conform with SFAS 109. Inventories GSU's fuel inventories (fuel oil and natural gas) are valued at weighted average 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 are expected to 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 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. Continued Application of SFAS 71 As a result of the EPAct and actions of regulatory commissions, the electric utility industry is moving toward a combination of competition and a modified regulatory environment. GSU's financial statements, for the most part, currently reflect assets and costs based on current cost-based ratemaking regulations, in accordance with SFAS. 71, "Accounting for the Effects of Certain Types of Regulation." Continued applicability of SFAS 71 to GSU's financial statements requires that rates set by an independent regulator on a cost of service basis (including a reasonable rate of return on invested capital) can actually be charged to and collected from customers. In the event that either all or a portion of a utility's operations cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation, or a change in the competitive environment for the utility's regulated services, the utility should discontinue application of SFAS 71 for the relevant portion. That discontinuation should be reported by elimination from the balance sheet of the effects of any actions of regulators recorded as regulatory assets and liabilities. As of December 31, 1994, and for the foreseeable future, GSU's financial statements continue to follow SFAS 71, with the exceptions noted below. SFAS 101 SFAS 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 71, to all or part of its operations should report that event in its financial statements. GSU discontinued regulatory accounting principles for its 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 financial instruments has been determined by GSU 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. The System adopted the provisions of SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," effective January 1, 1994. As a result, as of December 31, 1994, GSU recorded on the balance sheet an additional reduction of $0.9 million in decommissioning trust funds, representing the amount by which the fair value of the securities held in such funds exceeds the amounts recovered in rates for decommissioning and deposited in the funds and the related earnings on the amounts deposited. Due to the regulatory treatment for decommissioning trust funds, the System recorded an offsetting amount in unrealized losses on investment securities as a regulatory asset. 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 prudence, 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 prudence 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 a Texas 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. The Texas Supreme Court's decision stated that all issues relating to the merits of the original PUCT order, including the prudence of all River Bend- related costs, should be addressed in the Rate Appeal. In October 1991, the Texas 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. The court further stated that the PUCT had 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 1994, the Texas Third District Court of Appeals (the Appellate Court) affirmed the district court's decision that there was substantial evidence to support the PUCT's 1988 decision not to include the abeyed construction costs in GSU's rate base. While acknowledging that the PUCT had exceeded its authority when it attempted to defer a decision on the inclusion of those costs in rate base in order to allow GSU a further opportunity to demonstrate the prudence of those costs in a subsequent proceeding, the Appellate Court found that GSU had suffered no harm or lack of due process as a result of the PUCT's error. Accordingly, the Appellate Court held that the PUCT's action had the effect of disallowing the company-wide $1.4 billion of River Bend construction costs for ratemaking purposes. In its August 1994 opinion, the Appellate Court also held that GSU's deferred operating and maintenance costs associated with the allowed portion of River Bend should be included in rate base and that GSU's deferred River Bend carrying costs included in the Allowed Deferrals should also be included in rate base. The Appellate Court's August 1994 opinion affirmed the PUCT's original order in this case. The Appellate Court's August 1994 opinion was entered by two judges, with a third judge dissenting. The dissenting opinion states that the result of the majority opinion is, among other things, to deprive GSU of due process at the PUCT because the PUCT never reached a finding on the $1.4 billion of construction costs. In October 1994, the Appellate Court denied GSU's motion for rehearing on the August 1994 opinion as to the $1.4 billion in River Bend construction costs and other matters. GSU appealed the Appellate Court's decision to the Texas Supreme Court, where it is pending. As of December 31, 1994, the River Bend plant costs disallowed for retail ratemaking purposes in Texas, the River Bend plant costs held in abeyance, and the related operating and carrying cost deferrals totaled (net of taxes) approximately $13 million, $280 million (both net of depreciation), and $170 million, respectively. Allowed Deferrals were approximately $107 million, net of taxes and amortization, as of December 31, 1994. GSU estimates it has collected approximately $158 million of revenues as of December 31, 1994, as a result of the originally ordered rate treatment by the PUCT of these deferred costs. If recovery of the Allowed Deferrals is not upheld, future revenues based upon those allowed deferrals could also be lost, and no assurance can be given as to whether or not refunds of revenue received based upon such deferred costs previously recorded will be required. 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 or reserves 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, 1994, of up to $293 million could be required based on an ultimate adverse ruling by the PUCT on the abeyed and disallowed costs. 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 two 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 reasonably possible that the Allowed Deferrals will continue to be recovered in rates. Management also 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 deferred costs related to the $1.4 billion of abeyed River Bend plant costs will be recovered in rates to the extent that the $1.4 billion of abeyed River Bend plant is recovered. However, a net of tax write-off of the $170 million of deferred costs related to the $1.4 billion of abeyed River Bend plant costs would be required if they are not allowed to be recovered in rates. A proposed accounting standard, "Accounting for the Impairment of Long-Lived Assets," which is expected to become effective January 1, 1996, may require the write-off of the $170 million of rate deferrals discussed above, upon adoption of the standard unless there are favorable regulatory or court actions related to these costs prior to adoption. 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 AP&L, MP&L, and NOPSI agreed, among other things, 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. 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 future regulatory filings in November 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 System 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 acquire Cajun's 30% share in River Bend (see Note 8). Filings with the PUCT and Texas Cities In March 1994, the Texas Office of Public Utility Counsel and certain cities served by GSU instituted an investigation of the reasonableness of GSU's rates. In June 1994, GSU provided the cities with information that GSU believed supported the current rate level. GSU filed the same information with the PUCT in June 1994, pursuant to provisions of the Merger. In September 1994, the various cities adopted ordinances directing GSU to reduce its Texas retail rates by $45.9 million. GSU appealed the cities' ordinances to the PUCT for a determination of reasonableness of GSU's rates. In November 1994, those cities that intervened in the PUCT appeal filed testimony with the PUCT supporting a $118 million base rate reduction in lieu of the previously proposed $45.9 million reduction. In November 1994, the PUCT staff filed testimony that supported a $38.2 million base rate reduction. GSU filed information with the PUCT that it believed supported the current level of rates. Hearings were held in December 1994 and on March 20, 1995, the PUCT ordered a $72.9 million annual base rate reduction for the period March 31, 1994, through September 1, 1994, decreasing to an annual base rate reduction of $52.9 million after September 1, 1994. In accordance with the Merger agreement, the rate reduction is applied retroactively to March 31, 1994. As a result, GSU recorded in 1994 a $57 million reserve for rate refund and a $12.8 million reserve for franchise taxes to be refunded. These charges reduced net income after tax by $41.6 million. The rate reduction is being appealed and no assurance can be given as to the timing or outcome of the appeal. Texas Cities Rate Settlement - 1993 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 provided 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 effective September 1994. Pursuant to the settlement, GSU reduced rates with a $20 million one-time bill credit in December 1993, and refunded approximately $3 million to Texas retail customers on bills rendered in December 1993. The PUCT approved the settlement agreement on July 21, 1994. The cities' rate inquiries were settled earlier on the same terms. LPSC Rate Order - 1994 In May 1994, GSU made the required first post-Merger earnings analysis filing with the LPSC. On December 14, 1994, the LPSC ordered a $12.7 million annual rate reduction for GSU effective January 1995. The rate order included, among other things, a reduction in GSU's Louisiana jurisdictional authorized return on equity from 12.75% to 10.95% and the amortization for the benefit of the customers of $8.3 million of previously deferred unbilled revenue, representing one-half of the total resulting from a change in accounting discussed in Note 1. On December 28, 1994, GSU received a preliminary injunction from the 19th Judicial District Court regarding $8.3 million of the reduction. On January 1, 1995, GSU reduced rates by $4.4 million. The entire $12.7 million reduction is being appealed and no assurance can be given as to the timing or outcome of the appeal. PUCT Fuel Cost Review (December 1, 1986 - September 30, 1991) In January 1992, GSU applied to 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 concluding 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 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. In that proceeding, the PUCT also set GSU's fixed fuel factor in Texas at 1.84 cents per KWH in response to GSU's request that the factor be set at 2.02 cents per KWH. In October 1993, GSU appealed the PUCT's order to the Travis County District Court where the matter is still pending. No assurance can be given as to the timing or outcome of that appeal. In a subsequent proceeding to review GSU's fuel factor, the PUCT approved GSU's request to further reduce its fixed fuel factor in Texas to 1.78 cents per KWH from 1.84 cents per KWH. PUCT Fuel Cost Review (October 1, 1991 - December 31, 1993) On January 9, 1995, GSU and various parties reached an agreement for the reconciliation of over- and under-recovery of fuel and purchased power expenses for the period October 1, 1991, through December 31, 1993. While the settlement still requires PUCT approval, GSU believes it will ultimately be approved and has accordingly recorded a reserve of $7.6 million. LPSC Fuel Cost Review In November 1993, the LPSC ordered a review of GSU's fuel costs for the period October 1988 through September 1991 (Phase 1) based on the number of outages at River Bend and the findings in the June 1993 PUCT fuel reconciliation case. In July 1994, the LPSC ruled in the Phase 1 fuel review case and ordered GSU to refund approximately $27 million to its customers. Under the order, a refund of $13.1 million, which was not contested under a Louisiana Supreme Court decision as discussed below, was made through a billing credit on August 1994 bills. In August 1994, GSU appealed the remaining portion of the LPSC ordered refund to the district court. GSU has made no reserve for the remaining portion, pending outcome of the district court appeal, and no assurance can be given as to the timing or outcome of the appeal. On January 18, 1995, GSU met with the Special Counsel of the LPSC to discuss the procedural schedule for the upcoming fuel review (Phase II). The period under investigation was determined to be from October 1991 to December 1994. Hearings are scheduled to begin in July 1995. In February 1990, the LPSC disallowed the pass-through to ratepayers for the portion of GSU's cost to purchase power from NISCO representing the excess of NISCO's purchase price of the units over GSU's depreciated cost of the units. GSU appealed the 1990 order. In March 1994, the Louisiana Supreme Court ruled in favor of the LPSC. GSU recorded an estimated refund provision of $13.1 million, before related income taxes of $5.3 million. 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. 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, 1994, the unamortized balance of these costs was $321 million. Further, GSU deferred approximately $400.4 million of similar costs pursuant to a 1986 LPSC accounting order. These costs, of which approximately $122 million are unamortized as of December 31, 1994, are being amortized over a 10- year period ending in 1997. In accordance with a phase-in plan approved by the LPSC, GSU deferred $294 million of its River Bend costs related to the period February 1988 through February 1991. GSU has amortized $129 million through December 31, 1994, and the remainder of $165 million will be recovered over approximately 3.2 years. NOTE 3. INCOME TAXES (1) Income tax expense (benefit) consisted of the following:
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Current Federal $ 71 $16,714 $ 5,621 State 14 - - -------- ------- ------- Total 85 16,714 5,621 -------- ------- ------- Deferred - net Liberalized depreciation 21,560 37,951 24,287 Nuclear unit cancellation costs, net of amortization (2,111) (2,930) (3,107) Fuel and purchased power costs (accrued) 8,266 7,689 (669) Expenses deferred for tax purposes (33,358) 3,449 (12,387) Tax net operating loss carryforward 56,736 (8,357) 12,349 Rate deferrals - net (37,477) (24,458) (21,238) Unbilled revenues (2,093) 4,999 2,889 Income deferred for book purposes (1,845) (2,102) 2,328 Louisiana provision for rate refund - 3,793 4,416 Texas provision for rate refund (23,034) - - Alternative minimum tax 118 (22,183) (8,197) Loss on debt extinguishment, net of amortization (2,215) 1,398 22,314 Purchased power settlement - 66,753 6,562 Write-off of plant held for future use (29,572) - - Other (12,886) (3,689) 4,590 -------- ------- ------- Total (57,911) 46,477 49,973 -------- ------- ------- Investment tax credit adjustments - net (4,260) 1,093 (2,200) -------- ------- ------- Recorded income tax expense $(62,086) $64,284 $53,394 ======== ======= ======= Charged to operations $(6,448) $46,007 $38,058 Charged to other income (55,638) 12,009 17,801 Charged to extraordinary items - (671) (4,943) Charged to cumulative effect of accounting changes - 6,939 2,478 -------- ------- ------- Total income taxes $(62,086) $64,284 $53,394 ======== ======= =======
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:
For the Years Ended December 31, 1994 1993 1992 (1) % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income (Dollars in Thousands) Computed at statutory rate $(50,694) (35.0) $50,101 35.0 $63,662 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect (6,571) (4.5) 1,332 0.9 3,573 1.9 Rate deferrals - net 6,551 4.5 6,193 4.3 5,439 2.9 Depreciation (8,188) (5.7) (11,343) (7.9) (15,479) (8.3) Impact of change in tax rate - - 5,179 3.6 - - Book expenses not deducted for tax 151 0.1 15,134 10.6 142 0.1 Amortization of investment tax credits (4,472) (3.1) (4,435) (3.1) (4,356) (2.3) Other - net 1,137 0.8 2,123 1.5 413 0.2 -------- ----- ------- ---- ------- ---- Total income taxes $(62,086) (42.9) $64,284 44.9 $53,394 28.5 ======== ===== ======= ==== ======= ====
Significant components of net deferred tax liabilities, as of December 31, 1994 and 1993, were (in thousands):
1994 1993 Deferred tax liabilities: Net regulatory assets $ (494,443) $ (529,706) Plant related basis differences (1,065,053) (1,023,446) Rate deferrals - net (132,213) (169,689) Debt reacquisition loss (21,922) (24,140) Other (1,241) (25,871) ----------- ----------- Total $(1,714,872) $(1,772,852) =========== =========== Deferred tax assets: Net operating loss carryforwards $ 251,000 $ 307,737 Investment tax credit carryforward 173,852 176,032 Valuation allowance-investment tax credit carryforward (64,407) (15,213) Unbilled revenue 14,336 12,243 Plant related basis differences 23,796 25,007 Alternative minimum tax credit 39,743 39,860 Texas provision for rate refund 23,034 - Other 202,579 164,135 ----------- ---------- Total $ 663,933 $ 709,801 ----------- ----------- Net deferred tax liability $(1,050,939) $(1,063,051) =========== ===========
As of December 31, 1994, for tax purposes, GSU had federal tax loss carryforwards of approximately $666.7 million, state tax loss carryforward of approximately $498.2 million, and investment tax (ITC) and other credit carryforwards of approximately $176.4 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 $64.4 million of ITC carryforwards will expire unutilized as a result of limitations arising from the Merger. A valuation allowance has been provided for deferred tax assets relating to that amount. The alternative minimum tax credit, which can be carried forward indefinitely to reduce GSU's future federal income tax liability, was $40.6 million as of December 31, 1994. In 1993, GSU adopted SFAS 109. SFAS 109 required 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 required 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. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized GSU to effect short-term borrowings up to $125 million, which may be increased to as much as $395 million after further SEC approval. This authorization is effective through November 30, 1996. As of December 31, 1994, GSU had unused lines of credit for short-term borrowings of $5 million. Interest rates associated with these lines of credit generally are based on the prime rate, the EURO dollar rate, or a certificate of deposit rate. Commitment fees on these lines of credit are .125% of the amount of available credit. In addition, GSU can borrow from the Money Pool, subject to its maximum authorized level of short-term borrowings and the availability of funds. GSU had no outstanding borrowings under the Money Pool arrangement as of December 31, 1994. NOTE 5. PREFERRED, PREFERENCE, AND COMMON STOCK The number of shares and dollar value of GSU's preferred and preference stock were:
Call Price As of December 31 Per Share as Shares Outstanding Total Dollar Value of December 1994 1993 1994 1993 31, 1994 (Dollars in Thousands) Preference Stock Authorized 20,000,000 shares, without par value, cumulative 7% Series (2) 6,000,000 6,000,000 $150,000 $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 $102.64 --------- --------- --------- -------- Total without sinking fund 1,364,438 1,364,438 $ 136,444 $136,444 ========= ========= ========= ======== With sinking fund: 8.80% Series 226,807 237,963 $ 22,680 $ 23,796 $100.00 9.75% Series 21,565 22,576 2,154 2,258 $100.00 8.64% Series 182,000 196,000 18,200 19,600 $101.00 Adjustable Rate Series A, 7.10% (3) 204,000 216,000 20,400 21,600 $100.00 Adjustable Rate Series B, 7.15% (3) 315,000 337,500 31,500 33,750 $100.00 --------- --------- --------- -------- Total with sinking fund 949,372 1,010,039 $ 94,934 $101,004 ========= ========= ========= ========
(1)This series is not redeemable as of December 31, 1994. (2)The total dollar value represents the involuntary liquidation value of $25 per share. (3)Rates are as of December 31, 1994. The fair value of GSU's preferred and preference stock with sinking fund was estimated to be approximately $227.8 million and $255 million as of December 31, 1994 and 1993, respectively. The fair values were 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 1994 1993 1992 Common stock issuances - 100 - 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 (60,667) (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 1995-1999. Limitations based on the ratio of after-tax earnings to fixed charges and preferred dividends are imposed by GSU's Restated Articles of Incorporation (Articles) upon the issuance of additional preferred stock. Based upon the results of operations for the year ended December 31, 1994, GSU is unable to issue any additional preferred stock. NOTE 6. LONG-TERM DEBT GSU's long-term debt as of December 31, 1994 and 1993, was as follows:
Maturities Interest Rates December 31 From To From To 1994 1993 (In Thousands) First Mortgage Bonds 1996 1999 5% 7.35% $ 445,000 $ 345,000 2000 2004 6.41% 8-1/2% 670,000 470,000 2005 2009 6.77% 8-7/8% 120,000 420,000 2023 2024 8.70% 8.94% 450,000 450,000 Governmental and Industrial Development Bonds 2006 2024 5.9% 12% 482,460 482,885 Debentures - Due 1998, 9.72% 200,000 200,000 Other long-term debt 6,879 6,879 Unamortized premium and discount - net (5,497) (5,700) ---------- ---------- Total long-term debt 2,368,842 2,369,064 Less amount due within one year 50,425 425 ---------- ---------- Long-term debt excluding amount due within one year $2,318,417 $2,368,639 ========== ==========
The fair value of GSU's long-term debt as of December 31, 1994 and 1993 was estimated to be $2,277.3 million and $2,548.1 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 1995, 1996, 1997, 1998, and 1999, GSU has long-term debt maturities and cash sinking fund requirements of (in millions) $50.4, $145.4, $160.9, $190.9 and $100.9, respectively. In addition, other sinking fund requirements for the years 1995, 1996, 1997, 1998, and 1999 of (in millions) $16.7, $16.5, $15.2, $13.5, and $12.3, respectively, may be satisfied by cash or by certification of property additions at a rate of 167% of such requirements. GSU has two 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 $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, and applicable state and federal law. As of December 31, 1994, none of GSU's retained earnings were restricted against the payment of cash dividends or other distributions on common stock. 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. Issues to be finally resolved in PUCT rate proceedings and appeals thereof, as discussed in Note 2, combined with certain significant business relationships (discussed below) and the application of accounting standards, may result in substantial write-offs and charges that could result in substantial net losses being reported in 1995, 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, including co-ownership of River Bend and Big Cajun 2, Unit 3. GSU and Cajun own 70% and 30% undivided interests in River Bend, respectively, and 42% and 58% undivided interests in Big Cajun 2, Unit 3, respectively. In June 1989, Cajun filed a civil action against GSU in the United States District Court for the Middle District of Louisiana (District Court). Cajun's complaint seeks to annul, rescind, terminate, and/or dissolve the Joint Ownership Participation and Operating Agreement entered into on August 28, 1979 (Operating Agreement) relating 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 also to recover Cajun's alleged $1.6 billion investment in the unit as damages, plus attorneys' fees, interest, and costs. Two member cooperatives of Cajun have brought an independent action to declare the 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. A trial without jury on the portion of the suit by Cajun to rescind the Operating Agreement which began in April 1994 has been completed, and an order from the District Court is pending. 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 United States Bankruptcy Code. If GSU prevails in this litigation, there can be no assurance that the Bankruptcy Court will allow funding of all required costs of Cajun's ownership in River Bend. Since 1992 Cajun has not paid its full share of operating and maintenance expenses and other costs for repairs and improvements to River Bend. In addition, certain costs and expenses paid by Cajun were paid under protest. These actions were taken by Cajun based on its contention, which GSU disagrees, that River Bend's operating and maintenance expenses were excessive. In a letter dated October 21, 1994, and at a subsequent meeting, Cajun representatives advised Entergy Corporation and GSU that, on October 25, 1994, Cajun would exhaust its 1994 budget for operating and maintenance expenses for River Bend, and did not make any further payments to GSU in 1994 for River Bend operating, maintenance or capital costs. Cajun also advised that the RUS (which provided funding to Cajun for its investment in River Bend) would not permit Cajun to budget funds in 1995 to pay its share of operating and maintenance expenses or capital costs for River Bend. However, Cajun stated that it would continue to fund its share of the nuclear decommissioning trust payments for River Bend, as well as insurance and safety-related expenses. The unpaid portion of Cajun's River Bend operating, maintenance, and capital costs for 1994 (which has been fully reserved) was approximately $22.4 million. Cajun's total share of River Bend annual operating (including nuclear fuel) and maintenance expenses and capital costs was approximately $76.1 million in 1994. In view of Cajun's stated expectation that it will fund only a limited portion of its share of River Bend related operating, maintenance, and capital costs, GSU notified Cajun that it would (i) credit GSU's share of expenses for Big Cajun 2, Unit 3 against amounts due from Cajun to GSU and (ii) seek to market Cajun's share of the power from River Bend and apply the proceeds to the amounts due from Cajun to GSU. On November 2, 1994, Cajun discontinued GSU's entitlement of energy from Big Cajun 2, Unit 3. In response, on November 3, 1994, GSU filed pleadings in District Court seeking an order requiring Cajun to provide GSU with the energy from Big Cajun 2, Unit 3 to which GSU is entitled, and holding that GSU is entitled to credit amounts due from GSU to Cajun for Big Cajun 2, Unit 3 against amounts due from Cajun to GSU with respect to River Bend. On December 19, 1994, the District Court issued an injunction prohibiting Cajun from denying its share of energy from Big Cajun 2, Unit 3 and stipulating that GSU must make payments for its portion of expenses for Big Cajun 2, Unit 3 to the registry of the District Court. On December 14, 1994, the LPSC ordered Cajun to decrease the rates charged to its member distribution cooperatives by approximately $30 million per year. The rate decrease is associated with the LPSC's prior finding of imprudence in Cajun's participation in River Bend. On December 21, 1994, Cajun filed a petition in the United States Bankruptcy Court for the Middle District of Louisiana seeking bankruptcy relief under Chapter 11 of the United States Bankruptcy Code. Cajun's bankruptcy could have a material adverse effect on GSU, including the possibility of an NRC action with respect to the operation of River Bend. However, GSU is taking appropriate steps to protect its interests and its claims against Cajun arising from the co- ownership in River Bend and Big Cajun 2, Unit 3. On December 31, 1994, the District Court issued an order lifting an automatic stay as to certain proceedings, with the result that the preliminary injunction granted by the Court on December 19, 1994, remains in effect. Cajun filed a Notice of Appeal on January 18, 1995, to the United States Court of Appeals for the Fifth Circuit seeking a reversal of the District Court's grant of the preliminary injunction. No hearing date has been set on Cajun's appeal. In the bankruptcy proceedings, Cajun filed on January 10, 1995, a motion to reject the River Bend Operating Agreement as a burdensome executory contract. GSU responded on January 10, 1995, with a memorandum opposing Cajun's motion filed with the District Court. This memorandum argues that the motion should be denied because (1) the Operating Agreement is not an executory contract that can be rejected under the United States Bankruptcy Code, but an agreement establishing property rights and obligations; (2) Cajun legally cannot have its payment obligations under the Operating Agreement suspended while retaining the benefits from co-ownership in River Bend, as the benefits and obligations are indivisible; (3) Cajun cannot seek to dispose of its property interest in River Bend or reject the Operating Agreement with respect thereto without disposing of all of its property interests and rejecting all of the arrangements under the River Bend package of agreements consisting of the Operating Agreement, Big Cajun 2, Unit 3 facility, certain transmission lines and the buy-back agreement pursuant to when GSU paid Cajun approximately $600 million for River Bend capacity and energy during the early years of operation of River Bend; and (4) a legal determination of Cajun's obligations and interests in River Bend should only be made as part of a plan of reorganization in bankruptcy and such determination should be subject to regulatory approvals by certain agencies with jurisdiction over Cajun, including the NRC. If the court were to grant Cajun's motion to reject the Operating Agreement, Cajun would be relieved of its financial obligations under the contract, while GSU would likely have a substantial damage claim arising from any such rejection. Although GSU believes that Cajun's motion to reject the Operating Agreement is non-meritorious, it is not possible to predict the outcome or ultimate impact of these proceedings. During the period in which Cajun is not paying its share of River Bend costs, GSU intends to fund all costs necessary for the safe, continuing operation of the unit. The responsibilities of Entergy Operations as the licensed operator of River Bend, for safely operating and maintaining the unit are not affected by Cajun's actions. The total resulting from Cajun's failure to fund repair projects, Cajun's funding limitation on refueling outages, and the weekly funding limitation by Cajun was $55.6 million as of December 31, 1994, compared with $33.3 million as of December 31, 1993. These amounts are reflected in long-term receivables with an offsetting reserve in other deferred credits. Cajun's bankruptcy may affect the ultimate collectibility of the amounts owed to GSU, including any amounts that may be awarded in litigation. In September 1994, in connection with Entergy Corporation's analysis of certain preacquisition contingencies, Entergy Corporation increased its acquisition adjustment and GSU recorded a loss provision associated with the River Bend litigation between GSU and Cajun and certain underpayments by Cajun of River Bend costs, in accordance with SFAS 5, "Accounting for Contingencies." See Note 13 for additional information on provisions for preacquisition contingencies recorded during 1994. Cajun - Transmission Service GSU and Cajun are parties to FERC proceedings relating to transmission service charge disputes. In April 1992, FERC issued a final order. In May 1992, GSU and Cajun filed motions for rehearings which are pending at 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 pro ceedings consistent with its opinion. In December 1994, FERC held a hearing to address the issues remanded by the Court of Appeals. In February 1995, FERC clarified its order, eliminating an issue that GSU believes the Court of Appeals directed FERC to reconsider. GSU interprets the 1992 FERC order and the United States Court of Appeals' decision to mean that Cajun would owe GSU approximately $93.3 million as of December 31, 1994. However, FERC's February 1995 order indicates that FERC believes an issue, estimated by GSU to constitute approximately $26.2 million of this amount, may not be pursued by GSU in the remand proceedings. GSU further estimates that if it prevails in its May 1992 motion for rehearing, Cajun would owe GSU approximately $129.6 million as of December 31, 1994. 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 $85.6 million as of December 31, 1994. 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 payment. 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 $160.2 million as of December 31, 1994. This amount is reflected in long- term receivables with an offsetting reserve in other deferred credits. Capital Requirements and Financing Construction expenditures (excluding nuclear fuel) for the years 1995, 1996, and 1997 are estimated to total $177 million each year. GSU will also require $375 million during the period 1995-1997 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. 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. Nuclear Insurance The Price-Anderson Act limits public liability for a single nuclear incident to approximately $8.92 billion as of December 31, 1994. 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 $79.3 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 allocation in accordance with the respective ownership interests of 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 $3.2 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, 1994, GSU was insured against such losses up to $2.75 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, 1994, the maximum amount of such possible assessments to GSU was $22.6 million. Cajun shares approximately $4.4 million of GSU's obligation. The amount of property insurance presently carried by GSU 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 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. Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. In a statement released February 17, 1993, the DOE asserted that it does not have a legal obligation to accept spent nuclear fuel without an operational repository for which it has not yet arranged. Currently the DOE projects it will begin to accept spent fuel no earlier than 2010. 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 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 the DOE's repository program begins accepting River Bend's spent fuel. Entergy Operations and System Fuels joined in lawsuits against the DOE, seeking clarification of the DOE's responsibility to receive spent nuclear fuel beginning in 1998. The original suits, filed June 20, 1994, asked for a ruling stating that the Nuclear Waste Policy Act require the DOE to begin taking title to the spent fuel and to start removing it from nuclear power plants in 1998, a mandate for the DOE's nuclear waste management program to begin accepting fuel in 1998 and court monitoring of the program, and the potential for escrow of payments to the Nuclear Waste Fund instead of directly to the DOE. 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, which relates to GSU's 70% interest in River Bend. The amounts recovered in rates are deposited in external trust funds and reported at market value. The accumulated decommissioning liability of $22.2 million as of December 31, 1994, has been recorded in accumulated depreciation. Decommissioning expense amounting to $3.0 million was recorded in 1994. A more recent 1991 engineering study indicates decommissioning costs for GSU's 70% interest may be $267.8 million (in 1990 dollars). GSU filed the more recent cost study with the PUCT requesting a rate adjustment for decommissioning expense. As discussed in Note 2, on March 20, 1995, the PUCT ruled in the current rate case. The PUCT order included recovery of River Bend decommissioning costs totaling $204.9 million. GSU plans to ask the LPSC for a rate adjustment for decommissioning expense in conjunction with its next rate review in mid 1995. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. Management believes that actual decommissioning costs are likely to be higher than the amounts presented above. The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry, regarding the recognition, measurement, and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. In response to these questions, the FASB is currently reviewing the accounting for decommissioning. If current electric utility industry accounting practices for such decommissioning are changed, annual provisions for decommissioning could increase, the estimated cost for decommissioning could be recorded as a liability rather than as accumulated depreciation, and trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense. The EPAct 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 annual assessment, which will be adjusted annually for inflation, is $0.9 million (in 1995 dollars) for approximately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortized. The liability of $6.6 million as of December 31, 1994, is recorded in other current liabilities and other noncurrent liabilities and is offset in financial statements by a regulatory asset. 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, 1994, 1993, and 1992, the purchases of electricity from the joint venture totaled $58.3 million, $62.6 million, and $37.8 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. 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 5.3 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 material 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 allegedly resulting from exposure on GSU premises. While the amounts at issue in the cleanup efforts and suits may be substantial, GSU believes that its results of operations and financial condition will not be materially affected by the outcome of the suits. As of December 31, 1994, GSU has accrued cumulative amounts related to the cleanup of six sites at which GSU has been designated a potentially responsible party, totaling $27.7 million since 1990. Through December 31, 1994, GSU has expended $7.4 million cumulatively on the cleanup, resulting in a remaining recorded liability of $20.3 million as of December 31, 1994 Sales/Use Tax Issues In September 1994, the Louisiana Supreme Court (Court) issued an opinion (in a case in which none of the System companies was a party) holding, in part that the Louisiana state legislature's suspension of state sales and use tax exemptions also had the effect of suspending exemptions from local sales and use taxes. On January 27, 1995 the Court, after rehearing, reversed its opinion. Because of the Court's most recent ruling, sales of electricity and gas, fuels and other items used by GSU, LP&L, and NOPSI to generate electricity in Louisiana, as well as other items exempt from sales and use taxes, continue to be exempt from local sales and use taxes, even though the state exemptions for sales and use tax have been suspended. NOTE 9. LEASES General As of December 31, 1994, GSU had capital leases and noncancelable operating leases (excluding nuclear fuel leases) with minimum lease payments as follows: Capital Operating Leases Leases Year (In Thousands) 1995 $ 12,475 $ 10,695 1996 12,475 10,135 1997 12,475 13,742 1998 12,475 13,703 1999 12,475 13,703 Years thereafter 81,380 92,597 --------- --------- Minimum lease payments 143,755 $ 154,575 ========= Less: Amount representing interest 55,651 --------- Present value of net minimum lease payments $ 88,104 ========= Rental expense for capital and operating leases (excluding nuclear fuel leases) amounted to approximately $15.3, $31.9 million, and $21.9 million in 1994, 1993, and 1992, 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 in an 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 1993, has been extended to December 1997 and the notes have varying remaining maturities of up to 3 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 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 $37.2 million, $43.6 million, and $31.6 million (including interest of $8.7 million, $10.2 million, and $11.5 million) was charged to operations in 1994, 1993, and 1992, 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 average compensation generally during the last five 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. In 1994, GSU amended its defined benefit pension plan for non-bargaining unit employees to be consistent with the other System companies. Additionally, actuarial assumptions were also changed to be consistent with the other System companies. GSU's 1994, 1993, and 1992 pension cost, including amounts capitalized, included the following components:
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Service cost - benefits earned during the period $ 9,497 $10,417 $ 12,396 Interest cost on projected benefit obligation 21,335 17,643 16,307 Actual return on plan assets 6,785 (43,400) (28,117) Net amortization and deferral (39,405) 14,863 2,926 Other 17,963 - - -------- ------- -------- Net pension cost $ 16,175 $ (477) $ 3,512 ======== ======= ========
The funded status of GSU's pension plan as of December 31, 1994 and 1993, was:
1994 1993 (In Thousands) Actuarial present value of benefit obligations: Vested $273,509 $227,820 Nonvested 1,502 13,667 -------- -------- Accumulated benefit obligation $275,011 $241,487 ======== ======== Plan assets at fair market value $313,035 $337,922 Projected benefit obligation 290,802 282,722 -------- -------- Plan assets in excess of projected benefit obligation 22,233 55,200 Unrecognized prior service cost 13,720 11,985 Unrecognized transition asset (14,324) (16,712) Unrecognized net gain (73,423) (86,092) -------- -------- Accrued pension liability $(51,794) $(35,619) ======== ========
The accrued pension liability for GSU for 1993 has been restated to include liabilities for certain Early Retirement Programs. Prior to 1994, GSU accounted for such Early Retirement Programs in separate liability accounts other than the pension liability. However, effective in 1994, GSU changed its policy to include such liabilities in the pension liability account to be consistent with the other System companies. The significant actuarial assumptions used in computing the information above for 1994, 1993, and 1992 were as follows: weighted average discount rate, 8.5% for 1994, 7.5% for 1993, and 6.50% for 1992; weighted average rate of increase in future compensation levels, 5.1% for 1994, 5.0% for 1993, and 5.75% for 1992; and expected long-term rate of return on plan assets, 8.5%. Transition assets are being amortized over 15 years. In December 1993, GSU recorded a $17.0 million charge related to the announced early retirement program in connection with the Merger, of which $14.9 million was expensed. In 1994, GSU recorded an additional $18.0 million charge related to early retirement programs in connection with the Merger, of which $15.2 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 for 1992. Effective January 1, 1993, GSU adopted SFAS 106. This standard required 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 1994, GSU changed its actuarial assumptions and attribution methodology to be consistent with the other System companies. 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 1994 and 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components: 1994 1993 (In Thousands) Service cost - benefits earned during the period $ 2,169 $ 5,467 Interest cost on APBO 6,449 9,976 Actual return on plan assets - - Net amortization and deferral 2,832 6,402 ------- ------- Net periodic postretirement benefit cost $11,450 $21,845 ======= ======= The funded status of GSU's postretirement plan as of December 31, 1994 and 1993, was: 1994 1993 (In Thousands) Accumulated postretirement benefit obligation: Retirees $ 39,695 $ 46,270 Other fully eligible participants 26,069 38,091 Other active participants 13,445 18,359 -------- --------- 79,209 102,720 Plan assets at fair value - - -------- --------- Plan assets in excess of (less than APBO) (79,209) (102,720) Unrecognized transition obligation 115,232 121,634 Unrecognized net loss (gain) (57,410) (35,534) -------- --------- Accrued postretirement benefit liability $(21,387) $ (16,620) ======== ========= The assumed health care cost trend rate used in measuring the APBO is 9.4% for 1995, gradually decreasing each successive year until it reaches 5% in 2011. A one percentage-point increase in the assumed health care cost trend rate for each year would increase the APBO as of December 31, 1994, by 10.3% and the sum of the service cost and interest cost by approximately 12.2%. The assumed discount rate and rate of increase in future compensation used in determining the APBO were 8.5% for 1994 and 7.5% for 1993, and 5.1% for 1994 and 5% for 1993, respectively. NOTE 11.TRANSACTIONS WITH AFFILIATES GSU purchases electricity from and/or sells electricity to the other System operating companies, subsequent to the Merger, under rate schedules filed with FERC. In addition, GSU receives technical and advisory services from Entergy Services, and receives management and operating services from Entergy Operations. Operating revenues include revenues from sales to System operating companies amounting to $44.4 million in 1994. Operating expenses include charges from System operating companies for purchased power and related charges totaling $296.9 million in 1994, and $25.5 million in 1993, and $38.8 million in 1992, prior to the Merger. GSU pays directly or reimburses Entergy Operations for costs associated with operating River Bend (excluding nuclear fuel) which were approximately $210.2 million in 1994. NOTE 12. RESTRUCTURING COSTS During the third quarter of 1994, GSU announced a restructuring program related to certain of its operating units. The program is designed to reduce costs, improve operating efficiencies, and increase shareholder value in order to enable GSU to become a low-cost producer. The program includes reductions in the number of employees and the consolidation of offices and facilities. In 1994, GSU recorded restructuring charges of $6.5 million. These charges primarily include employee severance costs related to the expected termination of approximately 450 employees. As of December 31, 1994, no employees have been terminated and no termination benefits have been paid under this restructuring program. NOTE 13. 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 FERC, the PUCT, and the LPSC. As consideration to GSU's shareholders, Entergy Corporation paid $250 million and issued 56,695,724 shares of its common stock in exchange for the 114,055,065 outstanding shares of GSU common stock. 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. Additionally, GSU recorded $23.8 million in 1994 for remaining severance and augmented retirement benefits related to the Merger. See Note 2 for information regarding Merger-related rate agreements. In 1993, 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. During the allocation period (which expired on December 31, 1994), Entergy Corporation completed its analyses with respect to preacquisition contingencies and revised the allocation of the purchase price for a number of preacquisition contingencies. In 1994, GSU wrote-off assets or recorded liabilities totaling approximately $137 million net of tax for the Cajun-River Bend litigation, unfunded Cajun-River Bend costs, environmental cleanup costs, obsolete spare parts, Louisiana River Bend rate deferrals previously disallowed by the LPSC, plant held for future use, and the PUCT Fuel Reconciliation Settlement. Any items recorded in 1995 or later, will result in write-offs and/or losses charged to operations on GSU's financial statements and Entergy Corporation's consolidated financial statements. NOTE 14.QUARTERLY FINANCIAL DATA (UNAUDITED) GSU's business is subject to seasonal fluctuations with the peak period occurring during the third quarter. Operating results for the four quarters of 1994 and 1993 were: Income (Loss) Before Extraordinary Items and the Cumulative Effect Net Operating Operating of Accounting Income Revenues Income Changes (Loss) (In Thousands) 1994: First Quarter $429,658 $ 58,561 $ 11,043 $ 11,043 Second Quarter $456,855 $ 83,357 $ 33,084 $ 33,084 Third Quarter $545,531 $ 64,853 $(31,662) $(31,662) Fourth Quarter $365,321 $ 6,880 $(95,220) $(95,220) 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) See Note 2 for information regarding the recording of a reserve rate refund in December 1994, Note 12 for information regarding the recording of certain restructuring costs in 1994, and Note 13 for information regarding the recording of charges associated with certain preacquisition contingencies in 1994. See Note 1 for information regarding the change in accounting for unbilled revenues in 1993. See Note 2 for information regarding rate refunds during December 1993, and Note 13 for information regarding Merger-related charges recorded during the fourth quarter of 1993. GULF STATES UTILITIES COMPANY SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1994 1993 1992 1991 1990 (In Thousands) Operating revenues $1,797,365 $1,827,620 $1,773,374 $1,702,235 $1,690,685 Income (loss) before extraordinary items and the cumulative effect of accounting changes $ (82,755) $ 69,461 $ 139,413 $ 112,391 $ (36,399) Total assets $6,843,461 $7,137,351 $7,164,447 $7,183,119 $7,135,399 Long-term obligations (1) $2,689,042 $2,772,002 $2,798,768 $2,816,577 $2,663,249
(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.
1994 1993 1992 1991 1990 (Dollars in Thousands) Electric Department Operating Revenues: Residential $ 569,997 $ 585,799 $ 560,552 $ 547,147 $ 523,911 Commercial 414,929 415,267 400,803 383,883 378,253 Industrial 626,047 650,230 642,298 582,568 578,928 Governmental 25,242 26,118 26,195 24,792 24,101 ---------- ---------- ---------- ---------- ---------- Total retail 1,636,215 1,677,414 1,629,848 1,538,390 1,505,193 Sales for resale 98,230 31,898 24,485 44,136 48,125 Other (15,244) 38,649 40,203 41,433 43,317 ---------- ---------- ---------- ---------- ---------- Total Electric Department $1,719,201 $1,747,961 $1,694,536 $1,623,959 $1,596,635 ========== ========== ========== ========== ========== Billed Electric Energy Sales (Millions of KWH): Electric Department Residential 7,351 7,192 6,825 6,925 6,834 Commercial 6,089 5,711 5,474 5,460 5,388 Industrial 15,026 14,294 14,413 13,629 13,347 Governmental 297 296 302 295 285 ---------- ---------- ---------- ---------- ---------- Total retail 28,763 27,493 27,014 26,309 25,854 Sales for resale 3,516 666 540 1,049 1,180 ---------- ---------- ---------- ---------- ---------- Total Electric Department 32,279 28,159 27,554 27,358 27,034 Steam Department 1,659 1,597 1,722 1,711 1,930 ---------- ---------- ---------- ---------- ---------- Total 33,938 29,756 29,276 29,069 28,964 ========== ========== ========== ========== ==========
Louisiana Power & Light Company 1994 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 Entergy Services Entergy Services, Inc. EPAct The Energy Policy Act of 1992 FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission Grand Gulf 1 Unit No. 1 of the Grand Gulf Station (nuclear) Grand Gulf 2 Unit No. 2 of the Grand Gulf Station (nuclear) Grand Gulf Station Grand Gulf Steam Electric Generating Station (nuclear) 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 an 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 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS 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 (nuclear) 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 Entergy Corporation Board of Directors' Audit Committee functions as the Audit Committee for Louisiana Power & Light Company. The Audit Committee is comprised of four directors, who are not officers of LP&L: H. Duke Shackelford (Chairman), Lucie J. Fjeldstad, Dr. Norman C. Francis, and James R. Nichols. The committee held four meetings during 1994. 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 (Coopers & Lybrand L.L.P.) 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/ H. Duke Shackelford H. DUKE SHACKELFORD Chairman, Audit Committee REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Louisiana Power & Light Company We have audited the accompanying balance sheet of Louisiana Power & Light Company as of December 31, 1994, and the related statements of income, retained earnings and cash flows for the year then ended. 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 audit. The financial statements of the Company as of December 31, 1993 and for the years ended December 31, 1993 and 1992, were audited by other auditors, whose report, dated February 11, 1994, included an explanatory paragraph that described changes in methods of accounting for income taxes and postretirement benefits other than pensions which are discussed in Notes 3 and 10 respectively, to these financial statements. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1994, and the result of its operations and its cash flows for the year then ended in conformity with generally accepted accounting principles. /s/ Coopers & Lybrand L.L.P. COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 21, 1995 INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directors of Louisiana Power & Light Company We have audited the accompanying balance sheet of Louisiana Power & Light Company (LP&L) as of December 31, 1993, and the related statements of income, retained earnings, and cash flows for each of the two 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 the results of its operations and its cash flows for each of the two 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 LLP DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994
LOUISIANA POWER & LIGHT COMPANY BALANCE SHEETS ASSETS December 31, 1994 1993 (In Thousands) Utility Plant: Electric $4,778,126 $4,646,020 Electric plant under lease 229,468 225,083 Construction work in progress 94,791 133,536 Nuclear fuel under capital lease 44,238 61,375 Nuclear fuel 6,420 3,823 ---------- ---------- Total 5,153,043 5,069,837 Less - accumulated depreciation and amortization 1,600,510 1,496,107 ---------- ---------- Utility plant - net 3,552,533 3,573,730 ---------- ---------- Other Property and Investments: Nonutility property 20,060 20,060 Decommissioning trust fund 27,076 22,109 Investment in subsidiary company - at equity 14,230 14,230 Other 1,078 984 ---------- ---------- Total 62,444 57,383 ---------- ---------- Current Assets: Cash and cash equivalents: Temporary cash investments - at cost, which approximates market 28,718 33,489 Special deposits 3,237 19,077 Accounts receivable: Customer (less allowance for doubtful accounts of $1.2 million in 1994 and of $1.1 million in 1993) 58,858 66,575 Associated companies 9,827 2,952 Other 11,609 10,656 Accrued unbilled revenues 63,109 64,314 Accumulated deferred income taxes 3,702 6,031 Materials and supplies - at average cost 89,692 87,204 Rate deferrals 28,422 28,422 Prepayments and other 25,291 16,510 ---------- ---------- Total 322,465 335,230 ---------- ---------- Deferred Debits and Other Assets: Regulatory Assets: Rate deferrals 25,609 54,031 SFAS 109 regulatory asset - net 379,263 349,703 Unamortized loss on reacquired debt 43,656 47,853 Other regulatory assets 25,736 26,837 Other 23,733 19,231 ---------- ---------- Total 497,997 497,655 ---------- ---------- TOTAL $4,435,439 $4,463,998 ========== ========== See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 1994 1993 (In Thousands) Capitalization: Common stock, no par value, authorized 250,000,000 shares; issued and outstanding 165,173,180 shares in 1994 and 1993 $1,088,900 $1,088,900 Capital stock expense and other (5,367) (6,109) Retained earnings 113,420 89,849 ---------- ---------- Total common shareholder's equity 1,196,953 1,172,640 Preferred stock: Without sinking fund 160,500 160,500 With sinking fund 111,265 126,302 Long-term debt 1,403,055 1,457,626 ---------- ---------- Total 2,871,773 2,917,068 ---------- ---------- Other Noncurrent Liabilities: Obligations under capital leases 16,238 27,508 Other 54,216 28,909 ---------- ---------- Total 70,454 56,417 ---------- ---------- Current Liabilities: Currently maturing long-term debt 75,320 25,315 Notes payable: Associated companies 7,954 52,041 Other 19,200 - Accounts payable: Associated companies 20,793 33,523 Other 82,203 76,284 Customer deposits 54,934 52,234 Taxes accrued (1,860) 15,110 Interest accrued 42,987 42,141 Dividends declared 5,489 5,938 Deferred revenue - gas supplier judgment proceeds - 14,632 Deferred fuel cost 13,983 605 Obligations under capital leases 28,000 33,867 Other 20,156 9,741 ---------- ---------- Total 369,159 361,431 ---------- ---------- Deferred Credits: Accumulated deferred income taxes 883,945 834,899 Accumulated deferred investment tax credits 151,259 188,843 Deferred interest - Waterford 3 lease obligation 26,000 25,372 Other 62,849 79,968 ---------- ---------- Total 1,124,053 1,129,082 ---------- ---------- Commitments and Contingencies (Notes 2, 8, and 9) TOTAL $4,435,439 $4,463,998 ========== ========== See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1994 1993 1992 (In Thousands) Operating Activities: Net income $213,839 $188,808 $182,989 Noncash items included in net income: Change in rate deferrals 28,422 28,422 28,422 Depreciation and decommissioning 151,994 142,051 138,290 Deferred income taxes and investment tax credits (15,972) 40,261 42,896 Allowance for equity funds used during construction (3,486) (2,581) (1,714) Amortization of deferred revenues (14,632) (42,470) (38,646) Changes in working capital: Receivables 1,094 (8,046) (5,135) Accounts payable (6,811) (28,198) 7,733 Taxes accrued (16,970) 6,861 6,002 Interest accrued 846 1,003 2,917 Other working capital accounts 31,064 15,205 (16,037) Refunds to customers - gas contract settlement - (56,027) (56,066) Decommissioning trust contributions (4,815) (4,000) (2,000) Other 3,048 18,299 5,982 -------- -------- -------- Net cash flow provided by operating activities 367,621 299,588 295,633 -------- -------- -------- Investing Activities: Construction expenditures (140,669) (163,142) (150,527) Allowance for equity funds used during construction 3,486 2,581 1,714 -------- -------- -------- Net cash flow used in investing activities (137,183) (160,561) (148,813) -------- -------- -------- Financing Activities: Proceeds from the issuance of: First mortgage bonds - 100,000 269,000 Preferred stock - - 87,000 Other long-term debt 19,946 58,000 44,094 Changes in short-term borrowings (24,887) 52,041 - Retirement of: First mortgage bonds (25,000) (100,919) (309,205) Other long-term debt (322) (22,052) (15,977) Redemption of preferred stock (15,038) (22,500) (63,981) Dividends paid: Common stock (167,100) (167,600) (174,600) Preferred stock (22,808) (25,290) (28,845) -------- -------- -------- Net cash flow used in financing activities (235,209) (128,320) (192,514) -------- -------- -------- Net increase (decrease) in cash and cash equivalents (4,771) 10,707 (45,694) Cash and cash equivalents at beginning of period 33,489 22,782 68,476 -------- -------- -------- Cash and cash equivalents at end of period $28,718 $33,489 $22,782 ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $128,000 $127,497 $126,674 Income taxes $96,442 $62,414 $32,668 Noncash investing and financing activities: Capital lease obligations incurred $9,677 $33,210 $37,689 Deficiency of fair value of decommissioning trust assets over amount invested ($1,129) - - 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 its business, which requires large investments in long-lived assets. While large capital expenditures for the construction of new generating capacity are not currently planned, LP&L does require significant capital resources for the periodic maturity of certain series of debt and preferred stock and ongoing construction. Net cash flow from operations totaled $368 million, $300 million, and $296 million in 1994, 1993, and 1992, respectively. Net cash flow from operations in 1993 included payment of the last scheduled refund to customers of proceeds from a settlement with a gas supplier. 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 its continued efforts to streamline operations and reduce costs, as well as collections under its 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.) LP&L's Waterford 3 rate phase-in plan will continue to contribute to LP&L's cash position through 1996. See Note 2 for additional information on LP&L's rate phase-in plan. See Note 8 for additional information on LP&L's capital and refinancing requirements in 1995 - 1997. Also, to the extent current market interest and dividend rates allow, LP&L may continue to refinance high-cost debt and preferred stock prior to maturity. Earnings coverage tests and bondable property additions limit the amount of first mortgage bonds and preferred stock that LP&L can issue. Based on the most restrictive applicable tests as of December 31, 1994, and assuming an annual interest or dividend rate of 9.25%, LP&L could have issued $107 million of additional first mortgage bonds or $784 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 for information on LP&L's financing activities and Note 4 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, 1994 1993 1992 (In Thousands) Operating Revenues $1,708,541 $1,729,666 $1,553,745 ---------- ---------- ---------- Operating Expenses: Operation and maintenance: Fuel and fuel-related expenses 331,422 338,670 256,313 Purchased power 366,564 381,252 335,750 Nuclear refueling outage expenses 18,187 18,380 19,179 Other operation and maintenance 348,980 340,320 324,020 Depreciation and decommissioning 151,994 142,051 138,290 Taxes other than income taxes 56,101 50,391 49,507 Income taxes 63,751 108,568 83,984 Amortization of rate deferrals 28,422 28,422 28,422 ---------- ---------- ---------- Total 1,365,421 1,408,054 1,235,465 ---------- ---------- ---------- Operating Income 343,120 321,612 318,280 ---------- ---------- ---------- Other Income (Deductions): Allowance for equity funds used during construction 3,486 2,581 1,714 Miscellaneous - net 747 2,069 6,676 Income taxes 463 (2,245) (3,053) ---------- ---------- ---------- Total 4,696 2,405 5,337 ---------- ---------- ---------- Interest Charges: Interest on long-term debt 129,952 130,352 135,772 Other interest - net 6,494 6,605 5,591 Allowance for borrowed funds used during construction (2,469) (1,748) (735) ---------- ---------- ---------- Total 133,977 135,209 140,628 ---------- ---------- ---------- Net Income 213,839 188,808 182,989 Preferred Stock Dividend Requirements and Other 23,319 24,754 28,416 ---------- ---------- ---------- Earnings Applicable to Common Stock $190,520 $164,054 $154,573 ========== ========== ========== See Notes to Financial Statements. LOUISIANA POWER & LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1994 1993 1992 (In Thousands) Retained Earnings, January 1 $89,849 $94,510 $117,820 Add: Net income 213,839 188,808 182,989 -------- -------- -------- Total 303,688 283,318 300,809 -------- -------- -------- Deduct: Dividends declared: Preferred stock 22,359 24,553 28,416 Common stock 167,100 167,600 174,600 Capital stock expenses 809 1,316 3,283 -------- -------- -------- Total 190,268 193,469 206,299 -------- -------- -------- Retained Earnings, December 31 (Note 7) $113,420 $ 89,849 $ 94,510 ======== ======== ======== See Notes to Financial Statements. LOUISIANA POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income increased in 1994 due primarily to the fourth quarter write-off of the unamortized balances of deferred investment tax credits pursuant to the FERC settlement as discussed in Litigation and Regulatory Proceedings below, partially offset by lower electric operating revenues and higher other operation and maintenance expenses. Net income increased in 1993 due primarily to increased retail energy sales partially offset by the effects of implementing SFAS 109 and SFAS 106. Significant factors affecting the results of operations and causing variances between the years 1994 and 1993, and 1993 and 1992, are discussed under "Revenues and Sales" and "Expenses" below. Revenues and Sales See "Selected Financial Data - Five-Year Comparison," following the notes, for information on operating revenues by source and KWH sales. Operating revenues were lower in 1994 due primarily to the completion of the amortization of the proceeds resulting from litigation with a gas supplier in the second quarter and lower wholesale revenues partially offset by higher retail revenues. Wholesale revenues decreased due primarily to lower sales to non- associated utilities. Retail revenues increased due primarily to increases in sales to industrial and commercial customers. 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. Industrial energy sales also increased primarily in the petrochemical industry. Expenses Operating expenses decreased in 1994 due primarily to a decrease in income tax expense as a result of the write-off of the unamortized balances of deferred investment tax credits pursuant to a FERC settlement and lower fuel expense partially offset by higher other operation and maintenance expense. The decrease in fuel for electric generation and fuel-related expenses and purchased power expense is due primarily to lower fuel and purchased power prices. The increase in other operation and maintenance expense is due primarily to restructuring costs as discussed in Note 12 and power plant waste water site closures as discussed in Note 8. Operating expenses increased in 1993 due primarily to an increase in fuel expense because of increased generation requirements resulting primarily from increased retail energy sales and higher fuel costs. 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 1994 and 1993 as a result of the 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 The electric utility industry is becoming increasingly competitive and LP&L is seeking to become a leading competitor in the changing electric energy business. Competition presents LP&L with many challenges. The following have been identified by LP&L as its 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 philosophy is shifting in some jurisdictions from traditional cost of service regulation to incentive rate regulation. Incentive and performance-based rate plans encourage efficiencies and productivity while permitting utilities and their customers to share in the results. In August 1994, LP&L filed a performance-based formula rate plan with the LPSC. The proposed formula rate plan would continue existing LP&L rates at current levels, while providing financial incentive to reduce costs and maintain high levels of customer satisfaction and system reliability. Hearings were held in March 1995. See Note 2 for additional information. Recognizing that many industrial customers have energy alternatives, LP&L continues to work with these customers to address their needs. In certain cases, competitive prices are negotiated, using variable rate design. Retail wheeling, 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 area of service, is also evolving. Over a dozen states have been or are studying the concept of retail competition. In April 1994, the state of Michigan initiated a five-year experiment that allows limited competition among public utilities. During the same month, the California Public Utilities Commission proposed to deregulate that state's electric power industry, starting on January 1, 1996, to allow the largest industrial customers to select the lowest cost supplier for electricity service. Under the proposal, by the year 2002, smaller companies and residential customers in California would also be able to buy power from any suppliers. The California Public Utilities Commission is currently reviewing its proposal and is expected to make a ruling in the first half of 1995. The retail market for electricity is expected to become more competitive with such moves toward deregulation. In some areas of the country, municipalities (or comparable entities) whose residents are served at retail by an investor-owned utility pursuant to a franchise are exploring the possibility of establishing new or extending existing distribution systems or seeking new delivery points in order to serve retail customers, especially large industrial customers, that currently receive service from an investor-owned utility. These options depend on the terms of a utility's franchise as well as on state law and regulation. In addition, FERC's authority to order utilities to transmit for a new or expanding municipal system is limited in certain respects. Where successful, however, the establishment of a municipal system or the acquisition by a municipal system of a utility's customers could result in the inability to recover costs that the utility has incurred in serving those customers. In mid-1994, the FERC issued a notice of proposed rulemaking concerning a regulatory framework for dealing with recovery of stranded costs, such as high cost nuclear generating units, which may be incurred by electric utilities as a result of increased competition. In addition to addressing recovery of stranded costs related to wholesale service, the proposal requested comment as to recovery of retail stranded costs in transmission rates where state regulatory authorities failed to address the issue or were in conflict. Comments and reply comments have been filed, and the matter is pending. The risk of exposure to stranded costs which may result from competition in the industry will depend on the extent and timing of retail competition, the resolution of jurisdictional issues concerning stranded cost recovery, and the extent to which such costs are recovered from departing or remaining customers, among other matters. 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. On October 31, 1994, as amended on January 25, 1995, Entergy Services filed with FERC revised transmission tariffs intended to provide access to transmission service on the same or comparable basis, terms, and conditions as the System operating companies, and the matter is pending. Open access and market pricing, once in 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 become more competitive. In 1994, LP&L announced a restructuring program related to certain of its operating units. This program is designed to reduce costs and improve operating efficiencies. See Note 12 for further information. Also, in response to an increasingly competitive environment, LP&L announced intentions to revise its initial least cost planning activities. The Energy Policy Act of 1992 The EPAct addresses a wide range of energy issues and is altering the way Entergy and the rest of the electric utility industry operate. The EPAct encourages competition and affords utilities the opportunities, and the risks, associated with an open and more competitive market environment. The EPAct creates exemptions from regulation under the Holding Company Act and creates a class of exempt wholesale generators consisting of utility affiliates and nonutilities that are owners and operators of facilities for the generation and transmission of power for sales at wholesale. The EPAct also gives FERC the authority to order investor-owned utilities, including LP&L, 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. Both LP&L and Entergy Power expect to compete in this market. Litigation and Regulatory Proceedings In November 1994, FERC approved an agreement settling a long- standing dispute involving income tax allocation procedures of System Energy. In accordance with the agreement, System Energy refunded approximately $8.6 million to LP&L, which will make refunds or credits to its customers (except for those portions attributable to its retained share of Grand Gulf 1 costs). Additionally, System Energy will refund a total of approximately $8.7 million, plus interest, to LP&L over the period through June 2004. The settlement also required the write-off of approximately $31.5 million of certain related unamortized balances of deferred investment tax credits by LP&L. Property Tax Exemptions Exemption from the payment of Louisiana local property taxes on Waterford 3 , which has been in effect for 10 years, will expire in December 1995. LP&L is working with Louisiana local taxing authorities to determine the method for calculating the amount of the property taxes to be paid when the exemption expires. LP&L believes that assessed property taxes will be recovered from its customers through rates. Environmental Issues During 1993, the Louisiana Department of Environmental Quality 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 either upgrade or close them. The aggregate cost of the upgrades and closures, to be completed by 1996, is estimated to be $16 million. Accounting Issues Proposed Accounting Standards - The FASB has proposed a SFAS on "Accounting for the Impairment of Long-Lived Assets," effective January 1, 1996. The proposed standard describes circumstances which may result in assets being impaired and provides criteria for recognition and measurement of asset impairment. Certain operations of LP&L are potentially affected by this standard, and any resulting write-offs will depend on future operating costs, generating units' efficiency and availability, and the future market for energy over the remaining life of the units. Based on current estimates, LP&L anticipates that future revenues will fully recover the costs of such operations. Continued Application of SFAS 71 - LP&L's financial statements currently reflect assets and costs based on current cost-based ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." As discussed above, the electric utility industry is changing and these changes could possibly result in the discontinuance of the application of SFAS 71, which would result in the elimination of regulatory assets and liabilities. See Note 1 for further information. Accounting for Decommissioning Costs - The FASB is currently reviewing the accounting for decommissioning of nuclear plants. This project could possibly change the System's, as well as the entire utility industry's, accounting for such costs. For further information, see Note 8. 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 first mortgage indenture. In addition, certain assets of LP&L are subject to the liens of second mortgages related to pollution control revenue bonds. 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. Total LP&L net utility plant in service of $3.41 billion as of December 31, 1994 includes $2.36 billion of production plant, $.24 billion of transmission plant, $.74 billion of distribution plant, and $.07 billion of other plant. 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 2.8% in 1994, 3.0% in 1993, and 2.9% in 1992. 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 10.1%, 10.4%, and 10.7%, for 1994, 1993, and 1992, respectively. Income Taxes LP&L, its parent, and affiliates 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 Entergy Corporation subsidiary 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, in 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. Continued Application of SFAS 71 As a result of the EPAct and actions of regulatory commissions, the electric utility industry is moving toward a combination of competition and a modified regulatory environment. LP&L's financial statements currently reflect assets and costs based on current cost- based ratemaking regulations in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Continued applicability of SFAS 71 to LP&L's financial statements requires that rates set by an independent regulator on a cost of service basis (including a reasonable rate of return on invested capital) can actually be charged to and collected from customers. In the event that either all or a portion of a utility's operations cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation or a change in the competitive environment for the utility's regulated services, the utility should discontinue application of SFAS 71 for the relevant portion. That discontinuation should be reported by elimination from the balance sheet of the effects of any actions of regulators recorded as regulatory assets and liabilities. As of December 31, 1994, and for the foreseeable future, LP&L's financial statements continue to follow SFAS 71. Fair Value Disclosure The estimated fair value of financial instruments has 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. LP&L adopted the provisions of SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," effective January 1, 1994. As a result, at December 31, 1994, LP&L recorded on the balance sheet a reduction of $1.1 million in decommissioning trust funds, representing the amount by which the fair value of the securities held in such funds is less than amounts recovered in rates for decommissioning and deposited in the funds and the related earnings on the amounts deposited. Due to the regulatory treatment for decommissioning trust funds, LP&L recorded an offsetting amount in unrealized losses on investment securities as a regulatory asset. NOTE 2. RATE AND REGULATORY MATTERS LPSC Rate Review In August 1994, LP&L filed a performance-based formula rate plan with the LPSC. The proposed formula rate plan would continue existing LP&L rates at current levels, while providing financial incentive to reduce costs and maintain high levels of customer satisfaction and system reliability. A performance rating adjustment feature of the plan would allow LP&L the opportunity to earn a higher rate of return if it improves performance over time. Conversely, if performance declines, the rate of return LP&L could earn would be lowered. This provides financial incentive for LP&L to maintain continuous improvement in all three performance categories (customer price, customer satisfaction, and customer reliability). Under the proposed plan, if LP&L's earnings fall within a bandwidth around a benchmark rate of return, there would be no adjustment in rates. If LP&L's earnings are above the bandwidth, the proposed plan would automatically reduce LP&L's base rates. Alternatively, if LP&L's earnings are below the bandwidth, the proposed plan would automatically increase LP&L's base rates. 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 2% of LP&L's retail revenues. Hearings were held in March 1995. No assurance can be given that the LPSC will accept the performance- based formula rate plan, or that the current rate review will not result in a rate decrease. 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. LP&L is allowed to recover through the fuel adjustment clause 4.6 cents per KWH (as of 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, 1994, $66 million was billed to LP&L by System Energy. NOTE 3. INCOME TAXES Income tax expense consisted of the following:
