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 public utility holding company registered under PUHCA and does not own or operate any significant assets other than the stock of its subsidiaries. Entergy Corporation owns all of the outstanding common stock of five domestic 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, 1995, the Operating Companies provided electric service to approximately 2.4 million customers in the States of Arkansas, Louisiana, Mississippi, Tennessee, and Texas. In addition, GSU furnishes natural gas utility service in the Baton Rouge, Louisiana area, and NOPSI furnishes natural gas utility service in the New Orleans, Louisiana area. GSU produces and sells, on a nonregulated basis, process steam and by-product electricity supplied from its steam electric extraction plant to a large industrial customer. The business of the Operating Companies is subject to seasonal fluctuations with the peak period occurring during the third quarter. During 1995, the System's electric sales as a percentage of total System electric sales were: residential - - - - - 26.8%; commercial - 20%; and industrial - 40.8%. Electric revenues from these sectors as a percentage of total System electric revenues were: 35.6% - residential; 24.4% - commercial; and 29.6% - 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 directly all of the outstanding common stock of the following subsidiary companies: System Energy, Entergy Services, Entergy Operations, Entergy Power, Entergy Enterprises, Entergy S.A., Entergy Argentina S.A., Entergy Argentina S.A., Ltd., Entergy Power Development Corporation, Entergy Transener S.A., Entergy Power Marketing Corporation, Entergy Power Development International Holdings, Inc., and Entergy Power Development International Corporation. System Energy is a nuclear generating company that was incorporated under the laws of the State of Arkansas in 1974. System Energy sells at wholesale the capacity and energy 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 Operating 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 and in other 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 invests in and develops energy-related projects and other businesses that are or may be of benefit to the System's utility business (see "Domestic and Foreign Energy-Related Investments," below). Entergy Enterprises also markets outside the System technical expertise, products, and services developed by the Operating 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 also has subsidiaries that participate in utility projects located outside the System's retail service territory, both domestically and internationally. See "Domestic and Foreign Energy- Related Investments" and "CitiPower Acquisition," below) for a discussion of these subsidiaries.
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 Operating Companies.
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.
Unless otherwise noted, consolidated financial position and statistical information contained in this report for the years ended December 31, 1995, 1994, and 1993 (such as assets, liabilities, and property) includes the associated GSU amounts. Consolidated financial results and statistical information (such as revenues, sales, and expenses) for the years ended December 31, 1995 and 1994 includes such GSU amounts, while periods ending before January 1, 1994, do not include GSU amounts; those amounts are presented separately for GSU in this report.
Certain Industry and System Challenges
The System's business is affected by various challenges and issues, many of which confront the electric utility industry generally. These issues and challenges include:
- responding to an increasingly competitive environment (see "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - SIGNIFICANT FACTORS AND KNOWN TRENDS");
- addressing current and proposed structural changes in the electric utility industry and changes in the regulation of generation and transmission of electricity (see "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - SIGNIFICANT FACTORS AND KNOWN TRENDS");
- achieving cost savings anticipated with the Merger;
- complying 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);
- 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 - Cajun - River Bend Litigation," below); and
- implementing a new accounting standard that describes the circumstances in which assets are determined to be impaired, which may eventually be applied to "stranded costs" (costs not recoverable from those customers for whose benefit the costs were incurred) resulting from increased competition (see "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - SIGNIFICANT FACTORS AND KNOWN TRENDS,");
- achieving high levels of operating efficiencies, cost control, and returns on investments in Entergy Corporation's growing portfolio of non utility and overseas business ventures (see "Domestic and Foreign Energy-Related Investments" and "CitiPower Acquisition," below).
Domestic and Foreign Energy-Related Investments
Entergy Corporation seeks opportunities to expand its energy- related businesses that are not regulated by state and local regulatory authorities (nonregulated businesses). These nonregulated businesses currently include power development and new technology related to the utility business. Entergy Corporation's strategy is to identify and pursue nonregulated business opportunities that have the potential to earn a greater return than its regulated utility operations. Entergy Corporation has expanded its investments in nonregulated business opportunities overseas as well as in the United States. Through the end of 1995, Entergy Corporation had participated in foreign non- regulated electric ventures in Pakistan, Argentina, and Peru. As of December 31, 1995, Entergy Corporation had invested $555.5 million in equity capital (reduced by accumulated losses of $169 million) in nonregulated businesses. See the discussion below of Entergy Corporation's acquisition of CitiPower on January 5, 1996.
During 1995, Entergy Corporation's nonregulated businesses activities included the following:
(1) Entergy Power's $246.7 million debt obligation to Entergy Corporation was converted into equity in April 1995. Entergy Power sells capacity and energy from its 100% and 31.5% interest in Ritchie 2 and Independence 2, respectively. Entergy Power purchased an interest in these plants from AP&L in 1990. Entergy Corporation originally financed Entergy Power principally with a loan to Entergy Power. Entergy Power was formed to compete with other utilities and independent power producers in the bulk power market.
(2) In April 1995, Entergy Systems and Service, Inc. (Entergy SASI) and Systems and Service International, Inc. (SASI), amended their existing distribution agreement. As a result, Entergy SASI liquidated its equity interest in SASI. Previously, Entergy SASI, a subsidiary of Entergy Enterprises, held a 9.95% equity interest in SASI, a manufacturer of efficient lighting products. Entergy SASI distributes such products purchased under a distribution agreement with SASI, in conjunction with providing various energy management services to its customers. The amended distribution agreement discussed above provided for a reduction in SASI's profit margin on its sale of products to Entergy SASI and transferred the rights to certain of SASI's energy efficient technologies to Entergy SASI. In exchange, among other things, Entergy SASI transferred to SASI all of its equity ownership in SASI.
(3) In June 1995, Entergy Corporation contributed $125 million in equity capital to Entergy SASI through Entergy Enterprises, Inc., thus allowing Entergy SASI to retire its debt obligation to Entergy Corporation. Entergy Corporation had previously provided loans to Entergy SASI to fund Entergy SASI's business expansion.
(4) As of December 31, 1995, Entergy Enterprises wrote down its equity interest in First Pacific Networks (FPN), a communications company, by $9.3 million to reflect what management believes is a permanent decline in market value. Entergy Enterprises holds a 7.9% equity interest in FPN. The total cost of Entergy Enterprises' investment in FPN as of December 31, 1995, was approximately $1.2 million.
(5) In June 1995, Entergy Corporation received SEC authorization to invest up to $350 million through December 31, 1997, in Entergy Enterprises. Such investments may take the form of purchases of common stock, capital contributions, loans, and/or guarantees of indebtedness or other obligations of Entergy Enterprises or certain of its affiliated companies. In January 1995 Entergy Corporation guaranteed $65 million of EP Edegel, Inc., a subsidiary of Entergy Corporation, obligations.
(6) In 1995, Entergy Corporation has requested approval from the SEC to form a new nonregulated subsidiary named Entergy Technologies Company (ETC). ETC would offer bulk interstate telecommunications service to telecommunications carriers which in turn would market that service to third parties. The recently enacted Telecommunications Reform Act of 1996 permits Entergy to market such a service, pending state and local regulatory approval. See MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - SIGNIFICANT FACTORS AND KNOWN TRENDS for a discussion of the Telecommunications Act of 1996 and its impact on Entergy.
(7) During the third quarter of 1995, Entergy Corporation's subsidiary, Entergy S.A., purchased 3.9% of the outstanding stock of the Central Buenos Aires Project (CBA Project) for $1.7 million. Entergy S.A., owns a 10% interest in a consortium with other nonaffiliated companies that acquired a 60% interest in Central Costanera, S.A. (Costanera), a steam electric generating facility located in Argentina. Through Entergy S.A.'s interest in Costanera, Entergy S.A. indirectly purchased an additional 3% of the outstanding stock of the CBA Project. In October 1995, Entergy Power Holding Limited, a wholly owned subsidiary of Entergy Corporation, purchased Entergy S.A.'s interest in the CBA Project and purchased an additional 3.9% of the outstanding stock of the CBA Project for $1.9 million. The CBA Project includes the addition of a 220 MW combustion turbine and heat recovery boiler to a generating unit at the Costanera steam electric generating facility. This addition will provide electricity to the Argentina transmission grid and steam to the Costanera generating unit. The open cycle portion of the CBA Project, providing electricity to the Argentina grid, was placed into operation at the end of October 1995. The steam recovery portion, which will provide steam to the Costanera generating unit, is expected to be in operation in October 1996.
(8) On November 30, 1995, Entergy Corporation's subsidiary, Entergy Power Development Corporation, purchased through a consortium 20.8% of Edegel, S.A. for $100 million in equity and $65 million of debt guaranteed by Entergy Corporation. Edegel S.A. is a privatization project in Lima, Peru consisting of 5 hydroelectric generation stations (totaling 539 MW) and one thermal station (154 MW) supporting 345 miles of transmission lines. An additional 100 MW of thermal load capacity is required to be installed within one year. The additional plant is expected to be financed by Edegel S.A.
(9) In early October 1995, FERC issued an order granting exempt wholesale generator status to Entergy Power Marketing Corporation (EPM), a wholly owned subsidiary of Entergy Corporation. EPM was created during 1995 to become a buyer and seller of electrical energy and its generating fuels. In February 1996, FERC approved market-based rate sales of electricity by EPM. Such approval will allow EPM to begin providing wholesale customers with a variety of products including physical and financial trading. Pending approval from the SEC, EPM expects to begin financial trading by the summer of 1996.
Entergy Corporation's net investment in nonregulated subsidiaries, reduced by accumulated losses, as of December 31, 1995 and 1994, is as follows:
Net Investment Nonregulated Subsidiary 1995* 1994 ----------------------- --------- -------- (In Millions)
Entergy Power Development $ 180.6 $ 80.8 Corporation Entergy Power, Inc. 173.1 154.4 Entergy Enterprises, Inc. 112.0 22.2 Entergy Argentina S.A., Ltd. 42.0 41.1 Entergy Transener 19.0 22.7 Entergy Argentina 17.4 17.1 Entergy S.A. 11.4 13.3 -------- -------- Total $ 555.5 $351.6 ======== =======
* Excludes Entergy Corporation's equity investment in CitiPower completed on January 5, 1996. See "CitiPower Acquisition" below.
In 1995, Entergy Corporation's nonregulated investments reduced consolidated net income by approximately $64.8 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. Certain of 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 currency exchange controls, limitations on foreign participation in local energy-related enterprises, and other restrictions. Changes in the relative value of currencies occur 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.
CitiPower Acquisition
On January 5, 1996, Entergy Corporation finalized its acquisition of CitiPower, an electric distribution company serving Melbourne, Australia, and surrounding suburbs. The purchase price of CitiPower was approximately $1.2 billion, of which $294 million represented an equity investment by Entergy Corporation, and the remainder represented debt. Entergy Corporation funded the majority of the equity portion of the investment by using $230 million of its $300 million line of credit. CitiPower serves approximately 234,500 customers, the majority of which are commercial customers. At the time of the acquisition, CitiPower had 846 employees.
Selected Data
Selected domestic customer and sales data for 1995 are summarized in the following tables:
1995 - Selected Electric Energy Sales Data
NOPSI sold 16,782,805 MCF of natural gas to retail customers in 1995. Revenues from natural gas operations for each of the three years in the period ended December 31, 1995, were material for NOPSI, but not material for the System (see "INDUSTRY SEGMENTS" below for a description of NOPSI's business segments).
GSU sold 6,476,496 MCF of natural gas to retail customers in 1995. Revenues from natural gas operations for each of the three years in the period ended December 31, 1995, 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 financial statements in this report) for further information with respect to operating statistics.
Employees
As of December 31, 1995, Entergy had 13,521 employees as follows:
Full-time: Entergy Corporation - AP&L 1,647 GSU 1,833 LP&L 1,082 MP&L 892 NOPSI 489 System Energy - Entergy Operations 4,102 Entergy Services 2,529 Other Subsidiaries 869 ------ Total Full-time 13,443 Part-time 78 ------ Total Entergy System 13,521 ====== Competition
Refer to "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - SIGNIFICANT FACTORS AND KNOWN TRENDS" for a detailed discussion of competitive challenges Entergy faces in the utility industry.
CAPITAL REQUIREMENTS AND FUTURE FINANCING
Construction expenditures by company (including environmental expenditures, which are immaterial, and AFUDC, but excluding nuclear fuel) for the period 1996-1998 are estimated as follows:
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 System must meet scheduled long-term debt and preferred stock maturities and cash sinking fund requirements. See Notes 4, 5, and 6 to the financial statements for further capital requirements and financing information.
Entergy Corporation's primary capital requirements are to invest periodically in, or make loans to, its subsidiaries and to invest in new energy-related enterprises. See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - LIQUIDITY AND CAPITAL RESOURCES," for additional discussion of Entergy Corporation's current and future planned investments in its subsidiaries and financial sources for such investments. One source of funds for Entergy is dividend distributions from its subsidiaries. Certain events could limit the amount of these distributions. Such events include 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. See Notes 2 and 8 to the financial statements regarding River Bend rate appeals and pending litigation with Cajun.
Certain System Financial and Support Agreements
Unit Power Sales Agreement (AP&L, LP&L, MP&L, NOPSI, and System Energy)
The Unit Power Sales Agreement allocates capacity and energy from System Energy's 90% ownership and leasehold interests in Grand Gulf 1 (and the related costs) to AP&L (36%), LP&L (14%), MP&L (33%), and NOPSI (17%). AP&L, LP&L, MP&L, and NOPSI make payments 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 the receipt of payments from AP&L, LP&L, MP&L, and NOPSI. Payments made by AP&L, LP&L, MP&L, and NOPSI under the Unit Power Sales Agreement are generally recovered through rates. In the case of AP&L and LP&L, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf 1. See Note 1 to the financial statements for further information regarding retained shares.
Availability Agreement (AP&L, LP&L, MP&L, NOPSI, and System Energy)
The Availability Agreement among System Energy and AP&L, LP&L, MP&L, and NOPSI was entered into in 1974 in connection with the financing by System Energy of Grand Gulf. 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 Grand Gulf.
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 Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement, or otherwise) would at least equal System Energy's total operating expenses for Grand Gulf (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 become effective upon commercial operation of Grand Gulf 1 on July 1, 1985;
- the sale of capacity and energy generated by Grand Gulf 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 under such agreement 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 in Note 9 to the financial statements under "Sale and Leaseback Transactions - Grand Gulf 1 Lease Obligations (System Energy)." 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), 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 that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of 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 such filing with FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. 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 PUHCA, 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.
Since commercial operation of Grand Gulf 1 began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments under the Availability Agreement by AP&L, LP&L, MP&L, and NOPSI have ever been required. In the event such payments were required, the ability of AP&L, LP&L, MP&L, and NOPSI to recover from their customers amounts paid under the Availability Agreement, or under the assignments thereof, would depend upon the outcome of rate proceedings before state and local regulatory authorities. 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 full recovery would be likely and the outcome of such proceedings, should they occur, is not predictable.
Capital Funds Agreement (Entergy Corporation and System Energy)
System Energy and Entergy Corporation have entered into the Capital Funds Agreement whereby Entergy Corporation has agreed to supply System Energy with sufficient capital to (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 continued commercial operation of Grand Gulf 1 and 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 under such supplements as security for its first mortgage bonds and for reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 9 to the financial statements under "Sale and Leaseback Transactions - Grand Gulf 1 Lease Obligations (System Energy)." Each such supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of Grand Gulf may be secured by System Energy's rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as defined below). In addition, in the supplements to the Capital Funds Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital contributions directly to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). However, if there is an event of default, Entergy Corporation must make those payments directly to the holders of indebtedness benefiting from the supplemental agreements. The payments (other than the Specific Payments) must be made pro rata according to the amount of the respective obligations benefiting from the supplemental agreements.
RATE MATTERS AND REGULATION
Rate Matters
The Operating Companies' retail rates are regulated by state and/or local regulatory authorities, as described below. FERC regulates their wholesale rates (including intrasystem sales pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy's sales of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI pursuant to the Unit Power Sales Agreement.
Wholesale Rate Matters
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 capacity and energy under the Unit Power Sales Agreement.
On December 12, 1995, System Energy implemented a $65.5 million rate increase, subject to refund. Refer to Note 2 for a discussion of the rate increase filed by System Energy with FERC.
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 interest in Independence 2 and Ritchie 2, and to begin marketing the capacity and energy from the units in certain wholesale markets. The SEC order was appealed to the D.C. Circuit by various intervenors. The D.C. Circuit reversed a portion of the SEC 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. 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, pursuant to its settlement with NOPSI of various issues related to the Merger. In November 1995, the SEC issued an order in which the SEC reaffirmed its prior order authorizing the acquisition and formation of Entergy Power and denying the LPSC's request for a hearing. The November 1995 order was not appealed, and the statutory period for such an appeal has expired.
In a related matter, 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 and the effect of the transfer on AP&L, LP&L, MP&L, NOPSI, and their ratepayers. On October 20, 1995, the D.C. Circuit affirmed FERC's original orders that the transfer and its effect on current rates was prudent. However, a determination of the prudency of the transfer on future replacement costs was deferred until a time when the need for such replacement capacity occurs.
System Agreement (Energy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy)
AP&L, GSU, 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 as described under "PROPERTY - Generating Stations," below.
In connection with the Merger, FERC approved certain rate schedule changes to integrate GSU into the System Agreement. Certain commitments were also adopted to assure that the ratepayers of AP&L, LP&L, MP&L, and NOPSI will not be allocated higher costs. Such commitments included: (1) a tracking mechanism to protect these companies from certain unexpected increases in fuel costs; (2) the exclusion of 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 these companies be insulated from certain direct effects on capacity equalization payments if GSU should 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. In connection with this proceeding, the LPSC and the MPSC submitted testimony seeking retroactive refunds for LP&L and MP&L (estimated at $22.6 million and $13.2 million, respectively). The FERC staff subsequently submitted testimony concluding that Entergy's treatment was reasonable. However, because it concluded that Entergy's treatment violated the tariff, FERC staff maintained that 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.
On March 3, 1995, a FERC ALJ issued an opinion holding that the practice of including the out-of-service units in the reserve equalization calculations during the period 1987 through 1993 was not permitted by Service Schedule MSS-1 and, therefore, constituted a violation of the System Agreement. However, the ALJ found that the violation was in good faith and had benefited the customers of the System as a whole. Accordingly, the ALJ recommended that no retroactive refunds should be ordered. The ALJ also held that the System Agreement should be amended to allow out-of-service units to be included in reserve equalization as proposed in an offer of settlement filed by Entergy on February 16, 1994. The ALJ's opinion is subject to review by FERC. If FERC concurs with the finding that the System Agreement was violated, it would have the discretion to order that refunds be made. If that were to occur, certain Operating Companies may be required to refund some or all of the amount by which they were underbilled pursuant to the System Agreement. The Operating Companies cannot determine at this time whether they would be authorized to recover through retail rates any amounts associated with refunds that might be ordered by FERC in this proceeding. The matter remains pending before FERC.