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Current: Federal $68,891 $62,037 $30,326 State 10,369 8,514 6,139 ------- -------- ------- Total 79,260 70,551 36,465 ------- -------- ------- Deferred - net: Liberalized depreciation 55,083 54,297 53,751 Unbilled revenue 2,081 3,474 (7,906) Deferred Waterford 3 expenses (14,043) (14,043) (14,043) Adjustment of prior years' tax provisions 2,447 2,665 (5,331) Waterford 3 sale and leaseback (3,571) (3,632) (3,526) Gas contract settlement 5,483 9,513 15,180 Nuclear refueling and maintenance 3,407 (5,768) 1,989 Materials and supplies inventory adjustments (2,446) (2,505) (2,497) Alternative minimum tax (14,604) (8,781) - Property insurance reserve 521 23 3,119 Deferred fuel (5,148) (1,337) 2,977 Bond reacquisition (1,502) (243) 4,868 Decontamination and decommissioning fund 573 5,273 - Environmental reserve (5,832) 213 - Other (869) 3,868 3,308 ------- -------- ------- Total 21,580 43,017 51,889 ------- -------- ------- Investment tax credit adjustments - net (6,048) (2,755) (1,317) Investment tax credit amortization - FERC settlement (31,504) - - ------- -------- ------- Recorded income tax expense $63,288 $110,813 $87,037 ======= ======== ======= Charged to operations $63,751 $108,568 $83,984 Charged to other income (463) 2,245 3,053 ------- -------- ------- Recorded income tax expense 63,288 110,813 87,037 Income taxes applied against the debt component of AFUDC - - 442 ------- -------- ------- Total income taxes $63,288 $110,813 $87,479 ======= ======== =======
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, 1994 1993 1992 % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income (Dollars in Thousands) Computed at statutory rate $96,994 35.0 $104,867 35.0 $91,809 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 5,147 1.9 6,727 2.2 4,272 1.6 Depreciation 3,219 1.2 2,550 0.9 3,064 1.1 Impact of change in tax rate (2,749) (1.0) (2,767) (0.9) (3,989) (1.5) Amortization of investment tax credits (6,305) (2.3) (6,876) (2.3) (6,780) (2.5) Investment tax credit amortization - FERC Settlement (31,504) (11.3) - - - - SFAS 109 adjustment - - 4,193 1.4 - - Other - net (1,514) (0.6) 2,119 0.7 (1,339) (0.5) ------- ---- -------- ---- ------- ---- Recorded income tax expense $63,288 22.9 $110,813 37.0 $87,037 32.2 Income taxes applied against the debt component of AFUDC - - - - 442 0.2 ------- ---- -------- ---- ------- ---- Total income taxes $63,288 22.9 $110,813 37.0 $87,479 32.4 ======= ==== ======== ==== ======= ====
Significant components of LP&L's net deferred tax liabilities as of December 31, 1994 and 1993, were (in thousands): 1994 1993 Deferred tax liabilities: Net regulatory assets $ (437,468) $ (422,371) Plant related basis differences (722,653) (665,517) Rate deferrals (26,695) (40,737) Bond reacquisition loss (15,866) (17,368) Other (17,106) (14,429) ----------- ----------- Total $(1,219,788) $(1,160,422) =========== =========== Deferred tax assets: Unbilled revenues $ 11,108 $ 13,190 Accumulated deferred investment tax credit 58,205 72,667 Gas contract settlement 7,539 12,917 Removal cost 52,576 47,603 Alternative minimum tax credit 56,222 41,618 Standard coal plant 12,561 12,898 Waterford 3 sale/leaseback 102,111 98,541 Environmental reserve 6,308 476 Other 32,915 31,644 ----------- ---------- Total $ 339,545 $ 331,554 =========== ========== Net deferred tax liabilities $ (880,243) $ (828,868) =========== ========== The alternative minimum tax (AMT) credit as of December 31, 1994, was $56.2 million. This AMT credit can be carried forward indefinitely and will reduce LP&L's federal income tax liability in future years. In accordance with a System Energy FERC settlement, LP&L wrote off $31.5 million of unamortized deferred investment tax credits in 1994. In 1993, LP&L adopted SFAS 109. SFAS 109 required 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 required 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. 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. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. In August 1994, Entergy received an Internal Revenue Service report covering the federal income tax audit of Entergy Corporation and subsidiaries for the years 1988 - 1990. The report asserts an $80 million tax deficiency for the 1990 consolidated federal income tax returns related primarily to the application of accelerated investment tax credits associated with Waterford 3 and Grand Gulf nuclear plants. Entergy believes there is no material tax deficiency and is vigorously contesting the proposed assessment. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized LP&L to effect short-term borrowings up to $150 million, which may be increased to as much as $236 million after further SEC approval. This authorization is effective through November 30, 1996. As of December 31, 1994, LP&L had outstanding short-term lines of credit of $19.2 million from banks within its service territory. Interest rates associated with these lines of credit generally are based on the prime rate, the London interbank offered rate, or a bid rate. Commitment fees on these lines of credit are .125% of the amount of available credit. 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 $8 million of outstanding borrowings under the Money Pool arrangement as of December 31, 1994. NOTE 5. PREFERRED STOCK The number of shares and dollar value of LP&L's preferred stock were:
As of December 31, Shares Call Price Per Authorized and Total Share as of Outstanding Dollar Value December 31, 1994 1993 1994 1993 1994 (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 150,211 390,211 3,756 9,755 $25.67 13.12% Series - 61,121 - 1,528 - 14.72% Series - 416 - 10 - 12.64% Series 900,370 1,200,370 22,509 30,009 $27.37 --------- --------- -------- -------- Total with sinking fund 1,900,581 2,502,118 $111,265 $126,302 ========= ========= ======== ========
(1) These series are not redeemable as of December 31, 1994. The fair value of LP&L's preferred stock with sinking fund was estimated to be approximately $113.0 million and $141.9 million as of December 31, 1994 and 1993, respectively. The fair values were 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 preferred stock, with and without sinking fund, during the last three years were: Number of Shares 1994 1993 1992 Preferred stock issuances: $100 par value - - 500,000 $25 par value - - 1,480,000 Preferred stock retirements: $100 par value - - (370,000) $25 par value (601,537) (900,000) (1,015,160) Cash sinking fund requirements for the next five years for preferred stock outstanding as of December 31, 1994 are (in millions): 1995 - $6.8; 1996 - $4.5; 1997 - $3.8; 1998 - $3.8; and 1999 - $53.8. LP&L has the annual non-cumulative option to redeem, at par, additional amounts of certain series of its outstanding preferred stock. NOTE 6. LONG-TERM DEBT LP&L's long-term debt as of December 31, 1994 and 1993, was: Maturities Interest Rates From To From To 1994 1993 (In Thousands) First Mortgage Bonds 1995 1999 5-5/8% 10.36% $ 179,000 $ 204,000 2000 2004 6% 8% 361,520 361,520 2020 2022 8-1/2% 10-1/8% 185,000 185,000 Governmental Obligations* 1994 2009 6-2/5% 8% 40,472 37,794 2010 2023 5.95% 8-1/4% 367,400 350,000 Waterford 3 Lease Obligation, 8.76% (Note 9) 353,600 353,600 Unamortized Premium and Discount - Net (8,617) (8,973) ---------- ---------- Total Long-Term Debt 1,478,375 1,482,941 Less Amount Due Within One Year 75,320 25,315 ---------- ---------- Long-Term Debt Excluding Amount Due Within One $1,403,055 $1,457,626 Year ========== ========== * Consists of pollution control 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, 1994 and 1993 was estimated to be $1,089.2 million and $1,205.1 million, respectively. The fair values were 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 1995, 1996, 1997, 1998, and 1999, LP&L has long-term debt maturities and cash sinking fund requirements of (in millions): $75.3, $35.3, $34.3, $35.3 and $0.2, respectively. In addition, other sinking fund requirements of approximately $5.9 million annually may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements. 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, 1994, none of LP&L's retained earnings were restricted against the payment of cash dividends or other distributions on common stock. On February 1, 1995, LP&L paid Entergy Corporation a $55.7 million cash dividend on common stock. NOTE 8. COMMITMENTS AND CONTINGENCIES Capital Requirements and Financing Construction expenditures (excluding nuclear fuel) for the years 1995, 1996, and 1997 are estimated to total $115.4 million each year. LP&L will also require $160 million during the period 1995-1997 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. 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 $7 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. 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. 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, 1994, 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 the year 2031 to purchase energy generated by a hydroelectric facility. During 1994, 1993, and 1992, LP&L made payments under the contract of approximately $56.3 million, $66.9 million, and $39.1 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 $8.92 billion as of December 31, 1994. 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 $79.3 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 $3.2 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, 1994, LP&L was insured against such losses up to $2.75 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, 1994, the maximum amount of such possible assessments to LP&L was $34.7 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. 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. Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. In a statement released February 17, 1993, the DOE asserted that it does not have a legal obligation to accept spent nuclear fuel without an operational repository for which it has not yet arranged. Currently the DOE projects it will begin to accept spent fuel no earlier than 2010. 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. Entergy Operations and System Fuels joined in lawsuits against the DOE, seeking clarification of the DOE's responsibility to receive spent nuclear fuel beginning in 1998. The original suits, filed June 20, 1994, asked for a ruling stating that the Nuclear Waste Policy Act require the DOE to begin taking title to the spent fuel and to start removing it from nuclear power plants in 1998, a mandate for the DOE's nuclear waste management program to begin accepting fuel in 1998 and court monitoring of the program, and the potential for escrow of payments to a nuclear waste fund instead of directly to the DOE. 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 has funded at an annual rate of $4.8 million since January 1994, in anticipation of a 1994 study update and a related LPSC review and determination of appropriate funding levels. The updated cost study completed in 1994 (in 1993 dollars) reflected a cost of decommissioning of $320.1 million. LP&L filed the updated cost study with the LPSC and requested a rate adjustment for decommissioning expense, which is being reviewed. The amounts recovered in rates are deposited in an external trust fund and are reported at market value. The accumulated decommissioning liability of $28.2 million as of December 31, 1994 has been recorded in accumulated depreciation. Decommissioning expense in the amount of $4.8 million was recorded in 1994. 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. Management believes that actual decommissioning costs are likely to be higher than the amounts presented above. The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry, regarding the recognition, measurement, and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. In response to these questions, FASB is currently reviewing the accounting for decommissioning. If current electric utility industry accounting practices for such decommissioning are changed, annual provisions for decommissioning could increase, the estimated cost for decommissioning could be recorded as a liability rather than as accumulated depreciation, and trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense. The EPAct 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 $1.3 million (in 1995 dollars) for approximately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortized. The cumulative liability of $14.5 million at December 31, 1994 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. Sales/Use Tax Issues In September 1994, the Louisiana Supreme Court (Court) issued an opinion (in a case in which none of the System companies was a party) holding, in part, that the Louisiana state legislature's suspension of state sales and use tax exemptions also had the effect of suspending exemptions from local sales and use taxes. On January 27, 1995 the Court, after rehearing, reversed its opinion. Because of the Court's most recent ruling, sales of electricity and gas, fuels and other items used by LP&L to generate electricity in Louisiana, as well as other items exempt from sales and use taxes, continue to be exempt from local sales and use taxes, even though the state exemptions for sales and use tax have been suspended. Environmental Issues During 1993, the Louisiana Department of Environmental Quality 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 either upgrade or close them. The aggregate cost of the upgrades and closures, to be completed by 1996, is estimated to be $16 million. NOTE 9. LEASES General As of December 31, 1994, LP&L had noncancelable operating leases with minimum lease payments as follows (in thousands): 1995 $ 4,395 1996 4,038 1997 3,924 1998 3,811 1999 3,505 Years thereafter 3,413 -------- Minimum lease payments $ 23,086 ======== Rental expense for operating leases amounted to approximately $12.1 million, $6.6 million, and $8.7 million in 1994, 1993, and 1992, 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 1998, and the notes have varying remaining maturities of up to 4 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 $32.2 million, $39.9 million, and $38.3 million (including interest of $4.3 million, $4.9 million, and $5.4 million) was charged to operations in 1994, 1993, and 1992, 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. LP&L did 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. As a result, LP&L was required to provide collateral to the Owner Participants for the equity portion of certain amounts payable by LP&L under the lease. Such collateral was in the form of a new series of non-interest bearing first mortgage bonds in the aggregate principal amount of $208.2 million issued by LP&L in September 1994 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, 1994, LP&L's total equity capital (including preferred stock) was 49.10% of adjusted capitalization and its fixed charge coverage ratio was 3.01. In accordance with SFAS 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, 1994, 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): 1995 $ 32,569 1996 35,165 1997 39,805 1998 41,447 1999 50,530 Years thereafter 676,214 -------- Minimum lease payments $875,730 ======== 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. LP&L's 1994, 1993, and 1992 pension cost, including amounts capitalized, included the following components: For the Years Ended December 31, 1994 1993 1992 (In Thousands) Service cost - benefits earned during the period $5,441 $4,900 $4,307 Interest cost on projected benefit obligation 14,473 14,684 14,110 Actual return on plan assets 2,024 (26,533) (14,329) Net amortization and deferral (19,981) 8,712 (3,113) ------- ------- ------- Net pension cost $1,957 $1,763 $975 ======= ======= ======= The funded status of LP&L's pension plan as of December 31, 1994 and 1993, was (excluding amounts allocable to NOPSI):
1994 1993 (In Thousands) Actuarial present value of accumulated pension plan benefits: Vested $154,927 $179,049 Nonvested 795 768 -------- -------- Accumulated benefit obligation $155,722 $179,817 ======== ======== Plan assets at fair value $198,724 $224,203 Projected benefit obligation 178,895 211,928 -------- -------- Plan assets in excess of projected benefit obligation 19,829 12,275 Unrecognized prior service cost 4,881 6,257 Unrecognized transition asset (19,653) (22,460) Unrecognized net gain (16,677) (5,734) -------- -------- (11,620) (9,662) Unfunded portion of NOPSI pension liability (1,584) (12,256) -------- -------- Accrued pension liability $(13,204) $(21,918) ======== ========
The significant actuarial assumptions used in computing the information above for 1994, 1993, and 1992 were as follows: weighted average discount rate, 8.5% for 1994, 7.5% for 1993 and 8.25% for 1992 ; weighted average rate of increase in future compensation levels, 5.1% for 1994 and 5.6% for 1993 and 1992; 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. Effective January 1, 1993, LP&L adopted SFAS 106. This standard required 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 1994 and 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components: 1994 1993 (In Thousands) Service cost - benefits earned during the period $2,433 $2,083 Interest cost on APBO 4,422 4,749 Net amortization and deferral 3,066 2,971 ------ ------ Net periodic postretirement benefit cost $9,921 $9,803 ====== ====== The funded status of LP&L's postretirement plan as of December 31, 1994 and 1993, was as follows: 1994 1993 (In Thousands) Accumulated postretirement benefit obligation: Retirees $ 38,401 $ 41,769 Other fully eligible participants 8,550 6,825 Other active participants 9,695 21,085 -------- -------- 56,646 69,679 Plan assets at fair value - - -------- -------- Plan assets less than APBO (56,646) (69,679) Unrecognized transition obligation 53,488 56,459 Unrecognized net loss (gain) (8,253) 7,579 -------- -------- Accrued postretirement benefit liability $(11,411) $ (5,641) ======== ======== The assumed health care cost trend rate used in measuring the APBO was 9.4% for 1995, gradually decreasing each successive year until it reaches 5% in 2011. 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, 1994, by 8.9% and the sum of the service cost and interest cost by approximately 11.4%. The assumed discount rate and rate of increase in future compensation used in determining the APBO were 8.5% for 1994 and 7.5% for 1993 and 5.1% for 1994 and 5.5% for 1993, respectively. NOTE 11. TRANSACTIONS WITH AFFILIATES LP&L buys electricity from and/or sells electricity to the other System operating companies 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, and receives operating services from Entergy Operations. Operating revenues include revenues from sales to affiliates amounting to $1.0 million in 1994, $4.8 million in 1993, and $5.5 million in 1992. Operating expenses include charges from affiliates for fuel costs, purchased power and related charges, management services, and technical and advisory services totaling $365.8 million in 1994, $322 million in 1993, and $314.3 million in 1992. LP&L pays directly or reimburses Entergy Operations for the costs associated with operating Waterford 3 (excluding nuclear fuel), which were approximately $152.5 million in 1994, $118.9 million in 1993, and $152.1 million in 1992. NOTE 12. RESTRUCTURING COSTS During the third quarter of 1994, LP&L announced a restructuring program related to certain of its operating units. The program is designed to reduce costs, improve operating efficiencies, and increase shareholder value in order to enable LP&L to become a low-cost producer. The program includes reductions in the number of employees and the consolidation of offices and facilities. In 1994, LP&L recorded restructuring charges of $6.8 million. These charges primarily include employee severance costs related to the expected termination of approximately 296 employees. As of December 31, 1994, no employees have been terminated and no termination benefits have been paid under this restructuring program. NOTE 13. 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 1994 and 1993 were: Operating Operating Net Revenues Income Income (In Thousands) 1994: First Quarter $383,826 $ 68,668 $37,096 Second Quarter $441,643 $ 80,686 $48,353 Third Quarter $502,458 $ 99,824 $67,029 Fourth Quarter $380,614 $ 93,942 $61,361 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 See "Significant Factors and Known Trends - Litigation and Regulatory Proceedings" for information regarding the write-off of certain unamortized deferred investment tax credits in the fourth quarter of 1994.
LOUISIANA POWER & LIGHT COMPANY SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1994 1993 1992 1991 1990 (In Thousands) Operating revenues $1,708,541 $1,729,666 $1,553,745 $1,528,934 $1,485,572 Net income $ 213,839 $ 188,808 $ 182,989 $ 166,572 $ 155,049 Total assets $4,435,439 $4,463,998 $4,109,148 $4,131,751 $4,262,124 Long-term obligations (1) $1,530,558 $1,611,436 $1,622,909 $1,582,606 $1,867,369
(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. 1994 1993 1992 1991 1990 (Dollars in Thousands) Operating Revenues: Residential $577,084 $572,738 $518,255 $525,594 $520,800 Commercial 358,672 345,254 320,688 318,613 314,700 Industrial 659,061 652,574 578,741 558,036 532,800 Governmental 31,679 29,723 27,780 28,303 26,500 ---------- ---------- ---------- ---------- ---------- Total retail 1,626,496 1,600,289 1,445,464 1,430,546 1,394,800 Sales for resale 35,406 49,388 38,632 31,997 41,800 Other 46,639 79,989 69,649 66,391 49,000 ---------- ---------- ---------- ---------- ---------- Total $1,708,541 $1,729,666 $1,553,745 $1,528,934 $1,485,600 ========== ========== ========== ========== ========== Billed Electric Energy Sales (Millions of KWH): Residential 7,449 7,368 6,996 7,182 7,169 Commercial 4,631 4,435 4,307 4,367 4,299 Industrial 16,561 15,914 15,013 14,832 14,170 Governmental 423 398 385 405 382 ------ ------ ------ ------ ------ Total retail 29,064 28,115 26,701 26,786 26,020 Sales for resale 786 1,325 1,305 1,201 1,149 ------ ------ ------ ------ ------ Total 29,850 29,440 28,006 27,987 27,169 ====== ====== ====== ====== ====== Mississippi Power & Light Company 1994 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 Entergy Services Entergy Services, Inc. EPAct The Energy Policy Act of 1992 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 (nuclear) Grand Gulf 1 Unit No. 1 of the Grand Gulf Station (nuclear) Grand Gulf 2 Unit No. 2 of the Grand Gulf Station (nuclear) 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 92 SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the FASB SFAS 106 SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS 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 Entergy Corporation Board of Directors' Audit Committee functions as the Audit Committee for Mississippi Power & Light Company. The Audit Committee is comprised of four directors, who are not officers of MP&L: H. Duke Shackelford (Chairman), Lucie J. Fjeldstad, Dr. Norman C. Francis, and James R. Nichols. The committee held four meetings during 1994. 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 (Coopers & Lybrand L.L.P.) 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/ H. Duke Shackelford H. DUKE SHACKELFORD Chairman, Audit Committee REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Mississippi Power & Light Company We have audited the accompanying balance sheet of Mississippi Power & Light Company as of December 31, 1994, and the related statements of income, retained earnings and cash flows for the year then ended. 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 audit. The financial statements of the Company as of December 31, 1993 and for the years ended December 31, 1993 and 1992, were audited by other auditors, whose report, dated February 11, 1994, included an explanatory paragraph that described changes in methods of accounting for revenues, income taxes and postretirement benefits other than pensions which are discussed in Notes 1, 3 and 9 respectively, to these financial statements. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1994, and the result of its operations and its cash flows for the year then ended in conformity with generally accepted accounting principles. /s/ Coopers & Lybrand L.L.P. COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 21, 1995 INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directors of Mississippi Power & Light Company We have audited the accompanying balance sheet of Mississippi Power & Light Company (MP&L) as of December 31, 1993, and the related statements of income, retained earnings, and cash flows for each of the two 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 the results of its operations and its cash flows for each of the two 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 LLP DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994
MISSISSIPPI POWER & LIGHT COMPANY BALANCE SHEETS ASSETS December 31, 1994 1993 (In Thousands) Utility Plant: Electric $1,475,322 $1,389,229 Construction work in progress 67,119 62,699 ---------- ---------- Total 1,542,441 1,451,928 Less - accumulated depreciation and amortization 582,514 577,728 ---------- ---------- Utility plant - net 959,927 874,200 ---------- ---------- Other Property and Investments: Investment in subsidiary company - at equity 5,531 5,531 Other 5,624 4,760 ---------- ---------- Total 11,155 10,291 ---------- ---------- Current Assets: Cash and cash equivalents: Cash 5,080 7,999 Temporary cash investments - at cost, which approximates market Associated companies 276 - Other 4,242 - ---------- ---------- Total cash and cash equivalents 9,598 7,999 Notes receivable 9,681 7,118 Accounts receivable: Customer (less allowance for doubtful accounts of $2.1 million in 1994 and $2.5 million in 1993) 21,087 33,155 Associated companies 4,680 7,342 Other 2,789 3,672 Accrued unbilled revenues 39,873 57,414 Fuel inventory - at average cost 4,780 8,652 Materials and supplies - at average cost 20,642 20,886 Rate deferrals 106,538 96,935 Prepayments and other 10,672 13,763 ---------- ---------- Total 230,340 256,936 ---------- ---------- Deferred Debits and Other Assets: Regulatory Assets: Rate deferrals 385,720 504,428 Unamortized loss on reacquired debt 10,488 11,656 Other regulatory assets 10,168 2,949 Long-term receivables 13,078 9,951 Other 8,569 6,326 ---------- ---------- Total 428,023 535,310 ---------- ---------- TOTAL $1,629,445 $1,676,737 ========== ========== See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 1994 1993 (In Thousands) Capitalization: Common stock, no par value, authorized 15,000,000 shares; issued and outstanding 8,666,357 shares in 1994 and 1993 $199,326 $199,326 Capital stock expense and other (1,762) (1,864) Retained earnings 232,011 236,337 ---------- ---------- Total common shareholder's equity 429,575 433,799 Preferred stock: Without sinking fund 57,881 57,881 With sinking fund 31,770 46,770 Long-term debt 475,233 516,156 ---------- ---------- Total 994,459 1,054,606 ---------- ---------- Other Noncurrent Liabilities: Obligations under capital leases 552 686 Other 8,984 6,231 ---------- ---------- Total 9,536 6,917 ---------- ---------- Current Liabilities: Currently maturing long-term debt 65,965 48,250 Notes payable: Associated companies - 11,568 Other 30,000 - Accounts payable: Associated companies 2,350 29,181 Other 30,205 12,157 Customer deposits 22,793 21,474 Taxes accrued 20,821 24,252 Accumulated deferred income taxes 47,515 41,758 Interest accrued 20,377 23,171 Dividends declared 1,626 1,985 Other 28,692 17,303 ---------- ---------- Total 270,344 231,099 ---------- ---------- Deferred Credits: Accumulated deferred income taxes 301,288 311,616 Accumulated deferred investment tax credits 29,528 37,193 SFAS 109 regulatory liability - net 13,099 23,626 Other 11,191 11,680 ---------- ---------- Total 355,106 384,115 ---------- ---------- Commitments and Contingencies (Notes 2 and 8) TOTAL $1,629,445 $1,676,737 ========== ========== See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1994 1993 1992 (In Thousands) Operating Activities: Net income $48,779 $101,743 $65,036 Noncash items included in net income: Cumulative effect of a change in accounting principle - (32,706) - Change in rate deferrals 109,105 71,555 17,530 Depreciation and amortization 36,592 32,152 31,493 Deferred income taxes and investment tax credits (34,409) (17,881) 18,685 Allowance for equity funds used during construction (1,660) (928) (668) Changes in working capital: Receivables 33,154 (11,814) (924) Fuel inventory 3,872 (1,327) 2,061 Accounts payable (8,783) 5,055 (14,365) Other working capital accounts 13,480 (1,120) 1,918 Other 1,209 8,073 (4,272) -------- -------- -------- Net cash flow provided by operating activities 195,114 149,382 118,773 Investing Activities: -------- -------- -------- Construction expenditures (121,386) (66,404) (53,481) Allowance for equity funds used during construction 1,660 928 668 -------- -------- -------- Net cash flow used in investing activities (119,726) (65,476) (52,813) -------- -------- -------- Financing Activities: Proceeds from issuance of: General and refunding bonds 24,534 250,000 65,000 Other long-term debt 15,652 - - Common stock - - 25,000 Preferred stock - - 19,777 Retirement of: First mortgage bonds (18,000) (204,501) (101,416) General and refunding bonds (30,000) (55,000) - Other long-term debt (16,045) (230) (210) Redemption of preferred stock (15,000) (16,500) (9,500) Dividends paid: Common stock (45,600) (85,800) (68,400) Preferred stock (7,762) (9,452) (9,445) Changes in short-term borrowings 18,432 11,568 - -------- -------- -------- Net cash flow used in financing activities (73,789) (109,915) (79,194) -------- -------- -------- Net increase (decrease) in cash and cash equivalents 1,599 (26,009) (13,234) Cash and cash equivalents at beginning of period 7,999 34,008 47,242 -------- -------- -------- Cash and cash equivalents at end of period $9,598 $7,999 $34,008 ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $52,737 $52,459 $62,727 Income taxes $39,000 $58,831 $14,866 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 its business, which requires large investments in long-lived assets. While large capital expenditures for the construction of new generating capacity are not currently planned, MP&L does require significant capital resources for the periodic maturity of certain series of debt and preferred stock and ongoing construction expenditures. Net cash flow from operations totaled $195 million, $149 million, and $119 million in 1994, 1993, and 1992, respectively. Net cash flow from operations increased in 1994 due primarily to increased collections under the phase-in plan, as discussed below. 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 its continued efforts to streamline operations and reduce costs, as well as collections under its 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.) MP&L's Grand Gulf 1 rate phase-in plan will continue to contribute to MP&L's cash position through 1998. See Note 2 for additional information on MP&L's rate phase-in plan. See Note 8 for additional information on MP&L's capital and refinancing requirements in 1995 - 1997. Also, to the extent current market interest and dividend rates allow, MP&L may continue to refinance high-cost debt and preferred stock prior to maturity. In March 1994, the MPSC issued a final order adopting a formulary incentive rate plan. The order also adopted previously agreed-upon stipulations of a required return on equity of 11% and certain accounting adjustments that resulted in a 4.3% ($28.1 million) reduction in MP&L's June 30, 1993, test-year base revenues effective March 25, 1994. The plan allows for periodic small adjustments in rates based on an annual comparison of earned to benchmark rates of return and upon certain other performance factors. See Note 2 for additional information. Earnings coverage tests, bondable property additions, and accumulated deferred Grand Gulf 1-related costs recorded as assets, limit the amount of G&R Bonds and preferred stock that MP&L can issue. Based on the most restrictive applicable tests as of December 31, 1994 and assuming an annual interest or dividend rate of 9.25%, MP&L could have issued $246 million of additional G&R Bonds or $95 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 for information on MP&L's financing activities and Note 4 for information on MP&L's short-term borrowings and lines of credit. MP&L's liquidity was adversely affected during 1994 due to incurring $77 million of repairs and improvements associated with an ice storm in February. See Note 2 for information regarding a rate increase in September to recover ice storm costs. MISSISSIPPI POWER & LIGHT COMPANY STATEMENTS OF INCOME For the Years Ended December 31, 1994 1993 1992 (In Thousands) Operating Revenues $847,888 $895,806 $817,650 ---------- ---------- ---------- Operating Expenses: Operation and maintenance: Fuel and fuel-related expenses 160,227 140,391 112,032 Purchased power 235,019 289,016 301,912 Other operation and maintenance 156,954 156,405 146,440 Depreciation and amortization 36,592 32,152 31,493 Taxes other than income taxes 43,963 41,878 40,738 Income taxes 16,651 33,074 21,681 Rate deferrals: Rate deferrals - - (22,876) Amortization of rate deferrals 102,725 77,570 61,456 ---------- ---------- ---------- Total 752,131 770,486 692,876 ---------- ---------- ---------- Operating Income 95,757 125,320 124,774 ---------- ---------- ---------- Other Income (Deductions): Allowance for equity funds used during construction 1,660 928 668 Miscellaneous - net (1,117) 948 4,562 Income taxes - (debit) 4,176 (3,462) (1,467) ---------- ---------- ---------- Total 4,719 (1,586) 3,763 ---------- ---------- ---------- Interest Charges: Interest on long-term debt 47,835 53,558 62,394 Other interest - net 4,929 1,802 1,672 Allowance for borrowed funds used during construction (1,067) (663) (565) ---------- ---------- ---------- Total 51,697 54,697 63,501 ---------- ---------- ---------- Income before Cumulative Effect of a Change in Accounting Principle 48,779 69,037 65,036 Cumulative Effect to January 1, 1993 of Accruing Unbilled Revenues (net of income taxes of $19,456) - 32,706 - ---------- ---------- ---------- Net Income 48,779 101,743 65,036 Preferred Stock Dividend Requirements and Other 7,624 9,160 9,513 ---------- ---------- ---------- Earnings Applicable to Common Stock $41,155 $92,583 $55,523 ========== ========== ========== See Notes to Financial Statements. MISSISSIPPI POWER & LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1994 1993 1992 (In Thousands) Retained Earnings, January 1 $236,337 $230,201 $243,819 Add: Net income 48,779 101,743 65,036 -------- -------- -------- Total 285,116 331,944 308,855 -------- -------- -------- Deduct: Dividends declared: Preferred stock 7,404 8,964 9,513 Common stock 45,600 85,800 68,400 Preferred stock expenses 101 843 741 -------- -------- -------- Total 53,105 95,607 78,654 -------- -------- -------- Retained Earnings, December 31 (Note 7) $232,011 $236,337 $230,201 ======== ======== ======== See Notes to Financial Statements. MISSISSIPPI POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income decreased in 1994 due primarily to the one-time recording in the first quarter of 1993 of the cumulative effect of the change in accounting principle for unbilled revenues. In addition, net income was reduced by the rate reduction in connection with the formula incentive rate plan, partially offset by a FERC settlement (see Litigation and Regulatory Proceedings below). 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 and its ongoing effects, partially offset by the effects of implementing SFAS 109 and SFAS 106. 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. Significant factors affecting the results of operations and causing variances between the years 1994 and 1993, and 1993 and 1992, are discussed under "Revenues and Sales," "Expenses," and "Other" below. Revenues and Sales See "Selected Financial Data - Five-Year Comparison" following the notes, for information on operating revenues by source and KWH sales. Operating revenues decreased in 1994 due to the impact of the rate reduction in connection with the incentive rate plan that went into effect in March 1994, partially offset by higher energy sales. In addition to the factors cited above for revenues, accrued unbilled revenues decreased due to a change in the cycle billing dates offset by an increase in billed revenues. This decrease was partially offset by increased retail energy sales resulting from increased commercial and industrial sales. 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. Expenses Operating expenses decreased in 1994 due primarily to lower purchased power and income tax expense partially offset by increased amortization of rate deferrals. Operating expenses increased in 1993 due primarily to higher fuel and maintenance expenses and increased amortization of rate deferrals. Purchased power expense decreased in 1994 due primarily to changes in generation availability and requirements among the System operating companies. A lower per unit price for power purchased also contributed to the decrease in purchased power in 1994. 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. Other operation and maintenance expense was higher in 1993 due primarily to an increase in scheduled maintenance at MP&L's power plants. Income taxes decreased in 1994 due primary to lower pretax income, and the write-off of unamortized deferred investment tax credits in accordance with a FERC settlement. Income taxes increased in 1993 due to the effect of high pretax income, an increase in the federal income tax rate as a result of OBRA, and the effect of implementing SFAS 109. The amortization of rate deferrals increased in 1994 and 1993 reflecting the fact that MP&L, based on the Revised Plan, collected more Grand Gulf 1-related costs from its customers in 1994 than it recovered in 1993 and 1992. Interest expense decreased in 1994 and 1993 due primarily to the refinancing of high-cost long-term debt and the maturity of high-cost long-term debt. MISSISSIPPI POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Competition The electric utility industry is becoming increasingly competitive and MP&L is seeking to become a leading competitor in the changing electric energy business. Competition presents MP&L with many challenges. The following have been identified by MP&L as its major competitive challenges. Retail and Wholesale Rate Issues The retail regulatory philosophy is shifting in some jurisdictions from traditional cost of service regulation to incentive rate regulation. Incentive and performance-based rate plans encourage efficiencies and productivity while permitting utilities and their customers to share in the results. MP&L implemented an incentive rate plan in 1994. Recognizing that many industrial customers have energy alternatives, MP&L continues to work with these customers to address their needs. In certain cases, competitive prices are negotiated, using variable rate designs. MP&L's formulary incentive rate plan allows for periodic small adjustments in rates based on a comparison of earned to benchmark returns and upon certain performance factors. In addition, certain previously agreed-upon stipulations of a required return on equity of 11% and certain accounting adjustments resulted in a 4.3% ($28.1 million) reduction in MP&L's revenues effective March 25, 1994. For further information see Note 2. In connection with the Merger, MP&L agreed with their respective retail regulators not to request any general retail rate increases that would take effect before November 1998, with certain exceptions. Retail wheeling, 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, is evolving. Over a dozen states have been studying the concept of retail competition. In April 1994, the state of Michigan agreed to a five-year experiment that allows limited competition among public utilities. During the same month, the California Public Utilities Commission proposed to deregulate that state's electric power industry, starting on January 1, 1996, to allow the largest industrial customers to select the lowest cost supplier for electricity service. Under the proposal, by the year 2002, smaller companies and residential customers in California would also be able to buy power from any suppliers. The California Public Utilities Commission is currently reviewing its decision and is expected to make a ruling in the first half of 1995. The retail market for electricity is expected to become more competitive with such moves toward deregulation. In some areas of the country, municipalities (or comparable entities) whose residents are served at retail by an investor-owned utility pursuant to a franchise are exploring the possibility of establishing new or extending existing distribution systems or seeking new delivery points in order to serve retail customers, especially large industrial customers, that currently receive service from an investor-owned utility. These options depend on the terms of a utility's franchise as well as on state law and regulation. In addition, FERC's authority to order utilities to transmit for a new or expanding municipal system is limited in certain respects. Where successful, however, the establishment of a municipal system or the acquisition by a municipal system of a utility's customers could result in the inability to recover costs that the utility has incurred in serving those customers. On October 11, 1994, twelve Mississippi cities filed a complaint in state court against MP&L and eight electric power associations seeking a judgment from the court declaring unconstitutional certain Mississippi statutes that establish the procedure that must be followed before a municipality can acquire the facilities and certificate rights of a utility serving in the municipality. Specifically, the suit requests that the court declare unconstitutional certain 1987 amendments to the Mississippi Public Utilities Act that require that the MPSC cancel a utility's certificate to serve in the municipality before a municipality may acquire a utility's facilities located in the municipality. The suit also requests that the court find that Mississippi municipalities can serve any consumer in the boundaries of the municipality and within one mile thereof. Such a finding would be contrary to Mississippi Supreme Court decisions that have held that a municipality cannot serve in another utility's service area even where the municipal boundaries extend into such service area. On January 6, 1995, MP&L and the other defendants filed motions to dismiss. The matter is pending and will be vigorously contested by MP&L. In mid-1994, the FERC issued a notice of proposed rulemaking concerning a regulatory framework for dealing with recovery of stranded costs, such as high cost nuclear generating units, which may be incurred by electric utilities as a result of increased competition. In addition to addressing recovery of stranded costs related to wholesale service, the proposal requested comment as to recovery of retail stranded costs in transmission rates where state regulatory authorities failed to address the issue or were in conflict. Comments and reply comments have been filed, and the matter is pending. The risk of exposure to stranded costs which may result from competition in the industry will depend on the extent and timing of retail competition, the resolution of jurisdictional issues concerning stranded cost recovery and the extent to which such costs are recovered from departing or remaining customers, among other matters. 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. On January 25, 1995, Entergy Services filed with FERC revised transmission tariffs intended to provide access to transmission service on the same or comparable basis, terms, and conditions as the System operating companies. Open access and market pricing, once in 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 become more competitive. In 1994, MP&L announced a restructuring program related to certain of its operating units. This program is designed to reduce costs and improve operating efficiencies. See Note 12 for further information. Also, in response to an increasingly competitive environment, MP&L announced intentions to revise its initial least cost planning activities. The Energy Policy Act of 1992 The EPAct addresses a wide range of energy issues and is altering the way Entergy and the rest of the electric utility industry operate. The EPAct encourages competition and affords utilities the opportunities, and the risks, associated with an open and more competitive market environment. The EPAct creates exemptions from regulation under the Holding Company Act and creates a class of exempt wholesale generators consisting of utility affiliates and nonutilities that are owners and operators of facilities for the generation and transmission of power for sales at wholesale. The EPAct also gives FERC the authority to order investor-owned utilities, including MP&L, 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. Both MP&L and Entergy Power expect to compete in this market. In addition, the EPAct allows utilities to own and operate foreign generation, transmission, and distribution facilities. Litigation and Regulatory Proceedings In November 1994, FERC approved an agreement settling a long- standing dispute involving income tax allocation procedures of System Energy. In accordance with the agreement, System Energy refunded approximately $20.4 million to MP&L, which will in turn make refunds or credits to its customers. Additionally, System Energy will refund a total of approximately $20.5 million, plus interest, to MP&L over the period through June 2004. The settlement also required the write- off of approximately $6 million of certain unamortized deferred investment tax credits by MP&L. Accounting Issues Proposed Accounting Standards - The FASB has proposed a SFAS on "Accounting for the Impairment of Long-Lived Assets," effective January 1, 1996. The proposed standard describes circumstances which may result in assets being impaired and provides criteria for recognition and measurement of asset impairment. Certain operations of MP&L are potentially affected by this standard, and any resulting write-offs will depend on future operating costs, generating units' efficiency and availability, and the future market for energy over the remaining life of the units. Based on current estimates, MP&L anticipates that future revenues will fully recover the costs of such operations. Continued Application of SFAS 71 - MP&L's financial statements currently reflect assets and costs based on current cost-based ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." As discussed above, the electric utility industry is changing and these changes could possibly result in the discontinuance of the application of SFAS 71, which would result in the elimination of regulatory assets and liabilities. See Note 1 for further information. 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. Total MP&L net utility plant in service of $893 million as of December 31, 1994 includes $220 million of production plant, $249 million of transmission plant, $358 million of distribution plant, and $66 million of other plant. 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 1994 and 1993, and 2.5% in 1992. 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 8.0%, 11.8%, and 12.0%, for 1994, 1993, and 1992, respectively. 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 1,678 megawatts. MP&L records its investment in and expenses associated with this station to the extent of its ownership and interest. MP&L's investment in the Independence Station was approximately $222 million less accumulated depreciation of approximately $73.6 million as of December 31, 1994. 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 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 Entergy Corporation subsidiary 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, in 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. Continued Application of SFAS 71 As a result of the EPAct and actions of regulatory commissions, the electric utility industry is moving toward a combination of competition and a modified regulatory environment. MP&L's financial statements currently reflect assets and costs based on current cost- based ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Continued applicability of SFAS 71 to MP&L's financial statements requires that rates set by an independent regulator on a cost of service basis (including a reasonable rate of return on invested capital) can actually be charged to and collected from customers. In the event that either all or a portion of a utility's operations cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation, or a change in the competitive environment for the utility's regulated services, the utility should discontinue application of SFAS 71 for the relevant portion. That discontinuation should be reported by elimination from the balance sheet of the effects of any actions of regulators recorded as regulatory assets and liabilities. As of December 31, 1994, and for the foreseeable future, MP&L's financial statements continue to follow SFAS 71. Fair Value Disclosure The estimated fair value of financial instruments has 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 Formula Rate Plan Under a formulary incentive rate plan (Formula Rate Plan) effective March 25, 1994, MP&L's earned rate of return is calculated automatically every 12 months and compared to and adjusted against a benchmark rate of return (calculated under a separate formula within the Formula Rate Plan). The Formula Rate Plan allows for periodic small adjustments in rates based on a comparison of earned to benchmark returns and upon certain performance factors. In the same proceeding, the MPSC conducted a general review of MP&L's current rates and on March 1, 1994, issued a final order adopting the Formula Rate Plan and previously agreed-upon stipulations of (1) a required return on equity of 11% and (2) certain accounting adjustments that resulted in a 4.3% ($28.1 million) reduction in MP&L's June 30, 1993, test-year base revenues. The MPSC's order required MP&L to file rates designed to provide for this reduction in operating revenues for the test year on or before March 18, 1994, which became effective March 25, 1994. The final order was appealed to the Mississippi Supreme Court on May 17, 1994, by Mississippi Valley Gas Company (MVG) on the grounds that the MPSC issued the final order without having reviewed the cost of MP&L's promotional practices, some of which MVG alleged to be improper. On October 28, 1994, the Mississippi Supreme Court granted MVG's motion to dismiss the appeal. Merger - Related 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 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 for, among other things, increases associated with the 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. February 1994 Ice Storm/Rate Rider In early February 1994, an ice storm left more than 80,000 MP&L customers without electric power across the 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. Repair costs totaled approximately $77.2 million, with $64.6 million of these amounts capitalized as plant-related costs. The remaining balances have been recorded as a deferred debit. On April 15, 1994, MP&L filed for rate recovery of costs related to the ice storm. MP&L's filing, as subsequently amended, requested recovery of the revenue requirement associated with MP&L's ice storm costs recorded through April 30, 1994, representing approximately 86% of the total estimated ice storm costs. MP&L may make another ice storm rate filing with the MPSC during 1995 to recover ice storm costs recorded by MP&L after April 30, 1994. In August 1994, MP&L and the MPSC's Public Utilities Staff entered into a stipulation with respect to the recovery of ice storm costs recorded through April 30, 1994, and in September 1994, the MPSC approved the stipulation. Under the stipulation, MP&L implemented an ice storm rider schedule, which went into effect on September 29, 1994, that will increase rates approximately $8 million annually for five years. At the end of the five-year period, the revenue requirement associated with the undepreciated ice storm capitalized costs will be included in MP&L's base rates to the extent that this revenue requirement does not result in MP&L's rate of return on rate base being above the benchmark rate of return under MP&L's formula rate plan. NOTE 3. INCOME TAXES
Income tax expense consisted of the following: For the Years Ended December 31, 1994 1993 1992 (In Thousands) Current: Federal $ 39,505 $46,744 $4,532 State 7,379 7,673 (69) -------- ------- ------- Total 46,884 54,417 4,463 -------- ------- ------- Deferred - net: Federal reclassification due to net operating loss - - 28,561 State reclassification due to net operating loss - - 4,883 Liberalized depreciation 15,880 5,293 9,448 Rate deferral - net (45,565) (31,317) (11,220) Unbilled revenue 3,167 21,373 (5,722) Pension liability 434 (647) (1,233) Adjustments of prior year taxes (1,954) 4,299 (3,471) Bond reacquisition (447) 3,208 264 Other 1,722 (1,670) (1,079) -------- ------- ------- Total (26,763) 539 20,431 -------- ------- ------- Investment tax credit adjustments - net (1,673) 1,036 (1,746) Investment tax credit amortization - FERC settlement (5,973) - - -------- ------- ------- Recorded income tax expense $12,475 $55,992 $23,148 ======== ======= ======= Charged to operations $16,651 $33,074 $21,681 Charged (credited) to other income (4,176) 3,462 1,467 Charged to cumulative effect - 19,456 - -------- ------- ------- Total income taxes $12,475 $55,992 $23,148 ======== ======= =======
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, 1994 1993 1992 % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income (Dollars in Thousands) Computed at statutory rate $21,438 35.0 $55,207 35.0 $29,983 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 2,465 4.0 3,253 2.0 2,703 3.1 Depreciation 1,930 3.2 (5,890) (3.7) (2,571) (2.9) Amortization of excess deferred income taxes (3,810) (6.2) (4,680) (3.0) (2,456) (2.8) Amortization of investment tax credits (1,674) (2.7) (1,772) (1.1) (1,746) (2.0) Investment tax credit amortization - FERC settlement (5,973) (9.8) - - - - Adjustments of prior year taxes (1,954) (3.2) 5,228 3.3 (2,760) (3.2) SFAS 109 adjustment - - 3,439 2.2 - - Other - net 53 .1 1,207 0.8 (5) - ------- ---- ------- ---- ------- ---- Total income taxes $12,475 20.4 $55,992 35.5 $23,148 26.2 ======= ==== ======= ==== ======= ====
Significant components of MP&L's net deferred tax liabilities as of December 31, 1994 and 1993, were (in thousands): 1994 1993 Deferred tax liabilities: Plant related basis differences $(173,965) $(166,650) Rate deferrals (201,037) (246,604) Other (13,318) (6,406) --------- --------- Total $(388,320) $(419,660) ========= ========= Deferred tax assets: Net regulatory liabilities $ 1,804 $ 9,411 Accumulated deferred investment tax credits 11,295 13,420 Recoverable income tax - 13,854 Alternative minimum tax credit - 1,192 Removal cost 2,824 10,725 Standard coal plant 4,717 4,854 Pension related items 3,182 2,488 Other 15,695 10,342 -------- -------- Total $ 39,517 $ 66,286 ======== ======== Net deferred tax liabilities $(348,803) $(353,374) ========= ========= In accordance with a System Energy FERC settlement, MP&L wrote off $6.0 million of unamortized deferred investment tax credits in 1994. In 1993, MP&L adopted SFAS 109. SFAS 109 required 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 required 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. 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. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized MP&L to effect short-term borrowings up to $100 million, which may be increased to as much as $108 million after further SEC approval. This authorization is effective through November 30, 1996. As of December 31, 1994, MP&L had outstanding short-term lines of credit of $30 million from banks within its service territory. Interest rates associated with these lines of credit generally are based on the prime rate, the London interbank offered rate, or a bid rate. Commitment fees on these lines of credit are .125% of the amount of available credit. 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 no outstanding borrowings under the Money Pool arrangement as of December 31, 1994. NOTE 5. PREFERRED AND COMMON STOCK The number of shares and dollar value of MP&L's cumulative, $100 par value preferred stock were:
As of December 31, Shares Call Price Per Authorized and Total Share as of Outstanding Dollar Value December 31, 1994 1993 1994 1993 1994 (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 (1) 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 70,000 140,000 $7,000 $14,000 $106.75 9.76% Series 210,000 280,000 21,000 28,000 $102.17 12.00% Series 37,700 47,700 3,770 4,770 $106.00 ------- ------- ------- ------- Total with sinking fund 317,700 467,700 $31,770 $46,770 ======= ======= ======= =======
(1) This series is not redeemable as of December 31, 1994. The fair value of MP&L's preferred stock with sinking fund was estimated to be approximately $32.5 million and $49.3 million as of December 31, 1994 and 1993, respectively. The fair values were 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 and preferred stock, with and without sinking fund, during the last three years were:
Number of Shares 1994 1993 1992 Common stock issuances($23 issuance price) - - 1,086,957 Preferred stock issuances: - - 200,000 Preferred stock retirements: (150,000) (165,000) (95,000)
Cash sinking fund requirements for the next five years for preferred stock outstanding as of December 31, 1994, are (in millions): 1995 - $15, 1996 - $7.5, 1997 - $7.5, 1998 - $0.5; and 1999 - $0.5. MP&L has the annual non-cumulative option to redeem at par, additional amounts of its 12.00% Series preferred stock outstanding. NOTE 6. LONG-TERM DEBT The long-term debt of MP&L as of December 31, 1994 and 1993, was: Maturities Interest Rates From To From To 1994 1993 (In Thousands) First Mortgage Bonds 1995 1996 4-5/8% 6-3/8% $55,000 $55,000 G&R Bonds 1995 1997 5.95% 14.95%* 167,000 215,000 2003 2023 6-5/8% 8.65% 275,000 250,000 Governmental Obligations** 1995 2004 7-1/2% 8-1/2% 1,880 17,925 2012 2022 7% 11-1/2% 46,030 30,000 Unamortized Premium and Discount-Net (3,712) (3,519) -------- -------- Total Long-Term Debt 541,198 564,406 Less Amount Due Within One Year 65,965 48,250 -------- -------- Long-Term Debt Excluding Amount Due $475,233 $516,156 Within One Year ======== ======== * The 14.95% series of $20 million was due February 1, 1995. 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, 1994 and 1993, was estimated to be $523.1 million and $594.0 million, respectively. The fair values were 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 1995, 1996, 1997, 1998 and 1999, MP&L has long-term debt maturities and cash sinking fund requirements of (in millions) $66, $61, $96, $0, and $0, respectively. In addition, other sinking fund requirements of approximately $0.4 million for 1995 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, 1994, the total amount of G&R Bonds outstanding aggregated $442 million. 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, 1994, $139.3 million of MP&L's retained earnings were restricted against the payment of cash dividends or other distributions on common stock. On February 1, 1995, MP&L paid Entergy Corporation a $8.3 million cash dividend on common stock. NOTE 8. COMMITMENTS AND CONTINGENCIES Capital Requirements and Financing Construction expenditures for the years 1995, 1996, and 1997 are estimated to total $67.9 each year. MP&L will also require $253 million during the period 1995-1997 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. 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 under the agreement is approximately $16 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. 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. 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, 1994, 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 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 2011. 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 1994, 1993, and 1992 pension cost, including amounts capitalized, included the following components:
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Service cost - benefits earned during the period $2,484 $2,409 $ 2,059 Interest cost on projected benefit obligation 8,648 8,583 8,269 Actual return on plan assets 1,507 (15,053) (8,474) Net amortization and deferral (11,843) 5,325 (1,009) ------- ------- ------ Net pension cost $796 $1,264 $845 ======= ======= ======
The funded status of MP&L's pension plan as of December 31, 1994 and 1993, was:
1994 1993 (In Thousands) Actuarial present value of accumulated pension plan benefits: Vested $ 94,978 $101,664 Nonvested 299 390 -------- -------- Accumulated benefit obligation $ 95,277 $102,054 ======== ======== Plan assets at fair value $117,853 $126,990 Projected benefit obligation 109,250 122,056 -------- -------- Plan assets in excess of projected benefit obligation 8,603 4,934 Unrecognized prior service cost 4,198 3,574 Unrecognized transition asset (8,752) (10,003) Unrecognized net gain (8,138) (1,798) -------- -------- Accrued pension liability $ (4,089) $ (3,293) ======== ========
The significant actuarial assumptions used in computing the information above for 1994, 1993, and 1992 were as follows: weighted average discount rate, 8.5% for 1994, 7.5% for 1993 and 8.25% for 1992; weighted average rate of increase in future compensation levels, 5.1% for 1994 and 5.6% for 1993 and 1992; 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. Effective January 1, 1993, MP&L adopted SFAS 106. This standard required a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. At January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $30 million. This obligation is being amortized over a 20-year period beginning in 1993. MP&L is expensing its SFAS 106 costs, which is reflected in rates pursuant to an order from the MPSC in connection with MP&L's formulary incentive rate plan (see Note 2). In conjunction with such rate incentive plan, MP&L has established and commenced funding two Voluntary Employee's Beneficiary Association (VEBA) trusts (for bargaining and non-bargaining unit employees). During 1994, MP&L funded $2.9 million to these VEBA trusts. The trust's assets are invested in a money market fund. MP&L's 1994 and 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components: 1994 1993 (In Thousands) Service cost - benefits earned during the period $ 876 $ 812 Interest cost on APBO 1,833 2,400 Net amortization and deferral 1,122 1,502 ------ ------ Net periodic postretirement benefit cost $3,831 $4,714 ====== ====== The funded status of MP&L's postretirement plan as of December 31, 1994 and 1993, was 1994 1993 Accumulated postretirement benefit obligations: (In Thousands) Retirees $15,531 $21,435 Other fully eligible participants 4,293 5,816 Other active participants 3,561 7,794 ------- ------- 23,385 35,045 Plan assets at fair value 2,949 - ------- ------- Plan assets less than APBO (20,436) (35,045) Unrecognized transition obligation 27,035 28,537 Unrecognized net loss (gain) (8,636) 3,745 ------- ------- Accrued post retirement benefit liability $(2,037) $(2,763) ======= ======= The assumed health care cost trend rate used in measuring the APBO was 9.4% for 1995, gradually decreasing each successive year until it reaches 5.0% in 2011. 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, 1994, by 7.4% and the sum of the service cost and interest cost by approximately 9.5%. The assumed discount rate and rate of increase in future compensation used in determining the APBO were 8.5% for 1994 and 7.5% for 1993 and 5.1% for 1994 and 5.5% for 1993, respectively. NOTE 10. TRANSACTIONS WITH AFFILIATES MP&L buys electricity from and/or sells electricity to the other System operating companies 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. Operating revenues include revenues from sales to affiliates amounting to $45.8 million in 1994, $40.6 million in 1993, and $18 million in 1992. Operating expenses include charges from affiliates for fuel costs, purchased power and related charges, and technical and advisory services totaling $280.2 million in 1994, $360.5 million in 1993, and $364 million in 1992. See Note 1 for information on MP&L's jointly-owned generating station. NOTE 11. RESTRUCTURING COSTS During the third quarter of 1994, MP&L announced a restructuring program related to certain of its operating units. The program is designed to reduce costs, improve operating efficiencies, and increase shareholder value in order to enable MP&L to become a low-cost producer. The program includes reductions in the number of employees and the consolidation of offices and facilities. In 1994, MP&L recorded restructuring charges of $6.2 million. These charges primarily include employee severance costs related to the expected termination of approximately 262 employees. As of December 31, 1994, no employees have been terminated and no termination benefits have been paid under this restructuring program. 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 1994 and 1993 were: Operating Operating Net Revenues Income Income (In Thousands) 1994: First Quarter $187,417 $18,715 $ 6,249 Second Quarter $229,790 $33,828 $21,653 Third Quarter $234,274 $23,675 $10,856 Fourth Quarter $196,407 $19,539 $10,021 1993: First Quarter $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 See Note 1 for information regarding the recording of the cumulative effect of the change in accounting principle for unbilled revenues in January 1993. MISSISSIPPI POWER & LIGHT COMPANY SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1994 1993 1992 1991 1990 (In Thousands) Operating revenues $ 847,888 $ 895,806 $ 817,650 $ 754,632 $ 761,188 Income before cumulative effect of a change in accounting principle $ 48,779 $ 69,037 $ 65,036 $ 63,088 $ 60,830 Total assets $1,629,445 $1,676,737 $1,660,726 $1,672,275 $1,616,522 Long-term obligations (1) $ 507,555 $ 563,612 $ 576,787 $ 576,599 $ 679,458
(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. 1994 1993 1992 1991 1990 (Dollars in Thousands) Operating Revenues: Residential $331,007 $343,585 $308,346 $307,283 $302,622 Commercial 255,898 252,798 235,137 229,597 227,140 Industrial 183,398 183,537 168,853 162,072 160,007 Governmental 27,349 28,708 26,250 25,630 25,117 -------- -------- -------- -------- -------- Total retail 797,652 808,628 738,586 724,582 714,886 Sales for resale 54,475 55,740 37,983 25,487 35,678 Other (4,239) 31,438 41,081 4,563 10,624 -------- -------- -------- -------- -------- Total $847,888 $895,806 $817,650 $754,632 $761,188 ======== ======== ======== ======== ======== Billed Electric Energy Sales (Millions of KWH): Residential 4,014 3,983 3,644 3,739 3,701 Commercial 3,151 2,928 2,804 2,807 2,802 Industrial 2,985 2,787 2,631 2,582 2,564 Governmental 330 336 318 321 318 ------ ------ ------ ------ ------ Total retail 10,480 10,034 9,397 9,449 9,385 Sales for resale 1,591 1,428 1,190 1,032 902 ------ ------ ------ ------ ------ Total 12,071 11,462 10,587 10,481 10,287 ====== ====== ====== ====== ====== New Orleans Public Service Inc. 1994 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 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 Entergy Services Entergy Services, Inc. EPAct The Energy Policy Act of 1992 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 (nuclear) Grand Gulf 2 Unit No. 2 of the Grand Gulf Station (nuclear) Grand Gulf Station Grand Gulf Steam Electric Generating Station (nuclear) 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 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 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS 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 Entergy Corporation Board of Directors' Audit Committee functions as the Audit Committee for New Orleans Public Service Inc. The Audit Committee is comprised of four directors, who are not officers of NOPSI: H. Duke Shackelford (Chairman), Lucie J. Fjeldstad, Dr. Norman C. Francis, and James R. Nichols. The committee held four meetings during 1994. 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 (Coopers & Lybrand L.L.P.) 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/ H. Duke Shackelford H. DUKE SHACKELFORD Chairman, Audit Committee REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of New Orleans Public Service Inc. We have audited the accompanying balance sheet of New Orleans Public Service Inc. as of December 31, 1994, and the related statements of income, retained earnings and cash flows for the year then ended. 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 audit. The financial statements of the Company as of December 31, 1993 and for the years ended December 31, 1993 and 1992, were audited by other auditors, whose report, dated February 11, 1994, included an explanatory paragraph that described changes in methods of accounting for revenues, income taxes and postretirement benefits other than pensions which are discussed in Notes 1, 3 and 9 respectively, to these financial statements. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1994, and the result of its operations and its cash flows for the year then ended in conformity with generally accepted accounting principles. /s/ Coopers & Lybrand L.L.P. COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 21, 1995 INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directors of New Orleans Public Service Inc. We have audited the accompanying balance sheet of New Orleans Public Service Inc. (NOPSI) as of December 31, 1993, and the related statements of income, retained earnings, and cash flows for each of the two 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 the results of its operations and its cash flows for each of the two 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 LLP DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994
NEW ORLEANS PUBLIC SERVICE INC. BALANCE SHEETS ASSETS December 31, 1994 1993 (In Thousands) Utility Plant: Electric $470,560 $476,976 Natural gas 119,508 113,666 Construction work in progress 7,284 15,205 -------- -------- Total 597,352 605,847 Less - accumulated depreciation and amortization 319,576 330,268 -------- -------- Utility plant - net 277,776 275,579 -------- ------- Other Investments: Investment in subsidiary company - at equity 3,259 3,259 -------- -------- Current Assets: Cash and cash equivalents: Cash 849 1,176 Temporary cash investments - at cost, which approximates market: Associated companies 2,472 10,034 Other 4,710 32,107 -------- -------- Total cash and cash equivalents 8,031 43,317 Accounts receivable: Customer (less allowance for doubtful accounts of $0.8 million in 1994 and 1993) 23,938 35,801 Associated companies 3,503 1,378 Other 600 876 Accrued unbilled revenues 14,295 19,643 Deferred electric fuel and resale gas costs 856 6,323 Materials and supplies - at average cost 9,676 9,795 Rate deferrals 31,544 24,587 Income tax receivable 20,172 - Prepayments and other 5,636 5,084 -------- -------- Total 118,251 146,804 -------- -------- Deferred Debits and Other Assets: Regulatory Assets: Rate deferrals 173,127 204,190 SFAS 109 regulatory asset - net 8,792 9,004 Unamortized loss on reacquired debt 2,361 2,790 Other regulatory assets 5,647 4,027 Other 3,681 1,952 -------- -------- Total 193,608 221,963 -------- -------- TOTAL $592,894 $647,605 ======== ======== See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC. BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 1994 1993 (In Thousands) Capitalization: Common stock, $4 par value, authorized 10,000,000 shares; issued and outstanding 8,435,900 shares in 1994 and 1993 $33,744 $33,744 Paid-in capital 36,201 36,156 Retained earnings subsequent to the elimination of the accumulated deficit on November 30, 1988 78,886 100,556 -------- -------- Total common shareholder's equity 148,831 170,456 Preferred stock: Without sinking fund 19,780 19,780 With sinking fund 3,450 4,950 Long-term debt 164,160 188,312 -------- -------- Total 336,221 383,498 -------- -------- Other Noncurrent Liabilities: Accumulated provision for losses 17,318 18,062 Other 1,745 3,351 -------- -------- Total 19,063 21,413 -------- -------- Current Liabilities: Currently maturing long-term debt 24,200 15,000 Accounts payable: Associated companies 6,456 23,080 Other 19,503 22,011 Customer deposits 17,422 16,617 Accumulated deferred income taxes 4,925 4,968 Taxes accrued 2,329 5,161 Interest accrued 5,242 5,472 Other 19,982 7,367 -------- -------- Total 100,059 99,676 -------- -------- Deferred Credits: Accumulated deferred income taxes 89,246 105,096 Accumulated deferred investment tax credits 9,251 11,592 Other 39,054 26,330 -------- -------- Total 137,551 143,018 -------- -------- Commitments and Contingencies (Notes 2 and 8) TOTAL $592,894 $647,605 ======== ======== See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1994 1993 1992 (In Thousands) Operating Activities: Net income $13,211 $47,709 $26,424 Noncash items included in net income: Cumulative effect of a change in accounting principle - (10,948) - Change in rate deferrals 24,106 15,842 2,856 Depreciation and amortization 19,275 17,284 16,619 Deferred income taxes and investment tax credits (18,006) (2,132) (865) Allowance for equity funds used during construction (331) (141) (119) Net pension expense - - (23,131) Changes in working capital: Receivables 15,362 (6,725) 1,579 Accounts payable (19,132) 1,169 (1,455) Taxes accrued (2,832) (82) 1,473 Interest accrued (230) (1,319) (1,687) Income tax receivable (20,172) - - Other working capital accounts 18,454 1,365 (6,344) Other 8,851 8,345 7,047 -------- -------- -------- Net cash flow provided by operating activities 38,556 70,367 22,397 -------- -------- -------- Investing Activities: Construction expenditures (22,777) (24,813) (21,043) Allowance for equity funds used during construction 331 141 119 -------- -------- -------- Net cash flow used in investing activities (22,446) (24,672) (20,924) -------- -------- -------- Financing Activities: Proceeds from the issuance of general and refunding bonds - 100,000 - Retirement of: First mortgage bonds - (56,823) (28,000) General and refunding bonds (15,000) (44,400) - Redemption of preferred stock (1,500) (1,500) (1,500) Dividends paid: Common stock (33,300) (43,900) (32,154) Preferred stock (1,596) (1,825) (2,057) -------- -------- -------- Net cash flow used in financing activities (51,396) (48,448) (63,711) -------- -------- -------- Net decrease in cash and cash equivalents (35,286) (2,753) (62,238) Cash and cash equivalents at beginning of period 43,317 46,070 108,308 -------- -------- -------- Cash and cash equivalents at end of period $8,031 $43,317 $46,070 ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $17,707 $21,953 $26,330 Income taxes $45,984 $25,661 $15,632 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 its business, which requires large investments in long-lived assets. While large capital expenditures for the construction of new generating capacity are not currently planned, NOPSI does require significant capital resources for the periodic maturity of certain series of debt and preferred stock and ongoing construction expenditures. Net cash flow from operations totaled $39 million, $70 million, and $22 million in 1994, 1993, and 1992, respectively. Net cash flow from operations decreased in 1994 due primarily to the effects of the 1994 NOPSI Settlement, as discussed below. 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 its continued efforts to streamline operations and reduce costs, as well as collections under its 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.) NOPSI's Grand Gulf 1 rate phase-in plan will continue to contribute to NOPSI's cash position through 2001. See Note 2 for additional information on NOPSI's rate phase-in plan. See Note 8 for additional information on NOPSI's capital and refinancing requirements in 1995 - 1997. Also, to the extent current market interest and dividend rates allow, NOPSI may continue to refinance high-cost debt and preferred stock prior to maturity. As discussed in Note 2, NOPSI agreed to reduce electric and gas rates and issue credits and refunds to customers pursuant to the 1994 NOPSI Settlement. Under the terms of the settlement, NOPSI implemented rate reductions totaling $44.9 million effective January 1, 1995. NOPSI will implement an additional $4.4 million rate reduction on October 31, 1995. In addition, the 1994 NOPSI Settlement requires NOPSI to credit its customers $25 million over a 21-month period beginning January 1, 1995, in order to resolve disputes with the Council regarding the interpretation of the 1991 NOPSI Settlement. The 1994 NOPSI Settlement also required NOPSI to refund $9.3 million of overcollections associated with Grand Gulf 1 operating costs and $10.5 million of refunds associated with the settlement by System Energy of a FERC tax audit. See Note 2 for additional information. Earnings coverage tests, bondable property additions, and accumulated deferred Grand Gulf 1-related costs recorded as assets, limit the amount of G&R Bonds and preferred stock that NOPSI can issue. Based on the most restrictive applicable tests as of December 31, 1994, and an assumed annual interest or dividend rate of 9.25%, NOPSI could have issued $73 million of additional G&R Bonds or $17 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 for information on NOPSI's financing activities and Note 4 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, 1994 1993 1992 (In Thousands) Operating Revenues: Electric $360,430 $423,830 $391,936 Natural gas 87,357 90,992 72,943 ---------- ---------- ---------- Total 447,787 514,822 464,879 ---------- ---------- ---------- Operating Expenses: Operation and maintenance: Fuel, fuel-related expenses and gas purchased for resale 113,735 112,451 90,778 Purchased power 145,935 165,963 170,703 Other operation and maintenance 80,656 87,797 91,735 Depreciation and amortization 19,275 17,284 16,619 Taxes other than income taxes 27,814 26,643 27,487 Income taxes 3,602 24,232 14,382 Rate deferrals: Rate deferrals - (1,651) (1,300) Amortization of rate deferrals 27,009 22,351 4,426 ---------- ---------- ---------- Total 418,026 455,070 414,830 ---------- ---------- ---------- Operating Income 29,761 59,752 50,049 ---------- ---------- ---------- Other Income (Deductions): Allowance for equity funds used during construction 331 141 119 Miscellaneous - net 2,141 (1,055) 3,056 Income taxes (998) (1,115) (1,683) ---------- ---------- ---------- Total 1,474 (2,029) 1,492 ---------- ---------- ---------- Interest Charges: Interest on long-term debt 17,092 20,076 23,510 Other interest - net 1,179 1,016 1,714 Allowance for borrowed funds used during construction (247) (130) (107) ---------- ---------- ---------- Total 18,024 20,962 25,117 ---------- ---------- ---------- Income before Cumulative Effect of a Change in Accounting Principle 13,211 36,761 26,424 Cumulative Effect to January 1, 1993 of Accruing Unbilled Revenues (net of income taxes of $6,592) - 10,948 - ---------- ---------- ---------- Net Income 13,211 47,709 26,424 Preferred Stock Dividend Requirements and Other 1,581 1,768 1,999 ---------- ---------- ---------- Earnings Applicable to Common Stock $11,630 $45,941 $24,425 ========== ========== ========== See Notes to Financial Statements. NEW ORLEANS PUBLIC SERVICE INC. STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1994 1993 1992 (In Thousands) Retained Earnings, January 1 $100,556 $98,560 $106,341 Add: Net income 13,211 47,709 26,424 -------- -------- -------- Total 113,767 146,269 132,765 -------- -------- -------- Deduct: Dividends declared: Preferred stock 1,536 1,768 1,999 Common stock 33,300 43,900 32,154 Capital stock expenses 45 45 52 -------- -------- -------- Total 34,881 45,713 34,205 -------- -------- -------- Retained Earnings, December 31 (Note 7) $ 78,886 $100,556 $ 98,560 ======== ======== ======== See Notes to Financial Statements. NEW ORLEANS PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income decreased in 1994 due primarily to the effects of the 1994 NOPSI Settlement (see Note 2) and the one-time recording of the cumulative effect of the change in accounting principle for unbilled revenues in 1993, partially offset by lower operating expenses. 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) and its ongoing effects, partially offset by the effect of implementing SFAS 106 (see Note 9). 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. Significant factors affecting the results of operations and causing variances between the years 1994 and 1993, and 1993 and 1992, are discussed under "Revenues and Sales" and "Expenses" below. Revenues and Sales See "Selected Financial Data-Five-Year Comparison," following the notes, for information on electric operating revenues by source and KWH sales. Electric operating revenues decreased in 1994 due primarily to the effects of the 1994 NOPSI Settlement as discussed in Note 2. Electric energy sales increased slightly in 1994. 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. Gas operating revenues decreased slightly in 1994 as a result of lower gas sales. 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. Expenses Operating expenses decreased in 1994 due primarily to lower purchased power expense and lower income tax expense. Operating expenses increased in 1993 due primarily to higher fuel expenses, higher income tax expense, and increased amortization of rate deferrals. Purchased power expense decreased in 1994 due primarily to changes in generation availability and requirements among the System operating companies and lower costs. 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. Gas purchased for resale decreased in 1994 due to decreased gas sales. Gas purchased for resale increased in 1993 due primarily to a higher average per unit cost for gas purchased. Income taxes decreased in 1994 due primarily to lower pretax income, resulting from the 1994 NOPSI Settlement, and the write-off of the unamortized balances of deferred investment tax credits pursuant to the FERC Settlement. 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. The increases in the amortization of rate deferrals in 1994 and 1993 is primarily a result of the collection of larger amounts of previously deferred costs under the 1991 NOPSI Settlement, which allowed NOPSI to record an additional $90 million of previously incurred Grand Gulf 1-related costs. NEW ORLEANS PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Competition The electric utility industry is becoming increasingly competitive and NOPSI is seeking to become a leading competitor in the changing electric energy business. Competition presents NOPSI with many challenges. The following have been identified by NOPSI as its 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, 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. As a result of the 1994 NOPSI Settlement discussed in Note 2, NOPSI agreed to reduce electric and gas rates and issue credits and refunds to customers. Effective January 1, 1995, NOPSI implemented a $31.8 million permanent reduction in electric base rates and a $3.1 million permanent reduction in gas base rates. These adjustments resolved issues associated with NOPSI's return on equity exceeding 13.76% for the test year ended September 30, 1994. Under the 1991 NOPSI Settlement, NOPSI is recovering from its retail customers its allocable share of certain costs related to Grand Gulf 1. NOPSI's base rates to recover those costs were derived from estimates of those costs made at that time. Any overrecovery of costs is required to be returned to customers. Grand Gulf 1 has experienced lower operating costs than previously estimated, and NOPSI accordingly is reducing its base rates in two steps to more accurately match the current costs related to Grand Gulf 1. On January 1, 1995, NOPSI implemented a $10 million permanent reduction in base electric rates to reflect the reduced costs related to Grand Gulf 1, to be followed by an additional $4.4 million rate reduction on October 31, 1995. These Grand Gulf 1 rate reductions, which are expected to be largely offset by lower operating costs, may reduce NOPSI's after-tax net income by approximately $1.4 million per year beginning November 1, 1995. The next scheduled Grand Gulf 1 phase-in rate increase in the amount of $4.4 million on October 31, 1995, will not be affected by the 1994 NOPSI Settlement. The 1994 NOPSI Settlement also requires NOPSI to credit its customers $25 million over a 21-month period beginning January 1, 1995, in order to resolve disputes with the Council regarding the interpretation of the 1991 NOPSI Settlement. NOPSI reduced its revenues and recorded a $15.4 million net-of-tax reserve associated with the credit in the fourth quarter of 1994. The 1994 NOPSI Settlement further required NOPSI to refund, in December 1994, $13.3 million of credits previously scheduled to be made to customers during the period January 1995 through July 1995. These credits were associated with a July 7, 1994, Council resolution that ordered a $24.95 million rate reduction based on NOPSI's overearnings during the test year ended September 30, 1993. Accordingly, NOPSI recorded an $8 million net-of-tax charge in the fourth quarter of 1994. Retail wheeling, 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 area of service, is also evolving. Over a dozen states have been or are studying the concept of retail competition. In April 1994, the state of Michigan initiated a five-year experiment that allows limited competition among public utilities. During the same month, the California Public Utilities Commission proposed to deregulate that state's electric power industry, starting on January 1, 1996, to allow the largest industrial customers to select the lowest cost supplier for electricity service. Under the proposal, by the year 2002, smaller companies and residential customers in California would also be able to buy power from any suppliers. The California Public Utilities Commission is currently reviewing its proposal and is expected to make a ruling in the first half of 1995. The retail market for electricity is expected to become more competitive with such moves toward deregulation. In some areas of the country, municipalities (or comparable entities) whose residents are served at retail by an investor-owned utility pursuant to a franchise are exploring the possibility of establishing new or extending existing distribution systems or seeking new delivery points in order to serve retail customers, especially large industrial customers, that currently receive service from an investor-owned utility. These options depend on the terms of a utility's franchise as well as on state law and regulation. In addition, FERC's authority to order utilities to transmit for a new or expanding municipal system is limited in certain respects. Where successful, however, the establishment of a municipal system or the acquisition by a municipal system of a utility's customers could result in the inability to recover costs that the utility has incurred in serving those customers. In mid-1994, the FERC issued a notice of proposed rulemaking concerning a regulatory framework for dealing with recovery of stranded costs, such as high cost nuclear generating units, which may be incurred by electric utilities as a result of increased competition. In addition to addressing recovery of stranded costs related to wholesale service, the proposal requested comment as to recovery of retail stranded costs in transmission rates where state regulatory authorities failed to address the issue or were in conflict. Comments and reply comments have been filed, and the matter is pending. The risk of exposure to stranded costs which may result from competition in the industry will depend on the extent and timing of retail competition, the resolution of jurisdictional issues concerning stranded cost recovery, and the extent to which such costs are recovered from departing or remaining customers, among other matters. 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. On October 31, 1994, as amended on January 25, 1995, Entergy Services filed with FERC revised transmission tariffs intended to provide access to transmission service on the same or comparable basis, terms, and conditions as the System operating companies, and the matter is pending. Open access and market pricing, once in 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 become more competitive. In 1994, NOPSI announced a restructuring program related to certain of its operating units. This program is designed to reduce costs and improve operating efficiencies. See Note 12 for further information. Also, in response to an increasingly competitive environment, NOPSI announced intentions to revise its initial least cost planning activities. The Energy Policy Act of 1992 The EPAct addresses a wide range of energy issues and is altering the way Entergy and the rest of the electric utility industry operate. The EPAct encourages competition and affords utilities the opportunities, and the risks, associated with an open and more competitive market environment. The EPAct creates exemptions from regulation under the Holding Company Act and creates a class of exempt wholesale generators consisting of utility affiliates and nonutilities that are owners and operators of facilities for the generation and transmission of power for sales at wholesale. The EPAct also gives FERC the authority to order investor-owned utilities, including NOPSI, 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. Both NOPSI and Entergy Power expect to compete in this market. In addition, the EPAct allows utilities to own and operate foreign generation, transmission, and distribution facilities. Litigation and Regulatory Proceedings In November 1994, FERC approved an agreement settling a long- standing dispute involving income tax allocation procedures of System Energy. In accordance with the agreement, System Energy refunded approximately $10.5 million to NOPSI, which in turn made refunds on December 31, 1994, to customers. Additionally, System Energy will refund a total of approximately $10.5 million, plus interest, to NOPSI over the period through June 2004. The settlement also required the write-off of approximately $1.7 million of certain unamortized deferred investment tax credits by NOPSI. Accounting Issues Proposed Accounting Standards - The FASB has proposed a SFAS on "Accounting for the Impairment of Long-Lived Assets," effective January 1, 1996. The proposed standard describes circumstances which may result in assets being impaired and provides criteria for recognition and measurement of asset impairment. Certain operations of NOPSI are potentially affected by this standard, and any resulting write-offs will depend on future operating costs, generating units' efficiency and availability, and the future market for energy over the remaining life of the units. Based on current estimates, NOPSI anticipates that future revenues will fully recover the costs of such operations. Continued Application of SFAS 71 - NOPSI's financial statements currently reflect assets and costs based on current cost-based ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." As discussed above, the electric utility industry is changing and these changes could possibly result in the discontinuance of the application of SFAS 71, which would result in the elimination of regulatory assets and liabilities. See Note 1 for further information. 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 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. Total NOPSI net electric utility plant in service of $205 million as of December 31, 1994 includes $26 million of production plant, $20 million of transmission plant, $141 million of distribution plant, and $18 million of other plant. Total net gas utility plant of $66 million as of December 31, 1994 is primarily comprised of $60 million of distribution plant. 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 1994, 1993, and 1992. 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 10.4%, 11.4%, and 12.1% for 1994, 1993, and 1992, respectively. Income Taxes NOPSI, its parent, and affiliates 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 Entergy Corporation subsidiary 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, in 1993 NOPSI changed its accounting for income taxes to conform with SFAS 109. Other Noncurrent Liabilities NOPSI records provisions for uninsured risks and claims for injuries and damages through charges to operations 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. Continued Application of SFAS 71 As a result of the EPAct and actions of regulatory commissions, the electric utility industry is moving toward a combination of competition and a modified regulatory environment. NOPSI's financial statements currently reflect assets and costs based on current cost- based ratemaking regulations in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Continued applicability of SFAS 71 to NOPSI's financial statements requires that rates set by an independent regulator on a cost of service basis (including a reasonable rate of return on invested capital) can actually be charged to and collected from customers. In the event that either all or a portion of a utility's operations cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation or a change in the competitive environment for the utility's regulated services, the utility should discontinue application of SFAS 71 for the relevant portion. That discontinuation should be reported by elimination from the balance sheet of the effects of any actions of regulators recorded as regulatory assets and liabilities. As of December 31, 1994, and for the foreseeable future, NOPSI's financial statements continue to follow SFAS 71. Fair Value Disclosure The estimated fair value of financial instruments has 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 1994 NOPSI Settlement In a settlement with the Council that was approved on December 29, 1994, NOPSI agreed to reduce electric and gas rates and issue credits and refunds to customers. Effective January 1, 1995, NOPSI implemented a $31.8 million permanent reduction in electric base rates and a $3.1 million permanent reduction in gas base rates. These adjustments resolved issues associated with NOPSI's return on equity exceeding 13.76% for the test year ended September 30, 1994. Under the 1991 NOPSI Settlement, NOPSI is recovering from its retail customers its allocable share of certain costs related to Grand Gulf 1. NOPSI's base rates to recover those costs were derived from estimates of those costs made at that time. Any overrecovery of costs is required to be returned to customers. Grand Gulf 1 has experienced lower operating costs than previously estimated, and NOPSI accordingly is reducing its base rates in two steps to more accurately match the current costs related to Grand Gulf 1. On January 1, 1995, NOPSI implemented a $10 million permanent reduction in base electric rates to reflect the reduced costs related to Grand Gulf 1, to be followed by an additional $4.4 million rate reduction on October 31, 1995. These Grand Gulf rate reductions, which are expected to be largely offset by lower operating costs, may reduce NOPSI's after-tax net income by approximately $1.4 million per year beginning November 1, 1995. The next scheduled Grand Gulf 1 phase-in rate increase in the amount of $4.4 million on October 31, 1995 will not be affected by the 1994 NOPSI Settlement. The 1994 NOPSI Settlement also requires NOPSI to credit its customers $25 million over a 21-month period beginning January 1, 1995, in order to resolve disputes with the Council regarding the interpretation of the 1991 NOPSI Settlement. NOPSI reduced its revenues by $25 million and recorded a $15.4 million net-of-tax reserve associated with the credit in the fourth quarter of 1994. The 1994 NOPSI Settlement further required NOPSI to refund, in December 1994, $13.3 million of credits previously scheduled to be made to customers during the period January 1995 through July 1995. These credits were associated with a July 7, 1994, Council resolution that ordered a $24.95 million rate reduction based on NOPSI's overearnings during the test year ended September 30, 1993. Accordingly, NOPSI recorded an $8 million net-of-tax charge in the fourth quarter of 1994. The 1994 NOPSI Settlement also required NOPSI to refund $9.3 million of overcollections associated with Grand Gulf 1 operating costs, and $10.5 million of refunds associated with the settlement by System Energy of a FERC tax audit. The settlement of the FERC tax audit by System Energy required refunds to be passed on to NOPSI and to other Entergy subsidiaries and then on to customers. These refunds have no effect on current period net income. Merger - Related Rate Agreement In 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 a rate decrease in 1991, followed by a series of rate increases. The last of the rate increases will become effective on October 31, 1995, in the amount of $4.4 million. In connection with the rate changes, 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. NOPSI agreed to a five-year electric base rate freeze extending through October 31, 1996, excluding the annual rate increases provided for 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, 1992 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% (see discussion below). 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; however, this was amended by the 1994 NOPSI Settlement discussed above. 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 the five-year electric base rate freeze discussed above. In addition, the 1994 NOPSI Settlement now requires interest to be included in the "over/under" provision. 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; however, this was amended by the 1994 NOPSI Settlement discussed above. 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 Income tax expense consisted of the following: For the Years Ended December 31, 1994 1993 1992 (In Thousands) Current: Federal $19,557 $23,400 $16,575 State 3,049 4,079 - ------- ------- ------- Total 22,606 27,479 16,575 ------- ------- ------- Deferred - net: Rate deferrals - net (6,325) (7,395) (1,185) Net operating loss carryforward - 42 2,747 utilization Unbilled revenue 2,761 4,621 (2,800) Pension expense 1,308 2,935 (1,044) Liberalized depreciation 841 (19) (286) Deferred fuel or gas costs (2,104) 2,251 1,904 Bond reacquisition 165 1,074 328 Alternative minimum tax 1,116 2,317 (3) Rate refund (9,620) - - Severance accrual (1,518) - - Other (2,298) (623) (1) ------ ------ ------ Total (15,674) 5,203 (340) ------ ------ ------ Investment tax credit adjustments - net (681) (743) (170) Investment tax credit amortization - FERC settlement (1,651) - - ------ ------ ------- Recorded income tax expense $4,600 $31,939 $16,065 ====== ======= ======= Charged to operations $3,602 $24,232 $14,382 Charged to other income 998 1,115 1,683 Charged to cumulative effect - 6,592 - ------ ------- ------- Total income taxes $4,600 $31,939 $16,065 ====== ======= =======
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, 1994 1993 1992 % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income (Dollars in Thousands) Computed at statutory rate $6,234 35.0 $27,877 35.0 $14,446 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 456 2.6 3,411 4.3 1,462 3.5 Depreciation (586) (3.3) (780) (1.0) (731) (1.7) Amortization of investment (681) (3.8) (745) (0.9) (752) (1.8) tax credits Investment tax credit amortization - FERC settlement (1,651) (9.2) Amortization of excess deferred income tax 714 4.0 384 0.5 376 0.9 Adjustment of prior year 0.9 taxes (423) (2.4) 2,413 3.0 391 SFAS 109 adjustment - - (1,170) (1.5) - - Other - net 537 3.0 549 0.7 873 2.0 ------ ---- ------- ---- ------- ---- Total income taxes $4,600 25.9 $31,939 40.1 $16,065 37.8 ====== ==== ======= ==== ======= ====
Significant components of NOPSI's net deferred tax liabilities as of December 31, 1994 and 1993, were: 1994 1993 (In Thousands) Deferred tax liabilities: Net regulatory assets $(12,946) $(13,465) Plant related basis differences (50,624) (49,753) Rate deferrals (74,054) (80,380) Other (3,303) (5,194) --------- --------- Total $(140,927) $(148,792) ========= ========= Deferred tax assets: Unbilled revenues $ 3,051 $ 5,812 Accumulated deferred investment tax credit 4,154 4,460 Pension related items 4,497 5,804 Removal cost 9,146 8,197 Standard coal plant 2,783 2,861 Operating reserves 6,665 6,934 Rate refund 9,620 - Other 6,840 4,660 -------- -------- Total $ 46,756 $ 38,728 ======== ======== Net deferred tax liabilities $(94,171) $(110,064) ======== ========= In accordance with a System Energy FERC settlement, NOPSI wrote off $1.7 million of unamortized deferred investment tax credits in 1994. In 1993, NOPSI adopted SFAS 109. SFAS 109 required 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 required 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. 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. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized NOPSI to effect short-term borrowings of up to $39 million. This authorization is effective through November 30, 1996. 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 borrowings under these arrangements as of December 31, 1994.
NOTE 5. PREFERRED STOCK The number of shares and dollar value of NOPSI's cumulative, $100 par value preferred stock were: As of December 31, Shares Call Price Per Authorized and Total Share as of Outstanding Dollar Value December 31, 1994 1993 1994 1993 1994 (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 34,495 49,495 $3,450 $4,950 $107.72 ======= ======= ======= ======= The fair value of NOPSI's preferred stock with sinking fund was estimated to be approximately $3.6 million and $5.3 million as of December 31, 1994 and 1993, respectively. The fair values were 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 1994 1993 1992 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, 1994, are (in millions) 1995 - $1.5; 1996 - $0.75; 1997 - $0.75 and 1998 - $0.45. 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. NOTE 6. LONG-TERM DEBT NOPSI's long-term debt as of December 31, 1994 and 1993, was: Maturities Interest Rates From To From To 1994 1993 (In Thousands) First Mortgage Bonds 1995 1998 5-5/8% 5-7/8% $35,250 $35,250 G&R Bonds 1995 1998 10.95% 13.9% 54,200 69,200 1999 2023 7.0% 8.0% 100,000 100,000 Unamortized Premium and Discount-Net (1,090) (1,138) -------- -------- Total Long-Term Debt 188,360 203,312 Less Amount Due Within One Year 24,200 15,000 -------- -------- Long-Term Debt Excluding Amount Due Within One Year $164,160 $188,312 ======== ======== The fair value of NOPSI's long-term debt as of December 31, 1994 and 1993 was estimated to be $178.7 million and $211.5 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 1995, 1996, 1997 and 1998, NOPSI has long-term debt maturities of (in millions) $24.2, $38.3, $27 and $0, respectively. In addition, other sinking fund requirements of approximately $0.4 million and $0.1 million for 1995 and 1996, respectively, may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements. 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 bonds based upon property additions 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, 1994, the total amount of Rate Recovery Mortgage Bonds outstanding aggregated $54.2 million, or 26.5% 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, 1994, $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 1995, 1996, and 1997 are estimated to total $28.6 million each year. NOPSI will also require $92.5 million during the period 1995-1997 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, cash on hand, and the issuance of long-term debt. 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 $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. 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. 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, 1994, 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 that state, among other things, that the City has a continuing option to purchase NOPSI's electric and gas utility properties. Sales/Use Tax Issues In September 1994, the Louisiana Supreme Court (Court) issued an opinion (in a case in which none of the System companies was a party) holding, in part, that the Louisiana state legislature's suspension of state sales and use tax exemptions also had the effect of suspending exemptions from local sales and use taxes. On January 27, 1995 the Court, after rehearing, reversed its opinion. Because of the Court's most recent ruling, sales of electricity and gas, fuels and other items used by NOPSI to generate electricity in Louisiana, as well as others exempt from sales and use taxes, continue to be exempt from local sales and use taxes, even though the state exemptions for sales and use tax have been suspended. 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 1994, 1993, and 1992 pension cost, including amounts capitalized, included the following components: For the Years Ended December 31, 1994* 1993* 1992* (In Thousands) Service cost - benefits earned during the period $ 1,502 $1,387 $1,253 Interest cost on projected benefit obligation 2,740 2,422 2,119 Net amortization and deferral (970) (49) 173 ------- ------ ------ Net pension cost $ 3,272 $3,760 $3,545 ======= ====== ====== * 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, 1994 and 1993, was: 1994* 1993* (In Thousands) Actuarial present value of accumulated pension plan benefits: Vested $26,291 $26,173 Nonvested 41 36 ------- ------- Accumulated benefit obligation $26,332 $26,209 ======= ======= Plan assets at fair value $18,180 $7,523 Projected benefit obligation 33,738 36,831 ------- ------- Plan assets less than projected benefit (15,558) (29,308) obligation Unrecognized prior service cost 2,291 2,462 Unrecognized transition asset (1,159) (1,354) Unrecognized net loss 5,779 12,184 ------ ------ (8,647) (16,016) Unfunded portion of NOPSI pension liability 1,584 12,256 ------- ------- Accrued pension liability $(7,063) $(3,760) ======= ======= The significant actuarial assumptions used in computing the information above for 1994, 1993, and 1992 were as follows: weighted average discount rate, 8.5% for 1994, 7.5% for 1993 and 8.25% for 1992; weighted average rate of increase in future compensation levels, 5.1% for 1994 and 5.6% for 1993 and 1992; 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. Effective January 1, 1993, NOPSI adopted SFAS 106. This standard requires a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. 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. Furthermore, due to the Council resolutions, NOPSI has established and commenced funding a Voluntary Employee's Beneficiary Association (VEBA) trust. During 1994, NOPSI funded $6.8 million to the VEBA trust. The trusts assets are invested in a money market fund. NOPSI's 1994 and 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components: 1994 1993 (In Thousands) Service cost - benefits earned during the period $ 813 $ 822 Interest cost on APBO 3,502 4,248 Net deferral and amortization 2,569 2,678 ------ ------ Net periodic postretirement benefit cost $6,884 $7,748 ====== ====== The funded status of NOPSI's postretirement plan as of December 31, 1994 and 1993, was (in thousands): 1994 1993 (In Thousands) Accumulated postretirement benefit obligation: Retirees $38,059 $46,218 Other fully eligible participants 3,351 3,565 Other active participants 3,551 9,152 ------- ------ 44,961 58,935 Plan assets at fair value 6,784 - ------- ------ Plan assets less than APBO (38,177) (58,935) Unrecognized transition obligation 48,217 50,895 Unrecognized net loss (10,057) 4,835 ------- ------ Accrued post retirement benefit liability $ (17) $(3,205) ======= ======= The assumed health care cost trend rate used in measuring the APBO was 9.4% for 1995, gradually decreasing each successive year until it reaches 5.0% in 2011. 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, 1994, by 8.6% and the sum of the service cost and interest cost by approximately 10.0% The assumed discount rate and rate of increase in future compensation used in determining the APBO were 8.5% for 1994 and 7.5% for 1993 and 5.1%, for 1994 and 5.5% for 1993, respectively. NOTE 10. TRANSACTIONS WITH AFFILIATES NOPSI buys electricity from and/or sells electricity to the other System operating companies 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. Operating revenues include revenues from sales to affiliates amounting to $2.1 million in 1994, $2.5 million in 1993, and $3.1 million in 1992. Operating expenses include charges from affiliates for fuel costs, purchased power and related charges, and technical and advisory services totaling $170.1 million in 1994, $176.3 million in 1993, and $183.0 million in 1992.
NOTE 11. BUSINESS SEGMENT INFORMATION NOPSI supplies electric and natural gas services in the City. NOPSI's segment information follows: 1994 1993 1992 Electric Gas Electric Gas Electric Gas (In Thousands) Operating revenues $360,430 $87,357 $423,830 $90,992 $391,936 $72,943 Revenue from sales to unaffiliated customers (1) $358,369 $87,357 $421,343 $90,992 $388,851 $72,943 Operating income (loss) before income taxes $ 23,976 $ 9,387 $ 72,572 $11,412 $ 63,167 $ 1,264 Operating income (loss) $ 22,358 $ 7,403 $ 52,046 $ 7,706 $ 47,194 $ 2,855 Net utility plant $209,901 $67,875 $211,776 $63,803 $206,402 $61,783 Depreciation expense $ 15,743 $ 3,310 $ 14,308 $ 2,976 $ 13,776 $ 2,843 Construction expenditures $ 16,997 $ 5,780 $ 19,774 $ 5,039 $ 15,724 $ 5,319 (1) NOPSI's intersegment transactions are not material (less than 1% of sales to unaffiliated customers). NOTE 12. RESTRUCTURING COSTS During the third quarter of 1994, NOPSI announced a restructuring program related to certain of its operating units. The program is designed to reduce costs, improve operating efficiencies, and increase shareholder value in order to enable NOPSI to become a low-cost producer. The program includes reductions in the number of employees and the consolidation of offices and facilities. In 1994, NOPSI recorded restructuring charges of $3.4 million. These charges primarily include employee severance costs related to the expected termination of approximately 146 employees. As of December 31, 1994, no employees have been terminated and no termination benefits have been paid under this restructuring program. NOTE 13. 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 1994 and 1993 were: Net Operating Operating Income Revenues Income (Loss) (In Thousands) 1994: First Quarter $ 117,088 $ 6,459 $ 1,813 Second Quarter $ 124,402 $ 17,880 $ 13,812 Third Quarter $ 133,574 $ 15,941 $ 11,933 Fourth Quarter $ 72,723 $(10,519) $(14,347) 1993: First Quarter $ 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) See Note 2 for information regarding credits and refunds recorded in 1994 as a result of the 1994 NOPSI Settlement. See Note 1 for information regarding the recording of the cumulative effect of the change in accounting principle for unbilled revenues in January 1993. NEW ORLEANS PUBLIC SERVICE INC. SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1994 1993 1992 1991 1990 (In Thousands) Operating revenues $447,787 $514,822 $464,879 $476,165 $485,246 Income before cumulative effect of a change in accounting principle $ 13,211 $ 36,761 $ 26,424 $ 74,699 $ 27,542 Total assets $592,894 $647,605 $621,691 $685,217 $577,283 Long-term obligations (1) $167,610 $193,262 $165,917 $231,901 $243,239 (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. 1994 1993 1992 1991 1990 (Dollars in Thousands) Electric Operating Revenues: Residential $142,013 $151,423 $137,668 $136,030 $141,900 Commercial 162,410 167,788 160,229 159,118 162,600 Industrial 25,422 26,205 23,860 24,062 27,000 Governmental 58,726 61,548 56,023 55,097 53,500 -------- ------- ------- ------- ------- Total retail 388,571 406,964 377,780 374,307 385,000 Sales for resale 9,573 11,778 10,320 9,805 8,400 Other (37,714) 5,088 3,836 15,102 3,900 -------- ------- ------- ------- ------- Total $360,430 $423,830 $391,936 $399,214 $397,300 ======== ======== ======== ======== ======== Billed Electric Energy Sales (Millions of KWH): Residential 1,896 1,914 1,806 1,844 1,903 Commercial 2,031 1,989 1,977 2,023 2,054 Industrial 518 499 457 487 530 Governmental 951 924 888 887 846 ----- ----- ----- ----- ----- Total retail 5,396 5,326 5,128 5,241 5,333 Sales for resale 294 351 405 418 294 ----- ----- ----- ----- ----- Total 5,690 5,677 5,533 5,659 5,627 ===== ===== ===== ===== ===== System Energy Resources, Inc. 1994 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 New Orleans, Louisiana or City 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 Entergy Services Entergy Services, Inc. EPAct The Energy Policy Act of 1992 FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission FERC Complaint Case Settlement, effective May 21, 1991, whereby Settlement 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 Settlement, effective October 25, 1993, case 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 (nuclear) Grand Gulf 1 Unit No. 1 of the Grand Gulf Station (nuclear) Grand Gulf 2 Unit No. 2 of the Grand Gulf Station (nuclear) 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 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 Corporation Board of Directors' Audit Committee functions as the Audit Committee for System Energy. The Audit Committee is comprised of four directors, who are not officers of System Energy: H. Duke Shackelford (Chairman), Lucie J. Fjeldstad, Dr. Norman C. Francis, and James R. Nichols. The committee held four meetings during 1994. 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 (Coopers & Lybrand L.L.P.) 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/ H. Duke Shackelford H. DUKE SHACKELFORD Chairman, Audit Committee REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholder of System Energy Resources, Inc. We have audited the accompanying balance sheet of System Energy Resources, Inc. as of December 31, 1994, and the related statements of income, retained earnings and cash flows for the year then ended. 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 audit. The financial statements of the Company as of December 31, 1993 and for the years ended December 31, 1993 and 1992, were audited by other auditors, whose report, dated February 11, 1994, included explanatory paragraphs that described a change in a method of accounting for income taxes discussed in Note 3 to these financial statements and an uncertainty relating to a regulatory proceeding which is discussed in Note 2 to these financial statements. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1994, and the result of its operations and its cash flows for the year then ended in conformity with generally accepted accounting principles. /s/ Coopers & Lybrand L.L.P. COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 21, 1995 INDEPENDENT AUDITORS' REPORT To the Shareholder and Board of Directors of System Energy Resources, Inc. We have audited the accompanying balance sheet of System Energy Resources, Inc. (System Energy) as of December 31, 1993, and the related statements of income, retained earnings, and cash flows for each of the two 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 the results of its operations and its cash flows for each of the two years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. As discussed in Notes 3 to the financial statements, in 1993 System Energy changed its methods of accounting for income taxes. /s/ Deloitte & Touche LLP DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994 (November 30, 1994 as to Note 2, "Rate and Regulatory Matters - FERC Settlement")
SYSTEM ENERGY RESOURCES, INC. BALANCE SHEETS ASSETS December 31, 1994 1993 (In Thousands) Utility Plant: Electric $2,939,384 $3,027,537 Electric plant under lease 439,378 437,941 Construction work in progress 46,547 41,442 Nuclear fuel under capital lease 46,688 79,625 Nuclear fuel 26,360 - ---------- ---------- Total 3,498,357 3,586,545 Less - accumulated depreciation 751,717 669,666 ---------- ---------- Utility plant - net 2,746,640 2,916,879 ---------- ---------- Other Investments: Decommissioning trust fund 30,359 24,787 ---------- ---------- Current Assets: Cash and cash equivalents: Cash - 2,424 Temporary cash investments - at cost, which approximates market: Associated companies 5,489 46,601 Other 84,214 147,107 ---------- ---------- Total cash and cash equivalents 89,703 196,132 Accounts receivable: Associated companies 7,450 57,216 Other 3,412 2,057 Materials and supplies - at average cost 71,991 69,765 Recoverable income taxes - 63,400 Prepayments and other 5,429 4,835 ---------- ---------- Total 177,985 393,405 ---------- ---------- Deferred Debits and Other Assets: Regulatory Assets: SFAS 109 regulatory asset - net 389,264 384,317 Unamortized loss on reacquired debt 54,577 17,258 Other regulatory assets 199,080 108,518 Recoverable income taxes - 29,289 Other 15,454 16,613 ---------- ---------- Total 658,375 555,995 ---------- ---------- TOTAL $3,613,359 $3,891,066 ========== ========== See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC. BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 1994 1993 (In Thousands) Capitalization: Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 1994 and 1993 $789,350 $789,350 Paid-in capital 7 7 Retained earnings 85,681 228,574 ---------- ---------- Total common shareholder's equity 875,038 1,017,931 Long-term debt 1,438,305 1,511,914 ---------- ---------- Total 2,313,343 2,529,845 ---------- ---------- Other Noncurrent Liabilities: Obligations under capital leases 18,688 24,679 Other 14,342 18,229 ---------- ---------- Total 33,030 42,908 ---------- ---------- Current Liabilities: Currently maturing long-term debt 105,000 230,000 Accounts payable: Associated companies 32,272 1,928 Other 23,204 18,223 Taxes accrued 35,382 20,952 Interest accrued 40,796 48,929 Obligations under capital leases 28,000 55,000 Other 19,794 2,805 ---------- ---------- Total 284,448 377,837 ---------- ---------- Deferred Credits: Accumulated deferred income taxes 746,502 775,630 Accumulated deferred investment tax credits 110,584 113,849 FERC Settlement - refund obligation 60,388 - Other 65,064 50,997 ---------- ---------- Total 982,538 940,476 ---------- ---------- Commitments and Contingencies (Notes 2, 7, and 8) TOTAL $3,613,359 $3,891,066 ========== ========== See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1994 1993 1992 (In Thousands) Operating Activities: Net income $5,407 $93,927 $130,141 Noncash items included in net income: Depreciation and decommissioning 93,861 90,920 85,932 Deferred income taxes and investment tax credits (30,640) 15,832 70,356 Allowance for equity funds used during construction (1,090) (772) (681) Amortization of debt discount 4,388 4,520 6,417 Amortization of loss on reacquired debt 2,343 - - Changes in working capital: Receivables 48,411 6,199 225 Accounts payable 35,469 (15,123) (30,517) Taxes accrued 14,430 (2,272) 2,672 Interest accrued (8,133) (1,631) 1,252 Other working capital accounts 14,024 2,832 (4,412) Recoverable income taxes 92,689 130,152 (3,475) Decommissioning trust contributions (5,157) (4,911) (5,641) FERC Settlement - refund obligation 60,388 - - Other 10,597 (1,617) 86 -------- -------- -------- Net cash flow provided by operating activities 336,987 318,056 252,355 -------- -------- -------- Investing Activities: Construction expenditures (20,766) (23,083) (21,671) Allowance for equity funds used during construction 1,090 772 681 Nuclear fuel purchases (26,414) (32,822) (13,724) Proceeds from sale/leaseback of nuclear fuel - 32,822 28,094 -------- -------- -------- Net cash flow used in investing activities (46,090) (22,311) (6,620) -------- -------- -------- Financing Activities: Proceeds from the issuance of first mortgage bonds 59,410 60,000 220,000 Retirement of first mortgage bonds (260,000) (108,308) (240,750) Premium and expenses paid on refinancing sale/leaseback bonds (48,436) - - Common stock dividends paid (148,300) (233,100) (137,700) -------- -------- -------- Net cash flow used in financing activities (397,326) (281,408) (158,450) -------- -------- -------- Net increase (decrease) in cash and cash equivalents (106,429) 14,337 87,285 Cash and cash equivalents at beginning of period 196,132 181,795 94,510 -------- -------- -------- Cash and cash equivalents at end of period $89,703 $196,132 $181,795 ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid (received) during the period for: Interest - net of amount capitalized $176,503 $186,786 $201,287 Income taxes (refund) ($39,586) ($65,992) $21,431 Noncash investing and financing activities: Capital lease obligations incurred - $45,089 $28,094 Deficiency of fair value of decommissioning trust assets under amount invested ($1,515) - - 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 $337 million, $318 million, and $252 million in 1994, 1993, and 1992, 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 for information on System Energy's capital and refinancing requirements in 1995 - 1997. Also, to the extent current market interest and dividend rates allow, System Energy may continue to refinance high-cost debt prior to maturity. As discussed in Note 2, in November 1994, FERC approved an agreement settling a long-standing dispute involving income tax allocation procedures of System Energy. In connection with this settlement, System Energy refunded approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI, which in turn have made or will make refunds or credits to their customers (except for those portions attributable to AP&L's and LP&L's retained share of Grand Gulf 1 costs). Additionally, System Energy will refund a total of approximately $62 million, plus interest, to AP&L, LP&L, MP&L, and NOPSI over the period through June 2004. AP&L, LP&L, MP&L, and NOPSI also wrote-off certain related unamortized balances of deferred investment tax credits. See Note 2 for further information on the FERC Settlement. As a result of the charges associated with the FERC Settlement, System Energy obtained the consent of certain banks (parties to the Reimbursement Agreement) to waive temporarily the fixed charge coverage covenant in the letters of credit and Reimbursement Agreement related to the Grand Gulf 1 sale and leaseback transaction, until November 30, 1995. System Energy expects that upon expiration of the waiver period, it will be in compliance with the fixed charge coverage covenant. Absent a waiver, System Energy's failure to perform this covenant 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. 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 the Grand Gulf 1 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, 1994, and assuming an annual interest rate of 9.25%, System Energy could have issued $241 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 for information regarding System Energy's short-term borrowings. SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF INCOME For the Years Ended December 31, 1994 1993 1992 (In Thousands) Operating Revenues $474,963 $650,768 $723,410 ---------- ---------- ---------- Operating Expenses: Operation and maintenance: Fuel and fuel-related expenses 48,107 42,296 55,110 Other operation and maintenance 96,504 135,349 132,341 Depreciation and decommissioning 93,861 90,920 90,628 Taxes other than income taxes 26,637 26,589 28,717 Income taxes 38,087 83,412 93,438 ---------- ---------- ---------- Total 303,196 378,566 400,234 ---------- ---------- ---------- Operating Income 171,767 272,202 323,176 ---------- ---------- ---------- Other Income (Deductions): Allowance for equity funds used during construction 1,090 772 681 Miscellaneous - net 6,402 6,518 5,816 Income taxes 1,250 4,859 4,584 ---------- ---------- ---------- Total 8,742 12,149 11,081 ---------- ---------- ---------- Interest Charges: Interest on long-term debt 169,248 189,338 203,035 Other interest - net 7,257 1,600 1,506 Allowance for borrowed funds used during construction (1,403) (514) (425) ---------- ---------- ---------- Total 175,102 190,424 204,116 ---------- ---------- ---------- Net Income $5,407 $93,927 $130,141 ========== ========== ========== See Notes to Financial Statements. SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1994 1993 1992 (In Thousands) Retained Earnings, January 1 $228,574 $367,747 $375,306 Add: Net income 5,407 93,927 130,141 -------- -------- -------- Total 233,981 461,674 505,447 -------- -------- -------- Deduct: Dividends declared 148,300 233,100 137,700 -------- -------- -------- Retained Earnings, December 31 (Note 6) $ 85,681 $228,574 $367,747 ======== ======== ======== See Notes to Financial Statements. SYSTEM ENERGY RESOURCES, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income decreased in 1994 primarily due to the effect of the FERC Settlement which reduced income by $80.2 million (see Note 2) and a lower rate of return on System Energy's decreasing investment in Grand Gulf 1, partially offset by a decrease in interest expense. 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, as discussed in Note 2. This decrease in revenue was partially offset by a reduction in interest expense due to the retirement of high-cost debt. Significant factors affecting the results of operations and causing variances between the years 1994 and 1993, and 1993 and 1992 are discussed under "Revenues" and "Expenses" below. Revenues 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 for further information on the FERC Return on Equity Case) on System Energy's common equity funds allocable to its net investment in Grand Gulf 1 plus System Energy's effective interest cost for its debt allocable to its investment in Grand Gulf 1. Operating revenues decreased in 1994 due primarily to the effect of the FERC Settlement as discussed in "Net Income" above, a lower return on System Energy's decreasing investment in Grand Gulf 1 (caused by depreciation of the unit) and decreased operation and maintenance expenses. 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 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. Expenses Operating expenses decreased in 1994 due primarily to lower other operation and maintenance expense and lower income tax expense. Operating expenses decreased in 1993 due primarily to lower fuel and lower income tax expense. Grand Gulf 1 was on-line for 345 of 365 days in 1994 as compared with 284 of 365 days in 1993. 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 92.26% for 1994 as compared with 76.1% for 1993. These variances are primarily due to the unit's sixth refueling outage that lasted from September 28, 1993 to December 3, 1993, (67 days) and to a lesser extent, the unplanned outages in 1994 totaling 20 days, compared to 1993 of 14 days. The lower level of outages for 1994 increased fuel for electric generation, partially offset by less expensive nuclear fuel and increased operating efficiency. Nonfuel operation and maintenance expense decreased significantly in 1994 also due to the lower level of outages. The 1993 decrease in fuel for electric generation and fuel related expenses is primarily due to the sixth refueling outage and to refueling with less expensive nuclear fuel. Increased operating efficiency was another contributor to the 1993 decrease. Nonfuel operation and maintenance expense increased in 1993 due primarily to the sixth refueling outage as discussed above. Total income taxes decreased in 1994 due primarily to lower pretax book income. 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. Interest expense decreased in 1994 due primarily to the refinancing and maturity of high-cost long-term debt partially offset by interest associated with the FERC Settlement refunds (see Note 2). SYSTEM ENERGY RESOURCES, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS FERC Settlement See Note 2 for information with respect to a settlement between System Energy and FERC in which System Energy refunded approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI, which in turn have made or will make refunds or credits to their customers (except for those portions attributable to AP&L's and LP&L's retained share of Grand Gulf costs). Additionally, System Energy will refund a total of approximately $62 million, plus interest, to AP&L, LP&L, MP&L, and NOPSI over the period through June 2004. AP&L, LP&L, MP&L, and NOPSI also wrote-off certain related unamortized balances of deferred investment tax credits. Accounting Issues Proposed Accounting Standard - The FASB has proposed a SFAS on "Accounting for the Impairment of Long-Lived Assets," effective January 1, 1996. The proposed standard describes circumstances which may result in assets being impaired and provides criteria for recognition and measurement of asset impairment. Certain operations of System Energy are potentially affected by this standard, and any resulting write-offs will depend on future operating costs, efficiency and availability of Grand Gulf 1, and the future market for energy over the remaining life of the unit. Based on current estimates, System Energy anticipates that future revenues will fully recover the costs of such operations. Continued Application of SFAS 71 - System Energy's financial statements currently reflect assets and costs based on current cost- based ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." The electric utility industry is changing and these changes could possibly result in the discontinuance of the application of SFAS 71 which would result in the elimination of regulatory assets and liabilities. See Note 1 for further information. Accounting for Decommissioning Costs - The FASB is currently reviewing the accounting for decommissioning of nuclear plants. This project could possibly change System Energy's, as well as the entire utility industry's, accounting for such costs. For further information, see Note 7. 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 with a total capability of 1,143 MW that began 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. 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 as a regulatory asset 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 3.0% in 1994 and 2.9% in 1993 and 1992. 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. System Energy's effective composite rates for AFUDC were 10.7%, 11.6%, and 12.3% for 1994, 1993, and 1992, respectively. Income Taxes System Energy, its parent, and affiliates 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 Entergy Corporation subsidiary 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, in 1993 System Energy changed its accounting for income taxes to conform with SFAS 109. In addition, System Energy files a consolidated Mississippi state income tax return with certain other System companies. 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 System Energy considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Continued Application of SFAS 71 As a result of the EPAct and actions of regulatory commissions, the electric utility industry is moving toward a combination of competition and a modified regulatory environment. System Energy's financial statements currently reflect assets and costs based on current cost-based ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation". Continued applicability of SFAS 71 to System Energy's financial statements requires that rates set by an independent regulator on a cost of service basis (including a reasonable rate of return on invested capital) can actually be charged to and collected from customers. In the event that either all or a portion of a utility's operations cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation, or a change in the competitive environment for the utility's regulated services, the utility should discontinue application of SFAS 71 for the relevant portion. That discontinuation should be reported by elimination from the balance sheet of the effects of any actions of regulators recorded as regulatory assets and liabilities. As of December 31, 1994, and for the foreseeable future, System Energy's financial statements continue to follow SFAS 71. Fair Value Disclosure The estimated fair value of financial instruments has 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. System Energy adopted the provisions of SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," effective January 1, 1994. As a result, at December 31, 1994, System Energy has recorded on the balance sheet a reduction of $1.5 million in decommissioning trust funds, representing the amount by which the fair value of the securities held in such funds is less than amounts recovered in rates for decommissioning and deposited in the funds and the related earnings on the amounts deposited. Due to the regulatory treatment for decommissioning trust funds, System Energy recorded an offsetting amount in unrealized losses on investment securities as a regulatory asset. NOTE 2. RATE AND REGULATORY MATTERS FERC Settlement In November 1994, FERC approved an agreement settling a long- standing dispute involving income tax allocation procedures of System Energy. In accordance with the agreement, System Energy refunded approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI, which in turn have made or will make refunds or credits to their customers (except for those portions attributable to AP&L's and LP&L's retained share of Grand Gulf 1 costs). Additionally, System Energy will refund a total of approximately $62 million, plus interest, to AP&L, LP&L, MP&L, and NOPSI over the period through June 2004. The settlement also required the write-off of certain related unamortized balances of deferred investment tax credits by AP&L, LP&L, MP&L, and NOPSI. The settlement reduced Entergy Corporation's consolidated net income for the year ended December 31, 1994, by approximately $68.2 million, offset by the write-off of the unamortized balances of related deferred investment tax credits of approximately $69.4 million ($2.9 million for Entergy Corporation; $27.3 million for AP&L; $31.5 million for LP&L; $6 million for MP&L; and $1.7 million for NOPSI). System Energy also reclassified from utility plant to other deferred debits approximately $81 million of other Grand Gulf 1 costs. Although excluded from rate base, System Energy will be permitted to recover such costs over a 10-year period. Interest on the $62 million refund and the loss of the return on the $81 million of other Grand Gulf 1 costs will reduce Entergy's and System Energy's net income by approximately $10 million annually over the next 10 years. As a result of the charges associated with the settlement, System Energy obtained the consent of certain banks (parties to the Reimbursement Agreement) to waive temporarily the fixed charge coverage covenant in the letters of credit and Reimbursement Agreement related to the Grand Gulf 1 sale and leaseback transaction until November 30, 1995. System Energy expects that upon expiration of the waiver period, it will be in compliance with the fixed charge coverage covenant. Absent a waiver, System Energy's failure to perform this covenant 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. 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. NOTE 3. INCOME TAXES Income tax expense consisted of the following:
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Current: Federal $54,295 $59,050 $13,890 State 13,182 3,671 6,786 ------- ------- ------- Total 67,477 62,721 20,676 ------- ------- ------- Deferred - net: Liberalized depreciation 24,910 46,600 43,873 Nuclear fuel 790 2,706 (3,299) Capitalized interest (1,024) (456) (1,402) Taxes capitalized (929) (929) (935) Decontamination and decommissioning fund 1,117 5,601 - Bond reacquisition 626 (787) 852 Accrued FERC Settlement (23,098) - - Alternative minimum tax (17,727) (1,579) - Adjustment to GG2 tax basis (14,037) - - Adjustment of prior year taxes 2,747 (3,249) 1,157 Other (750) (1,623) (2,191) ------- ------- ------- Total (27,375) 46,284 38,055 ------- ------- ------- Investment tax credit adjustments - net (3,265) (30,452) 30,123 ------- ------- ------- Recorded income tax expense $36,837 $78,553 $88,854 ======= ======= ======= Charged to operations $38,087 $83,412 $93,438 Credited to other income (1,250) (4,859) (4,584) ------- ------- ------- Recorded income tax expense 36,837 78,553 88,854 Income taxes applied against the debt - - 253 component of AFUDC ------- ------- ------- Total income taxes $36,837 $78,553 $89,107 ======= ======= =======
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, 1994 1993 1992 % of % of % of Pretax Pretax Pretax Amount Income Amount Income Amount Income (Dollars in Thousands) Computed at statutory rate $14,785 35.0 $60,368 35.0 $74,458 34.0 Increases (reductions) in tax resulting from: Depreciation 14,541 34.4 12,839 7.4 11,520 5.3 State income taxes net of federal income tax effect 7,565 17.9 6,778 3.9 8,380 3.8 Amortization of investment tax credits (3,476) (8.2) (3,759) (2.2) (3,865) (1.8) Adjustment of Prior Year Taxes 2,947 7.0 5,292 3.0 - - Other - (net) 475 1.1 (2,965) (1.6) (1,639) (0.7) ------- ---- ------- ---- ------- ---- Recorded income tax expense 36,837 87.2 78,553 45.5 88,854 40.6 Income taxes applied against the debt component of AFUDC - - - - 253 0.1 ------- ---- ------- ---- ------- ---- Total income taxes $36,837 87.2 $78,553 45.5 $89,107 40.7 ======= ==== ======= ==== ======= ====
Significant components of System Energy's net deferred tax liabilities, as of December 31, 1994 and 1993, were: 1994 1993 (In Thousands) Deferred tax liabilities: Net regulatory assets $ (428,492) $(425,318) Plant related basis differences (577,286) (552,782) Other (14,350) (16,343) ----------- --------- Total $(1,020,128) $(994,443) =========== ========= Deferred tax assets: Sale and leaseback $ 145,731 $ 142,850 FERC Settlement 23,098 - Accumulated deferred investment tax credit 42,298 43,547 Alternative minimum tax credit 38,179 20,452 Recoverable income tax - 92,689 Adjustment to GG2 tax basis 14,037 - Other 10,283 11,964 ----------- --------- Total $ 273,626 $ 311,502 =========== ========= Net deferred tax liabilities $ (746,502) $(682,941) =========== ========= The alternative minimum tax (AMT) credit at December 31, 1994 was $38.2 million This AMT credit can be carried forward indefinitely and will reduce System Energy's federal income tax liability in the future. In 1993, System Energy adopted SFAS 109. SFAS 109 required 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. As a result of the adoption of SFAS 109, 1993 net income was reduced by $0.4 million, assets were increased by $327.9 million, and liabilities were increased by $327.5 million. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. In connection with an Internal Revenue Service (IRS) audit of Entergy's 1988, 1989, and 1990 consolidated federal income tax returns, the IRS proposed that adjustments be made to the Grand Gulf 2 abandonment loss deduction claimed on Entergy's 1989 consolidated federal income tax return. The final agreement with the IRS required Entergy Corporation to pay $4.3 million in connection with the abandonment loss issue. In August 1994, Entergy received an IRS report covering the federal income tax audit of Entergy Corporation and subsidiaries for the years 1988 - 1990. The report asserts an $80 million tax deficiency for the 1990 consolidated federal income tax returns related primarily to the application of accelerated investment tax credits associated with Waterford 3 and Grand Gulf nuclear plants. Entergy believes there is no material tax deficiency and is vigorously contesting the proposed assessment. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized System Energy to effect short-term borrowings up to $125 million, which may be increased to as much as $195 million after further SEC approval. This authorization is effective through November 30, 1996. 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 outstanding borrowings under the Money Pool arrangement or under bank lines of credit as of December 31, 1994. NOTE 5. LONG-TERM DEBT The long-term debt of System Energy as of December 31, 1994 and 1993, was as follows: Maturities Interest Rates From To From To 1994 1993 (In Thousands) First Mortgage Bonds 1995 1999 6.0% 10-1/2% $475,000 $615,000 2002 8-1/4% 70,000 130,000 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 (8,614) (10,005) ---------- ---------- Total Long-Term Debt 1,543,305 1,741,914 Less Amount Due Within One Year 105,000 230,000 ---------- ---------- Long-Term Debt Excluding Amount Due $1,438,305 $1,511,914 Within One Year ========== ========== * 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, 1994 and 1993, was estimated to be $1,091 million and $1,397.8 million, respectively. Fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. For the years 1995, 1996, 1997, 1998, and 1999 System Energy has long-term debt maturities and sinking fund requirements (in millions) of $105, $250, $10, $70, and $70, respectively. 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, 1994, $41.7 million of System Energy's retained earnings were restricted against the payment of cash dividends or other distributions on common stock. NOTE 7. COMMITMENTS AND CONTINGENCIES Capital Requirements and Financing Construction expenditures (excluding nuclear fuel) for the years 1995, 1996, and 1997 are estimated to total $22 million, $21.6 million, and $19.1 million, respectively. System Energy will also require $365 million during the period 1995-1997 to meet long-term debt maturities. 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 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. 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, most likely upon 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 $49 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 as defined, including an amount sufficient to amortize Grand Gulf 2 over 27 years. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Since commercial operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments have ever been required. 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, 1994, System Energy's equity approximated 34.25% of its adjusted capitalization, and its fixed charge coverage ratio was 1.23. As a result of the charges associated with an agreement with FERC settling a long-standing dispute involving income tax allocation procedures, System Energy has obtained the consent of certain banks (parties to the Reimbursement Agreement) to waive temporarily the fixed charge coverage covenant in the letters of credit and Reimbursement Agreement, until November 30, 1995. (See Note 2 for information on the FERC Settlement.) System Energy expects that upon expiration of the waiver period, it will be in compliance with the fixed charge coverage covenant. Absent a waiver, System Energy's failure to perform this covenant 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. 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 the drawing. Nuclear Insurance The Price-Anderson Act limits public liability for a single nuclear incident to approximately $8.92 billion as of December 31, 1994. 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 $79.3 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 $3.2 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, 1994, System Energy was insured against such losses up to $2.75 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, 1994, the maximum amount of such possible assessments to System Energy was $29.7 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'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 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. 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. Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. In a statement released February 17, 1993, the DOE asserted that it does not have a legal obligation to accept spent nuclear fuel without an operational repository for which it has not yet arranged. Currently the DOE projects it will begin to accept spent fuel no earlier than 2010. In the meantime, System Energy is responsible for spent fuel storage. Current on-site spent fuel pool storage capacity at Grand Gulf 1 is estimated to be sufficient until 2004. Thereafter, System Energy will provide additional storage capacity at an 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 the DOE's repository begins accepting Grand Gulf 1's spent fuel. Entergy Operations and System Fuels joined in lawsuits against the DOE, seeking clarification of the DOE's responsibility to receive spent nuclear fuel beginning in 1998. The original suits, filed June 20, 1994, asked for a ruling stating that the Nuclear Waste Policy Act require the DOE to begin taking title to the spent fuel and to start removing it from nuclear power plants in 1998, a mandate for the DOE's nuclear waste management program to begin accepting fuel in 1998 and court monitoring of the program, and the potential for escrow of payments to the Nuclear Waste Fund instead of directly to the DOE. Decommissioning costs were estimated to approximate $248.7 million in 1989 dollars for System Energy's 90% interest in Grand Gulf 1, 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). System Energy completed an updated cost study in 1994 which reflected a decommissioning cost of $365.9 million (in 1993 dollars) for System Energy's 90% interest. A filing with FERC to request the updated decommissioning costs in rates is under consideration by System Energy. The amounts recovered in rates are deposited in external trust funds and reported at market value. The accumulated decommissioning liability of $31.9 million as of December 31, 1994, has been recorded in other deferred credits. Decommissioning expense in the amount of $5.2 million was recorded in 1994. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. Management believes that actual decommissioning costs are likely to be higher than the amounts presented above. The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry, regarding the recognition, measurement, and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. In response to these questions, the FASB is currently reviewing the accounting for decommissioning. If current electric utility industry accounting practices for such decommissioning are changed, annual provisions for decommissioning could increase, the estimated cost for decommissioning could be recorded as a liability rather than as accumulated depreciation, and trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense. The EPAct 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 $1.4 million (in 1995 dollars) for approximately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortized. The cumulative liability of $15.8 million as of December 31, 1994, 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. 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 1998 and the notes have varying remaining maturities of up to 3 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 $37.8 million, $36.2 million, and $48.4 million (including interest of $6.8 million, $5.1 million, and $8.5 million) was charged to operations in 1994, 1993, and 1992, 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 transactions. On January 18, 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 for information on letters of credit maintained by System Energy for the benefit of the equity investors in the transactions. In accordance with SFAS 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 $78.5 million and $71.2 million as of December 31, 1994 and 1993, respectively. See Note 1 for further information regarding the accounting for the sale and leaseback transactions. As of December 31, 1994, System Energy had future minimum lease payments (reflecting an implicit rate of 7.02% after the above refinancing) as follows (in thousands): 1995 $ 42,464 1996 42,753 1997 42,753 1998 42,753 1999 42,753 Years thereafter 802,820 ---------- Total $1,016,296 ========== 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 1994, 1993, and 1992 pension cost, including amounts capitalized, included the following components:
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Service cost - benefits earned during the period $2,619 $2,045 $1,737 Interest cost on projected benefit obligation 2,148 1,709 1,439 Actual return on plan assets 498 (3,828) (2,070) Net amortization and deferral (3,535) 972 (587) ------ ------ ------ Net pension cost $1,730 $ 898 $ 519 ====== ====== ======
The funded status of System Energy's pension plan as of December 31, 1994 and 1993, was:
1994 1993 (In Thousands) Actuarial present value of accumulated pension plan benefits: Vested $13,305 $16,728 Nonvested 986 615 ------- ------- Accumulated benefit obligation $14,291 $17,343 ======= ======= Plan assets at fair value $33,285 $33,914 Projected benefit obligation 27,239 28,933 ------- ------- Plan assets in excess of projected benefit obligation 6,046 4,981 Unrecognized prior service cost 1,242 879 Unrecognized transition asset (6,484) (7,080) Unrecognized net loss (gain) (1,952) 1,802 ------- ------- Accrued pension asset $(1,148) $ 582 ======= =======
The significant actuarial assumptions used in computing the information above for 1994, 1993, and 1992, were as follows: weighted average discount rate, 8.5% for 1994, 7.5% for 1993 and 8.25% for 1992; weighted average rate of increase in future compensation levels, 5.1% for 1994 and 5.6% for 1993 and 1992; 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. Charges from MP&L and Entergy Services for technical, advisory and miscellaneous services amounted to approximately $10.5 million in 1994, $12.3 million in 1993, and $13.8 million in 1992. System Energy pays directly or reimburses Entergy Operations for the costs associated with operating Grand Gulf 1 (excluding nuclear fuel) which were approximately $179.6 million in 1994, $151.3 million in 1993, and $179 million in 1992. 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 $27.8 million in 1994, $32.8 million in 1993, and $13.7 million in 1992. NOTE 11. QUARTERLY FINANCIAL DATA (UNAUDITED) Operating results for the four quarters of 1994 and 1993 were: Operating Operating Net Revenue Income (Loss) Income (Loss) (In Thousands) 1994: First Quarter $147,847 $ 64,342 $ 21,549 Second Quarter $151,219 $ 65,779 $ 25,212 Third Quarter $150,949 $ 65,869 $ 24,934 Fourth Quarter $ 24,948 $(24,223) $(66,288) 1993: First Quarter $164,630 $ 76,331 $ 31,782 Second Quarter $153,527 $ 65,539 $ 21,268 Third Quarter $155,071 $ 63,992 $ 23,040 Fourth Quarter $177,540 $ 66,340 $ 17,837 See Note 2 for information regarding the recording of refunds in connection with the FERC Settlement in November 1994. See Note 2 for information regarding the recording of refunds as a result of the FERC Return on Equity Case settlement in the third quarter of 1993.