On March 14, 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 an Operating Company's responsibility for reserve equalization and transmission equalization costs results in an unjust and unreasonable cost allocation to the Operating Companies that does not cause these costs to be incurred, and also results in cross- subsidization among the Operating Companies. Further, the LPSC alleges that the mechanism by which the Operating Companies purchase energy under the System Agreement results in unjust and unreasonable rates because it does not permit Operating Companies that engage in real time pricing to be charged the marginal cost of the energy generated for the real time pricing customer. In May 1995, the LPSC amended its original complaint and Entergy subsequently filed an answer to the LPSC's amended complaint. The LPSC's amended complaint asserts that the System Agreement should be revised to exclude curtailable load from the cost allocation determination due to conflicts with federal policies under PURPA and with Entergy's system planning philosophy. Entergy's response asserts that both the provisions under PURPA and the Entergy system planning philosophy referred to in the LPSC's amended complaint are applicable only to retail sales.
In June 1995, the APSC filed a complaint with FERC alleging that, because of changed circumstances, FERC's allocation of nuclear decommissioning costs in the System is no longer just and reasonable. The APSC proposes that the System Agreement be amended to provide a new schedule that would equalize nuclear decommissioning costs according to load responsibility among the pre-merger operating companies.
Open Access Transmission (Entergy Corporation, AP&L, GSU, LP&L, MP&L, and NOPSI)
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. FERC approved the filing in August 1992, and various parties filed appeals with the D.C. Circuit. The case was remanded to FERC in July 1994 for further proceedings. On October 31, 1994, Entergy Services as agent for AP&L, GSU, LP&L, MP&L, and NOPSI filed revised transmission tariffs. On January 6, 1995, FERC issued an order accepting the tariffs for filing and made them effective, subject to refund. These tariffs provide both point-to-point and network transmission service, and are intended to provide "comparability of service" over the Entergy transmission network. In that order FERC also ordered that Entergy Power's market pricing authority be investigated, thereby making Entergy Power's market price rate schedules subject to refund. An order in the market price rate investigation is expected to be issued by January 1997. Entergy expects that no refunds relating to market price rates will be required.
On March 29, 1995, FERC issued a supplemental notice of proposed rulemaking (Mega-NOPR) which would require public utilities to provide non-discriminatory open access transmission service to wholesale customers, and which would also provide guidance on the recovery of wholesale and retail stranded costs. Under the proposal, public utilities would be required to file transmission tariffs for both point- to-point and network service. Model transmission tariffs were included in the proposal. With regard to pending proceedings, including Entergy's tariff proceeding, FERC directed the parties to proceed with their cases while taking into account FERC's views expressed in the proposed rule. Hearings relating to Entergy Services' open access tariffs concluded on February 22, 1996.
In September 1995 and January 1996, Entergy Services filed offers of partial settlement accepting certain provisions of the transmission tariffs contained in the Mega-NOPR and resolving certain rate issues. The remaining rate and tariff issues will be resolved as part of the FERC's rulemaking in the Mega-NOPR, or after scheduled hearings. In August 1995, EPM filed an application for permission to make market- based sales, but subsequently asked that action not be taken on that request until the open access transmission service proceeding discussed above is resolved. On December 13, 1995, Entergy Services filed revised transmission tariffs in a separate proceeding proposing terms and conditions for open access transmission service that are substantially identical to the terms and conditions contained in the Mega-NOPR transmission tariffs with rates to be the same as those determined in the pending proceeding. On February 14, 1996, FERC accepted for filing the revised transmission tariffs making rates subject to the outcome of the pending proceeding and conditionally accepted EPM's application for market based sales.
Wholesale Contract (AP&L)
In March 1994, North Little Rock, Arkansas awarded to 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. In September 1995, FERC denied the petition for rehearing.
Retail Rate Matters
General (AP&L, GSU, LP&L, MP&L, and NOPSI)
Certain costs related to Grand Gulf 1, Waterford 3, and River Bend were phased into retail rates over a period of years 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, GSU, LP&L, MP&L, and NOPSI are now recovering those costs that were previously deferred.
GSU is involved in several rate proceedings involving, among other things, recovery 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 was disallowed while other costs were 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 as discussed in "GSU" below.
As a means of minimizing the need for retail rate increases, the System is committed to containing costs to the greatest degree practicable. In accordance with this retail rate policy, the Operating Companies have agreed to retail rate caps and/or rate freezes for specified periods of time.
The retail regulatory philosophy is shifting in some jurisdictions from traditional cost of service regulation to incentive rate regulation. System management believes incentive and performance-based rate plans encourage efficiencies and productivity while permitting utilities and their customers to share in the resulting benefits. MP&L implemented an incentive-rate plan in March 1994, and, in June 1995, LP&L implemented a performance-based formula rate plan. 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.
Least Cost Integrated Resource Planning (AP&L, GSU, LP&L, MP&L, and NOPSI)
The System continues to utilize integrated resource planning (IRP), also known as least cost planning, in order to compete more effectively in both retail and wholesale markets. IRP is the development of integrated supply and demand side strategies to meet future electricity demands reliably, at the lowest possible cost, and in a more competitive manner.
In 1992, AP&L, LP&L, MP&L, and NOPSI each filed a Least Cost Integrated Resource Plan (LCIRP) with its respective regulator. However, in 1994 the System substantially revised its approach to IRP, and AP&L, LP&L, MP&L, and NOPSI requested that their retail regulators allow for significant changes in the IRP process. At MP&L's request, the MPSC dismissed MP&L's LCIRP filing. Due to the increasingly competitive nature of the electric service market, the System believes that changes in the IRP process are required. Entergy has adopted a streamlined process that focuses on minimizing the cost of incremental resources and maximizing the System's flexibility to adapt its resource plans to the changing environment in which electric utilities now operate.
On October 10, 1995, despite Entergy's request, the APSC issued an order requiring that Arkansas utilities file current integrated resource plans at least every three years. In this order, the APSC emphasized that planning processes must continue to evolve and publicly available information on utility resource plans must be maintained. The LPSC has established generic hearings to address IRP issues for all electric utilities within its jurisdiction. These proceedings are currently ongoing. The Council has suspended the requirement to file an LCIRP with the Council and has received testimony and held public hearings regarding the revision of its IRP Ordinance. LP&L and NOPSI are awaiting an order from the Council that would resolve the matter of IRP. Currently, the PUCT does not have formal IRP rules in place. Legislation passed in 1995 requires that the PUCT have IRP rules in place by September of 1996. This rulemaking process has been initiated by the PUCT, and GSU is actively participating in this process.
In the fourth quarter of 1995, the System provided to its retail regulators (the APSC, the Council, the LPSC, the MPSC, and the PUCT) a new IRP for informational purposes only. The new IRP provides for a flexible resource strategy to meet the System's additional resource requirements over the next ten years. The IRP provides for the utilization of capacity currently in extended reserve shutdown to meet additional load growth, but also provides the flexibility to rely on short-term power purchases, upgrades to existing nuclear capacity, or cogeneration when these resources are more economical.
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 certain instances. See Note 2 for a discussion of the rate freeze as well as other aspects of the settlement agreement between AP&L and the APSC.
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 1995 and subsequent years, AP&L retains 22% of its 36% interest in Grand Gulf 1 costs and recovers the remaining 78%. Deferrals ceased in l990, and AP&L is recovering a portion of the previously deferred costs each year through l998. As of December 31, l995, the balance of deferred costs was $360 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 accrue to the benefit of AP&L's stockholder.
Fuel Adjustment Clause
AP&L's retail rate schedules include a fuel adjustment clause to recover the excess cost of fuel and purchased power incurred in the second prior 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, which included the implementation of a five-year Rate Cap on GSU's retail electric base rates in the respective states and provisions for passing fuel and nonfuel savings created by the Merger on to the customers. See Note 2 for a discussion of the Rate Cap as well as other aspects of the settlement agreement between GSU and the LPSC and the PUCT.
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 as discussed in "Texas Jurisdiction - River Bend," below. As of December 31, 1995, the unamortized balance of these costs was $312 million. Further, GSU deferred approximately $400.4 million of similar costs pursuant to a 1986 LPSC accounting order. These costs, of which approximately $83 million are unamortized as of December 31, 1995, are being amortized over a 10-year period ending in 1998.
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 $172 million through December 31, 1995, and the remaining $122 million will be recovered over approximately 2.2 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 as to 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.
As discussed in Note 2, various appeals of the PUCT's order have been filed. GSU has filed an appeal with the Texas Supreme Court. On February 9, 1996, the Texas Supreme Court agreed to hear the appeal. Oral arguments are scheduled for March 19, 1996.
As of December 31, 1995, 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, $276 million (both net of depreciation), and $169 million, respectively. Allowed Deferrals were approximately $83 million, net of taxes and amortization, as of December 31, 1995. GSU estimates it has recorded approximately $182 million of revenues as of December 31, 1995, 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 be lost, and no assurance can be given as to whether or not refunds to customers of revenue received based upon such deferred costs will be required.
As discussed in Note 2, as of December 31, 1995, GSU has made no write-offs or reserves for the River Bend-related costs. See below for a discussion of the write-off of deferred operating and carrying costs required under SFAS 121 in 1996. Based on advice from Clark, Thomas & Winters, A Professional Corporation, legal counsel of record in the Rate Appeal, management believes that it is reasonably possible that the case will be remanded to the PUCT, and that the PUCT will be allowed to rule on the prudence of the abeyed River Bend plant costs. Management and legal counsel are unable to predict the amount, if any, of abeyed and previously disallowed River Bend plant costs that ultimately may be disallowed by the PUCT. As of December 31, 1995, a net of tax write-off of up to $289 million could be required if the PUCT ultimately issues an adverse ruling on the abeyed and disallowed plant costs.