SYSTEM ENERGY RESOURCES, INC. SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1994 1993 1992 1991 1990 (Dollars in Thousands) Operating revenues $ 474,963 $ 650,768 $ 723,410 $ 686,664 $ 801,618 Net income $ 5,407 $ 93,927 $ 130,141 $ 104,622 $ 168,677 Total assets $3,613,359 $3,891,066 $3,672,441 $3,642,203 $3,883,241 Long-term obligations (1) $1,456,993 $1,536,593 $1,768,299 $1,707,470 $1,849,000 Electric energy sales (Millions of KWH) 8,653 7,113 7,354 8,220 6,666 (1) Includes long-term debt (excluding current maturities) and noncurrent capital lease obligations. See Note 2 for information with respect to refunds and charges resulting from the FERC Settlement in 1994 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 26, 1995, and is incorporated herein by reference.
Name Age Position Period Officers Edwin Lupberger(a) 58 Chairman of the Board and Chief 1985-Present Executive Officer of Entergy Corporation Chairman of the Board and Chief 1993-Present Executive Officer of AP&L, LP&L, MP&L, and NOPSI Chairman of the Board and Chief 1994-Present Executive Officer of GSU Chairman of the Board of System Energy 1986-Present and Entergy Enterprises Chairman of the Board of Entergy 1990-Present Operations Chairman of the Board of Entergy 1985-Present Services Chief Executive Officer of Entergy 1991-Present Services President of Entergy Services and 1994-Present Entergy Enterprises Director of AP&L, LP&L, MP&L, NOPSI, 1986-Present and System Energy Director of Entergy Operations and 1994-Present Entergy Services Director of Entergy Enterprises 1984-Present Chief Executive Officer of Entergy 1993-Present Power, Entergy Power Development Corporation, and Entergy-Richmond Power Corporation Chief Executive Officer of Entergy 1994-Present Pakistan, Ltd. and Entergy Power Asia, Ltd. President of Entergy Corporation 1985-1991 Chairman of the Board of Entergy Power 1990-1993 Chief Executive Officer of Entergy 1991-1994 Enterprises President of Entergy Services and 1990-1991 Entergy Enterprises Chairman of the Board of System Fuels 1986-1990 Director of System Fuels 1986-1992 Jerry L. Maulden 58 President and Chief Operating Officer 1993-Present of Entergy Corporation Vice Chairman and Chief Operating 1993-Present Officer of AP&L, GSU, LP&L, MP&L, and NOPSI 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 Director of Entergy Services 1979-Present Chairman of the Board of AP&L 1989-1993 Chief Executive Officer of AP&L 1979-1993 Chairman of the Board and Chief 1991-1993 Executive Officer of LP&L and NOPSI Chairman of the Board and Chief 1989-1993 Executive Officer of MP&L Group President, System Executive - 1991-1993 Transmission, Distribution, and Customer Service of Entergy Corporation Senior Vice President, System 1988-1991 Executive - Arkansas/Mississippi/Missouri Division of Entergy Corporation Director of System Fuels 1979-1992 Group President, System Executive - 1991-1992 Transmission, Distribution, and Customer Service of Entergy Services Director of Entergy Enterprises 1984-1991 Jerry D. Jackson 50 Executive Vice President - Marketing 1994-Present and External Affairs of Entergy Corporation Executive Vice President - Marketing 1995-Present and External Affairs of AP&L, GSU, LP&L, MP&L, and NOPSI Executive Vice President - Marketing 1994-Present and External Affairs of Entergy Services Secretary of GSU 1994-1995 Director of AP&L,LP&L, MP&L, and NOPSI 1992-Present Director of GSU 1994-Present Director of System Energy 1993-Present Director of Entergy Services 1990-Present Executive Vice President - Finance and 1990-1994 External Affairs of Entergy Corporation Executive Vice President - Finance and 1992-1994 External Affairs and Secretary of AP&L, LP&L, MP&L, and NOPSI Executive Vice President - Finance and 1993-1994 External Affairs of GSU Executive Vice President - Finance and 1990-1992 External Affairs of Entergy Services President and Chief Administrative 1992-1994 Officer of Entergy Services Secretary of Entergy Corporation 1991-1994 President of Entergy Enterprises 1991-1992 Director of Entergy Power and Entergy 1990-1992 Enterprises Senior Vice President, System 1987-1990 Executive - Legal and External Affairs of Entergy Corporation and Entergy Services Donald C. Hintz 52 Executive Vice President and Chief 1994-Present Nuclear Officer of Entergy Corporation Executive Vice President - Nuclear of 1994-Present AP&L, GSU, and LP&L Director of AP&L, LP&L, MP&L, System 1992-Present Energy, System Fuels, and Entergy Services Director of GSU 1993-Present Chief Executive Officer and President 1992-Present of System Energy and Entergy Operations Director of Entergy Operations 1990-Present Director of GSG&T, Prudential Oil & 1994-Present Gas, Southern Gulf Railway, and Varibus Corporation Senior Vice President and Chief 1993-1994 Nuclear Officer of Entergy Corporation Senior Vice President - Nuclear of 1990-1994 AP&L Senior Vice President - Nuclear of GSU 1993-1994 Senior Vice President - Nuclear of 1992-1994 LP&L Director of NOPSI 1992-1994 President of Entergy Operations 1992-1992 Chief Operating Officer and Executive 1990-1992 Vice President of Entergy Operations Group Vice President - Nuclear of LP&L 1990-1992 Chief Operating Officer and Executive 1989-1990 Vice President of System Energy Gerald D. McInvale 51 Senior Vice President and Chief 1991-Present Financial Officer of Entergy Corporation, AP&L, LP&L, MP&L, NOPSI, System Energy, Entergy Operations, Entergy Services, and Entergy Enterprises Senior Vice President and Chief 1993-Present Financial Officer of GSU Senior Vice President and Chief 1994-Present Financial Officer of System Fuels Vice President, Treasurer, and 1993-Present Director of Entergy Power Director of System Fuels 1992-Present Treasurer of Entergy Enterprises 1992-Present Director and Acting Chief Operating 1994-Present Officer of Entergy Enterprises Chairman of the Board of Entergy 1994-Present Systems and Service, Inc. Director of Entergy Systems and 1993-Present Service, Inc. Vice President, Treasurer, and 1993-Present Director of Entergy Power Development Corporation and Entergy- Richmond Power Corporation Senior Vice President, Treasurer, and 1994-Present Director of Entergy Pakistan, Ltd. and Entergy Power Asia, Ltd. President - Executive Information 1990-1991 Strategies (Consulting Firm), Dallas, Texas Senior Vice President and Chief 1987-1990 Financial Officer of Frito-Lay, Inc. (Subsidiary of PepsiCo, Inc.), Dallas, Texas Michael G. Thompson 54 Senior Vice President and Chief Legal 1992-Present Officer of Entergy Corporation and Entergy Services Senior Vice President, Chief Legal 1992-Present Officer, and Secretary of Entergy Enterprises Senior Vice President, Secretary, and 1994-Present Director of Entergy Pakistan, Ltd. and Entergy Power Asia, Ltd. Vice President, Secretary, and 1994-Present Director of Entergy Power Vice President and Secretary of 1993-Present Entergy Systems and Service, Inc. Vice President, Secretary, and 1992-Present Director of Entergy Power Development and Entergy-Richmond Power Corporation Secretary of Entergy Corporation 1994-Present Secretary of AP&L, GSU, LP&L, MP&L, 1995-Present and NOPSI Director of Entergy Systems and 1992-Present Service, Inc. Senior Vice President and Chief Legal 1993-1994 Officer of Entergy Power Assistant Secretary of Entergy 1993-1994 Corporation Senior Partner of Friday, Eldredge & 1987-1992 Clark (law firm) S. M. Henry Brown, Jr. 56 Vice President - Federal Governmental 1989-Present Affairs of Entergy Corporation and Entergy Services Charles L. Kelly 58 Vice President - Corporate 1992-Present Communications and Public Relations of Entergy Corporation Vice President - Corporate 1991-Present Communications and Public Relations of Entergy Services Vice President - Corporate 1981-1991 Communications of AP&L Lee W. Randall 45 Vice President and Chief Accounting 1991-Present Officer of Entergy Corporation, AP&L, LP&L, MP&L, NOPSI, System Energy, Entergy Operations, and Entergy Services Vice President, Chief Accounting 1993-Present Officer, and Assistant Secretary of GSU Assistant Secretary of AP&L, LP&L, 1991-Present MP&L, NOPSI, Entergy Operations, and Entergy Services Senior Vice President - Finance and 1988-1991 Administration and Chief Financial Officer of AP&L Secretary of AP&L 1989-1991 Assistant Treasurer of AP&L 1988-1991 ARKANSAS POWER & LIGHT COMPANY Directors Michael B. Bemis(b) 47 Executive Vice President - Customer 1992-Present Service and Director of AP&L, LP&L, and MP&L Executive Vice President - Customer 1993-Present Service of GSU Executive Vice President - Customer 1992-Present Service of NOPSI and Entergy Services Director of GSU 1994-Present Director of System Fuels 1992-Present Director of Varibus Corporation, 1994-Present Prudential Oil & Gas, Inc., GSG&T, Inc., and Southern Gulf Railway Company Director of NOPSI 1992-1994 President and Chief Operating Officer 1992-1992 of LP&L and NOPSI President and Chief Operating Officer 1989-1991 of MP&L Secretary of MP&L 1991-1991 Donald C. Hintz 52 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry D. Jackson 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. R. Drake Keith 59 President and Director of AP&L 1989-Present Chief Operating Officer of AP&L 1989-1992 Secretary of AP&L 1991-1992 Edwin Lupberger 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Officers Edwin Lupberger 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. R. Drake Keith 59 See the information under the AP&L Directors Section above, incorporated herein by reference. Michael B. Bemis 47 See the information under the AP&L Directors Section above, incorporated herein by reference. Jerry D. Jackson 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Frank F. Gallaher 49 Executive Vice President - Fossil 1993-Present Operations of AP&L, LP&L, MP&L, NOPSI, and Entergy Services President of GSU 1994-Present Director of GSU 1993-Present Chairman of the Board of System Fuels 1992-Present Chairman of the Board of Varibus 1993-Present Corporation, Prudential Oil & Gas, Inc., GSG&T, Inc., and Southern Gulf Railway Company Director of Entergy Services and 1992-Present System Fuels Senior Vice President - Fossil 1992-1993 Operations of AP&L, LP&L, MP&L, NOPSI, and Entergy Services Vice President and Chief Engineer of 1985-1990 MP&L Vice President - System Planning of 1990-1992 Entergy Services Donald C. Hintz 52 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Gerald D. McInvale 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael G. Thompson 54 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael R. Niggli 45 Senior Vice President - Marketing of 1993-Present AP&L, GSU, LP&L, MP&L, NOPSI, and Entergy Services Vice President - Customer Services of 1993-1993 LP&L, NOPSI, and Entergy Services Vice President - Strategic Planning of 1990-1992 Entergy Services Vice President - Fuels Management of 1988-1990 Entergy Services Vice President and Director of Entergy 1991-1992 Enterprises Cecil L. Alexander(c) 59 Vice President - Governmental Affairs 1991-Present of AP&L Vice President - Public Affairs of 1989-1991 AP&L Richard J. Landy 49 Vice President - Human Resources and 1991-Present Administration of AP&L, LP&L, MP&L, NOPSI, Entergy Services, and EOI Vice President - Human Resources and 1993-Present Administration of GSU Vice President - Human Resources and 1986-1990 Administration of System Energy Vice President - Human Resources and 1990-1991 Administration of Entergy Operations James S. Pilgrim 59 Vice President - Customer Service of 1994-Present AP&L Director, Central Region, TDCS 1993-1994 Customer Service Central Division Manager of MP&L 1991-1993 Northern Division Manager of MP&L 1988-1991 Lee W. Randall 45 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. C. Hiram Walters 58 Vice President - Customer Service of 1993-Present AP&L Vice President - Customer Service of 1994-Present LP&L Vice President - Customer Service, 1993-Present Central Region of Entergy Services Vice President - Customer Service of 1984-1991 MP&L Senior Vice President - Customer 1991-1992 Service of Entergy Services GULF STATES UTILITIES COMPANY Directors Michael B. Bemis 47 See the information under the AP&L Directors Section above, incorporated herein by reference. Frank F. Gallaher 49 See the information under the AP&L Officers Section above, incorporated herein by reference. Donald C. Hintz 52 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry D. Jackson 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Edwin Lupberger 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Officers Edwin Lupberger 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Frank F. Gallaher 49 See the information under the AP&L Officers Section above, incorporated herein by reference. Michael B. Bemis 47 See the information under the AP&L Directors Section above, incorporated herein by reference. Jerry D. Jackson 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Donald C. Hintz 52 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Gerald D. McInvale 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael G. Thompson 54 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael R. Niggli 45 See the information under the AP&L Officers Section above, incorporated herein by reference. Richard J. Landy 49 See the information under the AP&L Officers Section above, incorporated herein by reference. William E. Colston 59 Vice President - Customer Service of 1994-Present GSU Vice President - Customer Service of 1993-Present LP&L Vice President - Customer Service of 1993-Present Southern Region of Entergy Services Vice President - Division Manager of 1988-1991 LP&L Regional Director of LP&L 1992-1993 Calvin J. Hebert 60 Vice President - Customer Service of 1993-Present GSU Senior Vice President - Division 1992-1993 Operations of GSU Senior Vice President - External 1986-1992 Affairs of GSU Karen Johnson 50 Vice President - Governmental Affairs 1994-Present of GSU - Texas Executive Director of State Bar of 1990-1994 Texas Attorney at Law, Akin Gump Strauss 1988-1990 Hauer & Feld Lee W. Randall 45 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. LOUISIANA POWER & LIGHT COMPANY Directors Michael B. Bemis 47 See the information under the AP&L Directors Section above, incorporated herein by reference. John J. Cordaro 61 President and Director of LP&L and 1992-Present NOPSI Group Vice President - External 1989-1992 Affairs of LP&L and NOPSI Donald C. Hintz 52 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry D. Jackson 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Edwin Lupberger 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Officers Edwin Lupberger 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. John J. Cordaro 61 See the information under the LP&L Directors Section above, incorporated herein by reference. Michael B. Bemis 47 See the information under the AP&L Directors Section above, incorporated herein by reference. Jerry D. Jackson 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Frank F. Gallaher 49 See the information under the AP&L Officers Section above, incorporated herein by reference. Donald C. Hintz 52 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Gerald D. McInvale 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael G. Thompson 54 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael R. Niggli 45 See the information under the AP&L Officers Section above, incorporated herein by reference. Richard C. Guthrie 52 Vice President - Governmental Affairs 1992-Present of LP&L and NOPSI Vice President - Public Affairs of 1986-1992 LP&L and NOPSI Richard J. Landy 49 See the information under the AP&L Officers Section above, incorporated herein by reference. James D. Bruno 55 Vice President - Customer Service of 1994-Present LP&L and NOPSI Vice President - Metro Region of 1993-Present Entergy Services Region Director - Metro Region of 1991-1993 Entergy Services Vice President - Division Manager - 1988-1991 Orleans Division of Entergy Services William E. Colston 59 See the information under the GSU Officers Section above, incorporated herein by reference. Lee W. Randall 45 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. C. Hiram Walters 58 See the information under the AP&L Officers Section above, incorporated herein by reference. MISSISSPPI POWER & LIGHT COMPANY Directors Michael B. Bemis 47 See the information under the AP&L Directors Section above, incorporated herein by reference. Donald C. Hintz 52 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry D. Jackson 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Edwin Lupberger 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Donald E. Meiners(d) 59 President and Director of MP&L 1992-Present Senior Vice President, System 1988-1990 Executive - Services Division of Entergy Corporation President and Chief Operating Officer 1990-1991 of LP&L and NOPSI Chief Operating Officer and Secretary 1992-1992 of MP&L President and Chief Executive Officer 1987-1990 of Entergy Services, System Fuels, and Entergy Enterprises Officers Edwin Lupberger 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Donald E. Meiners 59 See the information under the MP&L Directors Section above, incorporated herein by reference. Michael B. Bemis 47 See the information under the AP&L Directors Section above, incorporated herein by reference. Jerry D. Jackson 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Frank F. Gallaher 49 See the information under the AP&L Officers Section above, incorporated herein by reference. Gerald D. McInvale 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael G. Thompson 54 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael R. Niggli 45 See the information under the AP&L Officers Section above, incorporated herein by reference. Bill F. Cossar 56 Vice President - Governmental Affairs 1987-Present of MP&L Johnny D. Ervin 45 Vice President - Customer Service of 1991-Present MP&L Director of Entergy Enterprises 1991-1992 Vice President - Marketing of LP&L and 1988-1991 NOPSI Vice President - Division Manager of 1989-1991 LP&L Richard J. Landy 49 See the information under the AP&L Officers Section above, incorporated herein by reference. Lee W. Randall 45 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. NEW ORLEANS PUBLIC SERVICE INC. Directors John J. Cordaro 61 See the information under the LP&L Directors Section above, incorporated herein by reference. Jerry D. Jackson 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Edwin Lupberger 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Officers Edwin Lupberger 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. John J. Cordaro 61 See the information under the LP&L Directors Section above, incorporated herein by reference. Michael B. Bemis 47 See the information under the AP&L Directors Section above, incorporated herein by reference. Jerry D. Jackson 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Frank F. Gallaher 49 See the information under the AP&L Officers Section above, incorporated herein by reference. Gerald D. McInvale 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael G. Thompson 54 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Michael R. Niggli 45 See the information under the AP&L Officers Section above, incorporated herein by reference. Richard C. Guthrie 52 See the information under the LP&L Officers Section above, incorporated herein by reference. Daniel F. Packer 47 Vice President - Regulatory and 1994-Present Governmental Affairs of NOPSI General Manager - Plant Operations at 1991-1994 Waterford 3 Manager - Operations and Maintenance 1990-1991 at Waterford 3 Richard J. Landy 49 See the information under the AP&L Officers Section above, incorporated herein by reference. James D. Bruno 55 See the information under the LP&L Officers Section above, incorporated herein by reference. Lee W. Randall 45 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. SYSTEM ENERGY RESOURCES, INC. Directors Donald C. Hintz 52 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry D. Jackson 50 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Edwin Lupberger 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Jerry L. Maulden 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Officers Edwin Lupberger 58 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Donald C. Hintz 52 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Gerald D. McInvale 51 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Lee W. Randall 45 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Joseph L. Blount 48 Secretary of System Energy and Entergy 1991-Present Operations Vice President Legal and External 1989-1990 Affairs of System Energy Vice President Legal and External 1990-1993 Affairs of Entergy Operations Assistant Secretary for System Energy 1987-1991 Assistant Secretary for Entergy 1990-1991 Operations
(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. Bemis is a director of Deposit Guaranty National Bank, Jackson, MS and Deposit Guaranty Corporation, Jackson, MS. (c) Mr. Alexander is a director of First National Bank of Cleburne County, Heber Springs, AR. (d) Mr. Meiners is a director of Trustmark National Bank, Jackson, MS, and Trustmark Corporation, Jackson, MS. 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 26, 1995 AP&L - May 17, 1995 GSU - May 17, 1995 LP&L - May 17, 1995 MP&L - May 17, 1995 NOPSI - May 17, 1995 System Energy - April 14, 1995 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 SEC and to furnish Entergy Corporation with copies of all Section 16(a) and 17(a) forms they file. Shortly following the Merger, certain individuals were elected as officers of GSU. Although none of these individuals owned any reportable securities of GSU, their initial Forms 3 for GSU were not timely filed. These officers of GSU were: 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. Four individuals considered officers of the Corporation for purposes of Section 16 failed to report on their 1993 Forms 5 their receipt during 1993 of certain restricted shares of the Corporation's stock under the Equity Ownership Plan. These individuals and their respective unreported shares were: S.M. Henry Brown, 4,000 shares; Frank F. Gallaher, 4,000 shares; Charles L. Kelly, 4,000 shares, and Edwin Lupberger, 5,000 shares. Glenn E. Harder, a former officer of the Corporation, failed to timely report on a Form 4 the sale in October 1994 of 15 shares of the Corporation's stock which he had held in the Corporation's dividend reinvestment plan. Each of the above transactions has now been correctly reported. 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 26, 1995, 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, 1994 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 by each officer during the year 1994. See Item 10, "Directors and Executive Officers of the Registrants", incorporated herein by reference, for information on the principal positions of the executive officers named in the table below. AP&L, GSU, 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.
Long-Term Compensation Annual Compensation Awards Payouts Other Restricted Securities (b) (c) (a) Annual Stock Underlying LTIP All Other Name Year Salary Bonus Compensation Awards Options Payouts Compensation Michael B. Bemis 1994 $288,846 $ 76,923 $32,940 (d) 2,500 shares $ 28,275 $22,982 1993 258,538 161,142 62,372 (d) 2,500 50,125 74,619 1992 258,059 170,186 35,927 (d) 2,500 45,094 71,492 Joseph L. Blount 1994 $115,171 $ 17,064 $ 9,339 (d) 0 shares 0 $12,416 1993 109,090 0 4,416 (d) 0 0 15,926 1992 109,140 13,435 5,092 (d) 0 0 17,591 Donald C. Hintz* 1994 $320,769 $142,749 $52,389 (d) 5,000 shares $ 48,379 $23,056 1993 265,386 166,560 48,548 (d) 5,000 85,774 24,462 1992 228,024 114,822 38,364 (d) 2,500 77,165 24,205 Jerry D. Jackson 1994 $323,711 $106,155 $29,598 (d) 5,000 shares $ 56,550 $23,370 1993 288,559 217,287 36,166 (d) 6,719 100,250 25,961 1992 254,167 152,500 27,008 (d) 5,000 90,188 25,447 Edwin Lupberger** 1994 $681,539 $218,789 $39,961 (d) 10,000 shares $139,525 $29,457 1993 542,077 437,610 20,327 (d) 13,438 248,313 32,957 1992 527,499 374,100 39,760 (d) 10,000 180,375 33,671 Jerry L. Maulden 1994 $426,134 $135,962 $63,994 (d) 5,000 shares $ 56,550 $25,690 1993 385,000 286,985 84,655 (d) 5,000 100,250 25,639 1992 392,233 259,316 79,280 (d) 5,000 90,188 24,920 Gerald D. McInvale 1994 $244,165 $ 66,227 $14,146 (d) 2,500 shares $ 28,275 $19,581 1993 221,696 141,811 48,805 (d) 2,500 50,125 22,667 1992 209,975 93,686 45,585 (d) 2,500 45,094 43,594 Lee W. Randall 1994 $177,001 $ 36,392 $ 7,208 (d) 0 shares $ 0 $14,271 1993 176,321 57,142 8,014 (d) 0 0 17,986 1992 168,859 37,094 6,818 (d) 0 0 19,555
* Chief Executive Officer of System Energy. ** Chief Executive Officer of AP&L, GSU, LP&L, MP&L, and NOPSI. (a) Includes bonuses earned pursuant to the Annual Incentive Plan as well as any bonuses of an extraordinary or nonrecurring nature. (b) Amounts include the value of restricted shares that vested under Entergy's Equity Ownership Plan. (c) Includes the following: (1) 1994 Executive Medical Plan premiums of $1,761 for each of the above-named executives in 1994. (2) 1994 employer contributions to the Defined Contribution Restoration Plan as follows: Mr. Bemis $4,096; Mr. Hintz $5,210; Mr. Jackson $5,134; Mr. Lupberger $15,946; Mr. Maulden $8,359; Mr. McInvale $2,775; Mr. Randall $810. (3) 1994 employer contributions to the System Savings Plan as follows: Mr. Bemis $4,500; Mr. Blount $3,455; Mr. Hintz $4,500; Mr. Jackson $4,500; Mr. Lupberger $4,500; Mr. Maulden $4,500; Mr. McInvale $4,500; Mr. Randall $4,500. (4) 1994 reimbursements under the Executive Financial Counseling Program as follows: Mr. Bemis $2,725; Mr. Hintz $785; Mr. Jackson $1,175; Mr. Lupberger $2,623; Mr. Maulden $1,350; Mr. McInvale $645. (5) 1994 payments for personal use under the Private Ownership Vehicle Plan as follows: Mr. Bemis $9,900; Mr. Blount $7,200; Mr. Hintz $10,800; Mr. Jackson $10,800; Mr. Lupberger $4,627; Mr. Maulden $9,720; Mr. McInvale $9,900; Mr. Randall $7,200. (d) Restricted stock awarded under the Equity Ownership Plan is subject to performance based criteria. Restricted stock awards in 1994 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 1994 and the vesting schedule for such shares. At December 31, 1994, the number and value of the aggregate restricted stock holdings were as follows: Mr. Bemis: 12,750 shares, $278,907; Mr. Hintz: 17,568 shares, $384,300; Mr. Jackson: 18,000 shares, $393,750; Mr. Lupberger: 33,950 shares, $742,657; Mr. Maulden: 18,000 shares, $393,750; and Mr. McInvale: 12,750 shares, $278,907. Accumulated dividends are paid on restricted stock when vested. The value of stock for which restrictions were lifted in 1994, 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, 1994 are 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, 1994 ($21.875 per share). Option Grants in 1994 The following table summarizes option grants during 1994 to the executive officers named in the Summary Compensation Table above. The absence, in the table below, of any named officer indicates that no options were granted to such officer. AP&L, GSU, 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(b) Name Granted(a) 1994 share)(a) Date 5% 10% Michael B. Bemis 2,500 3.7% $37.00 01/27/04 $ 58,173 $147,421 Donald C. Hintz 5,000 7.4% 37.00 01/27/04 116,346 294,842 Jerry D. Jackson 5,000 7.4% 37.00 01/27/04 116,346 294,842 Edwin Lupberger 10,000 14.8% 37.00 01/27/04 232,691 589,685 Jerry L. Maulden 5,000 7.4% 37.00 01/27/04 116,346 294,842 Gerald D. McInvale 2,500 3.7% 37.00 01/27/04 58,173 147,421
(a) Options were granted on January 27, 1994, pursuant to the Equity Ownership Plan. All options granted on this date have an exercise price equal to the closing price of Entergy Corporation common stock on the New York Stock Exchange Composite Transactions on January 27, 1994. These options became exercisable on July 28, 1994. (b) 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. Long-Term Incentive Plan Awards in 1994 AP&L, GSU, 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 1994 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 1994. Estimated Future Payouts Under Performance Non-Stock Price-Based Plans(a) (b) Number Period Until of Maturation Name Shares or Payout Threshold Target Maximum Michael B. Bemis 11,250 01/01/94-12/31/96 3,750 7,500 11,250 Donald C. Hintz 15,000 01/01/94-12/31/96 5,000 10,000 15,000 Jerry D. Jackson 15,000 01/01/94-12/31/96 5,000 10,000 15,000 Edwin Lupberger 25,200 01/01/94-12/31/96 8,400 16,800 25,200 Jerry L. Maulden 15,000 01/01/94-12/31/96 5,000 10,000 15,000 Gerald D. McInvale 11,250 01/01/94-12/31/96 3,750 7,500 11,250 (a) Restricted shares awarded will vest at the end of a three-year period, subject to the attainment of approved performance goals for the participants. Restrictions are lifted based upon the achievement of the cumulative result of these goals for the performance period. 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) The Threshold, Target and Maximum levels correspond to the achievement of 50%, 100%, and 150%, respectively, of Equity Ownership Plan goals. Achievement of a Threshold, Target or Maximum level would result in the award of the number of shares indicated in the respective column. Achievement of a level between these three specified levels would result in the award of a number of shares calculated by means of interpolation. Pension Plan Tables AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy Retirement Income Plan Table Annual Covered Years of Service Compensation 15 20 25 30 35 $100,000 $ 22,500 $ 30,000 $ 37,500 $ 45,000 $ 52,000 200,000 45,500 60,000 75,000 90,000 105,000 300,000 67,500 90,000 112,500 135,000 157,500 400,000 90,000 120,000 150,000 180,000 210,000 500,000 112,500 150,000 187,500 225,000 262,500 850,000 191,250 255,000 318,750 382,500 446,250 AP&L, GSU (non-bargaining unit employees), 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 compensation. Final average compensation 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. 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. Prior to October 1, 1994, GSU sponsored a defined benefit pension plan for non-bargaining unit employees with different provisions from the other System Companies. However, effective October 1, 1994, GSU amended this plan for non-bargaining unit employees to be consistent with the other System companies. Bargaining unit employees for GSU are covered by the provisions of the pre-merger GSU defined benefit plan. The amount of the named executive officers' annual compensation covered by the plan as of December 31, 1994 is represented by the base salary column in the Summary Compensation Table of AP&L, GSU, 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, GSU, 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 (except GSU) 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. Effective January 1, 1995, the System companies Retirement Income Plans were amended to transfer assets and related liabilities to a single Entergy Corporation Retirement Plan for all non-bargaining unit employees. 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, 1994 for the following executive officers named in the Summary Compensation Table of AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy were: Mr. Bemis 12; Mr. Blount 10; Mr. Maulden 29; and Mr. Randall 15. The credited years of service under the respective Retirement Income Plans, as amended, as of December 31, 1994 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 23; Mr. Jackson 15; Mr. Lupberger 31; and Mr. McInvale 22. 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. 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. Blount and Mr. McInvale) have entered into PRP participation contracts. System Executive Retirement Plan Table (1) Annual Covered Years of Service Compensation 15 20 25 30+ $ 200,000 $ 90,000 $100,000 $110,000 $120,000 300,000 135,000 150,000 165,000 180,000 400,000 180,000 200,000 220,000 240,000 500,000 225,000 250,000 275,000 300,000 600,000 270,000 300,000 330,000 360,000 700,000 315,000 350,000 385,000 420,000 1,000,000 450,000 500,000 550,000 600,000 ___________ (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, GSU, 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 (except for Mr. Blount) named in the Summary Compensation Table of AP&L, GSU, 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, GSU, LP&L, MP&L, NOPSI, and System Energy for the base salary covered by the SERP as of December 31, 1994) plus the Target Incentive Award (i.e., a percentage of final annual base salary) for the participant in effect at retirement. Benefits paid under the SERP are calculated by multiplying the covered pay times target pay replacement ratios (45%, 50%, or 55%, dependent on job rating at retirement) that are attained, according to plan design, at 20 years of credited service. The target ratios are increased by 1% for each year of service over 20 years, up to a maximum of 30 years of service. In accordance with the SERP formula, the target ratios are reduced for each year of service below 20 years. The credited years of service under this plan are identical to the years of service for named executive officers (other than Mr. Bemis, Mr. Jackson and Mr. McInvale) disclosed above in the "Pension Plan Tables-Retirement Income Plan Table" section. Mr. Bemis, Mr. Jackson and Mr. McInvale have 22 years, 21 years and 13 years, respectively, of credited service under this plan. 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, GSU, 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, GSU, LP&L, MP&L, NOPSI, and System Energy, resignation of employment, or termination for cause. In addition to the non-bargaining unit employees Retirement Income 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 AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy currently have no non-employee directors, and each current director is not compensated for his responsibilities as director. However, for the period January 1, 1994 through May 5, 1994, AP&L, GSU, LP&L, MP&L, and NOPSI did have non-employee directors. These directors were 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 was 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 were 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 was set to enable Entergy System companies to attract and retain persons of outstanding competence to serve on the Boards of Directors. Directors were paid a portion of their compensation in the form of Entergy Corporation's common stock in order to assure that directors would have a personal interest in the performance of the stock of Entergy Corporation. Non-employee directors were awarded 50 shares of Entergy Corporation common stock quarterly, which may have been authorized but unissued shares or shares acquired in the open market. Effective May 6, 1994, all non- employee directors of AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy became advisory directors of the respective Company. Retired non-employee 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. Years of service as an advisory director are included in calculating this benefit. System Energy has no retired non-employee directors. Retired non-employee directors of GSU receive retirement benefits under a plan in which all directors who served continuously for a period of years will receive a percentage of their retainer fee in effect at the time of their retirement for life. The retirement benefit is 30 percent of the retainer fee for service of not less than five nor more than nine years, 40 percent for service of not less than ten nor more than fourteen years, and 50 percent for fifteen or more years of service. For those directors who retired prior to the retirement age, their benefits will be reduced. The plan also provides disability retirement and optional hospital and medical coverage if the director has served at least five years prior to the disability. The retired director pays one-third of the premium for such optional hospital and medical coverage and GSU pays the remaining two-thirds. Years of service as an advisory director are included in calculating these benefits. Employment Contracts and Termination of Employment and Change-in- Control Arrangements GSU 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 one time 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. As of December 31, 1994, the balance in the trust had been reduced to $8,102,203. If and to the extent outstanding benefits are not 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-System Executive Retirement Plan Table" section noted above. Personnel Committee Interlocks and Insider Participation The following persons served as members of the Personnel Committee of AP&L's, GSU's, LP&L's, MP&L's, and NOPSI's Board of Directors through May 5, 1994: 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* ______________ * Denotes Chairman of the Personnel Committee 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) was set by the Personnel Committee of Entergy Corporation's Board of Directors for 1994. After May 5, 1994, the compensation of AP&L, GSU, LP&L, MP&L, and NOPSI executive officers was set by the Personnel Committee of Entergy Corporation's Board of Directors due to the elimination of the Personnel Committees of these companies. No officers or employees of such companies participated in deliberations concerning compensation during 1994. The Personnel Committee of Entergy Corporation's Board of Directors is set forth under the heading "Report of Personnel Committee on Executive Compensation" contained in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held May 26, 1995, and is incorporated herein by reference. Mr. Lupberger is currently and was during 1994 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. 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 26, 1995, which information is incorporated herein by reference. The registrants know of no contractual arrangements that may, at a subsequent date, result in a change in control of any of the registrants. The 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, 1994 Entergy Corporation Common Stock Preferred Stock 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) Entergy Corporation W. Frank Blount* - - 2,934 - John A. Cooper, Jr.* 6,000 (a) - 5,734 - Lucie J. Fjeldstad* - - 1,984 - Dr. Norman C. Francis* - - 500 - Donald C. Hintz** - - 7,493 32,027 Kaneaster Hodges, Jr.* - - 2,800 - Jerry D. Jackson** - - 6,402 35,216 Robert v.d. Luft* - - 2,184 - Edwin Lupberger** - - 8,706 73,687(h)(i) Jerry L. Maulden** - - 37,420 44,048 Gerald D. McInvale** - - 3,173 20,908 Adm. Kinnaird R. McKee* - - 2,900 - Paul W. Murrill* - - 2,180 - James R. Nichols* - - 3,315 - Eugene H. Owen* - 3,500 (a) 1,692 - John N. Palmer, Sr.* - - 13,196 - Robert D. Pugh* - - 5,300 10,000(i) H. Duke Shackelford* - - 8,750 4,950(i) Wm. Clifford Smith* - - 3,775 - Bismark A. Steinhagen* - - 6,437 - All directors and executive officers 6,000 3,500 135,419 266,320 AP&L Michael B. Bemis** - - 7,488 25,540 Donald C. Hintz** - - 7,493 32,027 Jerry D. Jackson** - - 6,402 35,216 R. Drake Keith*** - - 2,891 13,260 Edwin Lupberger** - - 8,706 73,687(h)(i) Jerry L. Maulden** - - 37,420 44,048 All directors and executive officers - - 90,631 334,762 GSU Michael B. Bemis** - - 7,488 25,540 Frank F. Gallaher*** - - 3,725 24,696(j) Donald C. Hintz** - - 7,493 32,027 Jerry D. Jackson** - - 6,402 35,216 Edwin Lupberger** - - 8,706 73,687(h)(i) Jerry L. Maulden** - - 37,420 44,048 All directors and executive officers - - 82,755 313,558 LP&L Michael B. Bemis** - - 7,488 25,540 John J. Cordaro*** - - 1,747 9,877 Donald C. Hintz** - - 7,493 32,027 Jerry D. Jackson** - - 6,402 35,216 Edwin Lupberger** - - 8,706 73,687(h)(i) Jerry L. Maulden** - - 37,420 44,048 All directors and executive officers - - 86,348 335,037 MP&L Michael B. Bemis** - - 7,488 25,540 Donald C. Hintz* - - 7,493 32,027 Jerry D. Jackson** - - 6,402 35,216 Edwin Lupberger** - - 8,706 73,687(h)(i) Jerry L. Maulden** - - 37,420 44,048 Gerald D. McInvale** - - 3,173 20,908 Donald E. Meiners*** - - 1,382 15,033(j) All directors and executive officers - - 83,958 330,524 NOPSI Michael B. Bemis** - - 7,488 25,540 John J. Cordaro*** - - 1,747 9,877 Jerry D. Jackson** - - 6,402 35,216 Edwin Lupberger** - - 8,706 73,687(h)(i) Jerry L. Maulden** - - 37,420 44,048 Gerald D. McInvale** - - 3,173 20,908 All directors and executive officers - - 78,751 294,663 System Energy Joseph L. Blount** - - 834 2,287 Donald C. Hintz** - - 7,493 32,027 Jerry D. Jackson* - - 6,402 35,216 Edwin Lupberger** - - 8,706 73,687(h)(i) Jerry L. Maulden* - - 37,420 44,048 Gerald D. McInvale** - - 3,173 20,908 Lee W. Randall** - - - 4,561 All directors and executive officers - - 64,028 212,734 * 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 6,000 shares of AP&L's $0.01 Par Value ($25 liquidation value) Preferred Stock held by the John A. Cooper Trust, and 3,500 shares of AP&L's $0.01 Par Value ($25 liquidation value) Preferred Stock held by Eugene H. Owen. 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 that 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, 714 shares; Joseph L. Blount, 753 shares; John J. Cordaro, 1,007 shares; Frank F. Gallaher, 941 shares; Donald C. Hintz, 753 shares; Jerry D. Jackson, 753 shares; R. Drake Keith, 753 shares; Edwin Lupberger, 825 shares; Jerry L. Maulden, 796 shares; Gerald D. McInvale, 110 shares; Donald E. Meiners, 553 shares; and Lee W. Randall, 791 shares. (e) Includes, for the named persons, shares of Entergy Corporation common stock held in the System Savings Plan company account as follows: Michael B. Bemis, 4,576 shares; Joseph L. Blount, 1,534 shares; John J. Cordaro, 1,670 shares; Frank F. Gallaher, 3,455 shares; Donald C. Hintz, 1,206 shares; Jerry D. Jackson, 2,052 shares; R. Drake Keith, 3,833 shares; Edwin Lupberger, 6,088 shares; Jerry L. Maulden, 10,252 shares; Gerald D. McInvale, 548 shares; Donald E. Meiners, 4,404 shares; and Lee W. Randall, 3,770 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, 12,750 shares; John J. Cordaro, 2,200 shares; Frank F. Gallaher, 14,800 shares; Donald C. Hintz, 17,568 shares; Jerry D. Jackson, 18,000 shares; R. Drake Keith, 1,500 shares; Edwin Lupberger, 33,950 shares; Jerry L. Maulden, 18,000 shares; Gerald D. McInvale, 12,750 shares; and Donald E. Meiners, 1,500 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, 7,500 shares; John J. Cordaro 5,000 shares; Frank F. Gallaher, 5,000 shares; Donald C. Hintz, 12,500 shares; Jerry D. Jackson, 14,411 shares; R. Drake Keith, 7,174 shares; Edwin Lupberger, 28,824 shares; Jerry L. Maulden, 15,000 shares; Gerald D. McInvale, 7,500 shares; and Donald E. Meiners, 7,500 shares. (h) Includes 1,500 shares of Entergy Corporation common stock held jointly between Edwin Lupberger and Ms. E. H. Lupberger. (i) 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: Edwin Lupberger, 2,500 shares; Robert D. Pugh, 10,000 shares; and H. Duke Shackleford, 4,950 shares. (j) Includes, for the named persons, shares of Entergy Corporation common stock held jointly with their spouses as follows: Frank F. Gallaher, 500 shares; and Don E. Meiners, 1,076 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 26, 1995, which information is incorporated herein by reference. See Item 11, "Executive Compensation - Personnel Committee Interlocks and Insider Participation" for information on certain transactions required to be reported under this item. Other than as provided under applicable corporate laws, 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 for Entergy, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy are listed in the Index to Financial Statements (see pages 56 and 57) (a)2. Financial Statement Schedules Reports of Independent Accountants on Financial Statement Schedules (see pages 385 and 386) Financial Statement Schedules are listed in the Index to Financial Statement Schedules (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 (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 Entergy and GSU A current report on Form 8-K, dated October 21, 1994, was filed with the SEC on October 28, 1994, reporting information under Item 5 "Other Materially Important Events". A current report on Form 8-K, dated December 14, 1994, was filed with the SEC on December 16, 1994, reporting information under Item 5 "Other Materially Important Events". A current report on Form 8-K, dated December 21, 1994, was filed with the SEC on December 22, 1994, reporting information under Item 5 "Other Materially Important Events". Entergy, GSU, LP&L and NOPSI A current report on Form 8-K, dated December 9, 1994, was filed with the SEC on December 9, 1994, reporting information under Items 4 and 7. Entergy and NOPSI A current report on Form 8-K, dated December 9, 1994, was filed with the SEC on January 9, 1995, reporting information under Item 5 "Other Materially Important Events". 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 LEE W. RANDALL Lee W. Randall, Vice President and Chief Accounting Officer Date: March 27, 1995 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 LEE W. RANDALL Lee W. Randall Vice President, Chief Accounting March 27, 1995 Officer and Assistant Secretary (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., N. C. Francis, 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, and Bismark A. Steinhagen (Directors). By: LEE W. RANDALL March 27, 1995 (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 LEE W. RANDALL Lee W. Randall, Vice President, Chief Accounting Officer, and Assistant Secretary Date: March 27, 1995 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 LEE W. RANDALL Lee W. Randall Vice President, Chief Accounting March 27, 1995 Officer and Assistant Secretary (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, Donald C. Hintz, Jerry D. Jackson, R. Drake Keith, and Jerry L. Maulden (Directors). By: LEE W. RANDALL March 27, 1995 (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 LEE W. RANDALL Lee W. Randall, Vice President, Chief Accounting Officer and Assistant Secretary Date: March 27, 1995 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 LEE W. RANDALL Lee W. Randall Vice President, Chief Accounting March 27, 1995 Officer and Assistant Secretary (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 F. Gallaher, Donald C. Hintz, Jerry D. Jackson, and Jerry L. Maulden (Directors). By: LEE W. RANDALL March 27, 1995 (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 LEE W. RANDALL Lee W. Randall, Vice President, Chief Accounting Officer and Assistant Secretary Date: March 27, 1995 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 LEE W. RANDALL Lee W. Randall Vice President, Chief Accounting March 27, 1995 Officer and Assistant Secretary (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, Jerry D. Jackson, and Jerry L. Maulden (Directors). By: LEE W. RANDALL March 27, 1995 (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 LEE W. RANDALL Lee W. Randall, Vice President, Chief Accounting Officer and Assistant Secretary Date: March 27, 1995 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 LEE W. RANDALL Lee W. Randall Vice President, Chief Accounting March 27, 1995 Officer and Assistant Secretary (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, Donald C. Hintz, Jerry D. Jackson, Jerry L. Maulden, and Donald E. Meiners (Directors). By: LEE W. RANDALL March 27, 1995 (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 LEE W. RANDALL Lee W. Randall, Vice President, Chief Accounting Officer and Assiatant Secretary Date: March 27, 1995 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 LEE W. RANDALL Lee W. Randall Vice President, Chief Accounting March 27, 1995 Officer and Assistant Secretary (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); John J. Cordaro, Jerry D. Jackson, and Jerry L. Maulden (Directors). By: LEE W. RANDALL March 27, 1995 (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 LEE W. RANDALL Lee W. Randall, Vice President and Chief Accounting Officer Date: March 27, 1995 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 LEE W. RANDALL Lee W. Randall Vice President and Chief March 27, 1995 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), Donald C. Hintz, Jerry D. Jackson, and Jerry L. Maulden (Directors). By: LEE W. RANDALL March 27, 1995 (Lee W. Randall, Attorney-in-fact) EXHIBIT 23(a) CONSENT OF INDEPENDENT ACCOUNTANTS We consent to the incorporation by reference in Post-Effective Amendment Nos. 2, 3, 4A, and 5A on Form S-8 and the related Prospectuses to registration statement of Entergy Corporation on Form S-4 (File Number 33-54298), of our reports dated February 21, 1995, except for the last paragraph of the section of Note 2 to the consolidated financial statements subtitled "Filings with the PUCT and Texas Cities" as to which the date is March 20, 1995, on our audit of the consolidated financial statements and financial statement schedules of Entergy Corporation as of and for the year ended December 31, 1994, which reports include explanatory paragraphs related to rate- related contingencies and legal proceedings and are included in this Annual Report on Form 10-K. We consent to the incorporation by reference in the registration statements and the related Prospectuses of Arkansas Power & Light Company on Form S-3 (File Number 33-36149, 33-48356 and 33-50289) of our reports dated February 21, 1995 on our audit of the financial statements and financial statement schedules of Arkansas Power & Light Company as of and for the year ended December 31, 1994 which are included in this Annual Report on Form 10-K. We consent to the incorporation by reference in registration statements and the related Prospectuses 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 21, 1995, except for the last paragraph of the section of Note 2 to the financial statements subtitled "Filings with the PUCT and Texas Cities" as to which the date is March 20, 1995, on our audits of the financial statements and financial statement schedules of Gulf States Utilities Company as of December 31, 1994 and 1993 and for the three years ended December 31, 1994, 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. We consent to the incorporation by reference in the registration statements and the related Prospectuses of Louisiana Power & Light Company on Form S-3 (File Numbers 33-46085, 33-39221 and 33-50937) of our reports dated February 21, 1995 on our audit of the financial statements and financial statement schedules of Louisiana Power & Light Company as of and for the year ended December 31, 1994 which are included in this Annual Report on Form 10-K. We consent to the incorporation by reference in the registration statements and the related Prospectuses of Mississippi Power & Light Company on Form S-3 (File Numbers 33-53004, 33-55826 and 33-50507) of our reports dated February 21, 1995 on our audit of the financial statements and financial statement schedules of Mississippi Power & Light Company as of and for the year ended December 31, 1994 which are included in this Annual Report on Form 10-K. We consent to the incorporation by reference in the registration statement and the related Prospectus of New Orleans Public Service Inc. on Form S-3 (File Number 33-57926) of our reports dated February 21, 1995 on our audit of the financial statements and financial statement schedules of New Orleans Public Service Inc. as of and for the year ended December 31, 1994 which are included in this Annual Report on Form 10-K. We consent to the incorporation by reference in the registration statement and the related Prospectus of System Energy Resources, Inc. on Form S-3 (File Number 33-47662) of our reports dated February 21, 1995 on our audit of the financial statements and financial statement schedules of System Energy Resources, Inc. as of and for the year ended December 31, 1994 which are included in this Annual Report on Form 10-K. /s/ Coopers & Lybrand L.L.P. COOPERS & LYBRAND L.L.P. New Orleans, Louisiana March 24, 1995 EXHIBIT 23(b) 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. 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. 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. 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. 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. 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 (November 30, 1994 as to Note 2, "Rate and Regulatory Matters - FERC Settlement"), appearing in this Annual Report on Form 10-K of System Energy Resources, Inc. /s/ Deloitte & Touche LLP DELOITTE & TOUCHE LLP New Orleans, Louisiana March 27, 1995 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 27, 1995 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 CLARK, THOMAS & WINTERS A Professional Corporation Austin, Texas March 27, 1995 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 SANDLIN ASSOCIATES Management Consultants Pasco, Washington March 27, 1995 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 27, 1995 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 Robert B. McGehee Date: March 27, 1995 REPORT OF INDEPENDENT ACCOUNTANTS 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 and for the year ended December 31, 1994, and the financial statements of Gulf States Utilities Company as of December 31, 1994 and 1993, and for each of the three years in the period ended December 31, 1994, and have issued our reports included elsewhere in this Form 10-K, thereon dated February 21, 1995, except for the last paragraph of the section of the Entergy Corporation and Gulf States Utilities Company Note 2 subtitled "Filings with the PUCT and Texas Cities", as to which the date is March 20, 1995, which reports as to Entergy Corporation and Gulf States Utilities Company include explanatory paragraphs related to rate-related contingencies and legal proceedings, and which report as to Gulf States Utilities Company includes an explanatory paragraph related to changes in accounting for income taxes, postretirement benefits, unbilled revenue and power plant materials and supplies. In connection with our audits of such financial statements, we have also audited the related financial statement schedules 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 L.L.P. COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 21, 1995, except for the last paragraph of "Filings with the PUCT and Texas Cities" in Note 2, as to which the date is March 20, 1995 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 for each of the two 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. is dated November 30, 1994 as to Note 2, "Rate and Regulatory Matters - FERC Settlement"; such reports are included elsewhere in this Form 10-K. Our audits also included the 1993 and 1992 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 LLP DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994 INDEX TO FINANCIAL STATEMENT SCHEDULES Schedule Page I Financial Statements of Entergy Corporation: Balance Sheets, December 31, 1994 and 1993 S-2 Statements of Cash Flows - For the Years Ended December 31, 1994, 1993 and 1992 S-3 Statements of Income - For the Years Ended December 31, 1994, 1993 and 1992 S-4 Statements of Retained Earnings and Paid-In Capital - For the Years Ended December 31, 1994, 1993 and 1992 S-5 II Valuation and Qualifying Accounts 1994, 1993 and 1992: Entergy Corporation and Subsidiaries S-6 Arkansas Power & Light Company S-7 Gulf States Utilities Company S-8 Louisiana Power & Light Company S-9 Mississippi Power & Light Company S-10 New Orleans Public Service Inc. S-11 Schedules other than those listed above are omitted because they are not required, not applicable or the required information is shown in the financial statements or notes thereto. Columns have been omitted from schedules filed because the information is not applicable. ENTERGY CORPORATION SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION BALANCE SHEETS December 31, 1994 1993 (In Thousands) ASSETS Construction work in progress - $22,861 ---------- ---------- Investment in Wholly-owned Subsidiaries $6,110,504 6,449,165 ---------- ---------- Current Assets: Cash equivalents: Temporary cash investments - at cost, which approximates market: Associated companies 83,339 100,401 Other 169,369 52,150 ---------- ---------- Total cash equivalents 252,708 152,551 Accounts receivable: Associated companies 10,413 3,086 Other 375 2,467 Interest receivable 923 1,073 Other 6,901 1,166 ---------- ---------- Total 271,320 160,343 ---------- ---------- Deferred Debits 55,185 93,479 ---------- ---------- TOTAL $6,437,009 $6,725,848 ========== ========== CAPITALIZATION AND LIABILITIES Capitalization: Common stock, $.01 par value in 1994 and 1993: authorized 500,000,000 shares; issued and outstanding 230,017,485 shares in 1994 and 231,219,737 shares in 1993 $2,300 $2,312 Paid-in capital 4,202,134 4,223,682 Retained earnings 2,223,739 2,310,082 Less - treasury stock (2,608,908 shares in 1994) 77,378 - ---------- ---------- Total common shareholders' equity 6,350,795 6,536,076 ---------- ---------- Current Liabilities: Notes payable - 43,000 Accounts payable: Associated companies 4,578 7,556 Other 1,102 10,069 Other current liabilities 5,021 1,849 ---------- ---------- Total 10,701 62,474 ---------- ---------- Deferred Credits and Noncurrent Liabilities 75,513 127,298 ---------- ---------- Total $6,437,009 $6,725,848 ========== ========== See Entergy Corporation and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8. ENTERGY CORPORATION SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Operating Activities: Net income $341,841 $551,930 $437,637 Noncash items included in net income: Equity in earnings of subsidiaries (369,702) (557,681) (454,947) Deferred income taxes 7,007 3,771 3,146 Depreciation 959 Changes in working capital: Receivables (5,085) (1,082) 2,875 Payables (11,945) 1,367 (26,241) Other working capital accounts (2,563) 531 16,034 Common stock dividends received from subsidiaries 763,400 686,700 487,854 Other (12,136) (20,938) (15,012) -------- -------- -------- Net cash flow provided by operating activities 711,776 664,598 451,346 -------- -------- -------- Investing Activities: Merger with GSU - cash paid - (250,000) - Investment in subsidiaries (49,892) (86,221) (79,228) Capital expenditures (3,178) (22,861) - Decrease in other temporary investments - 17,012 114,651 Proceeds received from the sale of property 26,000 - - Advance to subsidiary (11,840) (24,642) (12,005) -------- -------- -------- Net cash flow provided by (used in) investing activities (38,910) (366,712) 23,418 -------- -------- -------- Financing Activities: Changes in short-term borrowings (43,000) 43,000 - Common stock dividends paid (410,223) (287,483) (256,117) Retirement of common stock (119,486) (20,558) (105,673) -------- -------- -------- Net cash flow used in financing activities (572,709) (265,041) (361,790) -------- -------- -------- Net increase in cash and cash equivalents 100,157 32,845 112,974 Cash and cash equivalents at beginning of period 152,551 119,706 6,732 -------- -------- -------- Cash and cash equivalents at end of period $252,708 $152,551 $119,706 ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Noncash investing and financing activities: Merger with GSU-Common stock issued - $2,031,101 -
See Entergy Corporation and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8. ENTERGY CORPORATION SCHEDULE I-FINANCIAL STATEMENTS OF ENTERGY CORPORATION STATEMENTS OF INCOME For the Years Ended December 31, 1994 1993 1992 (In Thousands) Income: Equity in income of subsidiaries $369,701 $557,681 $454,947 Interest on temporary investments 25,496 18,520 20,011 -------- -------- -------- Total 395,197 576,201 474,958 -------- -------- -------- Expenses and Other Deductions: Administrative and general expenses 57,846 25,129 32,412 Income taxes (credit) (6,350) 3,587 4,734 Taxes other than income (credit) 465 (696) 167 Interest (credit) 1,395 (3,749) 8 -------- -------- -------- Total 53,356 24,271 37,321 -------- -------- -------- Net Income $341,841 $551,930 $437,637 ======== ======== ======== See Entergy Corporation and Subsidiaries Notes to consolidated financial Statements in Part II, Item 8. ENTERGY CORPORATION SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL
For the Years Ended December 31, 1994 1993 1992 (In Thousands) Retained Earnings, January 1 $2,310,082 $2,062,188 $1,943,298 Add: Net income 341,841 551,930 437,637 ---------- ---------- ---------- Total 2,651,923 2,614,118 2,380,935 ---------- ---------- ---------- Deduct: Dividends declared on common stock 411,806 288,342 255,479 Common stock retirements 13,940 13,906 59,187 Capital stock and other expenses 2,438 1,788 4,081 ---------- ---------- ---------- Total 428,184 304,036 318,747 ---------- ---------- ---------- Retained Earnings, December 31 $2,223,739 $2,310,082 $2,062,188 ========== ========== ========== Paid-in Capital, January 1 $4,223,682 $1,327,589 $1,357,883 Add: Gain (loss) on reacquisition of subsidiaries' preferred stock (23) (20) (1,323) Issuance of 56,695,724 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 4,223,659 4,225,909 1,356,560 ---------- ---------- ---------- Deduct: Common stock retirements 22,468 4,389 28,127 Capital stock discounts and other expenses (943) (2,162) 844 ---------- ---------- ---------- Total 21,525 2,227 28,971 ---------- ---------- ---------- Paid-in Capital, December 31 $4,202,134 $4,223,682 $1,327,589 ========== ========== ==========
See Entergy Corporation and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8. ENTERGY CORPORATION AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1994, 1993, and 1992 (In Thousands)
Column A Column B Column C Column D Column E Column F Other Additions Changes ----------------- ---------- Balance at Charged to Deductions Balance Beginning Charged Other from at of to Accounts Provisions Acquisition End of Description Period Income (Note 1) (Note 2) of GSU Period Year ended December 31, 1994 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $8,808 $8,266 - $10,334 - $6,740 ======= ======= === ======= ======= ======= Accumulated Provisions Not Deducted from Assets: Property insurance $34,546 $25,592 - $27,267 - $32,871 Injuries and damages (Note 3) 23,096 10,993 - 12,023 - 22,066 Environmental 26,753 21,292 - 5,306 - 42,739 ------- ------- --- ------- ------- ------- Total $84,395 $57,877 - $44,596 - $97,676 ======= ======= === ======= ======= ======= 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 $25,177 $5,714 - $7,217 $10,872 $34,546 Injuries and damages (Note 3) 15,978 11,702 - 14,053 9,469 23,096 Environmental 8,006 1,672 - 1,076 18,151 26,753 ------- ------- --- ------- ------- ------- Total $49,161 $19,088 - $22,346 $38,492 $84,395 ======= ======= === ======= ======= ======= 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 $35,056 $10,820 - $20,699 - $25,177 Injuries and damages (Note 3) 14,614 11,053 20 9,709 - 15,978 Environmental 8,835 853 - 1,682 - 8,006 ------- ------- --- ------- ------- ------- Total $58,505 $22,726 $20 $32,090 - $49,161 ======= ======= === ======= ======= =======
___________ 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. ARKANSAS POWER & LIGHT COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1994, 1993, and 1992 (In Thousands)
Column A Column B Column C Column D Column E Other Additions Changes ----------------- ---------- Balance at Charged to Deductions Balance Beginning Charged Other from at of to Accounts Provisions End of Description Period Income (Note 1) (Note 2) Period Year ended December 31, 1994 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $2,050 $1,967 - $2,067 $1,950 ======= ======= === ======= ======= Accumulated Provisions Not Deducted from Assets: Property insurance $2,821 $18,782 - $19,687 $1,916 Injuries and damages (Note 2) 3,259 1,316 - 1,915 2,660 Environmental 6,825 1,510 - 2,985 5,350 ------- ------- --- ------- ------- Total $12,905 $21,608 - $24,587 $9,926 ======= ======= === ======= ======= 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 2) 5,851 4,070 - 6,662 3,259 Environmental 6,766 1,122 - 1,063 6,825 ------- ------- --- ------- ------- Total $17,799 $7,144 - $12,038 $12,905 ======= ======= === ======= ======= 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 2) 4,254 7,086 - 5,489 5,851 Environmental 7,595 853 - 1,682 6,766 ------- ------- --- ------- ------- Total $19,676 $11,939 - $13,816 $17,799 ======= ======= === ======= =======
___________ 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. GULF STATES UTILITIES COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1994, 1993 and 1992 (In Thousands)
Column A Column B Column C Column D Column E Other Additions Changes ----------------- ---------- Balance at Charged to Deductions Balance Beginning Charged Other from at of to Accounts Provisions End of Description Period Income (Note 1) (Note 2) Period Year ended December 31, 1994 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $2,383 $701 - $2,369 $715 ======= ======= === ====== ======= Accumulated Provisions Not Deducted from Assets-- Property insurance $10,872 $2,170 - $2,591 $10,451 Injuries and damages (Note 3) 9,469 2,970 - 5,517 6,922 Environmental 18,151 2,589 - 426 20,314 ------- ------- --- ------ ------- Total $38,492 $7,729 - $8,534 $37,687 ======= ======= === ====== ======= 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) 6,594 11,511 - 8,636 9,469 Environmental 19,328 3 - 1,180 18,151 ------- ------- --- ------ ------- Total $35,319 $12,816 - $9,643 $38,492 ======= ======= === ====== ======= 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) - $0 $9,397 Injuries and damages (Note 3) 5,120 3,367 - 1,893 6,594 Environmental 16,184 4,618 - 1,474 19,328 ------- ------- --- ------ ------- Total $32,279 $6,407 - $3,367 $35,319 ======= ======= === ====== =======
___________ 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 II - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1994, 1993, and 1992 (In Thousands)
Column A Column B Column C Column D Column E Other Additions Changes ----------------- ---------- Balance at Charged to Deductions Balance Beginning Charged Other from at of to Accounts Provisions End of Description Period Income (Note 1) (Note 2) Period Year ended December 31, 1994 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $1,075 $2,023 - $1,923 $1,175 ======= ======= === ======= ======= Accumulated Provisions Not Deducted from Assets: Property insurance $2,388 $3,120 - $4,694 814 Injuries and damages (Note 2) 4,779 5,848 - 3,277 7,350 Environmental 1,237 16,868 - 1,711 16,394 ------- ------- --- ------- ------- Total $8,404 $25,836 - $9,682 $24,558 ======= ======= === ======= ======= 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 Environmental 700 550 - 13 1,237 ------- ------- --- ------- ------- Total $9,327 $5,098 - $6,021 $8,404 ======= ======= === ======= ======= 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 $9,174 $4,300 - $11,000 $2,474 Injuries and damages (Note 2) 6,153 2,283 - 2,283 6,153 Environmental 700 - - - 700 ------- ------- --- ------- ------- Total $16,027 $6,583 - $13,283 $9,327 ======= ======= === ======= =======
___________ 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. MISSISSIPPI POWER & LIGHT COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1994, 1993, and 1992 (In Thousands)
Column A Column B Column C Column D Column E Other Additions Changes ----------------- ---------- Balance at Charged to Deductions Balance Beginning Charged Other from at of to Accounts Provisions End of Description Period Income (Note 1) (Note 2) Period Year ended December 31, 1994 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $2,470 $1,897 - $2,297 $2,070 ====== ====== === ====== ====== Accumulated Provisions Not Deducted from Assets: Property insurance $2,554 $1,520 - $295 $3,779 Injuries and damages (Note 3) 3,478 365 - 118 3,725 Environmental 500 300 - 116 684 ------ ------ --- ------ ------ Total $6,532 $2,185 - $529 $8,188 ====== ====== === ====== ====== 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) 1,645 3,202 - 1,369 3,478 Environmental 500 - - - 500 ------ ------ --- ------ ------ Total $4,196 $4,723 - $2,387 $6,532 ====== ====== === ====== ====== 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 $3,300 $1,520 - $2,769 $2,051 Injuries and damages (Note 3) 1,863 333 20 571 1,645 Environmental 500 - - - 500 ------ ------ --- ------ ------ Total $5,663 $1,853 $20 $3,340 $4,196 ====== ====== === ====== ======
___________ 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. NEW ORLEANS PUBLIC SERVICE INC. SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1994, 1993, and 1992 (In Thousands)
Column A Column B Column C Column D Column E Other Additions Changes ----------------- ---------- Balance at Charged to Deductions Balance Beginning Charged Other from at of to Accounts Provisions End of Description Period Income (Note 1) (Note 2) Period Year ended December 31, 1994 Accumulated Provisions Deducted from Assets-- Doubtful Accounts $830 $1,678 - $1,678 $830 ======= ====== === ====== ======= Accumulated Provisions Not Deducted from Assets: Property insurance $15,911 - - - $15,911 Injuries and damages (Note 2) 2,111 494 - 1,196 1,409 Environmental 40 25 - 68 (3) ------- ------ --- ------ ------- Total $18,062 $519 - $1,264 $17,317 ======= ====== === ====== ======= 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 Environmental 40 - - - 40 ------- ------ --- ------ ------- Total $17,839 $2,123 - $1,900 $18,062 ======= ====== === ====== ======= 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 Environmental 40 - - - 40 ------- ------ --- ------ ------- Total $17,139 $2,351 - $1,651 $17,839 ======= ====== === ====== =======
___________ Notes: (1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off. (2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages. EXHIBIT INDEX The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have heretofore been filed with the SEC, respectively, as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a (+) are management contracts or compensatory plans or arrangements required to be filed herewith and required to be identified as such by Item 14 of Form 10-K. Reference is made to a duplicate list of exhibits being filed as a part of this Form 10-K, which list, prepared in accordance with Item 102 of Regulation S-T of the SEC, immediately precedes the exhibits being physically filed with this Form 10-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 (3(a) to Form 10-Q for the quarter ended June 30, 1994 in 1-8474). MP&L (f) 1 -- Restated Articles of Incorporation of MP&L, as amended (3(b) to Form 10-Q for the quarter ended June 30, 1994 in 0-320). *(f) 2 -- Articles of Amendment to Restated Articles of Incorporation of MP&L, as amended, as executed January 18, 1995 and March 7, 1995. NOPSI (g) 1 -- Restated Articles of Incorporation of NOPSI, as amended (3(c) to Form 10-Q for the quarter ended June 30, 1994 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 (3(d) to Form 10-Q for the quarter ended June 30, 1994). (d) -- By-Laws of GSU (3(e) to Form 10-Q for the quarter ended June 30, 1994). (e) -- By-Laws of LP&L (A-4 in 70-6962). (f) -- By-Laws of MP&L (3(f) to Form 10-Q for the quarter ended June 30, 1994). (g) -- By-Laws of NOPSI (3(g) to Form 10-Q for the quarter ended June 30, 1994). (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 nineteen Supplemental Indentures (A-1 in 70-5890 (Mortgage); B and C to Rule 24 Certificate in 70-5890 (First); B to Rule 24 Certificate in 70-6259 (Second); 20(a)-5 to Form 10-Q for the quarter ended June 30, 1981, in 1-3517 (Third); A-1(e)-1 to Rule 24 Certificate in 70-6985 (Fourth); B to Rule 24 Certificate in 70-7021 (Fifth); B to Rule 24 Certificate in 70-7021 (Sixth); A-3(b) to Rule 24 Certificate in 70-7026 (Seventh); A-3(b) to Rule 24 Certificate in 70-7158 (Eighth); B to Rule 24 Certificate in 70-7123 (Ninth); B-1 to Rule 24 Certificate in 70-7272 (Tenth); B-2 to Rule 24 Certificate in 70-7272 (Eleventh); B-3 to Rule 24 Certificate in 70-7272 (Twelfth); B-1 to Rule 24 Certificate in 70-7382 (Thirteenth); B-2 to Rule 24 Certificate in 70-7382 (Fourteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Fifteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Sixteenth); A-2(d) to Rule 24 Certificate in 70-7946 (Seventeenth); A-2(e) to Rule 24 Certificate dated May 4, 1993 in 70-7946 (Eighteenth); and A-2(g) to Rule 24 Certificate dated May 6, 1994, in 70-7946 (Nineteenth)). (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 Country, 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-two Supplemental Indentures (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 7(c) in 2-7605 (Second); 7(d) in 2-8100 (Third); 7(a)-4 in 2-8482 (Fourth); 7(a)-5 in 2-9149 (Fifth); 4(a)-6 in 2-9789 (Sixth); 4(a)-7 in 2-10261 (Seventh); 4(a)-8 in 2-11043 (Eighth); 2(b)-9 in 2-11468 (Ninth); 2(b)-10 in 2-15767 (Tenth); D in 70-3952 (Eleventh); D in 70-4099 (Twelfth); 4(d) in 2-23185 (Thirteenth); 2(c) in 2-24414 (Fourteenth); 2(c) in 2-25913 (Fifteenth); 2(c) in 2-28869 (Sixteenth); 2(d) in 2-28869 (Seventeenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); 2(c) in 2-41080 (Twenty-first); C-1 to Rule 24 Certificate in 70-5151 (Twenty-second); C-1 to Rule 24 Certificate in 70-5257 (Twenty-third); C to Rule 24 Certificate in 70-5343 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-5404 (Twenty-fifth); C to Rule 24 Certificate in 70-5502 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-5556 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-5693 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6078 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6174 (Thirtieth); C-1 to Rule 24 Certificate in 70-6246 (Thirty-first); C-1 to Rule 24 Certificate in 70-6498 (Thirty-second); A-4b-2 to Rule 24 Certificate in 70-6326 (Thirty-third); C-1 to Rule 24 Certificate in 70-6607 (Thirty-fourth); C-1 to Rule 24 Certificate in 70-6650 (Thirty-fifth); C-1 to Rule 24 Certificate, dated December 1, 1982, in 70-6774 (Thirty-sixth); C-1 to Rule 24 Certificate, dated February 17, 1983, in 70-6774 (Thirty-seventh); A-2(a) to Rule 24 Certificate, dated December 5, 1984, in 70-6858 (Thirty-eighth); A-3(a) to Rule 24 Certificate in 70-7127 (Thirty-ninth); A-7 to Rule 24 Certificate in 70-7068 (Fortieth); A-8(b) to Rule 24 Certificate dated July 6, 1989 in 70-7346 (Forty-first); A-8(c) to Rule 24 Certificate, dated February 1, 1990 in 70-7346 (Forty-second); 4 to Form 10-Q for the quarter ended September 30, 1990 in 1-10764 (Forty-third); A-2(a) to Rule 24 Certificate, dated November 30, 1990, in 70-7802 (Forty-fourth); A-2(b) to Rule 24 Certificate, dated January 24, 1991, in 70-7802 (Forty-fifth); 4(d)(2) in 33-54298 (Forty-sixth); 4(c)(2) to Form 10-K for the year ended December 31, 1992 in 1-10764 (Forty-seventh); 4(b) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-eighth); 4(c) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-ninth); 4(b) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fiftieth); 4(c) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fifty-first); and 4(a) to Form 10-Q for the quarter ended June 30, 1994 (Fifty-second)). 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-nine 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); A-3(e) to Rule 24 Certificate dated December 21, 1993 in 70-7822 (Forty-eighth); and A-3(f) to Rule 24 Certificate dated August 1, 1994 in 70-7822 (Forty-ninth). (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 nine Supplemental Indentures (A-2(a)-2 to Rule 24 Certificate in 70-7461 (Mortgage); A-2(b)-2 in 70-7461 (First); A-5(b) to Rule 24 Certificate in 70-7419 (Second); A-4(b) to Rule 24 Certificate in 70-7554 (Third); A-1(b)-1 to Rule 24 Certificate in 70-7737 (Fourth); A-2(b) to Rule 24 Certificate dated November 24, 1992 in 70-7914 (Fifth); A-2(e) to Rule 24 Certificate dated January 22, 1993 in 70-7914 (Sixth); A-2(g) to Form U-1 in 70-7914 (Seventh); A- 2(i) to Rule 24 Certificate dated November 10, 1993 in 70- 7914 (Eighth); and A-2(j) to Rule 24 Certificate dated July 22, 1994 in 70-7914 (Ninth)). 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 -- Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-4 in 2-41080). (a) 5 -- Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080). (a) 6 -- Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)-5 in 2-41080). (a) 7 -- Amendment, dated January 1, 1972, to Service Agreement with Entergy Services (5(a)-6 in 2-43175). (a) 8 -- 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) 9 -- 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) 10 -- 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) 11 -- Amendment, dated January 1, 1992, to Service Agreement with Entergy Services. (a) 12 -- 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) 13 -- First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate, dated June 24, 1977, in 70-5399). (a) 14 -- Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592). (a) 15 -- 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) 16 -- Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399). (a) 17 -- 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) 18 -- 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) 19 -- 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) 20 -- 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) 21 -- 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) 22 -- 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) 23 -- 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) 24 -- 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) 25 -- 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) 26 -- 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) 27 -- Twenty-ninth Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey as Trustees (B- 2(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946). (a) 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 -- 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) 36 -- 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) 37 -- 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) 38 -- 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) 39 -- 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) 40 -- Twenty-ninth Supplementary Capital Funds Agreement and Assignment, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B- 3(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946). (a) 41 -- 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) 42 -- 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) 43 -- 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) 44 -- 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) 45 -- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). (a) 46 -- 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) 47 -- Operating Agreement dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337). (a) 48 -- 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) 49 -- 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) 50 -- Substitute Power Agreement, dated as of May 1, 1980, among MP&L, System Energy and SMEPA (B(3)(a) in 70-6337). (a) 51 -- Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033). (a) 52 -- 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) 53 -- Post-Retirement Plan (10(a)37 to Form 10-K for the fiscal year ended December 31, 1983, in 1-3517). (a) 54 -- 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) 55 -- 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) 56 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033). (a) 57 -- 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) 58 -- First Amendment, dated January 1, 1990, to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). (a) 59 -- Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). (a) 60 -- Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). (a) 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 (10(a) 81 to Form 10-K for the year ended December 31, 1993 in 1-11299). +(a) 82 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for the year ended December 31, 1993 in 1-11299). 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 -- 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) 12 -- 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) 13 -- 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) 14 -- 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) 15 -- 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) 16 -- Twenty-ninth Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey as Trustees (B- 2(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946). (b) 17 -- 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) 18 -- 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) 19 -- 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) 20 -- 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) 21 -- 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) 22 -- 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) 23 -- 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) 24 -- 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) 25 -- 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) 26 -- 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) 27 -- 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) 28 -- 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) 29 -- Twenty-ninth Supplementary Capital Funds Agreement and Assignment; dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B- 2(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946). (b) 30 -- 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) 31 -- 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) 32 -- 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) 33 -- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). (b) 34 -- 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) 35 -- Operating Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337). (b) 36 -- 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) 37 -- 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) 38 -- 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) 39 -- 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) 40 -- 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) 41 -- Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561) 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) 42 -- Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561) 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) 43 -- 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) 44 -- 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) 45 -- Collateral Trust Indenture, dated as of January 1, 1994, among System Energy, GG1B Funding Corporation and Bankers Trust Company, as Trustee (A-3(e) to Rule 24 Certificate dated January 31, 1994, in 70-8215), as supplemented by Supplemental Indenture No. 1 dated January 1, 1994, (A-3(f) to Rule 24 Certificate dated January 31, 1994, in 70-8215). (b) 46 -- Substitute Power Agreement, dated as of May 1, 1980, among MP&L, System Energy and SMEPA (B(3)(a) in 70-6337). (b) 47 -- Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033). (b) 48 -- 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) 49 -- 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) 50 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033). (b) 51 -- 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) 52 -- 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) 53 -- 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) 54 -- 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) 55 -- 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) 56 -- First Amendment, dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). (b) 57 -- Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). (b) 58 -- Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). (b) 59 -- 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) 60 -- 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) 61 -- 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) 62 -- 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) 63 -- 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) 64 -- 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) 65 -- 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 -- Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) 4 in 2-41080). (c) 5 -- Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080). (c) 6 -- Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)-5 in 2-41080). (c) 7 -- Amendment, dated January 1, 1972, to Service Agreement with Entergy Services (5(a)- 6 in 2-43175). (c) 8 -- 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) 9 -- 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) 10 -- 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) 11 -- Amendment, dated January 1, 1992, to Service Agreement with Entergy Services. (c) 12 -- 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) 13 -- First Amendment to Availability Agreement, dated June 30, 1977 (B to Rule 24 Certificate, dated June 24, 1977, in 70-5399). (c) 14 -- Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592). (c) 15 -- 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) 16 -- Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399). (c) 17 -- 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) 18 -- 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) 19 -- 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) 20 -- 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) 21 -- 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) 22 -- 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) 23 -- 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) 24 -- 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) 25 -- 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) 26 -- 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) 27 -- 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) 28 -- 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) 29 -- 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) 30 Twenty-ninth Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B- 2(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946). (c) 31 -- Agreement, dated August 20, 1954, between AP&L and the United States of America (SPA)(13(h) in 2-11467). (c) 32 -- Amendment, dated April 19, 1955, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-2 in 2-41080). (c) 33 -- Amendment, dated January 3, 1964, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-3 in 2-41080). (c) 34 -- Amendment, dated September 5, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-4 in 2-41080). (c) 35 -- Amendment, dated November 19, 1970, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-5 in 2-41080). (c) 36 -- Amendment, dated July 18, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-6 in 2-41080). (c) 37 -- Amendment, dated December 27, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-7 in 2-41080). (c) 38 -- Amendment, dated January 25, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-8 in 2-41080). (c) 39 -- Amendment, dated October 14, 1971, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-9 in 2-43175). (c) 40 -- Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-10 in 2-60233). (c) 41 -- Agreement, dated May 14, 1971, between AP&L and the United States of America (SPA) (5(e) in 2-41080). (c) 42 -- Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated May 14, 1971 (5(e)-1 in 2-60233). (c) 43 -- 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) 44 -- Agreement, dated April 3, 1972, between Entergy Services and Gulf United Nuclear Fuels Corporation (5(l)-3 in 2-46152). (c) 45 -- 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) 46 -- 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) 47 -- 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) 48 -- Agreement, dated June 29, 1979, between AP&L and City of Conway, Arkansas (5(r)-3 in 2-66235). (c) 49 -- 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) 50 -- 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) 51 -- 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) 52 -- 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) 53 -- 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) 54 -- Amendment, dated December 28, 1979, to the Independence Steam Electric Station Ownership Agreement (5(r)-7(a) in 2-66235). (c) 55 -- 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) 56 -- 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) 57 -- 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) 58 -- 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) 59 -- 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) 60 -- 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) 61 -- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). +(c) 62 -- Post-Retirement Plan (10(b) 55 to Form 10-K for the fiscal year ended December 31, 1983, in 1-10764). (c) 63 -- 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) 64 -- 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) 65 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033). (c) 66 -- 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) 67 -- 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) 68 -- First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). (c) 69 -- Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). (c) 70 -- Third Amendment dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). (c) 71 -- 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) 72 -- 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) 73 -- 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) 74 -- 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) 75 -- 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) 76 -- 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) 77 -- 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) 78 -- 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) 79 -- 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) 80 -- 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) 81 -- Entergy Corporation Annual Incentive Plan (10(a)54 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(c) 82 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831). +(c) 83 -- 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) 84 -- Supplemental Retirement Plan (10(a)69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(c) 85 -- 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) 86 -- 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) 87 -- 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) 88 -- 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) 89 -- 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) 90 -- 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) 91 -- 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) 92 -- 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) 93 -- 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) 94 -- 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) 95 -- 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) 96 -- 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) 97 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for the year ended December 31, 1993 in 1-11299). (c) 98 -- Loan Agreement dated June 15, 1993, between AP&L and Independence Country, Arkansas (B-1 (a) to Rule 24 Certificate dated July 9, 1993 in 70-8171). (c) 99 -- Installment Sale Agreement dated January 1, 1991, between AP&L and Pope Country, Arkansas (B-1 (b) to Rule 24 Certificate dated January 24, 1991 in 70-7802). (c) 100 -- Installment Sale Agreement dated November 1, 1990, between AP&L and Pope Country, Arkansas (B-1 (a) to Rule 24 Certificate dated November 30, 1990 in70-7802). (c) 101 -- Installment Sale Agreement dated December 1, 1985, between AP&L and Pople Country, Arkansas (B-1(a) to Rule 24 Certificate dated December 19, 1985 in 70-7127). (c) 102 -- Loan Agreement dated June 15, 1994, between AP&L and Jefferson County, Arkansas (B-1(a) to Rule 24 Certificate dated June 30, 1994 in 70-8405). (c) 103 -- Loan Agreement dated June 15, 1994, between AP&L and Pope County, Arkansas (B-1(b) to Rule 24 Certificate in 70-8405). GSU (d) 1 -- Guaranty Agreement, dated July 1, 1976, between GSU and American Bank and Trust Company (C and D to Form 8-K, dated August 6, 1976 in 1-2703). (d) 2 -- 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) 3 -- 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) 4 -- 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) 5 -- 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) 6 -- 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) 7 -- 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) 8 -- 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) 9 -- 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) 10 -- 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) 11 -- 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) 12 -- Lease Agreement, dated September 18, 1980, between BLC Corporation and GSU (1 to Form 8-K, dated October 6, 1980 in 1-2703). (d) 13 -- Joint Ownership Participation and Operating 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) 14 -- 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) 15 -- 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) 16 -- 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) 17 -- 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) 18 -- 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) 19 -- 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) 20 -- 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) 21 -- 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) 22 -- 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) 23 -- 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) 24 -- 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) 25 -- 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) 26 -- 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) 27 -- 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) 28 -- 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) 29 -- 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) 30 -- Trust Agreement for GSU's Nonqualified Directors and Designated Key Employees by and between GSU and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-2703). (d) 31 -- 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) 32 -- 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) 33 -- 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) 34 -- Credit Agreement, dated as of December 29, 1993, among River Bend Fuel Services, Inc. and Certain Commercial Lending Institutions and CIBC Inc. as Agent for the Lenders. (d) 35 -- 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) 36 -- 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) 37 -- Trust Agreement for GSU's Executive Continuity Plan, by and between GSU and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10- K for the year ended December 31, 1992 in 1-2703). +(d) 38 -- 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) 39 -- 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) 40 -- 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) 41 -- 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) 42 -- 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) 43 -- 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) 44 -- 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) 45 -- 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 Bank, Texas-Beaumont, N.A., (now Texas Commerce Bank ), as Trustee (2-A to Form 8-K dated October 20, 1989 in 1-2703). (d) 46 -- Operating Agreement between Entergy Operations and GSU, dated as of December 31, 1993 (B-2(f) to Rule 24 Certificate in 70- 8059). (d) 47 -- Guarantee Agreement between Entergy Corporation and GSU, dated as of December 31, 1993 (B-5(a) to Rule 24 Certificate in 70-8059). (d) 48 -- Service Agreement with Entergy Services, dated as of December 31, 1993 (B-6(c) to Rule 24 Certificate in 70-8059). +(d) 49 -- Amendment to Employment Agreement between J. L. Donnelly and GSU, dated December 22, 1993 (10(d) 57 to Form 10-K for the year ended December 31, 1993 in 1-2703). (d) 50 -- Amendment to Letter of Credit and Reimbursement Agreement between GSU and Westpac Banking Corporation (10(d) 58 to Form 10-K for the year ended December 31, 1993 in 1-2703). (d) 51 -- Third Amendment, dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). (d) 52 -- Refunding Agreement between GSU and West Feliciana Parish (dated December 20, 1994 (B-12(a) to Rule 24 Certificate dated December 30, 1994 in 70-8375). 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 -- Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) 4 in 2-41080). (e) 5 -- Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080). (e) 6 -- Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)-5 in 2-42523). (e) 7 -- Amendment, dated as of January 1, 1972, to Service Agreement with Entergy Services (4(a)-6 in 2-45916). (e) 8 -- 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) 9 -- 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) 10 -- 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) 11 -- Amendment, dated January 1, 1992, to Service Agreement with Entergy Services. (e) 12 -- 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) 13 -- First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate, dated June 30, 1977, in 70-5399). (e) 14 -- Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592). (e) 15 -- 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) 16 -- Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399). (e) 17 -- 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) 18 -- 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) 19 -- 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) 20 -- 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) 21 -- 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) 22 -- 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) 23 -- 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) 24 -- 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) 25 -- 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) 26 -- 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) 27 -- 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) 28 -- 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) 29 -- 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) 30 -- Twenty-ninth Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey, as Trustees, (B-2(f) to Rule 24 Certificate dated May 6, 1994 in 70-7946). (e) 31 -- 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) 32 -- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). (e) 33 -- 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) 34 -- Post-Retirement Plan (10(c)23 to Form 10-K for the year ended December 31, 1983, in 1-8474). (e) 35 -- 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) 36 -- 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) 37 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033). (e) 38 -- 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) 39 -- First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated January 1, 1990 (D-2 to Form U5S for the year ended December 31, 1989). (e) 40 -- Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). (e) 41 -- Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). (e) 42 -- 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) 43 -- 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) 44 -- 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) 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). +(e) 46 -- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(e) 47 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831). +(e) 48 -- Supplemental Retirement Plan (10(a) 69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(e) 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). +(e) 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). +(e) 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). +(e) 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). +(e) 53 -- 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) 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). +(e) 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). +(e) 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). +(e) 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). +(e) 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). +(e) 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). +(e) 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). +(e) 61 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for the year ended December 31, 1993 in 1-11299). (e) 62 -- Installment Sale Agreement, dated July 20, 1994, between LP&L and St. Charles Parish, Louisiana (B-6(e) to Rule 24 Certificate dated August 1, 1994 in 70-7822). 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 -- Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) 4 in 2- 41080). (f) 5 -- Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080). (f) 6 -- Service Agreement with Entergy Services, dated as of April 1, 1963 (D in 37-63). (f) 7 -- Amendment, dated January 1, 1972, to Service Agreement with Entergy Services (A to Notice, dated October 14, 1971, in 37-63). (f) 8 -- 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) 9 -- 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) 10 -- 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) 11 -- Amendment, dated January 1, 1992, to Service Agreement with Entergy Services. (f) 12 -- 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) 13 -- First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate, dated June 24, 1977, in 70-5399). (f) 14 -- Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592). (f) 15 -- 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) 16 -- Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399). (f) 17 -- 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) 18 -- 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) 19 -- 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) 20 -- 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) 21 -- 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) 22 -- 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) 23 -- 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) 24 -- 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) 25 -- 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) 26 -- 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) 27 -- Twenty-ninth Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey as Trustees (B- 2(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946). (f) 28 -- Installment Sale Agreement, dated as of June 1, 1974, between MP&L and Washington County, Mississippi (B-2(a) to Rule 24 Certificate, dated August 1, 1974, in 70-5504). (f) 29 -- Installment Sale Agreement, dated as of July 1, 1982, between MP&L and Independence County, Arkansas, (B-1(c) to Rule 24 Certificate dated July 21, 1982, in 70-6672). (f) 30 -- Installment Sale Agreement, dated as of December 1, 1982, between MP&L and Independence County, Arkansas, (B-1(d) to Rule 24 Certificate dated December 7, 1982, in 70-6672). (f) 31 -- Amended and Restated Installment Sale Agreement, dated as of April 1, 1994, between MP&L and Warren County, Mississippi, (B-6(a) to Rule 24 Certificate dated May 4, 1994, in 70- 7914). (f) 32 -- Amended and Restated Installment Sale Agreement, dated as of April 1, 1994, between MP&L and Washington County, Mississippi, (B-6(b) to Rule 24 Certificate dated May 4, 1994, in 70-7914). (f) 33 -- Substitute Power Agreement, dated as of May 1, 1980, among MP&L, System Energy and SMEPA (B-3(a) in 70-6337). (f) 34 -- 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) 35 -- 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) 36 -- 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) 37 -- 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) 38 -- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). +(f) 39 -- Post-Retirement Plan (10(d) 24 to Form 10-K for the fiscal year ended December 31, 1983, in 0-320). (f) 40 -- 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) 41 -- 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) 42 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033). (f) 43 -- 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) 44 -- 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) 45 -- 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) 46 -- 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) 47 -- First Amendment dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). (f) 48 -- Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). (f) 49 -- Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). +(f) 50 -- 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) 51 -- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(f) 52 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831). +(f) 53 -- Supplemental Retirement Plan (10(a)69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(f) 54 -- 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) 55 -- 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) 56 -- 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) 57 -- 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) 58 -- 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) 59 -- 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) 60 -- 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) 61 -- 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) 62 -- 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) 63 -- 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) 64 -- 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) 65 -- 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) 66 -- 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 -- Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) 4 in 2-41080). (g) 5 -- Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080). (g) 6 -- Service Agreement with Entergy Services dated as of April 1, 1963 (5(a)-5 in 2-42523). (g) 7 -- Amendment, dated as of January 1, 1972, to Service Agreement with Entergy Services (4(a)-6 in 2-45916). (g) 8 -- 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) 9 -- 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) 10 -- 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) 11 -- Amendment, dated January 1, 1992, to Service Agreement with Entergy Services. (g) 12 -- 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) 13 -- First Amendment to Availability Agreement, dated June 30, 1977 (B to Rule 24 Certificate, dated June 30, 1977, in 70-5399). (g) 14 -- Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592). (g) 15 -- 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) 16 -- Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399). (g) 17 -- 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) 18 -- 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) 19 -- 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) 20 -- 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) 21 -- 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) 22 -- 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) 23 -- 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) 24 -- 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) 25 -- 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) 26 -- 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) 27 -- 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) 28 -- 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) 29 -- 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) 30 -- Twenty-ninth Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B- 2(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946). (g) 31 -- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). +(g) 32 -- Post-Retirement Plan (10(e) 22 to Form 10-K for the fiscal year ended December 31, 1983, in 1-1319). (g) 33 -- 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) 34 -- 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) 35 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033). (g) 36 -- 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) 37 -- 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) 38 -- First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). (g) 39 -- Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). (g) 40 -- Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). +(g) 41 -- 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) 42 -- Entergy Corporation Annual Incentive Plan (10(a)54 to Form 10-K for the year ended December 31, 1989, in 1-3517). +(g) 43 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831). +(g) 44 -- Supplemental Retirement Plan (10(a)69 to Form 10-K for the year ended December 31, 1992 in 1-3517). +(g) 45 -- 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) 46 -- 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) 47 -- 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) 48 -- 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) 49 -- 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) 50 -- 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) 51 -- 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) 52 -- 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) 53 -- 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) 54 -- 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) 55 -- 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) 56 -- 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) 57 -- 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 Coopers & Lybrand L.L.P. is contained herein at page 373. *(b) The consent of Deloitte & Touche LLP is contained herein at page 374. *(c) The consent of Friday, Eldredge & Clark is contained herein at page 375. *(d) The consent of Clark, Thomas & Winters is contained herein at page 376. *(e) The consent of Sandlin Associates is contained herein at page 377. *(f) The consent of Monroe & Lemann (A Professional Corporation) is contained herein at page 378. *(g) The consent of Wise Carter Child & Caraway, Professional Association, is contained herein at page 379. *(24) Powers of Attorney (27) Financial Data Schedule *(a) Financial Data Schedule for Entergy Corporation and Subsidiaries as of December 31, 1994. *(b) Financial Data Schedule for AP&L as of December 31, 1994. *(c) Financial Data Schedule for GSU as of December 31, 1994. *(d) Financial Data Schedule for LP&L as of December 31, 1994. *(e) Financial Data Schedule for MP&L as of December 31, 1994. *(f) Financial Data Schedule for NOPSI as of December 31, 1994. *(g) Financial Data Schedule for System Energy as of December 31, 1994. (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 Clark, Thomas & Winters, a professional corporation, dated August 8, 1994 regarding recovery of costs deferred purusant to PUCT order in Docket 6525 (99 (j) to Quarterly Report on Form 10-Q for the quarter ended June 30, 1994 in No. 1-2703). *(a) 3 Opinion of Clark, Thomas & Winters, a professional corporation, confirming its opinions dated September 30, 1992 and August 8, 1994. _________________ * Filed herewith. + Management contracts or compensatory plans or arrangements. EX-3 2 Exhibit 3(i)(f)2 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 Incorporation: 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 anticipa tion 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 re quirements 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 not withstanding 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 qualifi cations 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 S tock, 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; (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 MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) March 17, 1994 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) 2,641,508 shares of preferred stock, 966,508 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) 37,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 140,000 shares of 9% preferred stock, cumulative, $100 par value; (viii) 210,000 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 17th day of March, 1994. MISSISSIPPI POWER & LIGHT COMPANY By: /s/ J. W. Snider, Jr. Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) August 1, 1994 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) 2,571,508 shares of preferred stock, 896,508 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) 37,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 70,000 shares of 9% preferred stock, cumulative, $100 par value; (viii) 210,000 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 1st day of August, 1994. MISSISSIPPI POWER & LIGHT COMPANY By: /s/ J. W. Snider, Jr. Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) January 18, 1995 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) 2,501,508 shares of preferred stock, 826,508 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) 37,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 70,000 shares of 9% preferred stock, cumulative, $100 par value; (viii) 140,000 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 18th day of January, 1995. MISSISSIPPI POWER & LIGHT COMPANY By: /s/ J. W. Snider, Jr. Assistant Secretary MISSISSIPPI POWER & LIGHT COMPANY Articles of Amendment Under Miss. Code Ann. Section 79-4-6.31 (1989) March 7, 1995 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) 2,491,508 shares of preferred stock, 816,508 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) 27,700 shares of 12% preferred stock, cumulative, $100 par value; (vii) 70,000 shares of 9% preferred stock, cumulative, $100 par value; (viii) 140,000 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 7th day of March, 1995. MISSISSIPPI POWER & LIGHT COMPANY By: /s/ J. W. Snider, Jr. Assistant Secretary EX-10 3 Exhibit 10(a)11 Amendment To Service Agreement The parties hereto do hereby stipulated and agree that the SERVICE AGREEMENT entered into by and between them under date of April 1, 1963, and as heretofore amended on January 1, 1972, April 27, 1984, August 1, 1988, and January 28, 1991, be and the same hereby is further amended by substituting for Exhibit II to the SERVICE AGREEMENT, the attached revised Exhibit II. The effective date of this amendment is January 1, 1992. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed this 23rd day of April, 1992. ENTERGY SERVICES, INC. By: /s/ Lee W. Randall Title: Vice President CLIENT COMPANY ENTERGY CORPORATION By: /s/ Edwin Lupberger Title: Chairman and CEO EXHIBIT II METHODS OF ALLOCATING COSTS AMONG CLIENT COMPANIES RECEIVING SERVICE UNDER THIS AND SIMILAR SERVICE AGREEMENTS WITH ENTERGY SERVICES, INC. (SERVICES) (January 1, 1992) 1. The costs of rendering service by Services will include all costs of doing business including interest on debt but excluding a return for the use of Services' initial equity capital amounting to $20,000. 2. (a) Services will maintain a separate record of the expenses of each department. The expenses of each department will include: (i) those expenses that are directly attributable to such department, and (ii) an appropriate portion of those office and housekeeping expenses that are not directly attributable to a department but which are necessary to the operation of such department. (b) Expenses of the department will include salaries and wages of employees, including social security taxes, vacations, paid absences, sickness, employee disability expenses, and other employee welfare expenses, rent and utilities, materials and supplies, depreciation, and all other expenses attributable to the department. (c) Departmental expenses will be categorized into one of two classes: (i) those expenses which are directly attributable to specific services rendered to a Client Company or group of Client Companies (Departmental Direct Costs), and (ii) those expenses which are attributable to the overall operation of the department and not to a specific service provided to Client Companies (Departmental Indirect Costs). Departmental Indirect Costs include: (1) Administrative labor costs associated with office and general service employees described in Section 3(a). This would include not only the salaries and wages of these employees but also other related employment costs described in Section 2(b) above. (2) Occupancy costs including rent and utilities. (3) Depreciation. (4) Materials and supplies, telephone use, postage, etc. (5) Other costs attributable to a department. (d) The indirect expenses of the department will not include: (i) those incremental out-of-pocket expenses that are incurred for the direct benefit and convenience of a Client Company or a group of Client Companies and are to be directly charged to such Client Company or group of Client Companies; and (ii) Services' overhead expenses that are attributable to maintaining the corporate existence of Services, franchise and other general taxes, and all other incidental overhead expenses including those auditing fees and accounting department expenses attributable to Services (Indirect Corporate Costs). (e) Services will establish annual budgets for controlling the expenses of each service department and those expenses outlined above in Section 2(d) which are not department specific. 3. (a) Employees in each department will be divided into two classes: A. Those employees rendered service to Client Companies (Class A), and B. Those office and general service employees, such as secretaries, stenographers, telephone operators and file clerks, who generally assist employees in Class A or render other house-keeping services and who are not engaged directly in rendering service to a Client Company or a group of Client Companies. In the event that any such office or general service employees are assigned to functions that are attributable to services being performed for Client Companies, such employees shall be reclassified as Class A employees. (b) Expenses set forth in Section 2 above will be separated to show: (i) salaries and wages of Class A employees, and (ii) all other expenses of the department. (c) Class A employees in each department will maintain a record of the time they are employed in rendering service to each Client Company or group of Client Companies. The hourly rate for each Class A employee will be determined each month. 4. (a) The charge to Client Company or a group of Client Companies for a particular service will be the sum of the figures derived by multiplying the hours reported by each Class A employee in rendering such service by the hourly rate applicable to such employee and other direct allocated expenses. (b) Departmental Indirect Costs as defined in Section 2(c)(ii) will be allocated in proportion to the direct salaries and wages charged. 5. Those expenses of Services that are not included in the expense of a department under Section 2 above will be charged to Client Companies receiving service as follows: (a) Incremental out-of-pocket costs incurred for the direct benefit and convenience of a Client Company or a group of Client Companies will be charged directly to such company or group of companies. (b) The Indirect Corporate Costs of Services referred to above in Section 2(d)(ii) will be allocated among the Client Companies in the same proportion as the charges to the Client Companies, excluding Indirect Corporate Costs. (c) If the method of allocation of Departmental Indirect Costs (Section 4(b)), or Indirect Corporate Costs (Section 5(b)), would result in an inequity because of a change in operations or organization of the Client Companies, then Services may adjust the basis to effect an equitable distribution. Any such change in allocation shall be made only after first giving to the Commission written notice of such proposed change not less than 60 days prior to the proposed effectiveness of any such change. 6. On the basis of the foregoing, monthly bills will be rendered to Client Companies. Billing procedures and amounts will be open to audit by Client Company and by any regulatory authority having jurisdiction in respect of the Client Company. 7. When services are rendered to a group of Client Companies, costs of such service shall be allocated equitably among the Companies based on the nature and scope of the service rendered according to the formulas outlined in Exhibit II, Supplement. Exhibit II, Supplement ALLOCATION FORMULAS FOR GROUPS OF CLIENT COMPANIES Note: Each allocation formula is based on data relevant to the participating Client Companies. Energy Sales Based on total kilowatt-hours of energy sold to Residential, Commercial, Industrial, Government and Municipal consumers. Customers Based on a twelve month average of Residential, Commercial, Industrial, Government and Municipal general business customers. Employees Based on the number of full time employees at year-end. Capability/Responsibility Ratio The Capability/Responsibility Ratio of a company is the System capability multiplied by the ratio obtained by dividing a company's peak load by the System peak load. The company's peak load is the average of the twelve monthly highest clock hour demands in kilowatts of the Company's interconnected system, occurring each month coincident with the System peak load, during the twelve month period ending with the current month. Composite - Energy Sales, Customers, Employees and Capability/Responsibility Ratio Based on four components with equal weighting to each: kilowatt-hour energy sales, average customers, number of employees and capability responsibility ratio. Composite - Energy Sales, Customers and DCS Employees Based on three components of equal weighting: kilowatt-hour energy sales, average customers and number of Distribution and Customer Service employees. Transmission Line Miles Based on the number of miles of transmission lines, weighted for design voltage. (Voltage < 500kv = 1, Voltage > 500kv = 2) Composite - Transmission Line Miles/Substations Based on two components: transmission line miles with a 30% weighting and the number of high voltage substations with a 70% weighting. Aircraft Ridership Based on employee use of company aircraft. Disaster Recovery Applications Based on the number of software applications that require alternate mainframe processing support for business continuity during a computer center disaster. Equity/Capitalization Ratio This ratio is computed for Entergy Corporation and the Client Companies as follows: - Entergy Corporation's allocation is the ratio of common shareholders equity to total capitalization; - the Client Companies allocation is the ratio of preferred stock plus long term debt to total capitalization. Final Bill Processing Based on the total number of final bills processed for collection. Gas Consumption Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System. Income and Deduction Ratio Based on the previous years federal income tax return, total income plus total deductions. Level of Service Based on Entergy Services' total billings to each Client Company excluding corporate overhead. Money Pool Transactions Based on each company's use of the money pool, weighted 75% on frequency of transactions, and 25% on dollar amount of the transaction. Nuclear and Casualty/Property Insurance Premiums Based on total Client Company costs for the previous year's insurance premium. Participants in Plans Several formulas are based on the number of participants in various Client Company plans and programs, such as: - Savings Plan - Flexible Benefits Programs - Master Trust Plan - ESOP - Student/Parent Loan Program - Systemwide Welfare Plans - Benefits Plus Flexible Spending Account - Non-Qualified Defined Contribution Restoration Plan - Personal Effects Floater Plan - Personal Property and Casualty Benefits Preferred Stockholders Based on total number of preferred stockholders at year-end. Revenues Based on total general business revenues from energy sales to Residential, Commercial, Industrial, Government and Municipal consumers. System Capacity Based on the power level, rated in kilowatts, that could be achieved if all generating units were operating at maximum capability simultaneously. EX-10 4 Exhibit 10(c)11 Amendment To Service Agreement The parties hereto do hereby stipulated and agree that the SERVICE AGREEMENT entered into by and between them under date of April 1, 1963, and as heretofore amended on January 1, 1972, April 27, 1984, August 1, 1988, and January 28, 1991, be and the same hereby is further amended by substituting for Exhibit II to the SERVICE AGREEMENT, the attached revised Exhibit II. The effective date of this amendment is January 1, 1992. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed this 23rd day of April, 1992. ENTERGY SERVICES, INC. By: /s/ Lee W. Randall Title: Vice President CLIENT COMPANY ARKANSAS POWER & LIGHT COMPANY By: /s/ R. D. Keith Title: President and COO EXHIBIT II METHODS OF ALLOCATING COSTS AMONG CLIENT COMPANIES RECEIVING SERVICE UNDER THIS AND SIMILAR SERVICE AGREEMENTS WITH ENTERGY SERVICES, INC. (SERVICES) (January 1, 1992) 1. The costs of rendering service by Services will include all costs of doing business including interest on debt but excluding a return for the use of Services' initial equity capital amounting to $20,000. 2. (a) Services will maintain a separate record of the expenses of each department. The expenses of each department will include: (i) those expenses that are directly attributable to such department, and (ii) an appropriate portion of those office and housekeeping expenses that are not directly attributable to a department but which are necessary to the operation of such department. (b) Expenses of the department will include salaries and wages of employees, including social security taxes, vacations, paid absences, sickness, employee disability expenses, and other employee welfare expenses, rent and utilities, materials and supplies, depreciation, and all other expenses attributable to the department. (c) Departmental expenses will be categorized into one of two classes: (i) those expenses which are directly attributable to specific services rendered to a Client Company or group of Client Companies (Departmental Direct Costs), and (ii) those expenses which are attributable to the overall operation of the department and not to a specific service provided to Client Companies (Departmental Indirect Costs). Departmental Indirect Costs include: (1) Administrative labor costs associated with office and general service employees described in Section 3(a). This would include not only the salaries and wages of these employees but also other related employment costs described in Section 2(b) above. (2) Occupancy costs including rent and utilities. (3) Depreciation. (4) Materials and supplies, telephone use, postage, etc. (5) Other costs attributable to a department. (d) The indirect expenses of the department will not include: (i) those incremental out-of-pocket expenses that are incurred for the direct benefit and convenience of a Client Company or a group of Client Companies and are to be directly charged to such Client Company or group of Client Companies; and (ii) Services' overhead expenses that are attributable to maintaining the corporate existence of Services, franchise and other general taxes, and all other incidental overhead expenses including those auditing fees and accounting department expenses attributable to Services (Indirect Corporate Costs). (e) Services will establish annual budgets for controlling the expenses of each service department and those expenses outlined above in Section 2(d) which are not department specific. 3. (a) Employees in each department will be divided into two classes: A. Those employees rendered service to Client Companies (Class A), and B. Those office and general service employees, such as secretaries, stenographers, telephone operators and file clerks, who generally assist employees in Class A or render other house-keeping services and who are not engaged directly in rendering service to a Client Company or a group of Client Companies. In the event that any such office or general service employees are assigned to functions that are attributable to services being performed for Client Companies, such employees shall be reclassified as Class A employees. (b) Expenses set forth in Section 2 above will be separated to show: (i) salaries and wages of Class A employees, and (ii) all other expenses of the department. (c) Class A employees in each department will maintain a record of the time they are employed in rendering service to each Client Company or group of Client Companies. The hourly rate for each Class A employee will be determined each month. 4. (a) The charge to Client Company or a group of Client Companies for a particular service will be the sum of the figures derived by multiplying the hours reported by each Class A employee in rendering such service by the hourly rate applicable to such employee and other direct allocated expenses. (b) Departmental Indirect Costs as defined in Section 2(c)(ii) will be allocated in proportion to the direct salaries and wages charged. 5. Those expenses of Services that are not included in the expense of a department under Section 2 above will be charged to Client Companies receiving service as follows: (a) Incremental out-of-pocket costs incurred for the direct benefit and convenience of a Client Company or a group of Client Companies will be charged directly to such company or group of companies. (b) The Indirect Corporate Costs of Services referred to above in Section 2(d)(ii) will be allocated among the Client Companies in the same proportion as the charges to the Client Companies, excluding Indirect Corporate Costs. (c) If the method of allocation of Departmental Indirect Costs (Section 4(b)), or Indirect Corporate Costs (Section 5(b)), would result in an inequity because of a change in operations or organization of the Client Companies, then Services may adjust the basis to effect an equitable distribution. Any such change in allocation shall be made only after first giving to the Commission written notice of such proposed change not less than 60 days prior to the proposed effectiveness of any such change. 6. On the basis of the foregoing, monthly bills will be rendered to Client Companies. Billing procedures and amounts will be open to audit by Client Company and by any regulatory authority having jurisdiction in respect of the Client Company. 