The following factors support management's position that a loss contingency requiring accrual has not occurred, and 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. Analysis by Sandlin Associates, management consultants with expertise in the cost of nuclear power plants, 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; and 4. The analysis of GSU's legal staff, which has considerable experience in Texas rate case litigation.
Additionally, based on advice from Clark, Thomas & Winters, A Professional Corporation, legal counsel of record in the Rate Appeal, management believes that it is reasonably possible that the Allowed Deferrals will continue to be recovered in rates, and 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.
The adoption of SFAS 121, "Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121), became effective January 1, 1996. SFAS 121 changes the standard for continued recognition of regulatory assets, and as a result in 1996 GSU will be required to write-off $169 million of rate deferrals discussed above. The standard also describes circumstances that may result in assets being impaired and provides criteria for recognition and measurement of asset impairment. See Note 1 for further information regarding SFAS 121.
NISCO Unrecovered Costs
In 1986, the PUCT ordered 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, on 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 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 under-recoveries and interest (including under- recoveries related to NISCO) over a twelve-month period. 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. In October 1993, GSU appealed the PUCT's order to the Travis County District Court where the matter is still pending. As of December 31, 1995, GSU has expensed $119.4 million of unrecovered purchased power costs and deferred revenue pending the appeal of the District Court. No assurance can be given as to the timing or outcome of the appeal.
PUCT Fuel Cost Review
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. On April 17, 1995, the PUCT issued a final order approving the settlement. As a result of the PUCT order, $7.6 million of prior period fuel costs were refunded to customers through the fuel adjustment clause.
Retail Rate Proceedings
Refer to Note 2 for a discussion of additional retail rate proceedings which have been resolved during the current year and/or are currently outstanding in the regulatory jurisdictions in which GSU operates.
Fuel Recovery
GSU's Texas rate schedules include a fixed fuel factor to recover fuel and purchased power costs not recovered in base rates. The fixed factor may be revised every six months in accordance with a schedule set by the PUCT for each utility. To the extent actual costs vary from the fixed factor, refunds or surcharges are required or permitted, respectively. Fuel costs are also subject to reconciliation proceedings every three years. GSU's Louisiana electric rate schedules include a fuel adjustment clause to reflect the cost of fuel and purchased power costs in the second prior month, adjusted by a surcharge for deferred fuel expense arising from the monthly reconciliation of actual fuel cost incurred with fuel revenues billed to customers.
GSU's Louisiana gas rates include a purchased gas adjustment to recover the cost of purchased gas.
Steam Customer Contract
GSU is currently negotiating with its only steam customer whose contract is scheduled to expire in 1997. It is anticipated that GSU will be successful in such negotiations and the contract will be renewed. During 1995 sales to this customer contributed $44.5 million in base revenues to GSU.
LP&L
Recovery of Waterford 3 and Grand Gulf 1 Costs
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, 1995, LP&L's unrecovered deferral balance was $26 million.
With respect to Grand Gulf l, LP&L agreed to retain, and not recover from retail ratepayers, 18% of its 14% share or, approximately 2.52% of the costs of Grand Gulf l's capacity and energy. LP&L is allowed to recover, through the fuel adjustment clause, 4.6 cents per KWh for the energy related to its retained portion of these costs. Alternatively, LP&L may sell such energy to nonaffiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC's approval.
Performance-Based Formula Rate Plan
In June 1995, in conjunction with the LPSC's rate review, a performance-based formula rate plan previously proposed by LP&L was approved with certain modifications. At the same time, the LPSC ordered a $49.4 million reduction in base rates. For a discussion of LP&L's approved performance-based formula rate plan, LP&L's subsequent appeal of the LPSC's June 1995 rate order, and the final settlement of this appeal, see Note 2.
Fuel Adjustment Clause
LP&L's rate schedules include a fuel adjustment clause to reflect the cost of fuel and purchased power in the second prior month. The fuel adjustment also reflects a surcharge for deferred fuel expense arising from the monthly reconciliation of actual fuel cost incurred with fuel revenues billed to customers.
MP&L
Retail Rate Proceedings
Refer to Note 2 for a discussion of the retail rate proceedings which have been resolved during the current year and/or are currently outstanding in the regulatory jurisdictions in which MP&L operates.
Rate Freeze
In connection with the settlement of various issues related to the Merger, MP&L agreed that it will not request any general retail rate increase to take effect before November 3, 1998, except for certain instances. See Note 2 for a discussion of the rate freeze as well as other aspects of the settlement agreement between MP&L and the MPSC.
Recovery of Grand Gulf 1 Costs
In 1988 the MPSC 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 MPSC 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, 1995, the uncollected balance of MP&L's deferred costs was approximately $378 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 actual earned returns to benchmark returns and upon certain performance factors. Pursuant to a stipulation with the MPSC's Public Utilities Staff, MP&L did not request an adjustment in rates based on its earned rate of return for the 12-months ended December 31, 1994.
Fuel Adjustment Clause
MP&L's rate schedules include a fuel adjustment clause that recovers changes in 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 and KWh sales for the second prior month.
NOPSI
Recovery of Grand Gulf 1 Costs
Under NOPSI's various Rate Settlements with the Council in 1986, 1988, and 1991, NOPSI agreed to absorb and not recover from ratepayers a total of $96.2 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, 1995, the uncollected balance of NOPSI's deferred costs was $171 million. The 1994 NOPSI Settlement did not affect the scheduled Grand Gulf 1 phase-in rate increases.
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. The 1994 NOPSI Settlement also required 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. See Note 2 for additional discussion of the rate reductions and refunds ordered by the Council in the 1994 NOPSI settlement, as well as the 1995 and 1996 annual earnings reviews required by the Council.
Fuel Adjustment Clause
NOPSI's electric rate schedules include a fuel adjustment clause to reflect the cost of fuel in the second prior month, adjusted by a surcharge for deferred fuel expense arising from the monthly reconciliation of actual fuel incurred with fuel cost revenues billed to customers. The adjustment, 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 an adjustment to reflect gas costs in excess of those collected in base rates, adjusted by a surcharge similar to that included in the electric fuel adjustment clause.
Regulation
Federal Regulation (Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy)
PUHCA
Entergy Corporation is a public utility holding company registered under PUHCA. As such, Entergy Corporation and its various direct and indirect subsidiaries (with the exception of its EWG and foreign utility subsidiaries) are subject to the broad regulatory provisions of that Act. Except with respect to investments in certain domestic power projects, foreign utility company projects, and telecommunication projects, PUHCA 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. See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - SIGNIFICANT FACTORS AND KNOWN TRENDS," for a discussion of the Telecommunications Act.
Entergy Corporation and other electric utility holding companies, have supported legislation in the United States Congress which would repeal PUHCA, which requires detailed oversight by the SEC of many business practices and activities of utility holding companies and their subsidiaries. The proposed legislation would transfer certain aspects of the oversight of public utility holding companies from the SEC to FERC.
Entergy believes that PUHCA inhibits its ability to compete in the evolving electric energy marketplace and largely duplicates the oversight activities already performed by FERC and state and local regulators. In June 1995, the SEC adopted a report proposing options for the repeal or significant modification of PUHCA and proposed rule changes that would reduce the regulations governing utility holding companies. One rule change adopted as a result of such proposals eliminated the requirement to receive prior authorization for capital contributions made by a parent company to its nonutility subsidiary companies and for financing its non utility subsidiary companies. Such rule was appealed to the D.C. Circuit by the City of New Orleans where the appeal was denied in January 1996.
Federal Power Act
The 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 transmission and wholesale sale of electric energy in interstate commerce, and certain other activities, 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 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 (Entergy Corporation, AP&L, GSU, LP&L, and System Energy)
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 these nuclear plants, and additional such expenditures could be required in the future.
The nuclear power industry faces uncertainties with respect to the cost and long-term availability of sites for disposal of spent nuclear fuel and other radioactive waste, nuclear plant operations, the technological and financial aspects of decommissioning plants at the end of their licensed lives, and 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. However, the DOE has not yet identified a permanent storage repository and, as a result, future expenditures may be required to increase spent fuel storage capacity at the plant sites. For further information concerning spent fuel disposal contracts with the DOE, schedules for initial shipments of spent nuclear fuel, current on-site storage capacity, and costs of providing additional on-site storage, see Note 8.
Low-Level Radioactive Waste
The availability and cost of disposal facilities for low-level radioactive waste resulting from normal nuclear plant operations 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 participate in regional compacts to fulfill their responsibilities jointly. 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 until recently both were closed to out-of-region generators. The Barnwell Disposal Facility (Barnwell), located in South Carolina and operated by the Southeast Compact, reopened to out-of-region generators in July 1995. The South Carolina State legislative action reopening Barnwell must be renewed annually. The availability of Barnwell provides only temporary relief from low-level radioactive waste storage and does not alleviate the need to develop new disposal capacity.
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. As of December 1995, the System's cumulative expenditures for the development of new disposal facilities totaled approximately $38 million. Future levels of expenditures cannot be predicted. Until long-term disposal facilities are established, the System will seek continued access to existing facilities. If such access is unavailable, the System will store low-level waste at its nuclear plant sites.
Decommissioning
AP&L, GSU, LP&L, and System Energy are recovering from ratepayers portions of their estimated decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf 1, respectively. These amounts are deposited in trust funds that, together with the related earnings, can only be used for future decommissioning costs. Estimated decommissioning costs are periodically reviewed and updated to reflect inflation and changes in regulatory requirements and technology, and applications are periodically 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, see Note 8.
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 decontamination and decommissioning of enrichment facilities. In accordance with the EPAct, contributions to decontamination and decommissioning funds are recovered through rates in the same manner as other fuel costs. See Note 8 for the estimated annual contributions by the System companies for decontamination and decommissioning fees.