7. When services are rendered to a group of Client Companies, costs of such service shall be allocated equitably among the Companies based on the nature and scope of the service rendered according to the formulas outlined in Exhibit II, Supplement. Exhibit II, Supplement ALLOCATION FORMULAS FOR GROUPS OF CLIENT COMPANIES Note: Each allocation formula is based on data relevant to the participating Client Companies. Energy Sales Based on total kilowatt-hours of energy sold to Residential, Commercial, Industrial, Government and Municipal consumers. Customers Based on a twelve month average of Residential, Commercial, Industrial, Government and Municipal general business customers. Employees Based on the number of full time employees at year-end. Capability/Responsibility Ratio The Capability/Responsibility Ratio of a company is the System capability multiplied by the ratio obtained by dividing a company's peak load by the System peak load. The company's peak load is the average of the twelve monthly highest clock hour demands in kilowatts of the Company's interconnected system, occurring each month coincident with the System peak load, during the twelve month period ending with the current month. Composite - Energy Sales, Customers, Employees and Capability/Responsibility Ratio Based on four components with equal weighting to each: kilowatt-hour energy sales, average customers, number of employees and capability responsibility ratio. Composite - Energy Sales, Customers and DCS Employees Based on three components of equal weighting: kilowatt-hour energy sales, average customers and number of Distribution and Customer Service employees. Transmission Line Miles Based on the number of miles of transmission lines, weighted for design voltage. (Voltage < 500kv = 1, Voltage > 500kv = 2) Composite - Transmission Line Miles/Substations Based on two components: transmission line miles with a 30% weighting and the number of high voltage substations with a 70% weighting. Aircraft Ridership Based on employee use of company aircraft. Disaster Recovery Applications Based on the number of software applications that require alternate mainframe processing support for business continuity during a computer center disaster. Equity/Capitalization Ratio This ratio is computed for Entergy Corporation and the Client Companies as follows: - Entergy Corporation's allocation is the ratio of common shareholders equity to total capitalization; - the Client Companies allocation is the ratio of preferred stock plus long term debt to total capitalization. Final Bill Processing Based on the total number of final bills processed for collection. Gas Consumption Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System. Income and Deduction Ratio Based on the previous years federal income tax return, total income plus total deductions. Level of Service Based on Entergy Services' total billings to each Client Company excluding corporate overhead. Money Pool Transactions Based on each company's use of the money pool, weighted 75% on frequency of transactions, and 25% on dollar amount of the transaction. Nuclear and Casualty/Property Insurance Premiums Based on total Client Company costs for the previous year's insurance premium. Participants in Plans Several formulas are based on the number of participants in various Client Company plans and programs, such as: - Savings Plan - Flexible Benefits Programs - Master Trust Plan - ESOP - Student/Parent Loan Program - Systemwide Welfare Plans - Benefits Plus Flexible Spending Account - Non-Qualified Defined Contribution Restoration Plan - Personal Effects Floater Plan - Personal Property and Casualty Benefits Preferred Stockholders Based on total number of preferred stockholders at year-end. Revenues Based on total general business revenues from energy sales to Residential, Commercial, Industrial, Government and Municipal consumers. System Capacity Based on the power level, rated in kilowatts, that could be achieved if all generating units were operating at maximum capability simultaneously. EX-10 5 Exhibit 10(d)34 U.S. $25,000,000 CREDIT AGREEMENT, dated as of December 29, 1993 among RIVER BEND FUEL SERVICES, INC., as the Borrower, and CERTAIN COMMERCIAL LENDING INSTITUTIONS, as the Lenders, and CIBC INC., as the Agent for the Lenders. CREDIT AGREEMENT THIS CREDIT AGREEMENT, dated as of December 29, 1993, among RIVER BEND FUEL SERVICES, INC., a Delaware corporation (the "Borrower"), the various financial institutions as are or may become parties hereto (collectively, the "Lenders"), and CIBC INC., a Delaware corporation ("CIBC"), as agent (the "Agent") for the Lenders, W I T N E S S E T H: WHEREAS, the Borrower is engaged in the business of owning Nuclear Fuel and leasing it to GSU; and WHEREAS, the Borrower desires to obtain Commitments from the Lenders pursuant to which Loans, in a maximum aggregate principal amount at any one time outstanding not to exceed $25,000,000, will be made to the Borrower from time to time prior to the Commitment Termination Date; and WHEREAS, the Lenders are willing, on the terms and subject to the conditions hereinafter set forth (including Article V), to extend such Commitments and make such Loans to the Borrower; and WHEREAS, the Loans will be secured as part of the Secured Obligations by the Collateral as provided in the Collateral Agreements; and WHEREAS, the proceeds of such Loans will be used for general corporate purposes and working capital purposes of the Borrower; NOW, THEREFORE, the parties hereto agree as follows: DEFINITIONS AND ACCOUNTING TERMS .1. Defined Terms. The following terms (whether or not underscored) when used in this Agreement, including its preamble and recitals, shall, except where the context otherwise requires, have the following meanings (such meanings to be equally applicable to the singular and plural forms thereof): "Additional Notes" means the notes issued from time to time under Section 12.2, and as provided in Section 2, of the Trust Indenture, including the Notes issued under this Agreement and designated the Series B Notes. "Affiliate" of any Person means any other Person which, directly or indirectly, controls, is controlled by or is under common control with such Person (excluding any trustee under, or any committee with responsibility for administering, any Plan). A Person shall be deemed to be "controlled by" any other Person if such other Person possesses, directly or indirectly, power (a) to vote 10% or more of the securities (on a fully diluted basis) having ordinary voting power for the election of directors or managing general partners; or (b) to direct or cause the direction of the management and policies of such Person whether by contract or otherwise. "Agent" is defined in the preamble and includes each other Person as shall have subsequently been appointed as the successor Agent pursuant to Section 9.4. "Agreement" means, on any date, this Credit Agreement as originally in effect on the Effective Date and as thereafter from time to time amended, supplemented, amended and restated, or otherwise modified and in effect on such date. "Alternate Base Rate" means, on any date and with respect to all Base Rate Loans, a fluctuating rate of interest per annum equal to the higher of (a) the rate of interest most recently announced by the Agent at its Domestic Office as its prime commercial lending rate; and (b) the Federal Funds Rate most recently determined by the Agent plus 1/2 of 1%. The Alternate Base Rate is not necessarily intended to be the lowest rate of interest determined by the Agent in connection with extensions of credit. Changes in the rate of interest on that portion of any Loans maintained as Base Rate Loans will take effect simultaneously with each change in the Alternate Base Rate. The Agent will give notice promptly to the Borrower and the Lenders of changes in the Alternate Base Rate. "Applicable Margin" means the number of basis points set forth in the following chart depending upon the Status and the type of Loan or the commitment fee: Commitment LIBO CD Base Status Fee Rate Loan Rate Loans Rate Loans Level I Status 20.00 50.00 62.50 -- Level II Status 30.00 62.50 75.00 -- Level III Status 32.50 80.00 90.00 -- Level IV Status 37.50 100.00 112.00 100.00 "Assessment Rate" is defined in Section 3.2.1. "Assigned Agreement" means a Nuclear Fuel Contract which has been assigned to Lessor in the manner specified in Section 4 of the Fuel Lease pursuant to a duly executed and delivered Assignment Agreement. The term "Assigned Agreement" shall include a Partially Assigned Agreement. "Assignee Lender" is defined in Section 10.11.1. "Assignment Agreement" means an assignment agreement substantially in the form of Schedule F-1 or F-2 to the Fuel Lease. "Atomic Energy Act" means the Atomic Energy Act of 1954, as from time to time amended. "Authorized Officer" means, relative to any Obligor, those of its officers whose signatures and incumbency shall have been certified to the Agent and the Lenders pursuant to Section 5.1.1. "Base Rate Loan" means a Loan bearing interest at a fluctuating rate determined by reference to the Alternate Base Rate. "Basic Documents" includes the Fuel Lease, the Note Purchase Agreements, Trust Indenture, Series A Notes, Series B Notes, the Louisiana Collateral Documents, the Assigned Agreements, the Assignment Agreements, the Trust Agreement, each Bill of Sale, and other agreements related or incidental thereto identified therein as one of the "Basic Documents" and approved by Lessee and the Required Lenders. The Basic Documents shall also include all Additional Notes, if any, issued under and in accordance with the Trust Indenture and Note Purchase Agreements or revolving or other credit agreements relating to the issuance and purchase of Additional Notes. "Bill of Sale" means a bill of sale substantially in the form of either Schedule C or E to the Fuel Lease, pursuant to which title to all or any portion of the Nuclear Fuel is transferred to Lessor or to Lessee. "Borrower" is defined in the preamble. "Borrowing" means the Loans of the same type and, in the case of Fixed Rate Loans, having the same Interest Period made by all Lenders on the same Business Day and pursuant to the same Borrowing Request in accordance with Section 2.1. "Borrowing Request" means a loan request and certificate duly executed by an Authorized Officer of the Borrower, substantially in the form of Exhibit B hereto. "Business Day" means (a) any day which is neither a Saturday or Sunday nor a legal holiday on which banks are authorized or required to be closed in New York; and (b) relative to the making, continuing, prepaying or repaying of any LIBO Rate Loans, any day on which dealings in Dollars are carried on in the London interbank market. "Capital Expenditures" means, for any period, the sum of (a) the aggregate amount of all expenditures of the Borrower and its Subsidiaries for fixed or capital assets made during such period which, in accordance with GAAP, would be classified as capital expenditures; and (b) the aggregate amount of all Capitalized Lease Liabilities incurred during such period. "Capitalized Lease Liabilities" means all monetary obligations of the Borrower or any of its Subsidiaries under any leasing or similar arrangement which, in accordance with GAAP, would be classified as capitalized leases, and, for purposes of this Agreement and each other Loan Document, the amount of such obligations shall be the capitalized amount thereof, determined in accordance with GAAP, and the stated maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be terminated by the lessee without payment of a penalty. "Cash Equivalent Investment" means, at any time: (a) any evidence of Indebtedness, maturing not more than one year after such time, issued or guaranteed by the United States Government; (b) commercial paper, maturing not more than nine months from the date of issue, which is issued by (i) a corporation (other than an Affiliate of any Obligor) organized under the laws of any state of the United States or of the District of Columbia and rated A-l by Standard & Poor's Corporation or P-l by Moody's Investors Service, Inc., or (ii) any Lender (or its holding company); (c) any certificate of deposit or bankers acceptance, maturing not more than one year after such time, which is issued by either (i) a commercial banking institution that is a member of the Federal Reserve System and has a combined capital and surplus and undivided profits of not less than $500,000,000, or (ii) any Lender; or (d) any repurchase agreement entered into with any Lender (or other commercial banking institution of the stature referred to in clause (c)(i)) which (i) is secured by a fully perfected security interest in any obligation of the type described in any of clauses (a) through (c); and (ii) has a market value at the time such repurchase agreement is entered into of not less than 100% of the repurchase obligation of such Lender (or other commercial banking institution) thereunder. "CD Rate" is defined in Section 3.2.1. "CD Rate Loan" means a Loan bearing interest, at all times during an Interest Period applicable to such Loan, at a fixed rate determined by reference to the CD Rate (Reserve Adjusted). "CD Rate (Reserve Adjusted)" is defined in Section 3.2.1. "CD Reserve Requirement" is defined in Section 3.2.1. "Change in Control" means the failure of the Owner Trustee to own, free and clear of all Liens or other encumbrances, 100% of the outstanding shares of voting stock of the Borrower on a fully diluted basis. "CIBC" is defined in the preamble. "Code" means the Internal Revenue Code of 1986, as amended, reformed or otherwise modified from time to time. "Collateral" has the meaning set forth in the granting clauses of the Trust Indenture and includes all property of the Borrower described in any Collateral Agreement as comprising a part of the Collateral. "Collateral Agreements" means, collectively, the Trust Indenture, all Assignment Agreements, the Louisiana Collateral Documents and any other assignment, security agreement or instrument executed and delivered to the Indenture Trustee hereafter relating to property of the Borrower which is security for the Secured Obligations. "Commitment" means, relative to any Lender, such Lender's obligation to make Loans pursuant to Section 2.1.1. "Commitment Amount" means, on any date, $25,000,000, as such amount may be reduced from time to time pursuant to Section 2.2. "Commitment Termination Date" means the earliest of (a) the Stated Maturity Date; (b) the date on which the Commitment Amount is terminated in full or reduced to zero pursuant to Section 2.2; and (c) the date on which any Commitment Termination Event occurs. Upon the occurrence of any event described in clause (b) or (c), the Commitments shall terminate automatically and without further action. "Commitment Termination Event" means (a) the occurrence of any Default described in clauses (a) through (d) of Section 8.1.9; or (b) the occurrence and continuance of any other Event of Default and either (i) the declaration of the Loans to be due and payable pursuant to Section 8.3, or (ii) in the absence of such declaration, the giving of notice by the Agent, acting at the direction of the Required Lenders, to the Borrower that the Commitments have been terminated. "Contingent Liability" means any agreement, undertaking or arrangement by which any Person guarantees, endorses or otherwise becomes or is contingently liable upon (by direct or indirect agreement, contingent or otherwise, to provide funds for payment, to supply funds to, or otherwise to invest in, a debtor, or otherwise to assure a creditor against loss) the indebtedness, obligation or any other liability of any other Person (other than by endorsements of instruments in the course of collection), or guarantees the payment of dividends or other distributions upon the shares of any other Person. The amount of any Person's obligation under any Contingent Liability shall (subject to any limitation set forth therein) be deemed to be the outstanding principal amount (or maximum principal amount, if larger) of the debt, obligation or other liability guaranteed thereby. "Continuation/Conversion Notice" means a notice of continuation or conversion and certificate duly executed by an Authorized Officer of the Borrower, substantially in the form of Exhibit C hereto. "Controlled Group" means all members of a controlled group of corporations and all members of a controlled group of trades or businesses (whether or not incorporated) under common control which, together with the Borrower, are treated as a single employer under Section 414(b) or 414(c) of the Code or Section 4001 of ERISA. "Debt Rating" means a rating of GSU's first mortgage bonds issued under the Indenture of Mortgage between GSU and The Chase National Bank of the City of New York, as Trustee, trustee predecessor to Central Hanover Bank and Trust Company and Manufacturers Hanover Trust Company (now Chemical Bank), dated as of September 1, 1926, as amended and supplemented by the various indentures supplemental thereto, and as further amended and supplemented from time to time. "Default" means any Event of Default or any condition, occurrence or event which, after notice or lapse of time or both, would constitute an Event of Default. "Disclosure Documents" means the following documents: (a) the annual report of GSU on Form 10-K for the fiscal year ended 1992; (b) GSU's quarterly reports on Form 10-Q for the quarters ended March 31, June 30, and September 30, 1993; (c) the periodic reports of GSU on Form 8-K dated March 22, 1993, April 27, 1993, June 21, 1993, July 22, 1993, August 16, 1993, August 23, 1993, September 21, 1993, October 19, 1993 and December 1, 1993, and any other periodic reports of GSU filed with the Securities and Exchange Commission which have been delivered to the Lenders before the Effective Date; and (d) the Proxy Statement for the 1993 Annual Meeting of Shareholders of GSU; "Disclosure Schedule" means the Disclosure Schedule attached hereto as Schedule I, as it may be amended, supplemented or otherwise modified from time to time by the Borrower with the written consent of the Agent and the Required Lenders. "Dollar" and the sign "$" mean lawful money of the United States. "Domestic Office" means, relative to any Lender, the office of such Lender designated as such on Schedule II hereto or designated in the Lender Assignment Agreement or such other office of a Lender (or any successor or assign of such Lender) within the United States as may be designated from time to time by notice from such Lender, as the case may be, to each other Person party hereto. A Lender may have separate Domestic Offices for purposes of making, maintaining or continuing, as the case may be, Base Rate Loans and CD Rate Loans. "Effective Date" means the date this Agreement becomes effective pursuant to Section 10.8. "Environmental Laws" means all applicable federal, state or local statutes, laws, ordinances, codes, rules, regulations and guidelines (including consent decrees and administrative orders) relating to public health and safety and protection of the environment. "ERISA" means the Employee Retirement Income Security Act of 1974, as amended, and any successor statute of similar import, together with the regulations thereunder, in each case as in effect from time to time. References to sections of ERISA also refer to any successor sections. "Event of Default" is defined in Section 8.1. "Excepted Payments" means any indemnity, expense, or other payment which by the terms of any of the Basic Documents shall be payable to the Trustor for its own account or to the Owner Trustee for its own account. "Federal Funds Rate" means, for any period, a fluctuating interest rate per annum equal for each day during such period to (a) the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System arranged by federal funds brokers, as published for such day (or, if such day is not a Business Day, for the next preceding Business Day) by the Federal Reserve Bank of New York; or (b) if such rate is not so published for any day which is a Business Day, the average of the quotations for such day on such transactions received by the Agent from three federal funds brokers of recognized standing selected by it. "Fee Letter" means that certain letter, dated the date hereof between the Borrower and CIBC relating to certain fees to be paid by the Borrower. "Fiscal Quarter" means any quarter of a Fiscal Year. "Fiscal Year" means any period of twelve consecutive calendar months ending on December 31; references to a Fiscal Year with a number corresponding to any calendar year (e.g. the "1993 Fiscal Year") refer to the Fiscal Year ending on December 31 occurring during such calendar year. "Fixed Rate Loan" means any CD Rate Loan or any LIBO Rate Loan. "F.R.S. Board" means the Board of Governors of the Federal Reserve System or any successor thereto. "Fuel Lease" means the Fuel Lease dated as of February 7, 1989 between Lessor and Lessee, as the same may from time to time be amended, modified or supplemented. "Fuel Schedule" means an instrument substantially in the form of schedule D to the Fuel Lease including, unless otherwise indicated, all annexes thereto. "GAAP" is defined in Section 1.4. "GSU" means Gulf States Utilities Company, a Texas corporation. "Hedging Obligations" means, with respect to any Person, all liabilities of such Person under interest rate swap agreements, interest rate cap agreements and interest rate collar agreements, and all other agreements or arrangements designed to protect such Person against fluctuations in interest rates or currency exchange rates. "herein", "hereof", "hereto", "hereunder" and similar terms contained in this Agreement or any other Loan Document refer to this Agreement or such other Loan Document, as the case may be, as a whole and not to any particular Section, paragraph or provision of this Agreement or such other Loan Document. "Highest Lawful Rate" is defined in Section 10.15(b). "including" means including without limiting the generality of any description preceding such term, and, for purposes of this Agreement and each other Loan Document, the parties hereto agree that the rule of ejusdem generis shall not be applicable to limit a general statement, which is followed by or referable to an enumeration of specific matters, to matters similar to the matters specifically mentioned. "Indebtedness" of any Person means, without duplication: (a) all obligations of such Person for borrowed money and all obligations of such Person evidenced by bonds, debentures, notes or other similar instruments; (b) all obligations, contingent or otherwise, relative to the face amount of all letters of credit, whether or not drawn, and banker's acceptances issued for the account of such Person; (c) all obligations of such Person as lessee under leases which have been or should be, in accordance with GAAP, recorded as Capitalized Lease Liabilities; (d) all other items which, in accordance with GAAP, would be included as liabilities on the liability side of the balance sheet of such Person as of the date at which Indebtedness is to be determined; (e) net liabilities of such Person under all Hedging Obligations; (f) whether or not so included as liabilities in accordance with GAAP, all obligations of such Person to pay the deferred purchase price of property or services, and indebtedness (excluding prepaid interest thereon) secured by a Lien on property owned or being purchased by such Person (including indebtedness arising under conditional sales or other title retention agreements), whether or not such indebtedness shall have been assumed by such Person or is limited in recourse; and (g) all Contingent Liabilities of such Person in respect of any of the foregoing. For all purposes of this Agreement, the Indebtedness of any Person shall include the Indebtedness of any partnership or joint venture in which such Person is a general partner or a joint venturer. "Indemnified Liabilities" is defined in Section 10.4. "Indemnified Parties" is defined in Section 10.4. "Indenture Trustee" means the institution designated as such in the Indenture and its permitted successors. "Interest Period" means, relative to any Fixed Rate Loans, the period beginning on (and including) the date on which such Fixed Rate Loan is made or continued as, or converted into, a Fixed Rate Loan pursuant to Section 2.3 or 2.4 and shall end on (but exclude) the day which is, in the case of a CD Rate Loan, 30, 60 or 90 days thereafter, or which, in the case of a LIBO Rate Loan, numerically corresponds to such date one, two or three months thereafter (or, if such month has no numerically corresponding day, on the last Business Day of such month), in either case as the Borrower may select in its relevant notice pursuant to Section 2.3 or 2.4; provided, however, that (a) the Borrower shall not be permitted to select Interest Periods to be in effect at any one time which have expiration dates occurring on more than five different dates; (b) Interest Periods commencing on the same date for Loans comprising part of the same Borrowing shall be of the same duration; (c) if such Interest Period would otherwise end on a day which is not a Business Day, such Interest Period shall end on the next following Business Day (unless, if such Interest Period applies to LIBO Rate Loans, such next following Business Day is the first Business Day of a calendar month, in which case such Interest Period shall end on the Business Day next preceding such numerically corresponding day); and (d) no Interest Period may end later than the Stated Maturity Date. "Investment" means, relative to any Person, (a) any loan or advance made by such Person to any other Person (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business); (b) any Contingent Liability of such Person; and (c) any ownership or similar interest held by such Person in any other Person. The amount of any Investment shall be the original principal or capital amount thereof less all returns of principal or equity thereon (and without adjustment by reason of the financial condition of such other Person) and shall, if made by the transfer or exchange of property other than cash, be deemed to have been made in an original principal or capital amount equal to the fair market value of such property. "Lease Event of Default" has the meaning specified therefor in Section 19 of the Fuel Lease. "Lender Assignment Agreement" means a Lender Assignment Agreement substantially in the form of Exhibit D hereto. "Lenders" is defined in the preamble. "Lessee" has the meaning specified therefor in the introduction to the Fuel Lease. "Lessor" has the meaning specified therefor in the introduction to the Fuel Lease. "Level I Status" exists at any date if, at such date, GSU has a Debt Rating of higher than BBB+ by S&P and a Debt Rating of higher than Baa1 by Moody's. "Level II Status" exists at any date if, at such date, (i) Level I Status does not exist and (ii) GSU has a Debt Rating of higher than BBB- by S&P and a Debt Rating of higher than Baa3 by Moody's. "Level III Status" exists at any date if, at such date, (i) neither Level I Status nor Level II Status exists and (ii) GSU has a Debt Rating of BBB- by S&P and a Debt Rating of Baa3 by Moody's. "Level IV Status" exists at any date if, at such date, none of Level I Status, Level II Status or Level III Status exists. "LIBO Rate" is defined in Section 3.2.1. "LIBO Rate Loan" means a Loan bearing interest, at all times during an Interest Period applicable to such Loan, at a fixed rate of interest determined by reference to the LIBO Rate (Reserve Adjusted). "LIBO Rate (Reserve Adjusted)" is defined in Section 3.2.1. "LIBOR Office" means, relative to any Lender, the office of such Lender designated as such on Schedule II hereto or designated in the Lender Assignment Agreement or such other office of a Lender as designated from time to time by notice from such Lender to the Borrower and the Agent, whether or not outside the United States, which shall be making or maintaining LIBO Rate Loans of such Lender hereunder. "LIBOR Reserve Percentage" is defined in Section 3.2.1. "Lien" means any security interest, mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory or otherwise), charge against or interest in property to secure payment of a debt or performance of an obligation or other priority or preferential arrangement of any kind or nature whatsoever or any "Lien" as defined in the Trust Indenture. "Loan" is defined in Section 2.1.1. "Loan Document" means this Agreement, the Notes and the documents, executed by GSU, substantially in the form of Exhibit J and Exhibit K hereto. "Louisiana Collateral Documents" means collectively the Collateral Chattel Mortgage, dated February 6, 1989, delivered by the Borrower and Lessee, the Collateral Chattel Mortgage Note dated February 6, 1989 delivered by the Borrower and Lessee, the Notice of Security Interest (Chattel Mortgage Records) dated February 6, 1989 delivered by the Borrower and Lessee, and the Pledge and Pawn of Collateral Chattel Mortgage Note dated February 6, 1989, delivered by the Borrower and Lessee to the Indenture Trustee, and the Louisiana Security Agreement, dated July 30, 1990, among the Borrower, the Lessee and the Indenture Trustee, and any periodic supplements thereto, as the same may from time to time be amended, modified or supplemented. "Manufacturer" means any supplier of Nuclear Fuel (including but not limited to Delta Fuel Services Corporation and the Lessee) or of any service (including without limitation, enrichment, fabrication, financing, transportation, storage, and processing) in connection therewith, or any agent or licensee of any such supplier. "Moody's" means Moody's Investors Service, Inc. "Note" means a promissory note of the Borrower payable to any Lender, in the form of Exhibit A hereto (as such promissory note may be amended, endorsed or otherwise modified from time to time), evidencing the aggregate Indebtedness of the Borrower to such Lender resulting from outstanding Loans, and also means all other promissory notes accepted from time to time in substitution therefor or renewal thereof, in each case as duly authenticated by the Indenture Trustee. "Note Purchase Agreements" means (i) the several but identical (except for the name of the purchaser) Note Agreements, each dated as of February 7, 1989, relating to the issue and sale by the Borrower of the Series A Notes, as from time to time in effect, and (ii) any similar agreements hereafter entered into by the Borrower relating to the issue and sale of its Notes pursuant to the Trust Indenture. "Note Purchase Agreement Obligations" means the principal of, premium, if any, and interest on the Series A Notes and the Additional Notes and all others costs, fees and expenses and amounts required to be paid by the Borrower on or with respect to the Series A Notes and the Additional Notes or under the Note Purchase Agreements. "Nuclear Fuel" means those items which have been purchased by or on behalf of Lessor for which a duly executed Fuel Schedule has been delivered to Lessor and which continue to be subject to the Fuel Lease consisting of (i) the items described in such Fuel Schedules and each of the components thereof in the respective forms in which such items exist during each stage of the Nuclear Fuel Cycle, being substances and materials which, when fabricated and assembled and loaded into a nuclear reactor, are intended to produce heat through the fission process, together with all replacements thereof and additions thereto and (ii) the substances and materials underlying the right, title and interest of Lessee under any Nuclear Fuel Contract assigned to Lessor pursuant to the Fuel Lease. "Nuclear Fuel Contract" means any contract, as from time to time amended, modified or supplemented, entered into by Lessee with one or more Manufacturers relating to the acquisition of Nuclear Fuel or any service in connection with the Nuclear Fuel and assigned to Lessor pursuant to the Fuel Lease as an Assigned Agreement. "Nuclear Fuel Cycle" means the various stages in the process, whether physical or chemical, by which the component parts of the Nuclear Fuel are designed, mined, milled, processed, converted, enriched, fabricated into assemblies utilizable for heat production, loaded or installed into a reactor core, utilized, disengaged, stored and disposed, together with all incidental processes with respect to the Nuclear Fuel at any such stage. "Obligations" means all obligations (monetary or otherwise) of the Borrower and each other Obligor arising under or in connection with this Agreement, the Notes and each other Loan Document. "Obligor" means the Borrower or any other Person (other than the Agent or any Lender) obligated under any Loan Document. "Organic Document" means, relative to any Obligor, its certificate of incorporation, its by-laws and all shareholder agreements, voting trusts and similar arrangements applicable to any of its authorized shares of capital stock. "Outstanding Note Indebtedness" means, at any particular time, the aggregate principal balance remaining unpaid on the Series A Notes and the Additional Notes then issued and outstanding. "Owner Trust" means the River Bend Fuel Services Trust, a New York Trust created by the Trust Agreement. "Owner Trust Beneficiary" means Gulf States Utilities Company. "Owner Trust Estate" means all estate, right, title and interest of the Owner Trustee in and to the outstanding stock of the Borrower and in and to all monies, securities, investments, instruments, documents, rights, claims, contracts, and other property held by the Owner Trustee under the Trust Agreement; provided, however, that there shall be excluded from the Owner Trust Estate all Excepted Payments. "Owner Trustee" means Chemical Bank (formerly Manufacturers Hanover Trust Company), acting as trustee under and pursuant to the Trust Agreement, and its permitted successors. "Partially Assigned Agreement" means a Nuclear Fuel Contract which has been assigned, in part but not in full, to Lessor in the manner specified in Section 4 of the Fuel Lease, pursuant to a duly executed and delivered Assignment Agreement. "Participant" is defined in Section 10.11.2. "Pension Plan" means a "pension plan", as such term is defined in section 3(2) of ERISA, which is subject to Title IV of ERISA (other than a multiemployer plan as defined in section 4001(a)(3) of ERISA), and to which the Borrower or any corporation, trade or business that is, along with the Borrower, a member of a Controlled Group, may have liability, including any liability by reason of having been a substantial employer within the meaning of section 4063 of ERISA at any time during the preceding five years, or by reason of being deemed to be a contributing sponsor under section 4069 of ERISA. "Percentage" means, relative to any Lender, the percentage set forth opposite its signature hereto or set forth in the Lender Assignment Agreement, as such percentage may be adjusted from time to time pursuant to Lender Assignment Agreement(s) executed by such Lender and its Assignee Lender(s) and delivered pursuant to Section 10.11. "Person" means any natural person, corporation, partnership, firm, association, trust, government, governmental agency or any other entity, whether acting in an individual, fiduciary or other capacity. "Plan" means any Pension Plan or Welfare Plan. "Quarterly Payment Date" means the last day of each March, June, September, and December or, if any such day is not a Business Day, the next succeeding Business Day. "Required Lenders" means, at any time, Lenders holding at least 66 2/3% of the then aggregate outstanding principal amount of the Notes then held by the Lenders, or, if no such principal amount is then outstanding, Lenders having at least 66 2/3% of the Commitments. "Secured Obligations" means: (a) all indemnifications, costs, expenses, fees and other compensation of the Indenture Trustee provided for, and all other amounts owed to the Indenture Trustee, under this Trust Indenture, and (b) all Note Purchase Agreement Obligations. "Secured Parties" means the holders from time to time of the Note Purchase Agreement Obligations. "Series A Notes" means the Notes issued pursuant to and referred to in Section 2.1 and Section 12.1 of the Trust Indenture. "Series B Notes" means the Notes. "S&P" means Standard & Poor's Corporation. "Stated Maturity Date" means December 27, 1996, as such date may be extended pursuant to Section 2.7. "Status" means Level I Status, Level II Status, Level III Status or Level IV Status. "Subsidiary" means any Person of which the Borrower (a) directly or indirectly owns at the time at least the greater of (i) a majority of the outstanding stock or shares of beneficial interest having by the terms thereof ordinary voting power to elect a majority of the directors (or other persons performing similar functions) of such Person, irrespective of whether or not at the time shares of any other class or classes of such Person shall have or might have voting power by reason of the happening of any contingency, or (ii) such lesser proportion of such outstanding stock or shares or beneficial interest as may from time to time constitute a controlling interest in accordance with GAAP, or (b) is a general partner. "Taxes" is defined in Section 4.6. "Terminating Event" shall have the meaning specified therefor in Section 17(a) of the Fuel Lease. "Trust Agreement" means the Trust Agreement dated as of February 7, 1989 between United States Trust Company of New York as Trustor and Chemical Bank (formerly Manufacturers Hanover Trust Company) as the Owner Trustee thereunder, as the same may be amended, modified or supplemented from time to time. "Trust Indenture" or "Indenture" means the Trust Indenture dated as of February 7, 1989 between the Borrower and the Indenture Trustee, as the same may from time to time be amended, modified or supplemented. "Trustor" means the institution designated as such in the Trust Agreement and its permitted successors. "type" means, relative to any Loan, the portion thereof, if any, being maintained as a Base Rate Loan, a CD Rate Loan or a LIBO Rate Loan. "United States" or "U.S." means the United States of America, its fifty States and the District of Columbia. "Welfare Plan" means a "welfare plan", as such term is defined in section 3(1) of ERISA. .2. Use of Defined Terms. Unless otherwise defined or the context otherwise requires, terms for which meanings are provided in this Agreement shall have such meanings when used in the Disclosure Schedule and in each Note, Borrowing Request, Continuation/Conversion Notice, Loan Document, notice and other communication delivered from time to time in connection with this Agreement or any other Loan Document. .3. Cross-References. Unless otherwise specified, references in this Agreement and in each other Loan Document to any Article or Section are references to such Article or Section of this Agreement or such other Loan Document, as the case may be, and, unless otherwise specified, references in any Article, Section or definition to any clause are references to such clause of such Article, Section or definition. .4. Accounting and Financial Determinations. Unless otherwise specified, all accounting terms used herein or in any other Loan Document shall be interpreted, all accounting determinations and computations hereunder or thereunder (including under Section 7.2.4) shall be made, and all financial statements required to be delivered hereunder or thereunder shall be prepared in accordance with, those generally accepted accounting principles ("GAAP") applied in the preparation of the financial statements referred to in Section 6.5. COMMITMENTS, BORROWING PROCEDURES AND NOTES .5. Commitments. On the terms and subject to the conditions of this Agreement (including Article V), each Lender severally agrees to make Loans pursuant to the Commitments described in this Section 2.1. 1. Commitment of Each Lender. From time to time on any Business Day occurring prior to the Commitment Termination Date, each Lender will make loans (relative to such Lender, and of any type, its "Loans") to the Borrower equal to such Lender's Percentage of the aggregate amount of the Borrowing requested by the Borrower to be made on such day. The commitment of each Lender described in this Section 2.1.1 is herein referred to as its "Commitment". On the terms and subject to the conditions hereof, the Borrower may from time to time borrow, prepay and reborrow Loans. 2. Lenders Not Permitted or Required To Make Loans. No Lender shall be permitted or required to make any Loan if, after giving effect thereto, the aggregate outstanding principal amount of all Loans (a) of all Lenders would exceed the Commitment Amount, or (b) of such Lender would exceed such Lender's Percentage of the Commitment Amount. .6. Optional Reduction of Commitment Amount. The Borrower may, from time to time on any Business Day, voluntarily reduce the Commitment Amount; provided, however, that all such reductions shall require at least three Business Days' prior notice to the Agent and be permanent, and any partial reduction of the Commitment Amount shall be in a minimum amount of $250,000 and in an integral multiple of $50,000. .7. Borrowing Procedure. By delivering a Borrowing Request to the Agent on or before 10:00 a.m., New York City time, on a Business Day, the Borrower may from time to time irrevocably request, on not less than three nor more than five Business Days' notice, that a Borrowing be made in a minimum amount of $250,000 and an integral multiple of $50,000, or in the unused amount of the Commitments. The Agent shall promptly notify the Lenders of the terms of such Borrowing Request. On the terms and subject to the conditions of this Agreement, each Borrowing shall be comprised of the type of Loans, and shall be made on the Business Day, specified in such Borrowing Request. On or before 12:00 noon (New York City time) on such Business Day each Lender shall deposit with the Agent same day or immediately available funds in an amount equal to such Lender's Percentage of the requested Borrowing. Such deposit will be made to an account which the Agent shall specify from time to time by notice to the Lenders. To the extent funds are received from the Lenders, the Agent shall make such funds available to the Borrower by wire transfer to the account the Borrower shall have specified in its Borrowing Request with the Indenture Trustee pursuant to the terms of the Trust Agreement. No Lender's obligation to make any Loan shall be affected by any other Lender's failure to make any Loan. .8. Continuation and Conversion Elections. By delivering a Continuation/Conversion Notice to the Agent on or before 10:00 a.m., New York City time, on a Business Day, the Borrower may from time to time irrevocably elect, on not less than three (or same day, in the case of Base Rate Loans) nor more than five Business Days' notice that all, or any portion in an aggregate minimum amount of $250,000 and an integral multiple of $50,000, of any Loans be, in the case of Base Rate Loans, converted into Fixed Rate Loans of either type or, in the case of Fixed Rate Loans of either type, be converted into a Base Rate Loan or a Fixed Rate Loan of the other type or continued as a Fixed Rate Loan of such type (in the absence of delivery of a Continuation/ Conversion Notice with respect to any Fixed Rate Loan at least three Business Days before the last day of the then current Interest Period with respect thereto, such Fixed Rate Loan shall, on such last day, automatically convert to a Base Rate Loan); provided, however, that (i) each such conversion or continuation shall be pro rated among the applicable outstanding Loans of all Lenders, and (ii) no portion of the outstanding principal amount of any Loans may be continued as, or be converted into, Fixed Rate Loans when any Default has occurred and is continuing. .9. Funding. Each Lender may, if it so elects, fulfill its obligation to make, continue or convert Fixed Rate Loans hereunder by causing one of its foreign branches or Affiliates (or an international banking facility created by such Lender) to make or maintain such Fixed Rate Loan; provided, however, that such Fixed Rate Loan shall nonetheless be deemed to have been made and to be held by such Lender, and the obligation of the Borrower to repay such Fixed Rate Loan shall nevertheless be to such Lender for the account of such foreign branch, Affiliate or international banking facility. In addition, the Borrower hereby consents and agrees that, for purposes of any determination to be made for purposes of Sections 4.1, 4.2, 4.3 or 4.4, it shall be conclusively assumed that each Lender elected to fund all Fixed Rate Loans by purchasing, as the case may be, Dollar certificates of deposit in the U.S. or Dollar deposits in its LIBOR Office's interbank eurodollar market. .10. Notes. Each Lender's Loans under its Commitment shall be evidenced by a Note payable to the order of such Lender in a maximum principal amount equal to such Lender's Percentage of the original Commitment Amount. The Borrower hereby irrevocably authorizes each Lender to make (or cause to be made) appropriate notations on the grid attached to such Lender's Note (or on any continuation of such grid), which notations, if made, shall evidence, inter alia, the date of, the outstanding principal of, and the interest rate and Interest Period applicable to the Loans evidenced thereby. The failure of any Lender to make any such notations shall not limit or otherwise affect any Obligations of the Borrower or any other Obligor or the effect of any repayment or prepayment made by the Borrower hereunder. .11. Termination; Extension of Stated Maturity Date. The Commitments shall terminate and each Lender shall be relieved of its obligations to make any Loan on the Commitment Termination Date. On or before October 15 of each year commencing on October 15, 1994 and prior to the termination of the Commitments, the Borrower may, at its option, deliver to the Agent (which shall promptly notify each Lender) a written request signed by the Borrower for an extension of the Stated Maturity Date for a period of one year. On or before December 15 of each year that the Borrower has delivered an extension request to the Agent, each Lender shall have the right, in its sole and absolute discretion, to consent to or reject such extension. If a Lender has not replied in writing to the Agent by December 15 of such year, such Lender shall be deemed not to have consented to the extension. If all of the Lenders consent to the extension in accordance with the terms of this Section, the Stated Maturity Date shall be extended for the year requested and the maturity date of each of the Notes of the Lenders shall be automatically extended for such one year period without any further action by the Borrower, the Agent or the Lenders. REPAYMENTS, PREPAYMENTS, INTEREST AND FEES .12. Repayments and Prepayments. The Borrower shall repay in full the unpaid principal amount of each Loan upon the Stated Maturity Date therefor. Prior thereto, the Borrower (a) may, from time to time on any Business Day, make a voluntary prepayment, in whole or in part, of the outstanding principal amount of any Loans; provided, however, that (i) any such prepayment shall be made pro rata among Loans of the same type and, if applicable, having the same Interest Period of all Lenders; (ii) no such prepayment of any Fixed Rate Loan may be made on any day other than the last day of the Interest Period for such Loan; (iii) all such voluntary prepayments shall require at least three but no more than five Business Days' prior written notice to the Agent; and (iv) all such voluntary partial prepayments shall be in an aggregate minimum amount of $250,000 and an integral multiple of $50,000; (b) shall, on each date when any reduction in the Commitment Amount shall become effective, including pursuant to Section 2.2, make a mandatory prepayment of all Loans equal to the excess, if any, of the aggregate outstanding principal amount of all Loans over the Commitment Amount as so reduced; and (c) shall, immediately upon any acceleration of the Stated Maturity Date of any Loans pursuant to Section 8.2 or Section 8.3, repay all Loans, unless, pursuant to Section 8.3, only a portion of all Loans is so accelerated. Each prepayment of any Loans made pursuant to this Section shall be without premium or penalty, except as may be required by Section 4.4. No voluntary prepayment of principal of any Loans shall cause a reduction in the Commitment Amount. .13. Interest Provisions. Interest on the outstanding principal amount of Loans shall accrue and be payable in accordance with this Section 3.2. 1. Rates. Pursuant to an appropriately delivered Borrowing Request or Continuation/Conversion Notice, the Borrower may elect that Loans comprising a Borrowing accrue interest at a rate per annum: (a) on that portion maintained from time to time as a Base Rate Loan, equal to the sum of the Alternate Base Rate from time to time in effect plus the Applicable Margin; (b) on that portion maintained as a CD Rate Loan, during each Interest Period applicable thereto, equal to the sum of the CD Rate (Reserve Adjusted) for such Interest Period plus the Applicable Margin; and (c) on that portion maintained as a LIBO Rate Loan, during each Interest Period applicable thereto, equal to the sum of the LIBO Rate (Reserve Adjusted) for such Interest Period plus the Applicable Margin. The "CD Rate (Reserve Adjusted)" means, relative to any Loan to be made, continued or maintained as, or converted into, a CD Rate Loan for any Interest Period, a rate per annum (rounded upwards, if necessary, to the nearest 1/16 of 1%) determined pursuant to the following formula: CDR(RA) = CDR + AR (1.00 - CDRR) where: CDR(RA) = CD Rate (Reserve Adjusted) CDR = CD Rate CDRR = CD Reserve Requirement AR = Assessment Rate The CD Rate (Reserve Adjusted) for any Interest Period for CD Rate Loans will be determined by the Agent on the basis of the CD Reserve Requirement and Assessment Rate in effect on, and the applicable rates determined by the Agent, on the first day of such Interest Period. "CD Rate" means, relative to any Interest Period for CD Rate Loans, the rate of interest determined by the Agent to be the arithmetic average (rounded upwards, if necessary, to the nearest 1/16 of 1%) of the prevailing rates per annum bid at 10:00 a.m., New York City time (or as soon thereafter as practicable), on the first day of such Interest Period by two or more certificate of deposit dealers of recognized standing located in New York City for the purchase at face value from the Agent of its certificates of deposit in an amount approximately equal to the CD Rate Loan being made or maintained by the Agent to which such Interest Period applies and having a maturity approximately equal to such Interest Period. The "CD Reserve Requirement" means, relative to any Interest Period for CD Rate Loans, a percentage (expressed as a decimal) equal to the maximum aggregate reserve requirements (including all basic, supplemental, marginal and other reserves and taking into account any transitional adjustments or other scheduled changes in reserve requirements), specified under regulations issued from time to time by the F.R.S. Board and then applicable to the class of banks of which the Agent is a member, on deposits of the type used as a reference in determining the CD Rate and having a maturity approximately equal to such Interest Period. The "Assessment Rate" means, for any Interest Period for CD Rate Loans, the net annual assessment rate (rounded upwards, if necessary, to the next higher 1/100 of 1%) estimated by the Agent to be the then current annual assessment payable by the Agent to the Federal Deposit Insurance Corporation (or any successor) for insuring time deposits at offices of the Agent in the United States. The "LIBO Rate (Reserve Adjusted)" means, relative to any Loan to be made, continued or maintained as, or converted into, a LIBO Rate Loan for any Interest Period, a rate per annum (rounded upwards, if necessary, to the nearest 1/16 of 1%) determined pursuant to the following formula: LIBO Rate = LIBO Rate (Reserve Adjusted) 1.00 - LIBOR Reserve Percentage The LIBO Rate (Reserve Adjusted) for any Interest Period for LIBO Rate Loans will be determined by the Agent on the basis of the LIBOR Reserve Percentage in effect on, and the applicable rates determined by the Agent, two Business Days before the first day of such Interest Period. "LIBO Rate" means, relative to any Interest Period for LIBO Rate Loans, the rate of interest equal to the average (rounded upwards, if necessary, to the nearest 1/16 of 1%) of the rates per annum at which Dollar deposits in immediately available funds are offered to the Agent's LIBOR Office in the London interbank market as at or about 11:00 a.m. London time two Business Days prior to the beginning of such Interest Period for delivery on the first day of such Interest Period, and in an amount approximately equal to the amount of the Agent's LIBO Rate Loan and for a period approximately equal to such Interest Period. "LIBOR Reserve Percentage" means, relative to any Interest Period for LIBO Rate Loans, the reserve percentage (expressed as a decimal) equal to the maximum aggregate reserve requirements (including all basic, emergency, supplemental, marginal and other reserves and taking into account any transitional adjustments or other scheduled changes in reserve requirements) specified under regulations issued from time to time by the F.R.S. Board and then applicable to assets or liabilities consisting of and including "Eurocurrency Liabilities", as currently defined in Regulation D of the F.R.S. Board, having a term approximately equal or comparable to such Interest Period. All Fixed Rate Loans shall bear interest from and including the first day of the applicable Interest Period to (but not including) the last day of such Interest Period at the interest rate determined as applicable to such Fixed Rate Loan. 2. Post-Maturity Rates. After the date any principal amount of any Loan is due and payable (whether on the Stated Maturity Date, upon acceleration or otherwise), or after any other monetary Obligation of the Borrower shall have become due and payable, the Borrower shall pay, but only to the extent permitted by law, interest (after as well as before judgment) on such amounts at a rate per annum equal to the Alternate Base Rate plus a margin of 2.0%. 3. Payment Dates. Interest accrued on each Loan shall be payable, without duplication: (a) on the Stated Maturity Date therefor; (b) on the date of any payment or prepayment, in whole or in part, of principal outstanding on such Loan; (c) with respect to Base Rate Loans, on each Quarterly Payment Date occurring after the date of the initial Borrowing hereunder; (d) with respect to Fixed Rate Loans, the last day of each applicable Interest Period (and, if such Interest Period shall exceed 90 days, on the 90th day of such Interest Period); (e) with respect to any Base Rate Loans converted into Fixed Rate Loans on a day when interest would not otherwise have been payable pursuant to clause (c), on the date of such conversion; and (f) on that portion of any Loans the Stated Maturity Date of which is accelerated pursuant to Section 8.2 or Section 8.3, immediately upon such acceleration. Interest accrued on Loans or other monetary Obligations arising under this Agreement or any other Loan Document after the date such amount is due and payable (whether on the Stated Maturity Date, upon acceleration or otherwise) shall be payable upon demand. .14. Fees. The Borrower agrees to pay the fees set forth in this Section 3.3. All such fees shall be non-refundable. 1. Commitment Fee. The Borrower agrees to pay to the Agent for the account of each Lender, for the period (including any portion thereof when its Commitment is suspended by reason of the Borrower's inability to satisfy any condition of Article V) commencing on the Effective Date and continuing through the final Commitment Termination Date, a commitment fee at the rate of the Applicable Margin per annum on such Lender's Percentage of the sum of the average daily unused portion of the Commitment Amount. Such commitment fees shall be payable by the Borrower in arrears on each Quarterly Payment Date, commencing with the first such day following the Effective Date, and on the Commitment Termination Date. 2. Facility Fee. The Borrower agrees to pay to the Agent for the account of each Lender, a facility fee in an amount as set forth in the Fee Letter, payable on the Effective Date. 3. Agent's Fee. To the Agent for its own account, a non-refundable Agent's fee as set forth in the Fee Letter. CERTAIN CD RATE, LIBO RATE AND OTHER PROVISIONS .15. Fixed Rate Lending Unlawful. If any Lender shall determine (which determination shall, upon notice thereof to the Borrower and the Lenders, be conclusive and binding on the Borrower) that the introduction of or any change in or in the interpretation of any law makes it unlawful, or any central bank or other governmental authority asserts that it is unlawful, for such Lender to make, continue or maintain any Loan as, or to convert any Loan into, a Fixed Rate Loan of a certain type, the obligations of all Lenders to make, continue, maintain or convert any such Loans shall, upon such determination, forthwith be suspended until such Lender shall notify the Agent that the circumstances causing such suspension no longer exist, and all Fixed Rate Loans of such type shall automatically convert into Base Rate Loans at the end of the then current Interest Periods with respect thereto or sooner, if required by such law or assertion. .16. Deposits Unavailable. If the Agent shall have determined that (a) Dollar certificates of deposit or Dollar deposits, as the case may be, in the relevant amount and for the relevant Interest Period are not available to the Agent in its relevant market; or (b) by reason of circumstances affecting the Agent's relevant market, adequate means do not exist for ascertaining the interest rate applicable hereunder to Fixed Rate Loans of such type, then, upon notice from the Agent to the Borrower and the Lenders, the obligations of all Lenders under Section 2.3 and Section 2.4 to make or continue any Loans as, or to convert any Loans into, Fixed Rate Loans of such type shall forthwith be suspended until the Agent shall notify the Borrower and the Lenders that the circumstances causing such suspension no longer exist. .17. Increased Fixed Rate Loan Costs, etc. The Borrower agrees to reimburse each Lender for any increase in the cost to such Lender of, or any reduction in the amount of any sum receivable by such Lender in respect of, making, continuing or maintaining (or of its obligation to make, continue or maintain) any Loans as, or of converting (or of its obligation to convert) any Loans into, Fixed Rate Loans. Such Lender shall promptly notify the Agent and the Borrower in writing of the occurrence of any such event, such notice to state, in reasonable detail, the reasons therefor, the additional amount required fully to compensate such Lender for such increased cost or reduced amount and the basis on which such amount was determined. Such additional amounts shall be payable by the Borrower directly to such Lender within five days of its receipt of such notice, and such notice shall, in the absence of manifest error, be conclusive and binding on the Borrower. .18. Funding Losses. In the event any Lender shall incur any loss or expense (including any loss or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by such Lender to make, continue or maintain any portion of the principal amount of any Loan as, or to convert any portion of the principal amount of any Loan into, a Fixed Rate Loan) as a result of (a) any conversion or repayment or prepayment of the principal amount of any Fixed Rate Loans on a date other than the scheduled last day of the Interest Period applicable thereto, whether pursuant to Section 3.1 or otherwise; (b) any Loans not being made as Fixed Rate Loans in accordance with the Borrowing Request therefor; or (c) any Loans not being continued as, or converted into, Fixed Rate Loans in accordance with the Continuation/ Conversion Notice therefor, then, upon the written notice of such Lender to the Borrower (with a copy to the Agent), the Borrower shall, within five days of its receipt thereof, pay directly to such Lender such amount as will (in the reasonable determination of such Lender) reimburse such Lender for such loss or expense. Such written notice (which shall include calculations in reasonable detail) shall, in the absence of manifest error, be conclusive and binding on the Borrower. .19. Increased Capital Costs. If any change in, or the introduction, adoption, effectiveness, interpretation, reinterpretation or phase-in of, any law or regulation, directive, guideline, decision or request (whether or not having the force of law) of any court, central bank, regulator or other governmental authority affects or would affect the amount of capital required or expected to be maintained by any Lender or any Person controlling such Lender, and such Lender determines (in its sole and absolute discretion) that the rate of return on its or such controlling Person's capital as a consequence of its Commitment or the Loans made by such Lender is reduced to a level below that which such Lender or such controlling Person could have achieved but for the occurrence of any such circumstance, then, in any such case upon notice from time to time by such Lender to the Borrower, the Borrower shall immediately pay directly to such Lender additional amounts sufficient to compensate such Lender or such controlling Person for such reduction in rate of return. A statement of such Lender as to any such additional amount or amounts (including calculations thereof in reasonable detail) shall, in the absence of manifest error, be conclusive and binding on the Borrower. In determining such amount, such Lender may use any method of averaging and attribution that it (in its sole and absolute discretion) shall deem applicable. .20. Taxes. All payments by the Borrower of principal of, and interest on, the Loans and all other amounts payable hereunder shall be made free and clear of and without deduction for any present or future income, excise, stamp or franchise taxes and other taxes, fees, duties, withholdings or other charges of any nature whatsoever imposed by any taxing authority, but excluding franchise taxes and taxes imposed on or measured by any Lender's net income or receipts (such non-excluded items being called "Taxes"). In the event that any withholding or deduction from any payment to be made by the Borrower hereunder is required in respect of any Taxes pursuant to any applicable law, rule or regulation, then the Borrower will (a) pay directly to the relevant authority the full amount required to be so withheld or deducted; (b) promptly forward to the Agent an official receipt or other documentation satisfactory to the Agent evidencing such payment to such authority; and (c) pay to the Agent for the account of the Lenders such additional amount or amounts as is necessary to ensure that the net amount actually received by each Lender will equal the full amount such Lender would have received had no such withholding or deduction been required. Moreover, if any Taxes are directly asserted against the Agent or any Lender with respect to any payment received by the Agent or such Lender hereunder, the Agent or such Lender may pay such Taxes and the Borrower will promptly pay such additional amounts (including any penalties, interest or expenses) as is necessary in order that the net amount received by such person after the payment of such Taxes (including any Taxes on such additional amount) shall equal the amount such person would have received had not such Taxes been asserted. If the Borrower fails to pay any Taxes when due to the appropriate taxing authority or fails to remit to the Agent, for the account of the respective Lenders, the required receipts or other required documentary evidence, the Borrower shall indemnify the Lenders for any incremental Taxes, interest or penalties that may become payable by any Lender as a result of any such failure. For purposes of this Section 4.6, a distribution hereunder by the Agent or any Lender to or for the account of any Lender shall be deemed a payment by the Borrower. Upon the request of the Borrower or the Agent, each Lender that is organized under the laws of a jurisdiction other than the United States shall, prior to the due date of any payments under the Notes, execute and deliver to the Borrower and the Agent, on or about the first scheduled payment date in each Fiscal Year, one or more (as the Borrower or the Agent may reasonably request) United States Internal Revenue Service Forms 4224 or Forms 1001 or such other forms or documents (or successor forms or documents), appropriately completed, as may be applicable to establish the extent, if any, to which a payment to such Lender is exempt from withholding or deduction of Taxes. .21. Payments, Computations, etc. Unless otherwise expressly provided, all payments by the Borrower pursuant to this Agreement, the Notes or any other Loan Document shall be made by the Borrower to the Agent for the pro rata account of the Lenders entitled to receive such payment. All such payments required to be made to the Agent shall be made, without setoff, deduction or counterclaim, not later than 11:00 a.m., New York City time, on the date due, in same day or immediately available funds, to such account as the Agent shall specify from time to time by notice to the Borrower. Funds received after that time shall be deemed to have been received by the Agent on the next succeeding Business Day. The Agent shall promptly remit in same day funds to each Lender its share, if any, of such payments received by the Agent for the account of such Lender. Each such receipt by the Agent shall discharge the obligation of the Borrower for the payment of such amount to such Lender and the Borrower shall have no duty to see to such application by the Agent. All interest and fees shall be computed on the basis of the actual number of days (including the first day but excluding the last day) occurring during the period for which such interest or fee is payable over a year comprised of 360 days (or, in the case of interest on a Base Rate Loan, 365 days or, if appropriate, 366 days). Whenever any payment to be made shall otherwise be due on a day which is not a Business Day, such payment shall (except as otherwise required by clause (c) of the definition of the term "Interest Period" with respect to LIBO Rate Loans) be made on the next succeeding Business Day and such extension of time shall be included in computing interest and fees, if any, in connection with such payment. .22. Sharing of Payments. If any Lender shall obtain any payment or other recovery (whether voluntary, involuntary, by application of setoff or otherwise) on account of any Loan (other than pursuant to the terms of Sections 4.3, 4.4 and 4.5) in excess of its pro rata share of payments then or therewith obtained by all Lenders, such Lender shall purchase from the other Lenders such participations in Loans made by them as shall be necessary to cause such purchasing Lender to share the excess payment or other recovery ratably with each of them; provided, however, that if all or any portion of the excess payment or other recovery is thereafter recovered from such purchasing Lender, the purchase shall be rescinded and each Lender which has sold a participation to the purchasing Lender shall repay to the purchasing Lender the purchase price to the ratable extent of such recovery together with an amount equal to such selling Lender's ratable share (according to the proportion of (a) the amount of such selling Lender's required repayment to the purchasing Lender to (b) the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. The Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section may, to the fullest extent permitted by law, exercise all its rights of payment (including pursuant to Section 4.9) with respect to such participation as fully as if such Lender were the direct creditor of the Borrower in the amount of such participation. If under any applicable bankruptcy, insolvency or other similar law, any Lender receives a secured claim in lieu of a setoff to which this Section applies, such Lender shall, to the extent practicable, exercise its rights in respect of such secured claim in a manner consistent with the rights of the Lenders entitled under this Section to share in the benefits of any recovery on such secured claim. .23. Setoff. Each Lender shall, upon the occurrence of any Default described in clauses (a) through (d) of Section 8.1.9 or any other Event of Default, have the right to appropriate and apply to the payment of the Obligations owing to it (whether or not then due), and (as security for such Obligations) the Borrower hereby grants to each Lender a continuing security interest in, any and all balances, credits, deposits, accounts or moneys of the Borrower then or thereafter maintained with such Lender; provided, however, that any such appropriation and application shall be subject to the provisions of Section 4.8. Each Lender agrees promptly to notify the Borrower and the Agent after any such setoff and application made by such Lender; provided, however, that the failure to give such notice shall not affect the validity of such setoff and application. The rights of each Lender under this Section are in addition to other rights and remedies (including other rights of setoff under applicable law or otherwise) which such Lender may have. .24. Use of Proceeds. The Borrower shall apply the proceeds of each Borrowing in accordance with the recitals; without limiting the foregoing, no proceeds of any Loan will be used to acquire any equity security of a class which is registered pursuant to Section 12 of the Securities Exchange Act of 1934 or any "margin stock", as defined in F.R.S. Board Regulation U. CONDITIONS TO BORROWING .25. Initial Borrowing. The obligations of the Lenders to fund the initial Borrowing shall be subject to the prior or concurrent satisfaction of each of the conditions precedent set forth in this Section 5.1. 1. Resolutions, etc. The Agent shall have received from the Borrower and GSU a certificate, dated the date of the initial Borrowing, of its Authorized Officer as to (a) resolutions of its Board of Directors or a committee thereof then in full force and effect authorizing the execution, delivery and performance of this Agreement, the Notes and each other Loan Document to be executed by it; and (b) the incumbency and signatures of those of its officers authorized to act with respect to this Agreement, the Notes and each other Loan Document executed by it, upon which certificate each Lender may conclusively rely until it shall have received a further certificate of an Authorized Officer of such Obligor canceling or amending such prior certificate. 2. Delivery of Notes. The Agent shall have received, for the account of each Lender, its Note duly executed and delivered by the Borrower and duly authenticated by the Indenture Trustee. 3. Loan Documents. The Agent shall have received Loan Documents, substantially in the form of Exhibit J and Exhibit K hereto, dated the date hereof, duly executed by the appropriate Obligor. 4. Basic Documents. The Agent shall have received copies of all Basic Documents (other than the Loan Documents) in effect on the Effective Date certified by an Authorized Officer of the Borrower and GSU, respectively. 5. Opinions of Counsel. The Agent shall have received opinions, dated the date of the initial Borrowing and addressed to the Agent and all Lenders, from (a) Orgain, Bell & Tucker, L.L.P., Texas counsel to GSU, substantially in the form of Exhibit E hereto; (b) Taylor, Porter, Brooks & Phillips L.L.P., Louisiana counsel for GSU, substantially in the form of Exhibit F hereto; (c) Morgan, Lewis & Bockius, New York counsel for the Borrower, substantially in the form of Exhibit G hereto; and (d) Mayer, Brown & Platt, counsel to the Agent, substantially in the form of Exhibit H hereto. 6. Closing Fees, Expenses, etc. The Agent shall have received for its own account, or for the account of each Lender, as the case may be, all fees, costs and expenses due and payable pursuant to Sections 3.3 and 10.3, if then invoiced, along with a duly executed copy of the Fee Letter. 7. Governmental Approvals. The Agent shall have received certified copies of all governmental approvals required pursuant to Section 6.3. 8. Trust Indenture. The Agent shall have received an executed original of each order, certificate and opinion delivered to the Indenture Trustee by the Borrower under Section 12.2 of the Trust Indenture. 9. Trust Agreement. The Agent shall have received an executed original of each instruction, certificate and other document delivered to the Owner Trustee under the Trust Agreement. .26. All Borrowings. The obligation of each Lender to fund any Loan on the occasion of any Borrowing (including the initial Borrowing) shall be subject to the satisfaction of each of the conditions precedent set forth in this Section 5.2. 1. Compliance with Warranties, No Default, etc. Both before and after giving effect to any Borrowing (but, if any Default of the nature referred to in Section 8.1.5 shall have occurred with respect to any other Indebtedness, without giving effect to the application, directly or indirectly, of the proceeds thereof) the following statements shall be true and correct (a) the representations and warranties set forth in Article VI (excluding, however, those contained in Section 6.7) shall be true and correct with the same effect as if then made (unless stated to relate solely to an early date, in which case such representations and warranties shall be true and correct as of such earlier date); (b) except as disclosed by the Borrower to the Agent and the Lenders pursuant to Section 6.7 (i) no labor controversy, litigation, arbitration or governmental investigation or proceeding shall be pending or, to the knowledge of the Borrower, threatened against the Borrower or any Obligor which would reasonably be expected to materially adversely affect the Borrower's or such Obligor's business, operations, assets, revenues, properties or prospects or which purports to affect the legality, validity or enforceability of this Agreement, the Notes or any other Loan Document or any other Basic Document; and (ii) no development shall have occurred in any labor controversy, litigation, arbitration or governmental investigation or proceeding disclosed pursuant to Section 6.7 which would reasonably be expected to materially adversely affect the businesses, operations, assets, revenues, properties or prospects of the Borrower or any Obligor; and (c) no Default shall have then occurred and be continuing, and neither the Borrower nor any other Obligor are in material violation of any law or governmental regulation or court order or decree which would reasonably be expected to materially adversely affect the businesses, operations, assets, revenues, properties or prospects of the Borrower or any Obligor. 2. Borrowing Request. The Agent shall have received a Borrowing Request for such Borrowing. Each of the delivery of a Borrowing Request and the acceptance by the Borrower of the proceeds of such Borrowing shall constitute a representation and warranty by the Borrower that on the date of such Borrowing (both immediately before and after giving effect to such Borrowing and the application of the proceeds thereof) the statements made in Section 5.2.1 are true and correct. 