Nuclear Insurance
The Price-Anderson Act limits public liability for a single nuclear incident to approximately $8.92 billion. AP&L, GSU, LP&L, and System Energy have protection with respect to this liability through a combination of private insurance and an industry assessment program, and also have insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units. For a discussion of insurance applicable to the nuclear programs of AP&L, GSU, LP&L, and System Energy, see Note 8.
Nuclear Operations
General (Entergy Corporation, AP&L, GSU, LP&L, and System Energy)
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.
ANO Matters (Entergy Corporation and AP&L)
Entergy Operations has made inspections and repairs from time to time on ANO 2's steam generators. During the October 1995 inspection, additional cracks in the tubes were discovered. Currently, Entergy Operations is monitoring the development of the cracks and assessing various options for the repair or the replacement of ANO 2's steam generators. See Note 8 for additional information.
River Bend (Entergy Corporation and GSU)
In connection with the Merger, GSU filed two applications with the NRC in January 1993 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. In August 1993 Cajun filed a petition to intervene and a request for a hearing in the proceeding. In January 1994, the presiding NRC Atomic Safety and Licensing Board (ASLB) issued an order granting Cajun's petition to intervene and ordering a hearing on one of Cajun's contentions. In 1994, subsequent to Cajun's intervention in such proceedings, the NRC Staff issued the two license amendments for River Bend, which were effective immediately upon consummation of the Merger. A hearing on the proceeding before the ASLB has been postponed, pending approval of a petition by Cajun to withdraw such a proceeding. On February 14, 1994, Cajun filed with the D.C. Circuit petitions for review of the two license amendments for River Bend. In March 1995, the D.C. Circuit ordered the original NRC order and license amendments be set aside, and remanded the case to the NRC for further consideration. Subsequently, the NRC affirmed its original findings and reissued the two license amendments approving the Merger and the change in the licensed operator of River Bend. Cajun has filed a petition for review with the D. C. Circuit, and oral arguments are expected to be heard in May 1996. These two amendments are in full force and effect, but are subject to the outcome of the two proceedings.
State Regulation (AP&L, GSU, LP&L, MP&L, and NOPSI)
General
Each of the Operating Companies is subject to regulation by state and/or local regulatory authorities having jurisdiction over the areas in which it operates. Such regulation includes authority to set rates for retail electric and gas service. (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, depreciation, accounting, and other matters.
LP&L is subject to regulation by the LPSC as to electric service, rates and charges, certification of generating facilities and power or capacity purchase contracts, depreciation, accounting, and other matters. LP&L is also subject to the jurisdiction of the Council with respect to such matters within Algiers.
MP&L is subject to regulation as to service, service areas, facilities, and retail rates by the MPSC. MP&L is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station.
NOPSI is subject to regulation by the Council as to electric and gas service, rates and charges, standards of service, depreciation, accounting, issuance of certain securities, and other matters.
Franchises
AP&L holds exclusive franchises to provide electric service in 300 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue until such a time when the municipalities purchase the utility property. 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 and 60-year franchises in Louisiana. GSU's current electric franchises will expire in 2007 - 2036 in Texas and in 2015 - 2046 in Louisiana. The natural gas franchise in the City of Baton Rouge will expire in 2015. In addition, GSU has received from the PUCT a certificate of convenience and necessity to provide electric service to areas within 21 counties in eastern Texas.
LP&L holds non-exclusive franchises to provide electric service in 116 incorporated villages, cities, and towns. Most of these municipal franchises have 25-year terms, although six municipalities have granted LP&L 60-year franchises. LP&L also supplies electric service in 353 unincorporated communities, all of which are located in parishes in which LP&L holds non-exclusive franchises.
MP&L has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties in western Mississippi, which include a number of municipalities. Under Mississippi statutory law, such certificates are exclusive. MP&L may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
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 distribution franchises. Its business is currently limited to wholesale power sales.
Environmental Regulation
General
In the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters, the facilities and operations of the System companies are subject to regulation by various federal, state, and local authorities. The System companies believe they are in substantial compliance with environmental regulations currently applicable to their respective facilities and operations. They have incurred significant costs in meeting environmental protection standards. Because environmental regulations are continually changing, the ultimate compliance costs to the System companies cannot be precisely estimated. However, management currently estimates that ultimate capital expenditures for environmental compliance 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 that affect the System companies: an acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx), an ozone nonattainment area program for control of NOx and volatile organic compounds, and an operating permits program for administration and enforcement of these and other Clean Air Act programs.
Under the acid rain program, no additional control equipment is expected to be required by the System to control SO2. The Act provides "allowances" to most of the affected System companies' generating units for emissions based upon past emission levels and operating characteristics. Each allowance is an entitlement to emit one ton of SO2 per year. Under the Act, utilities will be required to possess allowances for SO2 emissions from affected generating units. All of the Entergy company generating units are classified as "Phase II" units under the Act and are subject to SO2 allowance requirements beginning in the year 2000. Based on operating history, the System companies are considered "clean" utilities and have been allocated more allowances than are currently necessary for normal operations. Management believes that it will be able to operate its units efficiently without installing scrubbers or purchasing allowances from outside sources, and that one or more of the System companies may have excess allowances available for sale.
The System companies have installed continuous emission monitoring (CEM) equipment at their fossil generating units to comply with EPA regulations under the Act, and CEM software and computer equipment is currently being updated at AP&L, MP&L, LP&L, and NOPSI generating units. Such CEM equipment resulted in approximately $5.2 million of capital costs during 1995. No material costs for CEM equipment are expected in 1996.
Control equipment may eventually be required for NOx reductions due to the ozone nonattainment status of the areas served by GSU in and around Beaumont and Houston, Texas. Texas environmental authorities are studying the causes of ozone pollution and will decide during 1996 whether to require controls. If Texas decides to regulate NOx, the cost of such control equipment for the affected GSU plants is estimated at $10.4 million through the year 2000.
In accordance with the Act, the EPA promulgated operating permit regulations in 1994 that may set new operating criteria for fossil plants relating to fuels, emissions, and equipment maintenance practices. Some or all Entergy Companies may also have to install additional CEM equipment as a result of these regulations. The cost will be determined on a state-by-state basis as the plants are granted permits during 1996 and 1997. Related capital and operation and maintenance costs are expected to begin in 1996, but are not expected to be material. The authority to impose permit fees under this program has been delegated to the states by the EPA and, depending on the outcomes of various decisions of each state regulatory authority, total permit fees for the System could range from $1.6 to $5.0 million annually.
Other Environmental Matters
The provisions of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorize the EPA and, indirectly, the states to require generators and certain transporters of certain hazardous substances released from or at a site, and the owners or operators of any such site, to clean-up the site or reimburse such clean-up costs. CERCLA has been interpreted to impose joint and several liability on responsible parties. The System companies sent waste materials to various disposal sites over the years. Also, certain operating procedures and maintenance practices, that historically were not subject to regulation, are now regulated by environmental laws. Some of these sites have been the subject of governmental action under CERCLA, as a result of which the System companies have become involved with site clean-up activities. The System companies have participated to various degrees in accordance with their potential liability in such site clean-ups and have developed experience with clean-up costs. The System companies have established reserves for such environmental clean-up/restoration activities. In the aggregate, the cost of such remediation is not considered material to the System.
AP&L
AP&L has received notices from time to time from the EPA, the Arkansas Department of Pollution Control and Ecology (ADPC&E), and others alleging that it, along with others, may be a PRP for clean-up 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 polychlorinated biphenyls (PCBs), lead, and other hazardous substances.
In response to such notices from the EPA and the ADPC&E, the sites discussed below have been remediated:
At the EPA's request, AP&L voluntarily performed stabilization activities at the Benton Salvage site in Saline County, Arkansas. While the EPA has not named PRPs for this site, AP&L has negotiated an agreement with the EPA to remove waste stored at the site. AP&L will spend approximately $250,000 to remove and dispose of waste material at the Benton Salvage site. Although GSU and LP&L have had minor involvement in the Benton Salvage site, no remediation action is anticipated by these companies.
As a result of an internal investigation, AP&L has identified soil contamination at AP&L-owned sites located in Blytheville and Pine Bluff, Arkansas. The contamination appears to be a result of operating procedures that were performed prior to any applicable environmental regulation. Remediation of the Blytheville and Pine Bluff sites was completed in 1995 at a total cost of approximately $2.25 million.
Reynolds Metals Company (Reynolds) and AP&L notified the EPA in 1989 of possible PCB contamination at two former Reynolds plant sites (Jones Mill and Patterson) in Arkansas to which AP&L had supplied power. Subsequently, 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 Patterson facility to the Ouachita River. Reynolds demanded that AP&L participate in 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 possible 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 has thus far expended approximately $150,000 on investigation of the ditch. In May 1995, AP&L was named as a defendant in a suit by Reynolds seeking to recover a share of its costs associated with the clean-up of hazardous substances at the Patterson site. Reynolds alleges that it has spent $11.2 million to clean-up the site, and that AP&L bears some responsibility for PCB contamination at the site. AP&L believes that it has no liability for contamination at the Patterson site and is contesting the lawsuit.
AP&L entered into a Consent Administrative Order, dated February 21, 1991, with the ADPC&E that named AP&L as a PRP for the initial stabilization associated with contamination at the Utilities Services, Inc. state Superfund site located near Rison, Arkansas. This site was found to have soil contaminated by PCBs and pentachlorophenol (a wood preservative). 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 and $5.0 million. AP&L is attempting to identify and notify other PRPs with respect to this site. AP&L has received assurances that the ADPC&E will use its enforcement authority to allocate remediation expenses among AP&L and any other PRPs that can be identified. Approximately 20 PRPs have been identified to date. AP&L has performed the activities necessary to stabilize the site, at a cost of approximately $350,000. AP&L believes that its potential liability for this site will not be material.
GSU
GSU has been designated by the EPA as a PRP for the clean-up of certain hazardous waste disposal sites. GSU is currently negotiating with the EPA and state authorities regarding the clean-up 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 (see "Other Regulation and Litigation" below). While the amounts at issue may be substantial, GSU believes that its results of operations and financial condition will not be materially adversely affected by the outcome of the suits. Through December 31, 1995, $7.9 million has been expended on clean-up activities. As of December 31, 1995, a remaining recorded liability of $21.7 million existed relating to the clean-up of five sites at which GSU has been designated a PRP.
In 1971, GSU purchased property near its Sabine generating station, known as the Bailey site, for possible expansion of cooling water facilities. Although it was not known to GSU at the time, 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, an abandoned waste site on the property was included on the Superfund National Priorities List (NPL) by the EPA. GSU has pursued negotiations with the EPA and is a member of a task force with other PRPs for the voluntary clean-up of the waste site. A Consent Decree has been signed by all PRPs for the voluntary clean-up of the Bailey site. Additional wastes have been discovered at the site since the original clean-up costs were estimated. Remediation of the Bailey site is being redesigned and costs are currently expected to be approximately $33 million. GSU is expected to be responsible for 2.26% of the estimated clean-up 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 believe that its ultimate responsibility with respect to this site will be material after allowance for the existing clean-up reserve in the amount of $760,000.
GSU is currently involved in a multi-phased remedial investigation of an abandoned manufactured gas plant (MGP) site, known as the Lake Charles Service Center, located in Lake Charles, Louisiana. The property was the site of an MGP that is believed to have operated from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, was apparently routed to a portion of the property for disposal. The same area has also been used as a landfill. Under an order issued 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. Preliminary estimates of remediation costs are approximately $20 million. On February 13, 1995, the EPA published a proposed rule adding the Lake Charles Service Center 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 possible remedial action have been held and are expected to continue. GSU currently is awaiting notification from the EPA before initiating additional clean-up negotiations or actions. GSU does not presently believe that its ultimate responsibility with respect to this site will be material, after allowance for the existing clean-up reserve of $19.8 million.
GSU along with LP&L has been named as a PRP for an abandoned waste oil recycling plant site in Livingston Parish, Louisiana, known as Combustion, Inc., which is included on the NPL. Although most surface remediation has been completed, additional studies related to residual groundwater contamination are expected to continue in 1996. 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 Combustion, Inc. site, see "Other Regulation and Litigation" 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 was the depository of a variety of wastes, including medical and chemical wastes. In addition to GSU, over 200 parties have been named as PRPs. The EPA has completed remediation at the Iota site. However, it is continuing its investigation of the site and has notified the PRPs of the possibility of this site being linked to other sites. GSU does not believe it is implicated in these other sites. GSU has not received notification of liability or location with regard to the other sites, and does not believe that its ultimate responsibility with respect to these other sites will be material.
GSU, along with AP&L and LP&L, has been notified of its potential liability with respect to the Benton Salvage site located in Saline County, Arkansas. Although GSU and LP&L have had minor involvement in the Benton Salvage site, no remediation action is anticipated by these companies. See "AP&L" above for a discussion of the Benton Salvage site.
LP&L, NOPSI, and System Energy
LP&L, NOPSI, and System Energy have received notices from the EPA and/or the states of Louisiana and Mississippi that one or more than one company may be a PRP for disposal sites that are neither owned nor operated by any System company. In response to such notices the sites discussed below have been remediated:
LP&L and NOPSI have completed remediation at the Rose Chemical site located in Missouri and the aggregate remaining costs are considered immaterial.
LP&L, along with AP&L and GSU, was notified in 1990 of its potential liability at the Benton Salvage site located in Saline County, Arkansas. Although GSU and LP&L have been involved in the Benton Salvage site, their contributions are considered minor; and therefore, no remediation action is required by these companies. See "AP&L" above for a discussion of the Benton Salvage site.
The EPA named LP&L and System Energy as two of the 44 PRPs for the Disposal Systems, Inc. site in Mississippi. The State of Mississippi has indicated that it intends to have the PRPs conduct a clean-up of the Disposal Systems, Inc. site but has not yet taken formal action. LP&L has settled this matter with the EPA. The State of Mississippi is continuing to evaluate whether additional remediation measures are necessary. However, further remediation costs at the Disposal Systems, Inc. site are not expected to be material.
NOPSI received notice from the EPA with respect to a Mississippi site, known as Pike County, in the fall of 1994. The EPA alleged that NOPSI sold and shipped hazardous waste to the Pike County site during 1983 and 1984. NOPSI has negotiated a final settlement with the EPA for remediation of the site and no further costs are expected.
From 1992 to 1994, LP&L performed site assessments and remedial activities at three retired power plants, known as the Homer, Jonesboro, and Thibodaux municipal sites, previously owned and operated by 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 site assessments indicated some subsurface contamination from fuel oil. LP&L has completed all remediation work to the LDEQ's satisfaction for these three former generating plants, and follow-up sampling has been completed at the Homer site. Sampling at the Jonesboro and Thibodaux sites is expected to be completed in 1996. The costs incurred through December 31, 1995 for the Homer, Jonesboro, and Thibodaux sites are $22,000, $156,000, and $34,000, respectively. Any remaining costs are considered immaterial.
There are certain disposal sites in which LP&L and NOPSI have been named by the EPA as PRPs for associated clean-up costs, but management believes no liability exists in connection with these sites for LP&L and NOPSI. Such Louisiana sites include Combustion Inc., an abandoned waste oil recycling plant site located in Livingston Parish (involving at least 70 PRPs, including GSU), and the Dutchtown site (also included on the NPL and involving 57 PRPs). LP&L has found no evidence of its involvement in the Combustion Inc. site. (For information regarding litigation in connection with the Livingston Parish site, see "Other Regulation and Litigation," below). With respect to the Dutchtown site, NOPSI believes it has no liability because the material it sent to this site was not a hazardous substance.
During 1993, the LDEQ issued new rules for solid waste regulation, including regulation of waste water impoundments. LP&L has determined that certain of its power plant waste water impoundments were affected by these regulations and has chosen to upgrade or close them. As a result, a remaining recorded liability in the amount of $10.6 million existed at December 31, 1995, for waste water upgrades and closures to be completed by the end of 1996. Cumulative expenditures relating to the upgrades and closures of waste water impoundments were $5.6 million as of December 31, 1995.
Other Regulation and Litigation
Merger (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 PUHCA, 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.
FERC's December 15, 1993, and May 17, 1994, orders approving the Merger were appealed to the D.C. 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 City of Benton and other cities, 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, see discussion of tariff case in "RATE MATTERS AND REGULATION - Rate Matters - Wholesale Rate Matters - Open Access Transmission" above, 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 order dated December 15, 1993, 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.
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 and by Cajun in February 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.
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. In judgments issued in February and November 1995, the 19th Judicial District Court dismissed the appeals of the Alliance for Affordable Energy, Inc.
Flowage Easement Suits (AP&L)
Three lawsuits (subsequently consolidated into one) 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. Rulings issued by the Arkansas District Court in June and November 1991 found that AP&L had the right to enforce its flowage easements and that Entergy Services was entitled to the benefit of AP&L's flowage easements. Such rulings removed 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 the Arkansas District Court rulings to the Eighth Circuit, and these appeals were ultimately denied in December 1993. The remaining plaintiffs, to whom the flowage easements did not apply, had obtained a stay and an administrative termination of their claims, pending the outcome of the appeal. On February 10, 1995, such plaintiffs petitioned the Arkansas District Court to reopen the proceedings as to their claims. In March 1995, the Arkansas District Court ordered the reopening of the proceedings relating to the plaintiffs' claims which were previously stayed and administratively terminated, and the claims were subsequently tried. On November 9, 1995, the Arkansas District Court dismissed all remaining plaintiffs' claims, resolving the case in favor of AP&L.
Asbestos and Hazardous Waste Suits
(GSU and LP&L)
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, sued GSU and approximately 70 other defendants, including LP&L, in 17 suits filed in the Livingston Parish, Louisiana District Court (State District Court). 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 million to $10 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. No assurances can be given to the timing or outcome of these suits.
(GSU)
A total of six suits have been filed on behalf of approximately 3,415 plantiffs in state and federal courts in Jefferson County, Texas. These suits seek relief from GSU as well as numerous other defendants for damages caused by the alleged exposure to hazardous waste and asbestos on the defendants' premises. At least five other individual suits have been filed in Beaumont against GSU and others, seeking damages for alleged asbestos exposure. All of the plaintiffs in such suits are also suing GSU and all other defendants on a conspiracy count. It is not yet known how many of the plantiffs in the suits discussed above worked on GSU's premises. There have been approximately 55 asbestos-related law suits filed in the District Court of Calcasieu Parish in Lake Charles, Louisiana, on behalf of an aggregate of 119 plaintiffs naming numerous defendants including GSU, and GSU expects additional cases to 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 1,660 groups of claimants) and 38 suits in Calcasieu Parish (involving approximately 91 plantiffs) have been consummated. GSU was named as one of a number of defendants in nearly all of the suits. GSU's share of the settlements of these cases was not material to its financial position or results of operations.
Cajun - River Bend Litigation (Entergy Corporation and GSU)
GSU has significant business relationships with Cajun, including co-ownership of River Bend (operated by GSU) and Big Cajun 2, Unit 3 (operated by Cajun). GSU and Cajun, respectively, own 70% and 30% undivided interests in River Bend and 42% and 58% undivided interests in Big Cajun 2, Unit 3. Cajun is currently in reorganization proceedings under the United States Bankruptcy Code.