3. Satisfactory Legal Form. All documents executed or submitted pursuant hereto by or on behalf of the Borrower or any other Obligor shall be satisfactory in form and substance to the Agent and its counsel; the Agent and its counsel shall have received all information, approvals, opinions, documents or instruments as the Agent or its counsel may reasonably request. REPRESENTATIONS AND WARRANTIES In order to induce the Lenders and the Agent to enter into this Agreement and to make Loans hereunder, the Borrower represents and warrants unto the Agent and each Lender as set forth in this Article VI. .27. Organization, etc. (a) The Borrower is a corporation validly organized and existing and in good standing under the laws of the State of its incorporation, is duly qualified to do business and is in good standing as a foreign corporation in New York and in each jurisdiction (other than Louisiana where the Borrower will be in good standing by December 31, 1993) where the nature of its business requires such qualification, and has full power and authority and holds all requisite governmental licenses, permits and other approvals to enter into and perform its Obligations under this Agreement, the Notes, each other Loan Document and Basic Document to which it is a party and to own and hold under lease its property and to conduct its business substantially as currently conducted by it; (b) All of the Borrower's outstanding capital stock has been duly authorized and issued, is fully paid and nonassessable and is owned by the Owner Trustee free and clear of any Liens or restrictions on transfer, except for restrictions on transfer imposed by (i) federal, state and foreign securities laws and (ii) the Trust Agreement; and (c) Certified copies of the charter documents and bylaws of the Borrower as they will be in effect on the Effective Date have previously been delivered to you and are true, accurate and complete. .28. Due Authorization, Non-Contravention, etc. The execution, delivery and performance by the Borrower of this Agreement, the Notes and each other Loan Document and Basic Document executed or to be executed by it, and the execution, delivery and performance by each other Obligor of each Loan Document executed or to be executed by it and each such other Obligor's participation in the consummation of the Basic Documents are within the Borrower's and each such Obligor's corporate powers, have been duly authorized by all necessary corporate action, and do not (a) contravene the Borrower's or any such Obligor's Organic Documents; (b) contravene any contractual restriction, law or governmental regulation or court decree or order binding on or affecting the Borrower or any such Obligor; or (c) result in, or require the creation or imposition of, any Lien on any of the Borrower's or any Obligor's properties except as provided in the Basic Documents. .29. Government Approval, Regulation, etc. No authorization or approval or other action by, and no notice to or filing with, any governmental authority or regulatory body or other Person is required for the due execution, delivery or performance by the Borrower or any other Obligor of this Agreement, the Notes or any other Loan Document to which it is a party, or for the Borrower's and each such other Obligor's participation in the consummation of the Basic Documents, except as provided in the following sentence, all of which have been duly obtained or made and are in full force and effect. The Borrower and GSU have received all approvals of the Public Utility Commission of Texas, the Louisiana Public Service Commission and the Federal Energy Regulatory Commission required to be obtained by it or by GSU in order to enter into the Loan Documents and the Basic Documents, and to grant the security interests created under the Trust Indenture and the Louisiana Collateral Documents. No consent, license, approval, order or authorization of, or filing, registration or declaration with, any governmental authority, bureau or agency or any court or any other Person is required to be obtained or made in connection with the Borrower's or GSU's execution, delivery, performance or enforceability of the Loan Documents or the Basic Documents or the transactions contemplated hereby or thereby (provided that no representation is given with respect to the Nuclear Fuel Contracts insofar as the respective Manufacturers are concerned), except for a general license for the Borrower to own Nuclear Fuel from the Nuclear Regulatory Commission (currently granted under 10 C.F.R. Sections 40.21 and 70.20), which shall be in full force and effect upon the Effective Date. In addition, the Borrower and the Indenture Trustee will require a special license to possess Nuclear Fuel from the Nuclear Regulatory Commission in order to take possession of the Nuclear Fuel in event of default. No representation is given with respect to Federal, New York or Texas banking or insurance laws or regulations or the securities or blue sky laws or regulations of any State. The Borrower is not an "investment company" within the meaning of the Investment Company Act of 1940, as amended, or a "holding company", or a "subsidiary company" of a "holding company", or an "affiliate" of a "holding company" or of a "subsidiary company" of a "holding company", within the meaning of the Public Utility Holding Company Act of 1935, as amended. Neither the Trust Indenture nor any of the Louisiana Collateral Documents is required to be qualified under the Trust Indenture Act of 1939, as amended, and the creation of security interests in the Collateral by the Trust Indenture and the Louisiana Collateral Documents does not require an indenture to be qualified under said Act. .30. Validity, etc. This Agreement constitutes, and the Notes and each other Loan Document and Basic Document executed by the Borrower will, on the due execution and delivery thereof, constitute, the legal, valid and binding obligations of the Borrower enforceable in accordance with their respective terms; and each Loan Document and each Basic Document executed pursuant hereto by each other Obligor will, on the due execution and delivery thereof by such Obligor, be the legal, valid and binding obligation of such Obligor enforceable in accordance with its terms. .31. Financial Information. The balance sheet of the Borrower as at December 31, 1992 and the related income statement of the Borrower, copies of which have been furnished to the Agent and each Lender, present the financial condition of the Borrower as at the date thereof and the result of its operations for the period then ended. .32. No Material Adverse Change. Since December 31, 1992, there has been no material adverse change in the financial condition, operations, assets, business, properties or prospects of the Borrower. .33. Litigation, Labor Controversies, etc. There is no pending or, to the knowledge of the Borrower, threatened litigation, action, proceeding, or labor controversy affecting the Borrower, or any of its properties, businesses, assets or revenues, which may materially adversely affect the financial condition, operations, assets, business, properties or prospects of the Borrower or which purports to affect the legality, validity or enforceability of this Agreement, the Notes, any other Loan Document or any other Basic Document, except as disclosed in Item 6.7 ("Litigation") of the Disclosure Schedule or in the Disclosure Documents. .34. Subsidiaries. The Borrower has no Subsidiaries. .35. Ownership of Properties. The Borrower owns good and marketable title to all of its properties and assets, real and personal, tangible and intangible, of any nature whatsoever (including patents, trademarks, trade names, service marks and copyrights), free and clear of all Liens, charges or claims (including infringement claims with respect to patents, trademarks, copyrights and the like) except as permitted pursuant to Section 7.2.3. .36. Taxes. The Borrower has filed all tax returns and reports required by law to have been filed by it and has paid all taxes and governmental charges thereby shown to be owing, except any such taxes or charges which are being diligently contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been set aside on its books. .37. Pension and Welfare Plans. The Borrower has no Pension Plan or Welfare Plan. .38. Environmental Warranties. Except as set forth in Item 6.12 ("Environmental Matters") of the Disclosure Schedule the Borrower's present operations comply in all material respects with all applicable Environmental Laws. .39. Regulations G, U and X. The Borrower is not engaged in the business of extending credit for the purpose of purchasing or carrying margin stock, and no proceeds of any Loans will be used for a purpose which violates, or would be inconsistent with, F.R.S. Board Regulation G, U or X. Terms for which meanings are provided in F.R.S. Board Regulation G, U or X or any regulations substituted therefor, as from time to time in effect, are used in this Section with such meanings. .40. Accuracy of Information. All factual information heretofore or contemporaneously furnished by or on behalf of the Borrower in writing to the Agent or any Lender for purposes of or in connection with this Agreement or any transaction contemplated hereby, true and complete copies of which were furnished to the Agent and each Lender in connection with its execution and delivery hereof) is, and all other such factual information hereafter furnished by or on behalf of the Borrower to the Agent or any Lender will be, true and accurate in every material respect on the date as of which such information is dated or certified and as of the date of execution and delivery of this Agreement by the Agent and such Lender, and such information is not, or shall not be, as the case may be, incomplete by omitting to state any material fact necessary to make such information not misleading. .41. Absence of Foreign Status. The Borrower is not (i) a Person included within the definition of "designated foreign country" or "national" of a "designated foreign country" in Executive Order No. 9193, as amended, or in the Foreign Assets Control Regulations (31 C.F.R., Chapter V, Part 500, as amended), in the Cuban Assets Control Regulations (31 C.F.R., Chapter V, Part 515, as amended) or within the meaning of any of such orders or regulations, or of any regulations, interpretations or rulings issued thereunder, or in violation of such orders or regulations or of any regulations, interpretations or rulings issued thereunder, (ii) an entity listed in Sections 520.101, 545.306 or 550.304 of the Foreign Funds Control Regulations (31 C.F.R., Chapter V, Parts 520, 545 and 550, as amended) or (iii) a "South African entity" within the meaning of the Comprehensive Anti- Apartheid Act of 1986. .42. No Terminating Event of Default under Fuel Lease, etc. To the best knowledge of the Borrower after due inquiry, (a) no "Terminating Event" or "Lease Event of Default" or event which with the giving of notice or lapse of time or both would constitute a "Terminating Event" or "Lease Event of Default" has occurred and is continuing under the Fuel Lease and (b) no "Default" or "Event of Default" has occurred and is continuing under the Trust Indenture. COVENANTS .43. Affirmative Covenants. The Borrower agrees with the Agent and each Lender that, until all Commitments have terminated and all Obligations have been paid and performed in full, the Borrower will perform the obligations set forth in this Section 7.1. 1. Financial Information, Reports, Notices, etc. The Borrower will furnish, or will cause to be furnished, to the Agent (with sufficient copies for each Lender) the following financial statements, reports, notices and information: (a) as soon as available and in any event within 60 days after the end of each Fiscal Quarter of each Fiscal Year of the Borrower, the fuel schedule of the Lessee as of the end of such Fiscal Quarter, certified by an Authorized Officer of the Borrower; (b) as soon as available and in any event within 90 days after the end of each Fiscal Year of the Borrower, a copy of the annual unaudited report for such Fiscal Year for the Borrower, including therein a balance sheet of the Borrower as of the end of such Fiscal Year and an income statement of the Borrower for such Fiscal Year certified by an Authorized Officer of the Borrower; (c) as soon as available and in any event within 60 days after the end of each Fiscal Quarter, a certificate, executed by an Authorized Officer of the Borrower, stating that no Default has occurred and is continuing as of the end of such Fiscal Quarter (or if such a Default has occurred and is continuing a statement setting forth details of such Default and the action which the Borrower has taken and proposes to take with respect thereto); (d) as soon as possible a statement of an Authorized Officer of the Borrower setting forth details of each Default and the action which the Borrower has taken and proposes to take with respect thereto; (e) as soon as possible after (x) the occurrence of any adverse development with respect to any litigation, action, proceeding, or labor controversy described in Section 6.7 or (y) the commencement of any labor controversy, litigation, action, proceeding of the type described in Section 6.7, notice thereof and copies of all documentation relating thereto; (f) to the extent obtained or received by it, a copy of each authorization, license, permit, consent, order or approval of any governmental authority obtained or required to be obtained in connection with the transactions contemplated by any of the Loan Documents or the Basic Documents; (g) as soon as possible, all (i) amendments, modifications and waivers, (ii) all requests for any such amendment, modification or waiver, and (iii) any notice of an "Event of Default" or "Terminating Event" received or delivered by the Borrower under or with respect to the Fuel Lease, any of the Note Agreements or any of the other Basic Documents; (h) upon obtaining knowledge thereof, (i) any Terminating Event or Lease Event of Default or any event which with the giving of notice or lapse of time or both would constitute a Terminating Event or Lease Event of Default under the Fuel Lease, or (ii) any "Default" or " Event of Default" under the Trust Indenture; and (i) such other information respecting the condition or operations, financial or otherwise, of the Borrower as any Lender through the Agent may from time to time reasonably request. 2. Compliance with Laws, etc. The Borrower will comply in all material respects with all applicable laws, rules, regulations and orders including, without limitation, Environmental Laws, such compliance to include (without limitation): (a) the maintenance and preservation of its corporate existence and qualification as a foreign corporation; and (b) the payment, before the same become delinquent, of all taxes, assessments and governmental charges imposed upon it or upon its property except to the extent being diligently contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been set aside on its books. 3. Maintenance of Properties. The Borrower will maintain, preserve, protect and keep its properties in good repair, working order and condition, and make necessary and proper repairs, renewals and replacements so that its business carried on in connection therewith may be properly conducted at all times unless the Borrower determines in good faith that the continued maintenance of any of its properties is no longer economically desirable. 4. Insurance. The Borrower will maintain or cause to be maintained with responsible insurance companies (or through self-insurance) insurance with respect to its properties and business (including business interruption insurance) against such casualties and contingencies and of such types and in such amounts as is customary in the case of similar businesses and will, upon request of the Agent, furnish to each Lender at reasonable intervals a certificate of an Authorized Officer of the Borrower setting forth the nature and extent of all insurance maintained by the Borrower in accordance with this Section. 5. Books and Records. The Borrower will keep books and records which accurately reflect all of its business affairs and transactions and permit the Agent and each Lender or any of their respective representatives, at reasonable times and intervals, to visit all of its offices, to discuss its financial matters with its officers and to examine (and, at the expense of the Borrower, photocopy extracts from) any of its books or other corporate records. .44. Negative Covenants. The Borrower agrees with the Agent and each Lender that, until all Commitments have terminated and all Obligations have been paid and performed in full, the Borrower will perform the obligations set forth in this Section 7.2. 1. Business Activities. The Borrower will not, and will not permit any of its Subsidiaries to, engage in any business activity, except those described in the first recital and such activities as may be incidental or related thereto. 2. Indebtedness. The Borrower will not create, incur, assume or suffer to exist or otherwise become or be liable in respect of any Indebtedness, other than, without duplication, the following: (a) Indebtedness in respect of the Loans and other Obligations; (b) Indebtedness existing as of the Effective Date which is identified in Item 7.2.2(b) ("Ongoing Indebtedness") of the Disclosure Schedule; (c) Indebtedness in respect of Additional Notes issued in accordance with the provisions of the Trust Indenture; provided, however, that the aggregate principal amount of all Series A Notes and Additional Notes at any one time outstanding shall not exceed $250,000,000; provided, further, that if any such Additional Notes shall evidence the Borrower's Indebtedness, contingent or direct, in respect of a revolving credit and/or a letter of credit facility which in either case relates to so-called commercial paper to be issued by the Borrower, the documentation relating to such Indebtedness and the amendments and supplements to the Trust Indenture and any of the other Collateral Agreements required in connection therewith shall be reasonably satisfactory to the Required Lenders, and the Borrower shall have obtained the prior written consent of such Required Lenders to the incurrence of such Indebtedness; and provided, further, however, that immediately after giving effect to the issuance of any Additional Notes (i) there shall not exist an "Event of Default" or any event which with the giving of notice or lapse of time or both would constitute an "Event of Default" under the Trust Indenture and (ii) the aggregate Stipulated Loss Value (as defined in Exhibit A to the Trust Indenture) of the Nuclear Fuel plus any amounts in the Collateral Account shall equal or exceed the Outstanding Note Indebtedness; (d) unsecured Indebtedness incurred in the ordinary course of business (including open accounts extended by suppliers on normal trade terms in connection with purchases of goods and services, but excluding Indebtedness incurred through the borrowing of money or Contingent Liabilities); (e) Indebtedness for taxes, assessments, customs or supplies to the extent that payment thereof shall not at the time be required to be made in accordance with Section 6.4 of the Trust Indenture; and (f) Indebtedness for judgments or awards which have been in force for less than the applicable appeal period so long as execution is not levied, or for which (i) the Borrower shall at the time in good faith be diligently prosecuting an appeal or proceedings for review, (ii) a stay of execution shall have been obtained pending such appeal or review, and (iii) adequate reserves shall have been provided on the books of the Borrower. provided, however, that no Indebtedness otherwise permitted by clause (c) or (f) shall be permitted if, after giving effect to the incurrence thereof, any Default shall have occurred and be continuing. 3. Liens. The Borrower will not create, incur, assume or suffer to exist any Lien upon any of its property, revenues or assets, whether now owned or hereafter acquired, except: (a) Liens securing payment of the Obligations and the Note Purchase Agreement Obligations granted pursuant to any Loan Document or any Basic Document; (b) Liens granted prior to the Effective Date to secure payment of Indebtedness of the type permitted and described in clause (b) of Section 7.2.2; (c) Liens for taxes, assessments or other governmental charges or levies not at the time delinquent or thereafter payable without penalty or being diligently contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been set aside on its books; (d) Liens of carriers, warehousemen, mechanics, materialmen and landlords incurred in the ordinary course of business for sums not overdue or being diligently contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been set aside on its books; (e) Liens incurred in the ordinary course of business in connection with workmen's compensation, unemployment insurance or other forms of governmental insurance or benefits, or to secure performance of tenders, statutory obligations, leases and contracts (other than for borrowed money) entered into in the ordinary course of business or to secure obligations on surety or appeal bonds; (f) judgment Liens in existence less than 30 days after the entry thereof or with respect to which execution has been stayed or the payment of which is covered in full (subject to a customary deductible) by insurance maintained with responsible insurance companies; and (g) No Indebtedness in respect of any Additional Notes permitted under Section 7.2.2(c) shall (i) be secured by any collateral other than the Collateral, unless the Notes, the Series A Notes, and any other Additional Notes are secured equally and ratably by such additional collateral, or (ii) be guaranteed directly or indirectly by any Person nor shall the holder thereof be assured against loss or nonpayment, unless the Notes, the Series A Notes and any other Additional Notes shall have the benefit of such guaranty or assurance on a pro rata basis with the Indebtedness in respect of such Additional Notes. 4. [Intentionally Omitted.] 5. Investments. The Borrower will not make, incur, assume or suffer to exist any Investment in any other Person, except: (a) Investments existing on the Effective Date and identified in Item 7.2.5(a) ("Ongoing Investments") of the Disclosure Schedule; (b) Cash Equivalent Investments; (c) without duplication, Investments permitted as Indebtedness pursuant to Section 7.2.2; (d) without duplication, Investments permitted as Capital Expenditures pursuant to Section 7.2.7; (e) other Investments in an aggregate amount at any one time not to exceed $100,000; provided, however, that (f) any Investment which when made complies with the requirements of the definition of the term "Cash Equivalent Investment" may continue to be held notwithstanding that such Investment if made thereafter would not comply with such requirements; (g) no Investment otherwise permitted by clause (e) or (f) shall be permitted to be made if, immediately before or after giving effect thereto, any Default shall have occurred and be continuing; and (h) the Borrower shall not have any Subsidiaries. 6. Restricted Payments, etc. On and at all times after the Effective Date, the Borrower will not declare, pay or make any dividend or distribution (in cash, property or obligations) on any shares of any class of capital stock (now or hereafter outstanding) of the Borrower or on any warrants, options or other rights with respect to any shares of any class of capital stock (now or hereafter outstanding) of the Borrower or apply any of its funds, property or assets to the purchase, redemption, sinking fund or other retirement of any shares of any class of capital stock (now or hereafter outstanding) of the Borrower, or warrants, options or other rights with respect to any shares of any class of capital stock (now or hereafter outstanding) of the Borrower. 7. Capital Expenditures, etc. The Borrower will not make or commit to make Capital Expenditures, except Capital Expenditures of Nuclear Fuel to be leased under the Fuel Lease. 8. Rental Obligations. Except for the Basic Documents, the Borrower will not enter into at any time any arrangement which involves the leasing by the Borrower from any lessor of any real or personal property (or any interest therein). 9. Take or Pay Contracts. The Borrower will not enter into or be a party to any arrangement for the purchase of materials, supplies, other property or services if such arrangement by its express terms requires that payment be made by the Borrower regardless of whether such materials, supplies, other property or services are delivered or furnished to it. 10. Consolidation, Merger, etc. The Borrower will not liquidate or dissolve, consolidate with, or merge into or with, any other or with, any other corporation, or purchase or otherwise acquire all or substantially all of the assets of any Person (or of any division thereof). 11. Asset Dispositions, etc. The Borrower will not sell, transfer, lease, contribute or otherwise convey, or grant options, warrants or other rights with respect to, all or any substantial part of its assets to any Person, except as provided in the Basic Documents. 12. Modification of Certain Agreements. The Borrower will not consent to any amendment, supplement or other modification of any of the terms or provisions contained in, or applicable to, any Basic Document. 13. Transactions with Affiliates. The Borrower will not enter into, or cause, suffer or permit to exist any arrangement or contract (other than the Basic Documents) with GSU or any of GSU's Affiliates unless such arrangement or contract is fair and equitable to the Borrower and is an arrangement or contract of the kind which would be entered into by a prudent Person in the position of the Borrower with a Person which is not GSU or one of its Affiliates. 14. Negative Pledges, Restrictive Agreements, etc. The Borrower will not enter into any agreement (excluding this Agreement, the Basic Documents any other Loan Document and any agreement governing any Indebtedness permitted either by clause (b) of Section 7.2.2 as in effect on the Effective Date or by clause (c) of Section 7.2.2 as to the assets financed with the proceeds of such Indebtedness) prohibiting the creation or assumption of any Lien upon its properties, revenues or assets, whether now owned or hereafter acquired, or the ability of the Borrower to amend or otherwise modify this Agreement or any other Loan Document. EVENTS OF DEFAULT .45. Listing of Events of Default. Each of the following events or occurrences described in this Section 8.1 shall constitute an "Event of Default". 1. Non-Payment of Obligations. The Borrower shall default in the payment or prepayment when due of any principal of or interest on any Loan (and such default shall continue unremedied for a period of three days), or the Borrower shall default (and such default shall continue unremedied for a period of five days) in the payment when due of any commitment fee or of any other Obligation. 2. Breach of Warranty. Any representation or warranty of the Borrower or any other Obligor made or deemed to be made hereunder or in any other Loan Document or Basic Document or any other writing or certificate furnished by or on behalf of the Borrower or any other Obligor to the Agent or any Lender for the purposes of or in connection with this Agreement or any such other Loan Document or Basic Document (including any certificates delivered pursuant to Article V) is or shall be incorrect when made in any material respect. 3. Non-Performance of Certain Covenants and Obligations. The Borrower shall default in the due performance and observance of any of its obligations under Section 7.2 (and in the case of any default under Section 7.2.2, such default shall continue unremedied for a period of 10 days). 4. Non-Performance of Other Covenants and Obligations. The Borrower or any other Obligor shall default in the due performance and observance of any other agreement contained herein or in any other Loan Document and such default shall continue unremedied for a period of 30 days after notice thereof shall have been given to the Borrower by the Agent or any Lender (or if such default is capable of being remedied and the Borrower is diligently pursuing such remediation, such default shall continue for a period of 60 days after the occurrence thereof). 5. Default on Other Indebtedness. A default shall occur in the payment when due (subject to any applicable grace period), whether by acceleration or otherwise, of any Indebtedness (other than Indebtedness described in Section 8.1.1) of the Borrower or any other Obligor having a principal amount, individually or in the aggregate, in excess of $1,000,000 in the case of the Borrower or $10,000,000 in the case of any other Obligor, or a default shall occur in the performance or observance of any obligation or condition with respect to such Indebtedness if the effect of such default is to accelerate the maturity of any such Indebtedness or such default shall continue unremedied for any applicable period of time sufficient to permit the holder or holders of such Indebtedness, or any trustee or agent for such holders, to cause such Indebtedness to become due and payable prior to its expressed maturity. 6. Judgments. Any judgment or order for the payment of money in excess of $1,000,000 shall be rendered against the Borrower or any judgment or order for the payment of money in excess of $10,000,000 shall be rendered against any other Obligor and either (a) enforcement proceedings shall have been commenced by any creditor upon such judgment or order; or (b) there shall be any period of 30 consecutive days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect. 7. Basic Documents. (a) Any Terminating Event or Lease Event of Default under the Fuel Lease shall have occurred and be continuing or (b) any "Event of Default" under the Trust Indenture shall have occurred and be continuing. 8. Control of the Borrower. Any Change in Control shall occur. 9. Bankruptcy, Insolvency, etc. The Borrower or any other Obligor shall (a) become insolvent or generally fail to pay, or admit in writing its inability or unwillingness to pay, debts as they become due; (b) apply for, consent to, or acquiesce in, the appointment of a trustee, receiver, sequestrator or other custodian for the Borrower or any other Obligor or any property of any thereof, or make a general assignment for the benefit of creditors; (c) in the absence of such application, consent or acquiescence, permit or suffer to exist the appointment of a trustee, receiver, sequestrator or other custodian for the Borrower or any other Obligor or for a substantial part of the property of any thereof, and such trustee, receiver, sequestrator or other custodian shall not be discharged within 60 days, provided that the Borrower and each other Obligor hereby expressly authorizes the Agent and each Lender to appear in any court conducting any relevant proceeding during such 60-day period to preserve, protect and defend their rights under the Loan Documents; (d) permit or suffer to exist the commencement of any bankruptcy, reorganization, debt arrangement or other case or proceeding under any bankruptcy or insolvency law, or any dissolution, winding up or liquidation proceeding, in respect of the Borrower or any other Obligor, and, if any such case or proceeding is not commenced by the Borrower or such other Obligor, such case or proceeding shall be consented to or acquiesced in by the Borrower or such other Obligor or shall result in the entry of an order for relief or shall remain for 60 days undismissed, provided that the Borrower and each other Obligor hereby expressly authorizes the Agent and each Lender to appear in any court conducting any such case or proceeding during such 60-day period to preserve, protect and defend their rights under the Loan Documents; or (e) take any action authorizing, or in furtherance of, any of the foregoing. 10. Impairment of Security, etc. Any Collateral Agreement or any Lien granted thereunder, shall (except in accordance with its terms), in whole or in part, terminate, cease to be effective or cease to be the legally valid, binding and enforceable obligation of any Obligor party thereto; the Borrower, any other Obligor or any other party shall, directly or indirectly, contest in any manner such effectiveness, validity, binding nature or enforceability; or any Lien securing any Obligation shall, in whole or in part, cease to be a perfected first priority Lien, subject only to those exceptions expressly permitted by such Loan Document or Basic Document. .46. Action if Bankruptcy. If any Event of Default described in clauses (a) through (d) of Section 8.1.9 shall occur, the Commitments (if not theretofore terminated) shall automatically terminate and the outstanding principal amount of all outstanding Loans and all other Obligations shall automatically be and become immediately due and payable, without notice or demand. .47. Action if Other Event of Default. If any Event of Default (other than any Event of Default described in clauses (a) through (d) of Section 8.1.9) shall occur for any reason, whether voluntary or involuntary, and be continuing, the Agent, upon the direction of the Required Lenders, shall by notice to the Borrower declare all or any portion of the outstanding principal amount of the Loans and other Obligations to be due and payable and/or the Commitments (if not theretofore terminated) to be terminated, whereupon the full unpaid amount of such Loans and other Obligations which shall be so declared due and payable shall be and become immediately due and payable, without further notice, demand or presentment, and/or, as the case may be, the Commitments shall terminate. THE AGENT .48. Actions. Each Lender hereby appoints CIBC as its Agent under and for purposes of this Agreement, the Notes and each other Loan Document. Each Lender authorizes the Agent to act on behalf of such Lender under this Agreement, the Notes and each other Loan Document and, in the absence of other written instructions from the Required enders received from time to time by the Agent (with respect to which the Agent agrees that it will comply, except as otherwise provided in this Section or as otherwise advised by counsel), to exercise such powers hereunder and thereunder as are specifically delegated to or required of the Agent by the terms hereof and thereof, together with such powers as may be reasonably incidental thereto. Each Lender hereby indemnifies (which indemnity shall survive any termination of this Agreement) the Agent, pro rata according to such Lender's Percentage, from and against any and all liabilities, obligations, losses, damages, claims, costs or expenses of any kind or nature whatsoever which may at any time be imposed on, incurred by, or asserted against, the Agent in any way relating to or arising out of this Agreement, the Notes and any other Loan Document, including reasonable attorneys' fees, and as to which the Agent is not reimbursed by the Borrower; provided, however, that no Lender shall be liable for the payment of any portion of such liabilities, obligations, losses, damages, claims, costs or expenses which are determined by a court of competent jurisdiction in a final proceeding to have resulted solely from the Agent's gross negligence or wilful misconduct. The Agent shall not be required to take any action hereunder, under the Notes or under any other Loan Document, or to prosecute or defend any suit in respect of this Agreement, the Notes or any other Loan Document, unless it is indemnified hereunder to its satisfaction. If any indemnity in favor of the Agent shall be or become, in the Agent's determination, inadequate, the Agent may call for additional indemnification from the Lenders and cease to do the acts indemnified against hereunder until such additional indemnity is given. .49. Funding Reliance, etc. Unless the Agent shall have been notified by telephone, confirmed in writing, by any Lender by 5:00 p.m., New York City time, on the day prior to a Borrowing that such Lender will not make available the amount which would constitute its Percentage of such Borrowing on the date specified therefor, the Agent may assume that such Lender has made such amount available to the Agent and, in reliance upon such assumption, make available to the Borrower a corresponding amount. If and to the extent that such Lender shall not have made such amount available to the Agent, such Lender and the Borrower severally agree to repay the Agent forthwith on demand such corresponding amount together with interest thereon, for each day from the date the Agent made such amount available to the Borrower to the date such amount is repaid to the Agent, at the interest rate applicable at the time to Loans comprising such Borrowing. .50. Exculpation. Neither the Agent nor any of its directors, officers, employees or agents shall be liable to any Lender for any action taken or omitted to be taken by it under this Agreement or any other Loan Document, or in connection herewith or therewith, except for its own wilful misconduct or gross negligence, nor responsible for any recitals or warranties herein or therein, nor for the effectiveness, enforceability, validity or due execution of this Agreement or any other Loan Document, nor for the creation, perfection or priority of any Liens purported to be created by any of the Loan Documents or Basic Documents, or the validity, genuineness, enforceability, existence, value or sufficiency of any collateral security, nor to make any inquiry respecting the performance by the Borrower of its obligations hereunder or under any other Loan Document. Any such inquiry which may be made by the Agent shall not obligate it to make any further inquiry or to take any action. The Agent shall be entitled to rely upon advice of counsel concerning legal matters and upon any notice, consent, certificate, statement or writing which the Agent believes to be genuine and to have been presented by a proper Person. .51. Successor. The Agent may resign as such at any time upon at least 30 days' prior notice to the Borrower and all Lenders. If the Agent at any time shall resign, the Required Lenders may appoint another Lender as a successor Agent which shall thereupon become the Agent hereunder; provided, however, that, if no Default has then occurred and is continuing, the appointment of a successor Agent shall require the written consent of the Borrower (which consent shall not be unreasonably delayed or withheld and which consent shall be deemed to have been given in the absence of a written notice delivered by the Borrower to the Agent, on or before the fifth Business Day after receipt by the Borrower of the notice from the Agent and request for consent, stating, in reasonable detail, the reasons why the Borrower proposes to withhold such consent. If no successor Agent shall have been so appointed by the Required Lenders, and shall have accepted such appointment, within 30 days after the retiring Agent's giving notice of resignation, then the retiring Agent may, on behalf of the Lenders, appoint a successor Agent, which shall be one of the Lenders or a commercial banking institution organized under the laws of the U.S. (or any State thereof) or a U.S. branch or agency of a commercial banking institution, and having a combined capital and surplus of at least $500,000,000. Upon the acceptance of any appointment as Agent hereunder by a successor Agent, such successor Agent shall be entitled to receive from the retiring Agent such documents of transfer and assignment as such successor Agent may reasonably request, and shall thereupon succeed to and become vested with all rights, powers, privileges and duties of the retiring Agent, and the retiring Agent shall be discharged from its duties and obligations under this Agreement. After any retiring Agent's resignation hereunder as the Agent, the provisions of (a) this Article IX shall inure to its benefit as to any actions taken or omitted to be taken by it while it was the Agent under this Agreement; and (b) Section 10.3 and Section 10.4 shall continue to inure to its benefit. .52. Loans by CIBC. CIBC shall have the same rights and powers with respect to (x) the Loans made by it or any of its Affiliates, and (y) the Notes held by it or any of its Affiliates as any other Lender and may exercise the same as if it were not the Agent. CIBC and its Affiliates may accept deposits from, lend money to, and generally engage in any kind of business with the Borrower or any Subsidiary or Affiliate of the Borrower as if CIBC were not the Agent hereunder. .53. Credit Decisions. Each Lender acknowledges that it has, independently of the Agent and each other Lender, and based on such Lender's review of the financial information of the Borrower, this Agreement, the other Loan Documents (the terms and provisions of which being satisfactory to such Lender) and such other documents, information and investigations as such Lender has deemed appropriate, made its own credit decision to extend its Commitment. Each Lender also acknowledges that it will, independently of the Agent and each other Lender, and based on such other documents, information and investigations as it shall deem appropriate at any time, continue to make its own credit decisions as to exercising or not exercising from time to time any rights and privileges available to it under this Agreement or any other Loan Document. .54. Copies, etc. The Agent shall give prompt notice to each Lender of each notice or request required or permitted to be given to the Agent by the Borrower pursuant to the terms of this Agreement (unless concurrently delivered to the Lenders by the Borrower). The Agent will distribute to each Lender each document or instrument received for its account and copies of all other communications received by the Agent from the Borrower for distribution to the Lenders by the Agent in accordance with the terms of this Agreement. MISCELLANEOUS PROVISIONS .55. Waivers, Amendments, etc. The provisions of this Agreement and of each other Loan Document may from time to time be amended, modified or waived, if such amendment, modification or waiver is in writing and consented to by the Borrower and the Required Lenders; provided, however, that no such amendment, modification or waiver which would: (a) modify any requirement hereunder that any particular action be taken by all the Lenders or by the Required Lenders shall be effective unless consented to by each Lender; (b) modify this Section 10.1, change the definition of "Required Lenders", increase the Commitment Amount or the Percentage of any Lender, reduce any fees described in Article III, release any collateral security, except as otherwise specifically provided in any Loan Document or Basic Document or extend the Commitment Termination Date shall be made without the consent of each Lender and each holder of a Note; (c) extend the due date for, or reduce the amount of, any scheduled repayment or prepayment of principal of or interest on any Loan (or reduce the principal amount of or rate of interest on any Loan) shall be made without the consent of the holder of that Note evidencing such Loan; or (d) affect adversely the interests, rights or obligations of the Agent qua the Agent shall be made without consent of the Agent. No failure or delay on the part of the Agent, any Lender or the holder of any Note in exercising any power or right under this Agreement or any other Loan Document shall operate as a waiver thereof, nor shall any single or partial exercise of any such power or right preclude any other or further exercise thereof or the exercise of any other power or right. No notice to or demand on the Borrower in any case shall entitle it to any notice or demand in similar or other circumstances. No waiver or approval by the Agent, any Lender or the holder of any Note under this Agreement or any other Loan Document shall, except as may be otherwise stated in such waiver or approval, be applicable to subsequent transactions. No waiver or approval hereunder shall require any similar or dissimilar waiver or approval thereafter to be granted hereunder. .56. Notices. All notices and other communications provided to any party hereto under this Agreement or any other Loan Document shall be in writing or by Telex or by facsimile and addressed, delivered or transmitted to such party at its address, Telex or facsimile number set forth below its signature hereto or on Schedule II hereto or set forth in the Lender Assignment Agreement or at such other address, Telex or facsimile number as may be designated by such party in a notice to the other parties. A copy of all notices and other communications provided hereunder to any party shall be sent to the Indenture Trustee. Any notice, if mailed and properly addressed with postage prepaid or if properly addressed and sent by pre-paid courier service, shall be deemed given when received; any notice, if transmitted by Telex or facsimile, shall be deemed given when transmitted (answerback confirmed in the case of Telexes). .57. Payment of Costs and Expenses. The Borrower agrees to pay on demand all reasonable expenses of the Agent (including the reasonable fees and out-of-pocket expenses of counsel to the Agent and of local counsel, if any, who may be retained by counsel to the Agent) in connection with (a) the negotiation, preparation, execution and delivery of this Agreement and of each other Loan Document, including schedules and exhibits, and any amendments, waivers, consents, supplements or other modifications to this Agreement or any other Loan Document as may from time to time hereafter be required, whether or not the transactions contemplated hereby are consummated, (b) the filing, recording, refiling or rerecording of the Collateral Agreements and/or any Uniform Commercial Code financing statements relating thereto and all amendments, supplements and modifications to any thereof and any and all other documents or instruments of further assurance required to be filed or recorded or refiled or rerecorded by the terms hereof or of the Collateral Agreements, and (c) the preparation and review of the form of any document or instrument relevant to this Agreement or any other Loan Document or Basic Document. The Borrower further agrees to pay, and to save the Agent and the Lenders harmless from all liability for, any stamp or other taxes which may be payable in connection with the execution or delivery of this Agreement, the borrowings hereunder, or the issuance of the Notes or any other Loan Documents. The Borrower also agrees to reimburse the Agent and each Lender upon demand for all reasonable out-of-pocket expenses (including attorneys' fees and legal expenses) incurred by the Agent or such Lender in connection with (x) the negotiation of any restructuring or "work-out", whether or not consummated, of any Obligations and (y) the enforcement of any Obligations. .58. Indemnification. In consideration of the execution and delivery of this Agreement by each Lender and the extension of the Commitments, the Borrower hereby indemnifies, exonerates and holds the Agent and each Lender and each of their respective officers, directors, employees and agents (collectively, the "Indemnified Parties") free and harmless from and against any and all actions, causes of action, suits, losses, costs, liabilities and damages, and expenses incurred in connection therewith (irrespective of whether any such Indemnified Party is a party to the action for which indemnification hereunder is sought), including reasonable attorneys' fees and disbursements (collectively, the "Indemnified Liabilities"), incurred by the Indemnified Parties or any of them as a result of, or arising out of, or relating to (a) any transaction financed or to be financed in whole or in part, directly or indirectly, with the proceeds of any Loan; (b) the entering into and performance of this Agreement and any other Loan Document by any of the Indemnified Parties (including any action brought by or on behalf of the Borrower as the result of any determination by the Required Lenders pursuant to Article V not to fund any Borrowing); (c) any investigation, litigation or proceeding related to any environmental cleanup, audit, compliance or other matter relating to the protection of the environment or the release by the Borrower or any of its Subsidiaries of any hazardous material; or (d) the presence on or under, or the escape, seepage, leakage, spillage, discharge, emission, discharging or releases from, any real property owned or operated by the Borrower or any Subsidiary thereof of any Hazardous Material (including any losses, liabilities, damages, injuries, costs, expenses or claims asserted or arising under any Environmental Law), regardless of whether caused by, or within the control of, the Borrower or such Subsidiary, except for any such Indemnified Liabilities arising for the account of a particular Indemnified Party by reason of the relevant Indemnified Party's gross negligence or wilful misconduct or breach of this Agreement. If and to the extent that the foregoing undertaking may be unenforceable for any reason, the Borrower hereby agrees to make the maximum contribution to the payment and satisfaction of each of the Indemnified Liabilities which is permissible under applicable law. .59. Survival. The obligations of the Borrower under Sections 4.3, 4.4, 4.5, 4.6, 10.3 and 10.4, and the obligations of the Lenders under Section 9.1, shall in each case survive any termination of this Agreement, the payment in full of all Obligations and the termination of all Commitments. The representations and warranties made by each Obligor in this Agreement and in each other Loan Document shall survive the execution and delivery of this Agreement and each such other Loan Document. .60. Severability. Any provision of this Agreement or any other Loan Document which is prohibited or unenforceable in any jurisdiction shall, as to such provision and such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions of this Agreement or such Loan Document or affecting the validity or enforceability of such provision in any other jurisdiction. .61. Headings. The various headings of this Agreement and of each other Loan Document are inserted for convenience only and shall not affect the meaning or interpretation of this Agreement or such other Loan Document or any provisions hereof or thereof. .62. Execution in Counterparts, Effectiveness, etc. This Agreement may be executed by the parties hereto in several counterparts, each of which shall be executed by the Borrower and the Agent and be deemed to be an original and all of which shall constitute together but one and the same agreement. This Agreement shall become effective when counterparts hereof executed on behalf of the Borrower and each Lender (or notice thereof satisfactory to the Agent) shall have been received by the Agent and notice thereof shall have been given by the Agent to the Borrower and each Lender. .63. Governing Law; Entire Agreement. THIS AGREEMENT, THE NOTES AND EACH OTHER LOAN DOCUMENT SHALL EACH BE DEEMED TO BE A CONTRACT MADE UNDER AND GOVERNED BY THE INTERNAL LAWS OF THE STATE OF NEW YORK. This Agreement, the Notes and the other Loan Documents constitute the entire understanding among the parties hereto with respect to the subject matter hereof and supersede any prior agreements, written or oral, with respect thereto. .64. Successors and Assigns. This Agreement shall be binding upon and shall inure to the benefit of the parties hereto and their respective successors and assigns; provided, however, that: (a) the Borrower may not assign or transfer its rights or obligations hereunder without the prior written consent of the Agent and all Lenders; and (b) the rights of sale, assignment and transfer of the Lenders are subject to Section 10.11. .65. Sale and Transfer of Loans and Note; Participations in Loans and Note. Each Lender may assign, or sell participations in, its Loans and Commitment to one or more other Persons in accordance with this Section 10.11. 1. Assignments. Any Lender, (a) with the written consents of the Borrower and the Agent (which consents shall not be unreasonably delayed or withheld and which consent, in the case of the Borrower, shall be deemed to have been given in the absence of a written notice delivered by the Borrower to the Agent, on or before the fifth Business Day after receipt by the Borrower of such Lender's request for consent, stating, in reasonable detail, the reasons why the Borrower proposes to withhold such consent) may at any time assign and delegate to one or more commercial banks or other financial institutions, and (b) with notice to the Borrower and the Agent, but without the consent of the Borrower or the Agent, may assign and delegate to any other Lender (each Person described in either of the foregoing clauses as being the Person to whom such assignment and delegation is to be made, being hereinafter referred to as an "Assignee Lender"), all or any fraction of such Lender's total Loans and Commitment (which assignment and delegation shall be of a constant, and not a varying, percentage of all the assigning Lender's Loans and Commitment) in a minimum aggregate amount of $5,000,000; provided, however, that any such Assignee Lender will comply, if applicable, with the provisions contained in the final sentence of Section 4.6 and further, provided, however, that, the Borrower and the Agent shall be entitled to continue to deal solely and directly with such Lender in connection with the interests so assigned and delegated to an Assignee Lender until (c) written notice of such assignment and delegation, together with payment instructions, addresses and related information with respect to such Assignee Lender, shall have been given to the Borrower and the Agent by such Lender and such Assignee Lender, (d) such Assignee Lender shall have executed and delivered to the Borrower and the Agent a Lender Assignment Agreement, accepted by the Agent, and (e) the processing fees described below shall have been paid. From and after the date that the Agent accepts such Lender Assignment Agreement, (x) the Assignee Lender thereunder shall be deemed automatically to have become a party hereto and to the extent that rights and obligations hereunder have been assigned and delegated to such Assignee Lender in connection with such Lender Assignment Agreement, shall have the rights and obligations of a Lender hereunder and under the other Loan Documents, and (y) the assignor Lender, to the extent that rights and obligations hereunder have been assigned and delegated by it in connection with such Lender Assignment Agreement, shall be released from its obligations hereunder and under the other Loan Documents. Within five Business Days after its receipt of notice that the Agent has received an executed Lender Assignment Agreement, the Borrower shall execute and deliver to the Agent (for delivery to the relevant Assignee Lender) a new Note duly authenticated by the Indenture Trustee evidencing such Assignee Lender's assigned Loans and Commitment and, if the assignor Lender has retained Loans and a Commitment hereunder, a replacement Note duly authenticated by the Indenture Trustee in the principal amount of the Loans and Commitment retained by the assignor Lender hereunder (such Note to be in exchange for, but not in payment of, that Note then held by such assignor Lender). Each such Note shall be dated the date of the predecessor Note. The assignor Lender shall mark the predecessor Note "exchanged" and deliver it to the Indenture Trustee in exchange for such new Note(s). Accrued interest on that part of the predecessor Note evidenced by the new Note(s), and accrued fees, shall be paid as provided in the Lender Assignment Agreement. Accrued interest on that part of the predecessor Note evidenced by the replacement Note shall be paid to the assignor Lender. Accrued interest and accrued fees shall be paid at the same time or times provided in the predecessor Note and in this Agreement. Such assignor Lender or such Assignee Lender must also pay a processing fee to the Agent upon delivery of any Lender Assignment Agreement in the amount of $2,500. Any attempted assignment and delegation not made in accordance with this Section 10.11.1 shall be null and void. 2. Participations. Any Lender may at any time sell to one or more commercial banks (each of such commercial banks being herein called a "Participant") participating interests in any of the Loans, its Commitment, or other interests of such Lender hereunder; provided, however, that (a) no participation contemplated in this Section 10.11 shall relieve such Lender from its Commitment or its other obligations hereunder or under any other Loan Document, (b) such Lender shall remain solely responsible for the performance of its Commitment and such other obligations, (c) the Borrower and the Agent shall continue to deal solely and directly with such Lender in connection with such Lender's rights and obligations under this Agreement and each of the other Loan Documents, and (d) no Participant, unless such Participant is an Affiliate of such Lender, or is itself a Lender, shall be entitled to require such Lender to take or refrain from taking any action hereunder or under any other Loan Document, except that such Lender may agree with any Participant that such Lender will not, without such Participant's consent, take any actions of the type described in clause (b) or (c) of Section 10.1. The Borrower acknowledges and agrees that each Participant, for purposes of Sections 4.3, 4.4, 4.5, 4.6, 4.8, 4.9, 10.3 and 10.4, shall be considered a Lender; provided, however, that the Borrower shall not be required to pay any amount under Section 4.3, Section 4.5 or Section 4.6 that is greater than the amount which it would have been required to pay had no participating interest been sold. .66. Other Transactions. Nothing contained herein shall preclude the Agent or any other Lender from engaging in any transaction, in addition to those contemplated by this Agreement or any other Loan Document, with the Borrower or any of its Affiliates in which the Borrower or such Affiliate is not restricted hereby from engaging with any other Person. .67. Forum Selection and Consent to Jurisdiction. ANY LITIGATION BASED HEREON, OR ARISING OUT OF, UNDER, OR IN CONNECTION WITH, THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN) OR ACTIONS OF THE AGENT, THE LENDERS OR THE BORROWER MAY BE BROUGHT AND MAINTAINED IN THE COURTS OF THE STATE OF NEW YORK OR IN THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN DISTRICT OF NEW YORK. ANY SUIT SEEKING ENFORCEMENT AGAINST ANY COLLATERAL OR OTHER PROPERTY MAY BE BROUGHT, AT THE AGENT'S OPTION, IN THE COURTS OF ANY JURISDICTION WHERE SUCH COLLATERAL OR OTHER PROPERTY MAY BE FOUND. THE BORROWER HEREBY EXPRESSLY AND IRREVOCABLY SUBMITS TO THE JURISDICTION OF THE COURTS OF THE STATE OF NEW YORK AND OF THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN DISTRICT OF NEW YORK FOR THE PURPOSE OF ANY SUCH LITIGATION AS SET FORTH ABOVE AND IRREVOCABLY AGREES TO BE BOUND BY ANY JUDGMENT RENDERED THEREBY IN CONNECTION WITH SUCH LITIGATION. THE BORROWER FURTHER IRREVOCABLY CONSENTS TO THE SERVICE OF PROCESS BY REGISTERED MAIL, POSTAGE PREPAID, OR BY PERSONAL SERVICE WITHIN OR WITHOUT THE STATE OF NEW YORK. THE BORROWER HEREBY EXPRESSLY AND IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH IT MAY HAVE OR HEREAFTER MAY HAVE TO THE LAYING OF VENUE OF ANY SUCH LITIGATION BROUGHT IN ANY SUCH COURT REFERRED TO ABOVE AND ANY CLAIM THAT ANY SUCH LITIGATION HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. TO THE EXTENT THAT THE BORROWER HAS OR HEREAFTER MAY ACQUIRE ANY IMMUNITY FROM JURISDICTION OF ANY COURT OF FROM ANY LEGAL PROCESS (WHETHER THROUGH SERVICE OR NOTICE, ATTACHMENT PRIOR TO JUDGMENT, ATTACHMENT IN AID OF EXECUTION OR OTHERWISE) WITH RESPECT TO ITSELF OR ITS PROPERTY, THE BORROWER HEREBY IRREVOCABLY WAIVES SUCH IMMUNITY IN RESPECT OF ITS OBLIGATIONS UNDER THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS. .68. Waiver of Jury Trial. THE AGENT, THE LENDERS AND THE BORROWER HEREBY KNOWINGLY, VOLUNTARILY AND INTENTIONALLY WAIVE ANY RIGHTS THEY MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION BASED HEREON, OR ARISING OUT OF, UNDER, OR IN CONNECTION WITH, THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN) OR ACTIONS OF THE AGENT, THE LENDERS OR THE BORROWER. THE BORROWER ACKNOWLEDGES AND AGREES THAT IT HAS RECEIVED FULL AND SUFFICIENT CONSIDERATION FOR THIS PROVISION (AND EACH OTHER PROVISION OF EACH OTHER LOAN DOCUMENT TO WHICH IT IS A PARTY) AND THAT THIS PROVISION IS A MATERIAL INDUCEMENT FOR THE AGENT AND THE LENDERS ENTERING INTO THIS AGREEMENT AND EACH SUCH OTHER LOAN DOCUMENT. .69. Usury Not Intended. (a) Anything in this Agreement or any Note to the contrary notwithstanding, the Borrower shall never be required to pay unearned interest on any Note or any other obligation hereunder and shall never be required to pay interest on such Note or obligation at a rate in excess of the Highest Lawful Rate (as defined below), and if the effective rate of interest that would otherwise be payable under this Agreement and such Note would exceed the Highest Lawful Rate, or if the holder of such Note shall receive any unearned interest or shall receive monies that are deemed to constitute interest which would increase the effective rate of interest payable under this Agreement and such Note to a rate in excess of the Highest Lawful Rate, then (i) the amount of interest that would otherwise be payable under this Agreement and such Note shall be reduced to the amount allowed under applicable law, and (ii) any unearned interest paid by the Borrower or any interest paid by the Borrower in excess of the Highest Lawful Rate shall, at the option of the holder of such Note, be either refunded to the Borrower or credited on the principal of such Note. It is further agreed that, without limitation of the foregoing, all calculations of the rate of interest contracted for, charged or received by any Lender under its Note, or under this Agreement, that are made for the purpose of determining whether such rate exceeds the Highest Lawful Rate, shall be made, to the extent permitted by the applicable law (now or hereafter enacted) governing the Highest Lawful Rate, by (x) characterizing any nonprincipal payment as an expense, fee or premium rather than as interest and (y) amortizing, prorating and spreading in equal parts during the period of the full stated term of the Loans evidenced by the Notes all interest at any time contracted for, charged or received by such Lender in connection therewith. If at any time the effective rate of interest which would otherwise be payable under this Agreement or on any principal amount outstanding under any Note exceeds the Highest Lawful Rate, the rate of interest to accrue under this Agreement or on such unpaid principal balance during all such times shall be limited to the Highest Lawful Rate, but any subsequent reductions in such interest rate shall not become effective to reduce such interest rate below the Highest Lawful Rate until the total amount of interest accrued hereunder or on the unpaid principal balance equals the total amount of interest which would have accrued if the total amount of interest had been computed without giving effect to this Section. (b) As used in this Section, the term "Highest Lawful Rate" means as to any Loan the maximum nonusurious rate of interest permitted from time to time to be contracted for, taken, charged or received with respect to such Loan by the Lender making such Loan under applicable law. At all such times, if any, as Texas law shall establish the Highest Lawful Rate, the Highest Lawful Rate shall be the "indicated rate ceiling" (as defined in Chapter One of the Texas Credit Code, V.T.C.S. Art. 5069-1.04 et seq.) from time to time in effect. .70. Revolving Credit Statute. If, notwithstanding Section 10.9, Texas law shall be applied to this Agreement or the obligations of the Borrower hereunder or under any Note, the Borrower agrees that, pursuant to Article 15.10(b) of Chapter 15, Title 79, Revised Civil Statutes of Texas, 1925, as amended, such Chapter 15 shall not govern or in any manner apply to its obligations hereunder or under such Note. .71. No Recourse. The Loan Documents and the Basic Documents and any other document executed and delivered by the Borrower in connection therewith are intended to be corporate obligations of the Borrower only, and all of the statements, representations, covenants and agreements made by the Borrower contained therein are made and intended only for the purpose of binding the Borrower and establishing the existence of rights and remedies provided for herein or therein which can be exercised and enforced against the Borrower. Therefore, anything contained in the Loan Documents and the Basic Documents and any other document to the contrary notwithstanding, no recourse may be made by any Lender against River Bend Fuel Services Trust or Chemical Bank as trustee or in its individual capacity or any incorporator, shareholder (direct or indirect), affiliate, director, officer, employee or agent of the Borrower, River Bend Fuel Services Trust or Chemical Bank with respect to claims against the Borrower arising under or relating to this Agreement. Nothing in this Section shall relieve the Borrower from its corporate obligations under the Loan Documents and the Basic Documents nor prevent recourse by any Lender against Chemical Bank as trustee or in its individual capacity with respect to claims arising out of its own willful misconduct or gross negligence as provided in Section 7.1(b) of the Trust Agreement or its failure to discharge Liens pursuant to Section 6.5 of the Trust Agreement, nor prevent recourse by any Lender or the Indenture Trustee against the Lessee in connection with the exercise or enforcement by any Lender or the Indenture Trustee of any rights or remedies under any of the Collateral Agreements as provided therein. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized as of the day and year first above written. RIVER BEND FUEL SERVICES, INC. By_________________________________ Title: Address: c/o Chemical Bank 450 West 33rd Street 15th Floor New York, New York 10001 Facsimile No.: (212) 613-7682 Attention: Jim Foley CIBC INC., as Agent By_________________________________ Title: Vice President PERCENTAGE COMMITMENT LENDERS 100% $25,000,000 CIBC INC. By________________________________ Title: Vice President (..continued) SCHEDULE I DISCLOSURE SCHEDULE ITEM 6.7 Litigation. Description of Proceeding Action or Claim Sought None ITEM 7.2.2(b) Ongoing Indebtedness. Outstanding Principal Amount Series A Notes $105,000,000 ITEM 7.2.5(a) Ongoing Investments. None NAME OF LENDER: CIBC Inc. PAYMENT INSTRUCTIONS: VIA FED FUNDS Morgan Guaranty Trust Company of New York 60 Wall Street New York, New York 10260 ABA #021-000-238 For account of: CIBC, New York Agency Account Number: 630-00-480 Reference: River Bend Fuel Services, Inc./Gulf States Utilities Attention: The Atlanta Agency Account Number: 0701610 VIA CHIPS: Morgan Guaranty Trust Company of New York 60 Wall Street New York, New York 10260 CHIPS Routing #023 For account of: CIBC, New York Agency Account Number: 630-00-480 Reference: River Bend Fuel Services, Inc./Gulf States Utilities Attention: The Atlanta Agency Account Number: 0701610 CREDIT CONTACT: Peter D. Gaw Vice President-Utilities Group Canadian Imperial Bank of Commerce 200 West Madison, Suite 2300 Chicago, Illinois 60606 Telephone Number: 312-855-3255 Fax Number: 312-750-0927 OPERATIONS CONTACT: Clare Coyne Senior Associate Canadian Imperial Bank of Commerce Two Paces West 2727 Paces Ferry Rd., Suite 1200 Atlanta, Georgia 30339 Telephone Number: 404-319-4836 Fax Number: 404-319-4950 Telex Number: 54-2413 DOMESTIC OFFICE AND LIBOR OFFICE: Canadian Imperial Bank of Commerce Two Paces West 2727 Paces Ferry Rd., Suite 1200 Atlanta, Georgia 30339 MAILINGS: Peter D. Gaw Vice President Canadian Imperial Bank of Commerce 200 W. Madison, Suite 2300 Chicago, Illinois 60606 TAX WITHHOLDINGS: Non Resident Alien - No Please copy both credit and operations contacts with all notices EXHIBIT A NOTE [BR-________] New York, New York $___________ ____________, 19___ FOR VALUE RECEIVED, the undersigned, RIVER BEND FUEL SERVICES, INC., a Delaware corporation (the "Borrower"), promises to pay to the order of ______________________ (the "Lender") on the Stated Maturity Date the principal sum of __________________ DOLLARS ($___________) or, if less, the aggregate unpaid principal amount of all Loans shown on the schedule attached hereto (and any continuation thereof) made by the Lender pursuant to that certain Credit Agreement, dated as of December __, 1993 (together with all amendments and other modifications, if any, from time to time thereafter made thereto, the "Credit Agreement"), among the Borrower, CIBC INC., as Agent, and the various financial institutions (including the Lender) as are, or may from time to time become, parties thereto. The Borrower also promises to pay interest on the unpaid principal amount hereof from time to time outstanding from the date hereof until maturity (whether by acceleration or otherwise) and, after maturity, until paid, at the rates per annum and on the dates specified in the Credit Agreement. Payments of both principal and interest are to be made in lawful money of the United States of America in same day or immediately available funds to the account designated by the Agent pursuant to the Credit Agreement. This Note is a Note referred to in, and evidences Indebtedness incurred under, the Credit Agreement, to which reference is made for a description of the security for this Note and for a statement of the terms and conditions on which the Borrower is permitted and required to make prepayments and repayments of principal of the Indebtedness evidenced by this Note and on which such Indebtedness may be declared to be immediately due and payable. Unless otherwise defined, terms used herein have the meanings provided in the Credit Agreement. All parties hereto, whether as makers, endorsers, or otherwise, severally waive presentment for payment, demand, protest and notice of dishonor. If the principal of and interest on this Note shall have been fully paid, this Note shall be surrendered by the holder hereof to the Indenture Trustee and shall be retired and cancelled. Before any sale or transfer of this Note, the holder of this Note shall make a notation hereon of the date to which interest has been paid and of all principal payments theretofore made hereon and shall in writing notify the Indenture Trustee referred to below of the name and address of the transferee. This Note is one of an issue of notes designated "Additional Notes" of the Borrower issued in the original aggregate principal amount of $25,000,000 under the Trust Indenture. The holder of this Note is entitled to the benefits of the Trust Indenture and may enforce each of the agreements of the Borrower as contained therein and may exercise each of the remedies provided thereby, or otherwise available in respect thereof, against the Borrower (subject to the limitations on individual actions by Noteholders contained in the Trust Indenture), but neither this reference to the Trust Indenture nor any provision thereof shall affect or impair the absolute and unconditional obligation of the Borrower to pay the principal amount of and interest on this Note as provided herein and in the Credit Agreement. The holder of this Note is also entitled to the benefits of the Collateral, and the rights of the holder hereof in the Collateral are subject to and governed by the provisions of the Trust Indenture and the Collateral Agreements, and the holder hereof shall not have any right to enforce any remedies with respect to the Collateral except to the extent and in the manner provided in the Trust Indenture. Reference is made to the Trust Indenture and the Collateral Agreements and supplements thereto for a description of the Collateral, the nature and extent of the security and rights of the Indenture Trustee in the Collateral and the rights of the holder or holders of the Notes in respect of the Collateral. Certain Series A Notes and any Additional Notes which may be issued from time to time under the Trust Indenture will be, secured equally and ratably with this Note to the extent provided in the Trust Indenture. As further provided in the Trust Indenture, upon surrender of this Note for transfer or exchange, a new Note or new Notes of the same tenor (except for the name of the holder) dated the date to which interest has been paid, or dated the date of this Note if no interest has theretofore been paid hereon, and in an aggregate principal amount equal to the unpaid principal amount of this Note will be issued to, and in the name of, the transferee or transferees. The Indenture Trustee may treat the person in whose name this Note is registered as the owner hereof for the purpose of receiving payment and for all other purposes, and the Indenture Trustee shall not be affected by any notice to the contrary. This Note shall not be valid until the Indenture Trustee signs the certificate of authentication on this Note. As more fully provided in the Trust Indenture and the Credit Agreement, the institutions or persons acting as Trustor, Owner Trustee and Indenture Trustee shall not be personally liable to the holder hereof for any amounts payable under this Note and such holder shall look solely to the Borrower, the Collateral under the Indenture and the Collateral Agreements to satisfy the obligations created hereby. THIS NOTE HAS BEEN DELIVERED IN NEW YORK, NEW YORK AND SHALL BE DEEMED TO BE A CONTRACT MADE UNDER AND GOVERNED BY THE INTERNAL LAWS OF THE STATE OF NEW YORK. Attest: RIVER BEND FUEL SERVICES, INC. By:________________________ By_____________________________ Title: Title: DATE OF AUTHENTICATION: UNITED STATES TRUST COMPANY OF NEW YORK, as Indenture Trustee, certifies that this is one of the Additional Notes referred to in the Indenture. By:___________________________ Authorized Officer LOANS AND PRINCIPAL PAYMENTS Amount of Unpaid Amount of Principal Principal Loan Made Repaid Balance _____________ Interest _______________ _______________ Base CD LIBO Period (if Base CD LIBO Base CD LIBO Notation Date Rate Rate Rate applicable) Rate Rate Rate Rate Rate Rate Total Made By ________________________________________________________________________________ ________________________________________________________________________________ ________________________________________________________________________________ ________________________________________________________________________________ ________________________________________________________________________________ ________________________________________________________________________________ ________________________________________________________________________________ ________________________________________________________________________________ ________________________________________________________________________________ ________________________________________________________________________________ ________________________________________________________________________________ ________________________________________________________________________________ EXHIBIT B BORROWING REQUEST [Name of Agent] [Address] Attention: [Name] [Title] RIVER BEND FUEL SERVICES, INC. Gentlemen and Ladies: This Borrowing Request is delivered to you pursuant to Section 2.3 of the Credit Agreement, dated as of December __, 1993 (together with all amendments, if any, from time to time made thereto, the "Credit Agreement"), among RIVER BEND FUEL SERVICES, INC., a Delaware corporation (the "Borrower"), certain financial institutions and CIBC INC. (the "Agent"). Unless otherwise defined herein or the context otherwise requires, terms used herein have the meanings provided in the Credit Agreement. The Borrower hereby requests that a Loan be made in the aggregate principal amount of $__________ on __________, 19___ as a [CD Rate Loan having an Interest Period of ____ days] [LIBO Rate Loan having an Interest Period of _______ months] [Base Rate Loan]. The Borrower hereby acknowledges that, pursuant to Section 5.2.2 of the Credit Agreement, each of the delivery of this Borrowing Request and the acceptance by the Borrower of the proceeds of the Loans requested hereby constitute a representation and warranty by the Borrower that, on the date of such Loans, and before and after giving effect thereto and to the application of the proceeds therefrom, all statements set forth in Section 5.2.1 are true and correct in all material respects. The Borrower agrees that if prior to the time of the Borrowing requested hereby any matter certified to herein by it will not be true and correct at such time as if then made, it will immediately so notify the Agent. Except to the extent, if any, that prior to the time of the Borrowing requested hereby the Agent shall receive written notice to the contrary from the Borrower, each matter certified to herein shall be deemed once again to be certified as true and correct at the date of such Borrowing as if then made. Please wire transfer the proceeds of the Borrowing in same day or immediately available funds to the Account of the Indenture Trustee at the financial institution indicated: Amount to be Person to be Paid Name, Address, etc. Transferred Name of Account Account No. of Indenture Trustee $___________ River Bend __________ ________________________ Fuel Services, ____________________ Inc. Collateral Attention ________ Account The Borrower has caused this Borrowing Request to be executed and delivered, and the certification and warranties contained herein to be made, by its duly Authorized Officer this ___ day of ___________, 19___. RIVER BEND FUEL SERVICES, INC. By _______________________________ Title: EXHIBIT C CONTINUATION/CONVERSION NOTICE [Name of Agent] [Address] Attention: [Name] [Title] RIVER BEND FUEL SERVICES, INC. Gentlemen and Ladies: This Continuation/Conversion Notice is delivered to you pursuant to Section 2.4 of the Credit Agreement, dated as of December __, 1993 (together with all amendments, if any, from time to time made thereto, the "Credit Agreement"), among RIVER BEND FUEL SERVICES, INC., a Delaware corporation (the "Borrower"), certain financial institutions and CIBC INC. (the "Agent"). Unless otherwise defined herein or the context otherwise requires, terms used herein have the meanings provided in the Credit Agreement. The Borrower hereby requests that on ____________, 19___, II $___________ of the presently outstanding principal amount of the Loans originally made on __________, 19___ [and $__________ of the presently outstanding principal amount of the Loans originally made on __________, 19___], III and all presently being maintained as *[Base Rate Loans] [CD Rate Loans] [LIBO Rate Loans], IV be [converted into] [continued as], (4) **[CD Rate Loans having an Interest Period of ______ days] [LIBO Rate Loans having an Interest Period of ______ months] [Base Rate Loans]. _______________________________ * Select appropriate interest rate option. ** Insert appropriate interest rate option. The Borrower hereby: .1. certifies and warrants that no Default has occurred and is continuing; and .2. agrees that if prior to the time of such continuation or conversion any matter certified to herein by it will not be true and correct at such time as if then made, it will immediately so notify the Agent. Except to the extent, if any, that prior to the time of the continuation or conversion requested hereby the Agent shall receive written notice to the contrary from the Borrower, each matter certified to herein shall be deemed to be certified at the date of such continuation or conversion as if then made. The Borrower has caused this Continuation/Conversion Notice to be executed and delivered, and the certification and warranties contained herein to be made, by its Authorized Officer this ___ day of _________, 19___. RIVER BEND FUEL SERVICES, INC. By _______________________________ Title: EXHIBIT D LENDER ASSIGNMENT AGREEMENT To: [Name of Borrower] To: [Name of Agent], as the Agent RIVER BEND FUEL SERVICES, INC. Gentlemen and Ladies: We refer to clause (d) of Section 10.11.1 of the Credit Agreement, dated as of December __, 1993 (together with all amendments and other modifications, if any, from time to time thereafter made thereto, the "Credit Agreement"), among RIVER BEND FUEL SERVICES, INC., a Delaware corporation (the "Borrower"), the various financial institutions (the "Lenders") as are, or shall from time to time become, parties thereto, and CIBC INC., as agent (the "Agent") for the Lenders. Unless otherwise defined herein or the context otherwise requires, terms used herein have the meanings provided in the Credit Agreement. This agreement is delivered to you pursuant to clause (d) of Section 10.11.1 of the Credit Agreement and also constitutes notice to each of you, pursuant to clause (c) of Section 10.11.1 of the Credit Agreement, of the assignment and delegation to _______________ (the "Assignee") of ___% of the Loans and Commitment of _____________ (the "Assignor") outstanding under the Credit Agreement on the date hereof. After giving effect to the foregoing assignment and delegation, the Assignor's and the Assignee's Percentages for the purposes of the Credit Agreement are set forth opposite such Person's name on the signature pages hereof. [Add paragraph dealing with accrued interest and fees with respect to Loans assigned.] The Assignee hereby acknowledges and confirms that it has received a copy of the Credit Agreement and the exhibits related thereto, together with copies of the documents which were required to be delivered under the Credit Agreement as a condition to the making of the Loans thereunder. The Assignee further confirms and agrees that in becoming a Lender and in making its Commitment and Loans under the Credit Agreement, such actions have and will be made without recourse to, or representation or warranty by the Agent. Except as otherwise provided in the Credit Agreement, effective as of the date of acceptance hereof by the Agent V the Assignee .1. shall be deemed automatically to have become a party to the Credit Agreement, have all the rights and obligations of a "Lender" under the Credit Agreement and the other Loan Documents as if it were an original signatory thereto to the extent specified in the second paragraph hereof; and .2. agrees to be bound by the terms and conditions set forth in the Credit Agreement and the other Loan Documents as if it were an original signatory thereto; and VI the Assignor shall be released from its obligations under the Credit Agreement and the other Loan Documents to the extent specified in the second paragraph hereof. The Assignor and the Assignee hereby agree that the [Assignor] [Assignee] will pay to the Agent the processing fee referred to in Section 10.11.1 of the Credit Agreement upon the delivery hereof. The Assignee hereby advises each of you of the following administrative details with respect to the assigned Loans and Commitment and requests the Agent to acknowledge receipt of this document: 1. Address for Notices: Institution Name: Attention: Domestic Office: Telephone: Facsimile: Telex (Answerback): LIBOR Office: Telephone: Facsimile: Telex (Answerback): 2. Payment Instructions: The Assignee agrees to furnish the tax form required by the second to last sentence of Section 4.6 (if so required) of the Credit Agreement no later than the date of acceptance hereof by the Agent. This Agreement may be executed by the Assignor and Assignee in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Adjusted Percentage [ASSIGNOR] Commitment and Loans: ___% By:__________________________ Title: Percentage [ASSIGNEE] Commitment and Loans: ___% By:__________________________ Title: Accepted and Acknowledged this ___ day of _______, 19__ ____________________________, as Agent By:_________________________ Title: EXHIBIT E [Opinion of Texas Counsel to GSU] EXHIBIT F [Opinion of Louisiana Counsel to GSU] EXHIBIT G [Opinion of New York Counsel to Borrower] EXHIBIT H [Opinion of Counsel to the Agent] EXHIBIT I Certificate of Authorized Officer of Obligor I, the undersigned, [Assistant] Secretary of ______________, a _______________ corporation (the "Obligor"), DO HEREBY CERTIFY that: This Certificate is furnished pursuant to Section 5.1.1 of that certain Credit Agreement, dated as of _______________, 19___ (the "Credit Agreement"), among the River Bend Fuel Services, Inc., certain financial institutions and ______________________ (the "Agent"). Unless otherwise defined herein, capitalized terms used in this Certificate have the meanings assigned to such terms in the Credit Agreement. There have been no amendments to the Articles of Incorporation of the Obligor since _________, 19__. Attached hereto as Annex I is a true, correct and complete copy of the by-laws of the Obligor as in effect on the date hereof. Attached hereto as Annex II is a true, correct and complete copy of resolutions duly adopted at a meeting of the Board of Directors and/or a committee thereof of the Obligor, convened and held on the ___ day of ____________, 19__ , which resolutions have not been revoked, modified, amended or rescinded and are still in full force and effect, and the [Credit Agreement, the Notes and the other Loan Documents] to which the Obligor is a party are in substantially the forms of those documents submitted to and approved by the Board of Directors of the Obligor at such meeting. _______________________________ * Insert the date of the Secretary of State's Certificate (attached to which is a copy of the Articles of Incorporation of the Obligor) furnished to the Agent at the execution of the Credit Agreement. The persons named in Annex III attached hereto have been duly elected, have duly qualified as and at all times since ____________, 19__ (to and including the date hereof), have been officers of the Obligor holding the respective offices set forth therein opposite their names, and the signatures set forth therein opposite their names are their genuine signatures. I know of no proceeding for the dissolution or liquidation of the Obligor or threatening its existence. WITNESS my hand and seal of the Obligor this ____ day of ________________, 19___. ____________________________ [Authorized Officer] [Affix Corporate Seal] I, the undersigned, [ ] of the Obligor DO HEREBY CERTIFY that: ___________________ is [a] the duly elected and qualified [ ] of the Obligor and the signature above is his genuine signature. The representations and warranties on the part of the Obligor contained in the Loan Documents executed by the Obligor are as true and correct at and as of the date hereof as though made on and as of the date hereof. No Default has occurred and is continuing, or would result from the consummation of the initial borrowing on this date. WITNESS my hand on this ____ day of __________________, 19___. _______________________________ [ ] Annex I to Exhibit I [Copy of the by-laws of ______________________] Annex II to Exhibit I Resolutions of the Board of Directors of _______________________ WHEREAS, there has been presented to this meeting a form of Credit Agreement (draft of ________________, 19___) (the "Credit Agreement"), among this Corporation, certain financial institutions (the "Lenders") and ____________________ (the "Agent"), providing for the making by the Lenders of certain Loans (as defined in the Credit Agreement) to this Corporation; [and] WHEREAS, it payment of this Corporation's obligations under and in connection with the Credit Agreement and the promissory notes to be executed by this Corporation pursuant thereto be secured by the Collateral Agreements (as defined in the Credit Agreement). NOW, THEREFORE, BE IT RESOLVED, that the President or any Vice President of this Corporation, and each of them, be and he hereby is authorized to execute, in the name and on behalf of this Corporation, and deliver a credit agreement among this Corporation, the Lenders and the Agent, substantially in the form of the Credit Agreement presented to this meeting, except for such changes, additions and deletions as to any or all of the terms and provisions thereof as the officer executing the Credit Agreement on behalf of this Corporation shall deem proper, such execution by such officer of the Credit Agreement to be conclusive evidence that such officer deems all of the terms and provisions thereof to be proper; FURTHER RESOLVED, that the President or any Vice President of this Corporation, and each of them, be and he hereby is authorized to borrow from time to time on behalf of this Corporation the amounts permitted or provided to be borrowed by this Corporation under the Credit Agreement executed by this Corporation pursuant to these resolutions, and to execute and deliver on behalf of this Corporation the promissory notes payable to the order of the Lenders, substantially in the form provided for as an exhibit to the Credit Agreement, evidencing such borrowings; [and] FURTHER RESOLVED, that each and every officer of this Corporation be and he hereby is authorized in the name and on behalf of this Corporation from time to time to take such actions and to execute and deliver such certificates, instruments, notices and documents as may be required or as such officer may deem necessary, advisable or proper in order to carry out and perform the obligations of this Corporation under the Credit Agreement, the Collateral Agreements and the Basic Documents (as defined in the Credit Agreement) executed by this Corporation pursuant to these resolutions, or under any other instrument or document executed pursuant to or in connection with the Credit Agreement, the Collateral Agreements or the Basic Documents; all such actions to be performed in such manner, and all such certifi cates, instruments, notices and documents to be executed and delivered in such form, as the officer performing or executing the same shall approve, the performance or execution thereof by such officer to be conclusive evidence of the approval thereof by such officer and by this Board of Directors. Annex III to Exhibit I Name of Officer Office Signature || TABLE OF CONTENTS Page I DEFINITIONS AND ACCOUNTING TERMS 1 1.1. Defined Terms 1 1.2. Use of Defined Terms 17 1.3. Cross-References 17 1.4. Accounting and Financial Determinations 18 II COMMITMENTS, BORROWING PROCEDURES AND NOTES 18 2.1. Commitments 18 2.1.1. Commitment of Each Lender 18 2.1.2. Lenders Not Permitted or Required To Make Loans 18 2.2. Optional Reduction of Commitment Amount 18 2.3. Borrowing Procedure 19 2.4. Continuation and Conversion Elections 19 2.5. Funding 19 2.6. Notes 20 2.7. Termination; Extension of Stated Maturity Date. 20 III REPAYMENTS, PREPAYMENTS, INTEREST AND FEES 21 3.1. Repayments and Prepayments 21 3.2. Interest Provisions 21 3.2.1. Rates 21 3.2.2. Post-Maturity Rates 24 3.2.3. Payment Dates 24 3.3. Fees 25 3.3.1. Commitment Fee 25 3.3.2. Facility Fee 25 3.3.3. Agent's Fee 25 IV CERTAIN CD RATE, LIBO RATE AND OTHER PROVISIONS 25 4.1. Fixed Rate Lending Unlawful 25 4.2. Deposits Unavailable 25 4.3. Increased Fixed Rate Loan Costs, etc. 26 4.4. Funding Losses 26 4.5. Increased Capital Costs 27 4.6. Taxes 27 4.7. Payments, Computations, etc. 28 4.8. Sharing of Payments 29 4.9. Setoff 30 4.10. Use of Proceeds 30 V CONDITIONS TO BORROWING 30 5.1. Initial Borrowing 30 5.1.1. Resolutions, etc. 30 5.1.2. Delivery of Notes 31 5.1.3. Loan Documents 31 5.1.4. Basic Documents 31 5.1.5. Opinions of Counsel 31 5.1.6. Closing Fees, Expenses, etc. 31 5.1.7. Governmental Approvals 32 5.1.8. Trust Indenture 32 5.1.9. Trust Agreement 32 5.2. All Borrowings 32 5.2.1. Compliance with Warranties, No Default, etc. 32 5.2.2. Borrowing Request 33 5.2.3. Satisfactory Legal Form 33 VI REPRESENTATIONS AND WARRANTIES 33 6.1. Organization, etc. 33 6.2. Due Authorization, Non-Contravention, etc. 34 6.3. Government Approval, Regulation, etc. 34 6.4. Validity, etc. 35 6.5. Financial Information 35 6.6. No Material Adverse Change 35 6.7. Litigation, Labor Controversies, etc. 36 6.8. Subsidiaries 36 6.9. Ownership of Properties 36 6.10. Taxes 36 6.11. Pension and Welfare Plans 36 6.12. Environmental Warranties 36 6.13. Regulations G, U and X 36 6.14. Accuracy of Information 36 6.15. Absence of Foreign Status 37 VII COVENANTS 37 7.1. Affirmative Covenants 37 7.1.1. Financial Information, Reports, Notices, etc. 37 7.1.2. Compliance with Laws, etc. 39 7.1.3. Maintenance of Properties 39 7.1.4. Insurance 39 7.1.5. Books and Records 40 7.2. Negative Covenants 40 7.2.1. Business Activities 40 7.2.2. Indebtedness 40 7.2.3. Liens 41 7.2.4. [Intentionally Omitted.] 42 7.2.5. Investments 42 7.2.6. Restricted Payments, etc. 43 7.2.7. Capital Expenditures, etc. 43 7.2.8. Rental Obligations 43 7.2.9. Take or Pay Contracts 43 7.2.10. Consolidation, Merger, etc. 43 7.2.11. Asset Dispositions, etc. 44 7.2.12. Modification of Certain Agreements 44 7.2.13. Transactions with Affiliates 44 7.2.14. Negative Pledges, Restrictive Agreements, etc. 44 VIII EVENTS OF DEFAULT 44 8.1. Listing of Events of Default 44 8.1.1. Non-Payment of Obligations 44 8.1.2. Breach of Warranty 45 8.1.3. Non-Performance of Certain Covenants and Obligations 45 8.1.4. Non-Performance of Other Covenants and Obligations 45 8.1.5. Default on Other Indebtedness 45 8.1.6. Judgments 45 8.1.7. Basic Documents 46 8.1.8. Control of the Borrower 46 8.1.9. Bankruptcy, Insolvency, etc. 46 8.1.10. Impairment of Security, etc. 47 8.2. Action if Bankruptcy 47 8.3. Action if Other Event of Default 47 IX THE AGENT 47 9.1. Actions 47 9.2. Funding Reliance, etc. 48 9.3. Exculpation 48 9.4. Successor 49 9.5. Loans by CIBC 50 9.6. Credit Decisions 50 9.7. Copies, etc. 50 X MISCELLANEOUS PROVISIONS 50 10.1. Waivers, Amendments, etc. 50 10.2. Notices 51 10.3. Payment of Costs and Expenses 52 10.4. Indemnification 52 10.5. Survival 53 10.6. Severability 53 10.7. Headings 54 10.8. Execution in Counterparts, Effectiveness, etc. 54 10.9. Governing Law; Entire Agreement 54 10.10. Successors and Assigns 54 10.11. Sale and Transfer of Loans and Note; Participations in Loans and Note 54 10.11.1. Assignments 54 10.11.2. Participations 56 10.12. Other Transactions 57 10.13. Forum Selection and Consent to Jurisdiction 57 10.14. Waiver of Jury Trial 57 10.15. Usury Not Intended 58 10.16. Revolving Credit Statute 59 10.17. No Recourse 59 SCHEDULE I - Disclosure Schedule SCHEDULE II - Name and Address of Lenders EXHIBIT A - Form of Note EXHIBIT B - Form of Borrowing Request EXHIBIT C - Form of Continuation/Conversion Notice EXHIBIT D - Form of Lender Assignment Agreement EXHIBIT E - Form of Opinion of Texas Counsel to GSU EXHIBIT F - Form of Opinion of Louisiana Counsel to GSU EXHIBIT G - Form of Opinion of New York Counsel to the Borrower EXHIBIT H - Form of Opinion of Counsel to the Agent EXHIBIT I - Form of Certificate of Authorized Officer of each Obligor EXHIBIT J - Form of Letter from GSU to the Lenders EXHIBIT K - Form of Certificate from GSU EX-10 6 Exhibit 10(e)11 Amendment To Service Agreement The parties hereto do hereby stipulated and agree that the SERVICE AGREEMENT entered into by and between them under date of April 1, 1963, and as heretofore amended on January 1, 1972, April 27, 1984, August 1, 1988, and January 28, 1991, be and the same hereby is further amended by substituting for Exhibit II to the SERVICE AGREEMENT, the attached revised Exhibit II. The effective date of this amendment is January 1, 1992. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed this 23rd day of April, 1992. ENTERGY SERVICES, INC. By: /s/ Lee W. Randall Title: Vice President CLIENT COMPANY LOUIANA POWER & LIGHT COMPANY By: /s/ Michael B. Bemis Title: President EXHIBIT II METHODS OF ALLOCATING COSTS AMONG CLIENT COMPANIES RECEIVING SERVICE UNDER THIS AND SIMILAR SERVICE AGREEMENTS WITH ENTERGY SERVICES, INC. (SERVICES) (January 1, 1992) 1. The costs of rendering service by Services will include all costs of doing business including interest on debt but excluding a return for the use of Services' initial equity capital amounting to $20,000. 2. (a) Services will maintain a separate record of the expenses of each department. The expenses of each department will include: (i) those expenses that are directly attributable to such department, and (ii) an appropriate portion of those office and housekeeping expenses that are not directly attributable to a department but which are necessary to the operation of such department. (b) Expenses of the department will include salaries and wages of employees, including social security taxes, vacations, paid absences, sickness, employee disability expenses, and other employee welfare expenses, rent and utilities, materials and supplies, depreciation, and all other expenses attributable to the department. (c) Departmental expenses will be categorized into one of two classes: (i) those expenses which are directly attributable to specific services rendered to a Client Company or group of Client Companies (Departmental Direct Costs), and (ii) those expenses which are attributable to the overall operation of the department and not to a specific service provided to Client Companies (Departmental Indirect Costs). Departmental Indirect Costs include: (1) Administrative labor costs associated with office and general service employees described in Section 3(a). This would include not only the salaries and wages of these employees but also other related employment costs described in Section 2(b) above. (2) Occupancy costs including rent and utilities. (3) Depreciation. (4) Materials and supplies, telephone use, postage, etc. (5) Other costs attributable to a department. (d) The indirect expenses of the department will not include: (i) those incremental out-of-pocket expenses that are incurred for the direct benefit and convenience of a Client Company or a group of Client Companies and are to be directly charged to such Client Company or group of Client Companies; and (ii) Services' overhead expenses that are attributable to maintaining the corporate existence of Services, franchise and other general taxes, and all other incidental overhead expenses including those auditing fees and accounting department expenses attributable to Services (Indirect Corporate Costs). (e) Services will establish annual budgets for controlling the expenses of each service department and those expenses outlined above in Section 2(d) which are not department specific. 3. (a) Employees in each department will be divided into two classes: A. Those employees rendered service to Client Companies (Class A), and B. Those office and general service employees, such as secretaries, stenographers, telephone operators and file clerks, who generally assist employees in Class A or render other house-keeping services and who are not engaged directly in rendering service to a Client Company or a group of Client Companies. In the event that any such office or general service employees are assigned to functions that are attributable to services being performed for Client Companies, such employees shall be reclassified as Class A employees. (b) Expenses set forth in Section 2 above will be separated to show: (i) salaries and wages of Class A employees, and (ii) all other expenses of the department. (c) Class A employees in each department will maintain a record of the time they are employed in rendering service to each Client Company or group of Client Companies. The hourly rate for each Class A employee will be determined each month. 4. (a) The charge to Client Company or a group of Client Companies for a particular service will be the sum of the figures derived by multiplying the hours reported by each Class A employee in rendering such service by the hourly rate applicable to such employee and other direct allocated expenses. (b) Departmental Indirect Costs as defined in Section 2(c)(ii) will be allocated in proportion to the direct salaries and wages charged. 5. Those expenses of Services that are not included in the expense of a department under Section 2 above will be charged to Client Companies receiving service as follows: (a) Incremental out-of-pocket costs incurred for the direct benefit and convenience of a Client Company or a group of Client Companies will be charged directly to such company or group of companies. (b) The Indirect Corporate Costs of Services referred to above in Section 2(d)(ii) will be allocated among the Client Companies in the same proportion as the charges to the Client Companies, excluding Indirect Corporate Costs. (c) If the method of allocation of Departmental Indirect Costs (Section 4(b)), or Indirect Corporate Costs (Section 5(b)), would result in an inequity because of a change in operations or organization of the Client Companies, then Services may adjust the basis to effect an equitable distribution. Any such change in allocation shall be made only after first giving to the Commission written notice of such proposed change not less than 60 days prior to the proposed effectiveness of any such change. 6. On the basis of the foregoing, monthly bills will be rendered to Client Companies. Billing procedures and amounts will be open to audit by Client Company and by any regulatory authority having jurisdiction in respect of the Client Company. 7. When services are rendered to a group of Client Companies, costs of such service shall be allocated equitably among the Companies based on the nature and scope of the service rendered according to the formulas outlined in Exhibit II, Supplement. Exhibit II, Supplement ALLOCATION FORMULAS FOR GROUPS OF CLIENT COMPANIES Note: Each allocation formula is based on data relevant to the participating Client Companies. Energy Sales Based on total kilowatt-hours of energy sold to Residential, Commercial, Industrial, Government and Municipal consumers. Customers Based on a twelve month average of Residential, Commercial, Industrial, Government and Municipal general business customers. Employees Based on the number of full time employees at year-end. Capability/Responsibility Ratio The Capability/Responsibility Ratio of a company is the System capability multiplied by the ratio obtained by dividing a company's peak load by the System peak load. The company's peak load is the average of the twelve monthly highest clock hour demands in kilowatts of the Company's interconnected system, occurring each month coincident with the System peak load, during the twelve month period ending with the current month. Composite - Energy Sales, Customers, Employees and Capability/Responsibility Ratio Based on four components with equal weighting to each: kilowatt-hour energy sales, average customers, number of employees and capability responsibility ratio. Composite - Energy Sales, Customers and DCS Employees Based on three components of equal weighting: kilowatt-hour energy sales, average customers and number of Distribution and Customer Service employees. Transmission Line Miles Based on the number of miles of transmission lines, weighted for design voltage. (Voltage < 500kv = 1, Voltage > 500kv = 2) Composite - Transmission Line Miles/Substations Based on two components: transmission line miles with a 30% weighting and the number of high voltage substations with a 70% weighting. Aircraft Ridership Based on employee use of company aircraft. Disaster Recovery Applications Based on the number of software applications that require alternate mainframe processing support for business continuity during a computer center disaster. Equity/Capitalization Ratio This ratio is computed for Entergy Corporation and the Client Companies as follows: - Entergy Corporation's allocation is the ratio of common shareholders equity to total capitalization; - the Client Companies allocation is the ratio of preferred stock plus long term debt to total capitalization. Final Bill Processing Based on the total number of final bills processed for collection. Gas Consumption Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System. Income and Deduction Ratio Based on the previous years federal income tax return, total income plus total deductions. Level of Service Based on Entergy Services' total billings to each Client Company excluding corporate overhead. Money Pool Transactions Based on each company's use of the money pool, weighted 75% on frequency of transactions, and 25% on dollar amount of the transaction. Nuclear and Casualty/Property Insurance Premiums Based on total Client Company costs for the previous year's insurance premium. Participants in Plans Several formulas are based on the number of participants in various Client Company plans and programs, such as: - Savings Plan - Flexible Benefits Programs - Master Trust Plan - ESOP - Student/Parent Loan Program - Systemwide Welfare Plans - Benefits Plus Flexible Spending Account - Non-Qualified Defined Contribution Restoration Plan - Personal Effects Floater Plan - Personal Property and Casualty Benefits Preferred Stockholders Based on total number of preferred stockholders at year-end. Revenues Based on total general business revenues from energy sales to Residential, Commercial, Industrial, Government and Municipal consumers. System Capacity Based on the power level, rated in kilowatts, that could be achieved if all generating units were operating at maximum capability simultaneously. EX-10 7 Exhibit 10(f)11 Amendment To Service Agreement The parties hereto do hereby stipulated and agree that the SERVICE AGREEMENT entered into by and between them under date of April 1, 1963, and as heretofore amended on January 1, 1972, April 27, 1984, August 1, 1988, and January 28, 1991, be and the same hereby is further amended by substituting for Exhibit II to the SERVICE AGREEMENT, the attached revised Exhibit II. The effective date of this amendment is January 1, 1992. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed this 23rd day of April, 1992. ENTERGY SERVICES, INC. By: /s/ Lee W. Randall Title: Vice President CLIENT COMPANY Mississippi Power & Light Company By: /s/ Donald E. Meiners Title: President EXHIBIT II METHODS OF ALLOCATING COSTS AMONG CLIENT COMPANIES RECEIVING SERVICE UNDER THIS AND SIMILAR SERVICE AGREEMENTS WITH ENTERGY SERVICES, INC. (SERVICES) (January 1, 1992) 1. The costs of rendering service by Services will include all costs of doing business including interest on debt but excluding a return for the use of Services' initial equity capital amounting to $20,000. 2. (a) Services will maintain a separate record of the expenses of each department. The expenses of each department will include: (i) those expenses that are directly attributable to such department, and (ii) an appropriate portion of those office and housekeeping expenses that are not directly attributable to a department but which are necessary to the operation of such department. (b) Expenses of the department will include salaries and wages of employees, including social security taxes, vacations, paid absences, sickness, employee disability expenses, and other employee welfare expenses, rent and utilities, materials and supplies, depreciation, and all other expenses attributable to the department. (c) Departmental expenses will be categorized into one of two classes: (i) those expenses which are directly attributable to specific services rendered to a Client Company or group of Client Companies (Departmental Direct Costs), and (ii) those expenses which are attributable to the overall operation of the department and not to a specific service provided to Client Companies (Departmental Indirect Costs). Departmental Indirect Costs include: (1) Administrative labor costs associated with office and general service employees described in Section 3(a). This would include not only the salaries and wages of these employees but also other related employment costs described in Section 2(b) above. (2) Occupancy costs including rent and utilities. (3) Depreciation. (4) Materials and supplies, telephone use, postage, etc. (5) Other costs attributable to a department. (d) The indirect expenses of the department will not include: (i) those incremental out-of-pocket expenses that are incurred for the direct benefit and convenience of a Client Company or a group of Client Companies and are to be directly charged to such Client Company or group of Client Companies; and (ii) Services' overhead expenses that are attributable to maintaining the corporate existence of Services, franchise and other general taxes, and all other incidental overhead expenses including those auditing fees and accounting department expenses attributable to Services (Indirect Corporate Costs). (e) Services will establish annual budgets for controlling the expenses of each service department and those expenses outlined above in Section 2(d) which are not department specific. 3. (a) Employees in each department will be divided into two classes: A. Those employees rendered service to Client Companies (Class A), and B. Those office and general service employees, such as secretaries, stenographers, telephone operators and file clerks, who generally assist employees in Class A or render other house-keeping services and who are not engaged directly in rendering service to a Client Company or a group of Client Companies. In the event that any such office or general service employees are assigned to functions that are attributable to services being performed for Client Companies, such employees shall be reclassified as Class A employees. (b) Expenses set forth in Section 2 above will be separated to show: (i) salaries and wages of Class A employees, and (ii) all other expenses of the department. (c) Class A employees in each department will maintain a record of the time they are employed in rendering service to each Client Company or group of Client Companies. The hourly rate for each Class A employee will be determined each month. 4. (a) The charge to Client Company or a group of Client Companies for a particular service will be the sum of the figures derived by multiplying the hours reported by each Class A employee in rendering such service by the hourly rate applicable to such employee and other direct allocated expenses. (b) Departmental Indirect Costs as defined in Section 2(c)(ii) will be allocated in proportion to the direct salaries and wages charged. 5. Those expenses of Services that are not included in the expense of a department under Section 2 above will be charged to Client Companies receiving service as follows: (a)Incremental out-of-pocket costs incurred for the direct benefit and convenience of a Client Company or a group of Client Companies will be charged directly to such company or group of companies. (b)The Indirect Corporate Costs of Services referred to above in Section 2(d)(ii) will be allocated among the Client Companies in the same proportion as the charges to the Client Companies, excluding Indirect Corporate Costs. (c)If the method of allocation of Departmental Indirect Costs (Section 4(b)), or Indirect Corporate Costs (Section 5(b)), would result in an inequity because of a change in operations or organization of the Client Companies, then Services may adjust the basis to effect an equitable distribution. Any such change in allocation shall be made only after first giving to the Commission written notice of such proposed change not less than 60 days prior to the proposed effectiveness of any such change. 6. On the basis of the foregoing, monthly bills will be rendered to Client Companies. Billing procedures and amounts will be open to audit by Client Company and by any regulatory authority having jurisdiction in respect of the Client Company. 7. When services are rendered to a group of Client Companies, costs of such service shall be allocated equitably among the Companies based on the nature and scope of the service rendered according to the formulas outlined in Exhibit II, Supplement. Exhibit II, Supplement ALLOCATION FORMULAS FOR GROUPS OF CLIENT COMPANIES Note: Each allocation formula is based on data relevant to the participating Client Companies. Energy Sales Based on total kilowatt-hours of energy sold to Residential, Commercial, Industrial, Government and Municipal consumers. Customers Based on a twelve month average of Residential, Commercial, Industrial, Government and Municipal general business customers. Employees Based on the number of full time employees at year-end. Capability/Responsibility Ratio The Capability/Responsibility Ratio of a company is the System capability multiplied by the ratio obtained by dividing a company's peak load by the System peak load. The company's peak load is the average of the twelve monthly highest clock hour demands in kilowatts of the Company's interconnected system, occurring each month coincident with the System peak load, during the twelve month period ending with the current month. Composite - Energy Sales, Customers, Employees and Capability/Responsibility Ratio Based on four components with equal weighting to each: kilowatt-hour energy sales, average customers, number of employees and capability responsibility ratio. Composite - Energy Sales, Customers and DCS Employees Based on three components of equal weighting: kilowatt-hour energy sales, average customers and number of Distribution and Customer Service employees. Transmission Line Miles Based on the number of miles of transmission lines, weighted for design voltage. (Voltage < 500kv = 1, Voltage > 500kv = 2) Composite - Transmission Line Miles/Substations Based on two components: transmission line miles with a 30% weighting and the number of high voltage substations with a 70% weighting. Aircraft Ridership Based on employee use of company aircraft. Disaster Recovery Applications Based on the number of software applications that require alternate mainframe processing support for business continuity during a computer center disaster. Equity/Capitalization Ratio This ratio is computed for Entergy Corporation and the Client Companies as follows: - Entergy Corporation's allocation is the ratio of common shareholders equity to total capitalization; - the Client Companies allocation is the ratio of preferred stock plus long term debt to total capitalization. Final Bill Processing Based on the total number of final bills processed for collection. Gas Consumption Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System. Income and Deduction Ratio Based on the previous years federal income tax return, total income plus total deductions. Level of Service Based on Entergy Services' total billings to each Client Company excluding corporate overhead. Money Pool Transactions Based on each company's use of the money pool, weighted 75% on frequency of transactions, and 25% on dollar amount of the transaction. Nuclear and Casualty/Property Insurance Premiums Based on total Client Company costs for the previous year's insurance premium. Participants in Plans Several formulas are based on the number of participants in various Client Company plans and programs, such as: - Savings Plan - Flexible Benefits Programs - Master Trust Plan - ESOP - Student/Parent Loan Program - Systemwide Welfare Plans - Benefits Plus Flexible Spending Account - Non-Qualified Defined Contribution Restoration Plan - Personal Effects Floater Plan - Personal Property and Casualty Benefits Preferred Stockholders Based on total number of preferred stockholders at year-end. Revenues Based on total general business revenues from energy sales to Residential, Commercial, Industrial, Government and Municipal consumers. System Capacity Based on the power level, rated in kilowatts, that could be achieved if all generating units were operating at maximum capability simultaneously. EX-10 8 Exhibit 10(g)11 Amendment To Service Agreement The parties hereto do hereby stipulated and agree that the SERVICE AGREEMENT entered into by and between them under date of April 1, 1963, and as heretofore amended on January 1, 1972, April 27, 1984, August 1, 1988, and January 28, 1991, be and the same hereby is further amended by substituting for Exhibit II to the SERVICE AGREEMENT, the attached revised Exhibit II. The effective date of this amendment is January 1, 1992. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed this 23rd day of April, 1992. ENTERGY SERVICES, INC. By: /s/ Lee W. Randall Title: Vice President CLIENT COMPANY New Orleans Public Service Inc. By: /s/ Michael B. Bemis Title: President EXHIBIT II METHODS OF ALLOCATING COSTS AMONG CLIENT COMPANIES RECEIVING SERVICE UNDER THIS AND SIMILAR SERVICE AGREEMENTS WITH ENTERGY SERVICES, INC. (SERVICES) (January 1, 1992) 1. The costs of rendering service by Services will include all costs of doing business including interest on debt but excluding a return for the use of Services' initial equity capital amounting to $20,000. 2. (a) Services will maintain a separate record of the expenses of each department. The expenses of each department will include: (i) those expenses that are directly attributable to such department, and (ii) an appropriate portion of those office and housekeeping expenses that are not directly attributable to a department but which are necessary to the operation of such department. (b) Expenses of the department will include salaries and wages of employees, including social security taxes, vacations, paid absences, sickness, employee disability expenses, and other employee welfare expenses, rent and utilities, materials and supplies, depreciation, and all other expenses attributable to the department. (c) Departmental expenses will be categorized into one of two classes: (i) those expenses which are directly attributable to specific services rendered to a Client Company or group of Client Companies (Departmental Direct Costs), and (ii) those expenses which are attributable to the overall operation of the department and not to a specific service provided to Client Companies (Departmental Indirect Costs). Departmental Indirect Costs include: (1) Administrative labor costs associated with office and general service employees described in Section 3(a). This would include not only the salaries and wages of these employees but also other related employment costs described in Section 2(b) above. (2) Occupancy costs including rent and utilities. (3) Depreciation. (4) Materials and supplies, telephone use, postage, etc. (5) Other costs attributable to a department. (d) The indirect expenses of the department will not include: (i) those incremental out-of-pocket expenses that are incurred for the direct benefit and convenience of a Client Company or a group of Client Companies and are to be directly charged to such Client Company or group of Client Companies; and (ii) Services' overhead expenses that are attributable to maintaining the corporate existence of Services, franchise and other general taxes, and all other incidental overhead expenses including those auditing fees and accounting department expenses attributable to Services (Indirect Corporate Costs). (e) Services will establish annual budgets for controlling the expenses of each service department and those expenses outlined above in Section 2(d) which are not department specific. 3. (a) Employees in each department will be divided into two classes: A. Those employees rendered service to Client Companies (Class A), and B. Those office and general service employees, such as secretaries, stenographers, telephone operators and file clerks, who generally assist employees in Class A or render other house-keeping services and who are not engaged directly in rendering service to a Client Company or a group of Client Companies. In the event that any such office or general service employees are assigned to functions that are attributable to services being performed for Client Companies, such employees shall be reclassified as Class A employees. (b) Expenses set forth in Section 2 above will be separated to show: (i) salaries and wages of Class A employees, and (ii) all other expenses of the department. (c) Class A employees in each department will maintain a record of the time they are employed in rendering service to each Client Company or group of Client Companies. The hourly rate for each Class A employee will be determined each month. 4. (a) The charge to Client Company or a group of Client Companies for a particular service will be the sum of the figures derived by multiplying the hours reported by each Class A employee in rendering such service by the hourly rate applicable to such employee and other direct allocated expenses. (b) Departmental Indirect Costs as defined in Section 2(c)(ii) will be allocated in proportion to the direct salaries and wages charged. 5. Those expenses of Services that are not included in the expense of a department under Section 2 above will be charged to Client Companies receiving service as follows: (a) Incremental out-of-pocket costs incurred for the direct benefit and convenience of a Client Company or a group of Client Companies will be charged directly to such company or group of companies. (b) The Indirect Corporate Costs of Services referred to above in Section 2(d)(ii) will be allocated among the Client Companies in the same proportion as the charges to the Client Companies, excluding Indirect Corporate Costs. (c) If the method of allocation of Departmental Indirect Costs (Section 4(b)), or Indirect Corporate Costs (Section 5(b)), would result in an inequity because of a change in operations or organization of the Client Companies, then Services may adjust the basis to effect an equitable distribution. Any such change in allocation shall be made only after first giving to the Commission written notice of such proposed change not less than 60 days prior to the proposed effectiveness of any such change. 6. On the basis of the foregoing, monthly bills will be rendered to Client Companies. Billing procedures and amounts will be open to audit by Client Company and by any regulatory authority having jurisdiction in respect of the Client Company. 7. When services are rendered to a group of Client Companies, costs of such service shall be allocated equitably among the Companies based on the nature and scope of the service rendered according to the formulas outlined in Exhibit II, Supplement. Exhibit II, Supplement ALLOCATION FORMULAS FOR GROUPS OF CLIENT COMPANIES Note: Each allocation formula is based on data relevant to the participating Client Companies. Energy Sales Based on total kilowatt-hours of energy sold to Residential, Commercial, Industrial, Government and Municipal consumers. Customers Based on a twelve month average of Residential, Commercial, Industrial, Government and Municipal general business customers. Employees Based on the number of full time employees at year-end. Capability/Responsibility Ratio The Capability/Responsibility Ratio of a company is the System capability multiplied by the ratio obtained by dividing a company's peak load by the System peak load. The company's peak load is the average of the twelve monthly highest clock hour demands in kilowatts of the Company's interconnected system, occurring each month coincident with the System peak load, during the twelve month period ending with the current month. Composite - Energy Sales, Customers, Employees and Capability/Responsibility Ratio Based on four components with equal weighting to each: kilowatt-hour energy sales, average customers, number of employees and capability responsibility ratio. Composite - Energy Sales, Customers and DCS Employees Based on three components of equal weighting: kilowatt-hour energy sales, average customers and number of Distribution and Customer Service employees. Transmission Line Miles Based on the number of miles of transmission lines, weighted for design voltage. (Voltage < 500kv = 1, Voltage > 500kv = 2) Composite - Transmission Line Miles/Substations Based on two components: transmission line miles with a 30% weighting and the number of high voltage substations with a 70% weighting. Aircraft Ridership Based on employee use of company aircraft. Disaster Recovery Applications Based on the number of software applications that require alternate mainframe processing support for business continuity during a computer center disaster. Equity/Capitalization Ratio This ratio is computed for Entergy Corporation and the Client Companies as follows: - Entergy Corporation's allocation is the ratio of common shareholders equity to total capitalization; - the Client Companies allocation is the ratio of preferred stock plus long term debt to total capitalization. Final Bill Processing Based on the total number of final bills processed for collection. Gas Consumption Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System. Income and Deduction Ratio Based on the previous years federal income tax return, total income plus total deductions. Level of Service Based on Entergy Services' total billings to each Client Company excluding corporate overhead. Money Pool Transactions Based on each company's use of the money pool, weighted 75% on frequency of transactions, and 25% on dollar amount of the transaction. Nuclear and Casualty/Property Insurance Premiums Based on total Client Company costs for the previous year's insurance premium. Participants in Plans Several formulas are based on the number of participants in various Client Company plans and programs, such as: - Savings Plan - Flexible Benefits Programs - Master Trust Plan - ESOP - Student/Parent Loan Program - Systemwide Welfare Plans - Benefits Plus Flexible Spending Account - Non-Qualified Defined Contribution Restoration Plan - Personal Effects Floater Plan - Personal Property and Casualty Benefits Preferred Stockholders Based on total number of preferred stockholders at year-end. Revenues Based on total general business revenues from energy sales to Residential, Commercial, Industrial, Government and Municipal consumers. System Capacity Based on the power level, rated in kilowatts, that could be achieved if all generating units were operating at maximum capability simultaneously. EX-12 9 Exhibit 12(a)
Arkansas Power and Light Company Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Dividends Twelve Months Ended December 31, 1990 1991 1992 1993 1994 (In Thousands, Except for Ratios) Fixed charges, as defined: Interest on long-term debt $101,412 $100,533 $89,317 $77,980 $71,704 Interest on long-term debt - other 31,195 33,321 31,000 29,791 29,735 Interest on notes payable 1,027 -- 117 349 1,311 Amortization of expense and premium on debt-net(cr) 1,792 1,112 1,359 2,702 4,563 Other interest 1,567 1,303 2,308 8,769 3,501 Interest applicable to rentals 24,233 21,969 17,657 16,860 19,140 ------------------------------------------------ Total fixed charges, as defined 161,226 158,238 141,758 136,451 129,954 Preferred dividends, as defined (a) 30,851 31,458 32,195 30,334 23,234 ------------------------------------------------ Combined fixed charges and preferred dividends, as defined $192,077 $189,696 $173,953 $166,785 $153,188 ================================================ Earnings as defined: Net Income $129,765 $143,451 $130,529 $205,297 $142,263 Add: Provision for income taxes: Federal & State 50,921 44,418 57,089 58,162 83,300 Deferred - net 17,943 11,048 3,490 34,748 (17,939) Investment tax credit adjustment - net (12,022) (1,600) (9,989) (10,573) (36,141) Fixed charges as above 161,226 158,238 141,758 136,451 129,954 ------------------------------------------------ Total earnings, as defined $347,833 $355,555 $322,877 $424,085 $301,437 ================================================ Ratio of earnings to fixed charges, as defined 2.16 2.25 2.28 3.11 2.32 ================================================ Ratio of earnings to combined fixed charges and preferred dividends, as defined 1.81 1.87 1.86 2.54 1.97 ================================================
------------------------ (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 10 Exhibit 12(b) Gulf States Utilities Company Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Dividends
Twelve Months Ended December 31, 1990 1991 1992 1993 1994 Fixed charges, as defined: Interest on mortgage bonds $218,462 $201,335 $197,218 $172,494 $167,082 Interest on notes payable 24,295 8,446 - - 763 Interest on long-term debt - other 12,668 19,507 21,155 19,440 19,440 Other interest 18,380 29,169 26,564 10,561 7,957 Amortization of expense and premium on debt-net(cr) 2,192 1,999 3,479 8,104 8,892 Interest applicable to rentals 23,761 24,049 23,759 23,455 21,539 ------------------------------------------------ Total fixed charges, as defined 299,758 284,505 272,175 234,054 225,673 Preferred dividends, as defined (a) 104,484 90,146 69,617 65,299 52,210 ------------------------------------------------ Combined fixed charges and preferred dividends, as defined $404,242 $374,651 $341,792 $299,353 $277,883 ================================================ Earnings as defined: Income (loss) from continuing operations before extrodinary items and the cumulative effect of accounting changes ($36,399) $112,391 $139,413 $69,462 ($82,755) Add: Income Taxes (24,216) 48,250 55,860 58,016 (62,086) Fixed charges as above 299,758 284,505 272,175 234,054 225,673 ------------------------------------------------ Total earnings, as defined $239,143 $445,146 $467,448 $361,532 $80,832 ================================================ Ratio of earnings to fixed charges, as defined 0.80 1.56 1.72 1.54 0.36 ================================================ Ratio of earnings to combined fixed charges and preferred dividends, as defined 0.59 1.19 1.37 1.21 0.29 ================================================
(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, 1994 and 1990, for GSU were not adequate to cover fixed charges by $144.8 million and $60.6 million, respectively. Earnings for the years ended December 31, 1994 and 1990, were not adequate to cover fixed charges and preferred dividends by $197.1 million and $165.1 million, respectively. EX-12 11 Exhibit 12(c) Louisiana Power and Light Company Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Dividends
Twelve Months Ended December 31, 1990 1991 1992 1993 1994 Fixed charges, as defined: Interest on mortgage bonds $101,996 $97,324 $68,247 $60,939 $58,338 Interest on long-term debt - other 52,361 61,492 60,425 63,694 66,482 Interest on notes payable 87 -- 150 898 1,948 Other interest charges 6,378 5,924 5,591 5,706 4,546 Amortization of expense and premium on debt - net(cr) 3,397 3,282 7,100 5,720 5,130 Interest applicable to rentals 12,906 11,381 9,363 8,519 8,332 ------------------------------------------------ Total fixed charges, as defined 177,125 179,403 150,876 145,476 144,776 Preferred dividends, as defined (a) 42,365 41,212 42,026 40,779 29,171 ------------------------------------------------ Combined fixed charges and preferred dividends, as defined $219,490 $220,615 $192,902 $186,255 $173,947 ================================================ Earnings as defined: Net Income $155,049 $166,572 $182,989 $188,808 $213,839 Add: Provision for income taxes: Federal and State 62,236 8,684 36,465 70,552 79,260 Deferred Federal and State - net (9,655) 67,792 51,889 43,017 21,580 Investment tax credit adjustment - net 26,646 8,244 (1,317) (2,756) (37,552) Fixed charges as above 177,125 179,403 150,876 145,476 144,776 ------------------------------------------------ Total earnings, as defined $411,401 $430,695 $420,902 $445,097 $421,903 ================================================ Ratio of earnings to fixed charges, as defined 2.32 2.40 2.79 3.06 2.91 ================================================ Ratio of earnings to combined fixed charges and preferred dividends, as defined 1.87 1.95 2.18 2.39 2.43 ================================================
------------------------ (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 12 Exhibit 12(d)
Mississippi Power and Light Company Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Dividends Twelve Months Ended December 31, 1990 1991 1992 1993 1994 Fixed charges, as defined: Interest on long-term debt $59,675 $59,440 $56,646 $48,029 $42,265 Interest on long-term debt - other 4,300 4,188 4,063 4,070 3,816 Interest on notes payable 1,512 953 36 7 1,348 Other interest charges 1,494 1,444 1,636 1,795 3,581 Amortization of expense and premium on debt-net(cr) 1,737 1,617 1,685 1,458 1,754 Interest applicable to rentals 596 574 521 1,264 1,716 ----------------------------------------------- Total fixed charges, as defined 69,314 68,216 64,587 56,623 54,480 Preferred dividends, as defined (a) 17,584 14,962 12,823 12,990 9,447 ----------------------------------------------- Combined fixed charges and preferred dividends, as defined $86,898 $83,178 $77,410 $69,613 $63,927 =============================================== Earnings as defined: Net Income $60,830 $63,088 $65,036 $101,743 $48,779 Add: Provision for income taxes: Federal and State 4,027 (1,001) 4,463 54,418 46,884 Deferred Federal and State - net 35,721 32,491 20,430 539 (26,763) Investment tax credit adjustment - net (1,835) (1,634) (1,746) 1,036 (7,645) Fixed charges as above 69,314 68,216 64,587 56,623 54,480 ------------------------------------------------ Total earnings, as defined $168,057 $161,160 $152,770 $214,359 $115,735 ================================================ Ratio of earnings to fixed charges, as defined 2.42 2.36 2.37 3.79 2.12 ================================================ Ratio of earnings to combined fixed charges and preferred dividends, as defined 1.93 1.94 1.97 3.08 1.81 ================================================
------------------------ (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 13 Exhibit 12(e)
New Orleans Public Service Inc. Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Dividends Twelve Months Ended December 31, 1990 1991 1992 1993 1994 Fixed charges, as defined: Interest on mortgage bonds $24,472 $23,865 $22,934 $19,478 $16,382 Interest on notes payable -- -- -- -- 153 Other interest charges 831 793 1,714 1,016 1,027 Amortization of expense and premium on debt-net(cr) 579 565 576 598 710 Interest applicable to rentals 160 517 444 544 1,245 Total fixed charges, as defined 26,042 25,740 25,668 21,636 19,517 Preferred dividends, as defined (a) 4,020 3,582 3,214 2,952 2,071 ----------------------------------------------- Combined fixed charges and preferred dividends, as defined $30,062 $29,322 $28,882 $24,588 $21,588 =============================================== Earnings as defined: Net Income $27,542 $74,699 $26,424 $47,709 $13,211 Add: Provision for income taxes: Federal and State 134 8,885 16,575 27,479 22,606 Deferred Federal and State - net 17,370 36,947 (340) 5,203 (15,674) Investment tax credit adjustment - net (75) (591) (170) (744) (2,332) Fixed charges as above 26,042 25,740 25,668 21,636 19,517 ----------------------------------------------- Total earnings, as defined $71,013 $145,680 $68,157 $101,283 $37,328 =============================================== Ratio of earnings to fixed charges, as defined 2.73 5.66 2.66 4.68 1.91 =============================================== Ratio of earnings to combined fixed charges and preferred dividends, as defined 2.36 4.97 2.36 4.12 1.73 ===============================================
------------------------ (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 14 Exhibit 12(f)
System Energy Resources, Inc. Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Fixed Charges Twelve Months Ended December 31, 1990 1991 1992 1993 1994 Fixed charges, as defined: Interest on mortgage bonds $138,689 $126,351 $104,429 $91,472 $79,025 Interest on other long-term debt 91,955 92,187 92,189 93,346 83,492 Interest on notes payable 0 0 0 0 88 Amortization of expense and premium on debt-net 10,532 7,495 6,417 4,520 6,731 Interest applicable to rentals 13,830 10,007 6,265 6,790 7,546 Other interest charges 1,460 3,617 1,506 1,600 7,168 ------------------------------------------------ Total fixed charges, as defined $256,466 $239,657 $210,806 $197,728 $184,050 ================================================ Earnings as defined: Net Income $168,677 $104,622 $130,141 $93,927 $5,407 Add: Provision for income taxes: Federal and State 4,620 (26,848) 35,082 48,314 67,477 Deferred Federal and State - net 52,962 37,168 23,648 60,690 (27,374) Investment tax credit adjustment - net 56,320 63,256 30,123 (30,452) (3,265) Fixed charges as above 256,466 239,657 210,806 197,728 184,050 ------------------------------------------------ Total earnings, as defined $539,045 $417,855 $429,800 $370,207 $226,295 ================================================ Ratio of earnings to fixed charges, as defined 2.10 1.74 2.04 1.87 1.23 ================================================
EX-21 15 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 Transener, S.A., LTD. (a) Cayman Islands Entergy Power Development Corporation (a) Delaware Entergy Richmond Power Corporation (e) Delaware Entergy Systems and Service, Inc. (f) Delaware Entergy Pakistan, LTD. (a) Delaware Entergy Power Asia, LTD. (a) Cayman Islands Entergy SASI (a) 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., Entergy Transener, S.A., LDT., Entergy Power Development Corporation, Entergy Pakistan, LTD., Entergy Power Asia, LTD., and Entergy SASI. (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 16 Exhibit 24 DATE: February 27, 1995 TO: Lee W. Randall Laurence M. Hamric FROM: Edwin Lupberger, et. al. SUBJECT: Power of Attorney Entergy Corporation, referred to herein as the Company, will file with the Securities and Exchange Commission their Annual Report on Form 10-K for the year ended December 31, 1994 pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. The Company and the undersigned, in their respective capacities as directors and/or officers of said Company 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 the undersigned and in his or her name, place and stead to sign and cause to be filed with the Securities and Exchange Commission the aforementioned Annual Report on Form 10-K and any amendments thereto. Yours very truly, Entergy Corporation By: /s/ Edwin Lupberger /s/ Gerald D. McInvale Edwin Lupberger Gerald D. McInvale Chairman of the Board Senior Vice President and and Chief Executive Officer Chief Financial Officer /s/ W. Frank Blount /s/ John A. Cooper, Jr. W. Frank Blount John A. Cooper, Jr. /s/ Lucie J. Fjeldstad /s/ Norman C. Francis Lucie J. Fjeldstad Norman C. Francis /s/ Kaneaster Hodges, Jr. /s/ Robert v.d. Luft Kaneaster Hodges, Jr. Robert v.d. Luft /s/ Edwin Lupberger /s/ Kinnaird R. McKee Edwin Lupberger Kinnaird R. McKee /s/ Paul W. Murrill _/s/ James R. Nichols Paul W. Murrill James R. Nichols /s/ Eugene H. Owen /s/ John N. Palmer, Sr. Eugene H. Owen John N. Palmer, Sr. /s/ Robert D. Pugh /s/ H. Duke Shackelford Robert D. Pugh H. Duke Shackelford /s/ Wm. Clifford Smith /s/ Bismark A. Steinhagen Wm. Clifford Smith Bismark A. Steinhagen Entergy Corporation Chairman of the Board, Chief Executive Officer and Director (principal executive officer) - Edwin Lupberger Senior Vice President and Chief Financial Officer (principal financial officer) - Gerald D. McInvale Directors - W. Frank Blount, John A. Cooper, Jr., Lucie J. Fjeldstad, Norman C. Francis, 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. DATE: February 27, 1995 TO: Lee W. Randall Laurence M. Hamric FROM: Edwin Lupberger, et. al. SUBJECT: Power of Attorney 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 respective Annual Reports on Form 10-K for the year ended December 31, 1994 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 the undersigned and in his or her name, place and stead to sign and cause to be filed with the Securities and Exchange Commission the aforementioned Annual Report on Form 10-K and any amendments thereto. Yours very truly, 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. By: /s/ Edwin Lupberger By: /s/ Donald C. Hintz Edwin Lupberger Donald C. Hintz Chairman of the Board and President and Chief Executive Officer Chief Executive Officer /s/ Gerald D. McInvale Gerald D. McInvale Senior Vice President and Chief Financial Officer /s/ Michael B. Bemis /s/ John J. Cordaro Michael B. Bemis John J. Cordaro /s/ Frank F. Gallaher /s/ Donald C. Hintz Frank F. Gallaher Donald C. Hintz /s/ Jerry D. Jackson /s/ R. Drake Keith Jerry D. Jackson R. Drake Keith /s/ Edwin Lupberger /s/ Jerry L. Maulden Edwin Lupberger Jerry L. Maulden /s/ Donald E. Meiners Donald E. Meiners Arkansas Power & Light Company Chairman of the Board, Chief Executive Officer and Director (principal executive officer) - Edwin Lupberger Senior Vice President and Chief Financial Officer (principal financial officer) - Gerald D. McInvale Directors - Michael B. Bemis, Donald C. Hintz, Jerry D. Jackson, R. Drake Keith, Jerry L. Maulden. Gulf States Utilities Company Chairman of the Board, Chief Executive Officer and Director (principal executive officer) - Edwin Lupberger Senior Vice President and Chief Financial Officer (principal financial officer) - Gerald D. McInvale Directors - Michael B. Bemis, Frank F. Gallaher, Donald C. Hintz, Jerry D. Jackson, Jerry L. Maulden. Louisiana Power & Light Company Chairman of the Board, Chief Executive Officer and Director (principal executive officer) - Edwin Lupberger Senior Vice President and Chief Financial Officer (principal financial officer) - Gerald D. McInvale Directors - Michael B. Bemis, John J. Cordaro, Donald C. Hintz, Jerry D. Jackson, Jerry L. Maulden. Mississippi Power & Light Company Chairman of the Board, Chief Executive Officer and Director (principal executive officer) - Edwin Lupberger Senior Vice President and Chief Financial Officer (principal financial officer) - Gerald D. McInvale Directors - Michael B. Bemis, Donald C. Hintz, Jerry D. Jackson, Jerry L. Maulden, Donald E. Meiners. New Orleans Public Service Inc. Chairman of the Board, Chief Executive Officer and Director (principal executive officer) - Edwin Lupberger Senior Vice President and Chief Financial Officer (principal financial officer) - Gerald D. McInvale Directors - John J. Cordaro, Jerry D. Jackson, Jerry L. Maulden. System Energy Resources, Inc. President, Chief Executive Officer and Director (principal executive officer) - Donald C. Hintz Senior Vice President and Chief Financial Officer (principal financial officer) - Gerald D. McInvale Directors - Edwin Lupberger, Jerry D. Jackson, Jerry L. Maulden. EX-5 17 Exhibit 99(a)3 [Letterhead of Clark, Thomas & Winters] March 27, 1995 Gulf States Utilities Company 639 Loyola Avenue New Orleans, Louisiana 70112 Attn: Scott Forbes Re: SEC Form 10-K Gulf States Utilities Company (the "Company") for the year ending December 31, 1994 Dear Mr. Forbes: Our firm has rendered to the Company two opinion letters dated September 30, 1992 and August 8, 1994, concerning certain issues presented in the appeal of PUCT Docket No. 7195 now pending in the Texas Supreme Court. 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 the letter dated August 8, 1994 and in the September 30, 1992 letter which addressed the recovery of $1.45 billion of abeyed construction costs.1 CLARK, THOMAS & WINTERS, A Professional Corporation By: /s/ CLARK, THOMAS & WINTERS, A Professional Corporation ________________________ The opinion letter dated September 30, 1992 indicates 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.