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 (Operating Agreement) entered into on August 28, 1979 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 on the portion of the suit by Cajun to rescind the Operating Agreement began in April 1994 and was completed in March 1995. On October 24, 1995, the District Court issued a memorandum opinion ruling in favor of GSU. The District Court found that Cajun did not prove that GSU fraudulently induced it to execute the Operating Agreement and that Cajun failed to timely assert its claim. A final judgment on this portion of the suit is not expected to be entered until all claims asserted by Cajun have been heard. The trial of the second portion of the suit currently is scheduled to begin on July 2, 1996. If GSU is ultimately unsuccessful in this litigation and is required to pay substantial damages, GSU would probably be unable to make such payments and could be forced 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 by Cajun of all required costs of ownership in River Bend.
In the bankruptcy proceedings, Cajun filed 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. If the District 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 without merit, it is not possible to predict the outcome or ultimate impact of these proceedings.
See Note 8 for additional information regarding the Cajun litigation, Cajun's bankruptcy filing, related filings, and the ongoing potential effects of these matters upon GSU.
As the result of an order issued by the District Court in August 1995, a former federal bankruptcy judge, Ralph Mabey, was appointed as trustee to oversee Cajun in bankruptcy. The LPSC and Cajun appealed the appointment of a trustee to the Fifth Circuit where the action of the District Court was reversed and remanded for further proceedings. However, in January 1996, the Fifth Circuit reversed its original position and affirmed the appointment of the trustee.
In October 1995, the appeals court affirmed the District Court's preliminary injunction in the Cajun litigation. The preliminary injunction stipulated that GSU should make payments for its portion of expenses for Big Cajun 2, Unit 3 into the registry of the District Court. As of December 31, 1995, $38 million had been paid by GSU into the registry of the District Court.
Cajun has not paid its full share of capital costs, operating and maintenance expenses and other costs for repairs and improvements to River Bend since 1992. However, Cajun continues to pay its share of decommissioning costs for River Bend. Cajun's unpaid portion of River Bend operating and maintenance expenses (including nuclear fuel) and capital costs for 1995 was approximately $58.7 million. The cumulative cost (excluding nuclear fuel) to GSU resulting from Cajun's failure to pay its full share of River Bend-related costs, reduced by the proceeds from the sale by GSU of Cajun's share of River Bend power and payments for GSU's portion of expenses for Big Cajun 2, Unit 3 into the registry of the District Court, was $31.1 million as of December 31, 1995. 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.
Cajun - Transmission Service (Entergy Corporation and GSU)
GSU and Cajun are parties to FERC proceedings relating to transmission service charge disputes. See Note 8 for additional information regarding these FERC proceedings, FERC orders issued as a result of such proceedings and the potential effects of these proceedings upon GSU.
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 is 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 in Note 8.
Service Area Dispute
(Entergy Corporation and GSU)
GSU was requested by Cajun and Jefferson Davis Electric Cooperative, Inc. (Jefferson Davis), to provide the transmission of power over GSU's system for delivery to an area near Lake Charles, Louisiana. GSU provides electric service to industrial and other customers in this area, and Cajun and Jefferson Davis do not. In October 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. Subsequently, the 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. Ultimately, in March 1994, the FERC issued an order dismissing Cajun's complaint and finding that GSU properly exercised its contractual right to refuse to provide transmission service to Cajun. In August 1994, the FERC denied a rehearing. Subsequently, Cajun filed a petition for review of the FERC's orders in the D.C. Circuit. In October 1995, the D.C. Circuit affirmed the FERC's previous opinion in its entirety.
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. In November 1989, the district court denied Cajun's and Jefferson Davis' motion for a preliminary injunction. In May 1991, the judge stayed the proceeding pending final resolution of the matters still pending before FERC.
(Entergy Corporation and MP&L)
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. On January 6, 1995, MP&L and the other defendants filed motions to dismiss. In October 1995, the state court dismissed the complaint. The plaintiffs have appealed the dismissal to the Mississippi Supreme Court.
Cajun/River Bend Repairs (Entergy Corporation and GSU)
In December 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 has defaulted on the payment of 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 that GSU may not demand payment or attempt to implement default provisions in the Operating Agreement. 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 - River Bend" 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.
Taxes Paid Under Protest (Entergy Corporation and LP&L)
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. In October 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 that unspecified additional taxes, interest, and penalties are due. Subsequently, the suit filed by the Parish tax authorities was dismissed. In September 1995, LP&L similarly paid use tax under protest in the amount of $209,000 with regard to the delivery of a new batch of fuel. In June 1995, LP&L received a favorable decision from the Louisiana Fifth Circuit Court of Appeals that confirmed that no such use taxes are due. The Parish and LP&L are currently discussing a possible settlement of all pending tax-related litigation including the likely return of the amounts paid under protest in October 1994 and September 1995. The suits by LP&L with regard to state use tax paid under protest on nuclear fuel are still pending.
Federal Income Tax Audit (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.
Panda Energy Corporation Complaint (Entergy Corporation)
Panda Energy Corporation (Panda) has commenced litigation in the Dallas District Court naming Entergy Corporation, Energy Enterprises, Entergy Power, Entergy Power Asia, Ltd., and Entergy Power Development Corporation as defendants. The allegations against the defendants include, among others, tortious interference with contractual relations, conspiracy, misappropriation of corporate opportunity, unfair competition and fraud, and constructive trust issues. Panda seeks damages of approximately $4.8 billion, of which $3.6 billion is claimed in punitive damages. Entergy believes that this lawsuit is without merit, that the damages claimed are insupportable, and that some or all of the claims against Entergy will be dismissed. However, no assurance can be given as to the timing or outcome of this matter.
Catalyst Technologies, Inc. (Entergy Corporation)
In June 1993 Catalyst Technologies, Inc. (CTI) filed a petition against Electec, Inc. (Electec), the predecessor to Entergy Enterprises. Prior to the filing of the petition, CTI and Electec entered into an agreement whereby CTI was required to raise a specified amount of funding in exchange for the right to acquire Electec's computer software technology marketing rights. CTI alleges that due to actions of Electec, it was unable to secure the necessary funding, and therefore, was not able to meet the terms of the agreement. The petition alleges breach of contract, breach of the obligation of good- faith and fair dealing, and bad-faith breach of contract against Electec. Subsequent to the filing of the petition, CTI indicated that it is seeking to recover approximately $36 million from Entergy Enterprises. No trial date has been set at this time. No assurance can be given as to the timing or outcome of this matter.
EARNINGS RATIOS OF OPERATING COMPANIES AND SYSTEM ENERGY
The Operating Companies and System Energy's ratios of earnings to fixed charges and ratios of earnings to fixed charges and preferred dividends pursuant to Item 503 of SEC Regulation S-K are as follows:
(a) "Preferred Dividends" in the case of GSU also include dividends on preference stock.
(b) Earnings for the year ended December 31, 1991, include the $90 million effect of the 1991 NOPSI Settlement.
(c) 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.
(d) Earnings for the year ended December 31, 1994, for GSU were not adequate to cover fixed charges and combined fixed charges and preferred dividends by $144.8 million and $197.1 million, respectively.
INDUSTRY SEGMENTS
NOPSI
Narrative Description of NOPSI Industry Segments
Electric Service
NOPSI supplied retail electric service to 190,332 customers as of December 31, 1995. During 1995, 39% of electric operating revenues was derived from residential sales, 40% from commercial sales, 6% from industrial sales, and 15% from sales to governmental and municipal customers.
Natural Gas Service
NOPSI supplied retail natural gas service to 153,370 customers as of December 31, 1995. During 1995, 56% of gas operating revenues was derived from residential sales, 19% from commercial sales, 9% from industrial sales, and 16% 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 14.
Employees by Segment
NOPSI's full-time employees by industry segment as of December 31, 1995, were as follows:
Electric 378 Natural Gas 111 --- Total 489 ===
(For further information with respect to NOPSI's segments, see "PROPERTY.")
GSU
For the year ended December 31, 1995, 96% of GSU's operating revenues was derived from the electric utility business. Of the remaining operating revenues 3% was derived from the steam business and 1% from the natural gas business.
PROPERTY
Generating Stations
The total capability of the System's owned and leased generating stations as of December 31, 1995, by company and by fuel type, is indicated below:
(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.
(4) Includes 188 MW of capacity leased by AP&L through 1999.
Load and capacity projections are regularly reviewed 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. 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 Operating Companies. Among other things, the System Agreement provides that parties having generating capacity greater than their load requirements (long companies) shall sell receive payments from those parties having deficiencies in generating capacity (short companies) and an amount sufficient to cover certain of the long companies' 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 long companies' steam electric generating units fueled by oil or gas. In addition, for all energy exchanged among the Operating Companies under the System Agreement, the short companies are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs (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 1995 (and all-time) peak demand of 19,590 MW occurred on August 16, 1995. The net System capability at the time of peak was 21,100 MW, net of off- system firm sales of 302 MW. The capacity margin at the time of the peak was approximately 7.2%, excluding 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 kilovolts. Generally, with the exception of Grand Gulf 1, Entergy Power's capacity and a small portion of MP&L's capacity, operating facilities or interests therein are owned by the System operating company serving the area in which the facilities are located. However, all of the System's generating facilities are centrally dispatched and operated in order to obtain the lowest cost sources of energy with a minimum of investment and the most efficient use of plant.
In addition to the many neighboring utilities with which the Operating Companies interconnect, the 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. The Operating Companies are also members of the Western Systems Power Pool.
Gas Property
As of December 31, 1995, NOPSI distributed and transported natural gas for distribution solely within the limits of the City of New Orleans through a total of 1,421 miles of gas distribution mains and 40 miles of gas transmission lines. Koch Gateway Pipeline Company is a principal supplier of natural gas to NOPSI, delivering to 6 of NOPSI's 14 delivery points.
As of December 31, 1995, the gas properties of GSU were not material to GSU.
Titles
The System's generating stations are generally located on properties owned in fee simple. The greater portion of the transmission and distribution lines of the Operating Companies has been constructed over property of private owners pursuant to easements or on public highways and streets pursuant to appropriate franchises. The rights of each Operating Company in the realty on which its facilities 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 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 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 to 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
Entergy's sources of generation and average fuel cost per KWh, excluding Entergy Power, for the years 1993-1995 were:
The System's actual 1995 and projected 1996 sources of generation, excluding Entergy Power, are:
(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%.
The balance of generation, which was immaterial, was provided by hydroelectric power.
Natural Gas
The Operating Companies have long-term firm and short-term interruptible gas contracts. Long-term firm contracts 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. GSU has a transportation service agreement with a gas supplier that provides flexible natural gas service to certain generating stations by using such supplier's pipeline and gas storage facility.
Many factors, including wellhead deliverability, storage and pipeline capacity, and demand requirements of end users influence the availability and price of natural gas supplies for power plants. Demand is tied to regional weather conditions as well as to the prices of other energy sources. Supplies of natural gas are expected to be adequate in 1996. 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 Operating Companies will use alternate fuels, such as oil, or rely on coal and nuclear generation.
Coal
AP&L has long-term contracts with mines in the State of Wyoming for the supply of low-sulfur coal for the White Bluff Steam Electric Generating Station and Independence. These contracts, which expire in 2002 and 2011, provide for approximately 85% of AP&L's expected annual coal requirements. Additional requirements are satisfied by annual spot market purchases. 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 1999 for the operation of Big Cajun 2, Unit 3.
Nuclear Fuel
The nuclear fuel cycle 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 maintaining inventories of such materials during the various stages of processing. Each of these companies contracts for the fabrication of its own nuclear fuel and purchases the required enriched uranium hexafluoride from System Fuels. The requirements for GSU's River Bend plant are covered by contracts made by GSU. Entergy Operations acts as agent for System Fuels and GSU in negotiating and/or administering nuclear fuel contracts.
In October 1989, System Fuels entered into a revolving credit agreement with a bank that provides up to $45 million in borrowings to finance its 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 under the agreement.
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:
(1) Current contracts will provide a significant percentage of these materials and services through termination dates ranging from 1996-1999. Additional materials and services required beyond these dates are estimated to be available for the foreseeable future.
(2) Current contracts will provide a significant percentage of these materials and services through approximately 2000.
(3) The Nuclear Waste Policy Act of 1982 provides for the disposal of spent nuclear fuel or high level waste by the DOE.
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 currently have arrangements to lease nuclear fuel and related equipment and services in aggregate amounts up to $130 million, $70 million, $80 million, and $80 million, respectively. As of December 31, 1995, the unrecovered cost base of AP&L's, GSU's, LP&L's, and System Energy's nuclear fuel leases amounted to approximately $98.7 million, $69.9 million, $72.9 million, and $71.4 million, respectively. The lessors finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. 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, GSU, LP&L, and System Energy have been extended and now have termination dates of December 1998, December 1998, January 1999, and February 1999, respectively. The debt securities 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 upon the maturity of the current arrangements. 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 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. 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 in 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 under a "No-Notice" type of agreement from Mid Louisiana Gas Company. 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 1995, 1994, and 1993, the System contributed approximately $9 million, $18 million, and $17 million, respectively, for the various research programs in which Entergy was involved.
Item 2.

Item 2. Properties
Refer to Item 1. "Business - PROPERTY," for information regarding the properties of the registrants.
Item 3.

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 1995.
Item 4.

Item 4. Submission of Matters to a Vote of Security Holders
During the fourth quarter of 1995, no matters 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.

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 of Entergy Corporation's common stock for each quarterly period in 1995 and 1994 were as follows:
Dividends of 45 cents per share were paid on Entergy Corporation's common stock in each of the quarters of 1995 and 1994.
As of February 29, 1996, there were 98,911 stockholders of record of Entergy Corporation.
For information with respect to Entergy Corporation's future ability to pay dividends, refer to Note 7, "DIVIDEND RESTRICTIONS." In addition to the restrictions described in Note 7, PUHCA provides that, without approval of the SEC, the unrestricted, undistributed retained earnings of any Entergy Corporation subsidiary are not available for distribution to Entergy Corporation's common stockholders until such earnings are made available to Entergy Corporation through the declaration of dividends by such subsidiaries.
AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy
There is no market for the common stock of Entergy Corporation's subsidiaries as all shares are owned by Entergy Corporation. Cash dividends on common stock paid by the subsidiaries to Entergy Corporation during 1995 and 1994, were as follows:
In February 1996, Entergy Corporation received common stock dividend payments from its subsidiaries totaling $48.7 million. For information with respect to restrictions that limit the ability of System Energy and the Operating Companies to pay dividends, see Note 7.
Item 6.

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.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Entergy Corporation and Subsidiaries. Refer to information under the heading "ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - LIQUIDITY AND CAPITAL RESOURCES," " - - - - - SIGNIFICANT FACTORS AND KNOWN TRENDS," and "- RESULTS OF OPERATIONS."
AP&L. Refer to information under the heading "ARKANSAS POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - RESULTS OF OPERATIONS."
GSU. Refer to information under the heading "GULF STATES UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - RESULTS OF OPERATIONS."
LP&L. Refer to information under the heading "LOUISIANA POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - RESULTS OF OPERATIONS."
MP&L. Refer to information under the heading "MISSISSIPPI POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - RESULTS OF OPERATIONS."
NOPSI. Refer to information under the heading "NEW ORLEANS PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - RESULTS OF OPERATIONS."
System Energy. Refer to information under the heading "SYSTEM ENERGY RESOURCES, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - RESULTS OF OPERATIONS."
Item 8.

Item 8. Financial Statements and Supplementary Data.
Entergy Corporation and Subsidiaries: Report of Management 44 Audit Committee Chairperson's Letter 45 Management's Financial Discussion and Analysis for Entergy 46 Corporation and Subsidiaries Report of Independent Accountants for Entergy Corporation 55 and Subsidiaries Independent Auditors' Report for Entergy Corporation and 56 Subsidiaries Management's Financial Discussion and Analysis for Entergy 57 Corporation and Subsidiaries Statements of Consolidated Income For the Years Ended December 31, 1995, 1994, and 1993 for Entergy Corporation and 59 Subsidiaries Statements of Consolidated Cash Flows For the Years Ended December 31, 1995, 1994, and 1993 for Entergy Corporation and 60 Subsidiaries Balance Sheets, December 31, 1995 and 1994 for Entergy 62 Corporation and Subsidiaries Statements of Consolidated Retained Earnings and Paid-In Capital for the Years Ended December 31, 1995, 1994, and 1993 64 for Entergy Corporation and Subsidiaries Selected Financial Data - Five-Year Comparison for Entergy 65 Corporation and Subsidiaries Report of Independent Accountants for Arkansas Power & Light 66 Company Independent Auditors' Report for Arkansas Power & Light 67 Company Management's Financial Discussion and Analysis for Arkansas 68 Power & Light Company Statements of Income For the Years Ended December 31, 1995, 1994, and 1993 for Arkansas Power & Light Company 70 Statements of Cash Flows For the Years Ended December 31, 1995, 1994, and 1993 for Arkansas Power & Light Company 71 Balance Sheets, December 31, 1995 and 1994 for Arkansas 72 Power & Light Company Statements of Retained Earnings for the Years Ended December 31, 1995, 1994, and 1993 for Arkansas Power & Light Company 74 Selected Financial Data - Five-Year Comparison for Arkansas 75 Power & Light Company Report of Independent Accountants for Gulf States Utilities 76 Company Management's Financial Discussion and Analysis for Gulf 78 States Utilities Company Statements of Income For the Years Ended December 31, 1995, 1994, and 1993 for Gulf States Utilities Company 80 Statements of Cash Flows For the Years Ended December 31, 1995, 1994, and 1993 for Gulf States Utilities Company 81 Balance Sheets, December 31, 1995 and 1994 for Gulf States 82 Utilities Company Statements of Retained Earnings and Paid-In Capital for the Years Ended December 31, 1995, 1994, and 1993 for Gulf States 84 Utilities Company Selected Financial Data - Five-Year Comparison for Gulf 85 States Utilities Company Report of Independent Accountants for Louisiana Power & 86 Light Company Independent Auditors' Report for Louisiana Power & Light 87 Company Management's Financial Discussion and Analysis for Louisiana 88 Power & Light Company Statements of Income For the Years Ended December 31, 1995, 1994, and 1993 for Louisiana Power & Light Company 90 Statements of Cash Flows For the Years Ended December 31, 1995, 1994, and 1993 for Louisiana Power & Light Company 91 Balance Sheets, December 31, 1995 and 1994 for Louisiana 92 Power & Light Company Statements of Retained Earnings for the Years Ended December 31, 1995, 1994, and 1993 for Louisiana Power & Light Company 94 Selected Financial Data - Five-Year Comparison for Louisiana 95 Power & Light Company Report of Independent Accountants for Mississippi Power & 96 Light Company Independent Auditors' Report for Mississippi Power & Light 97 Company Management's Financial Discussion and Analysis for 98 Mississippi Power & Light Company Statements of Income For the Years Ended December 31, 1995, 1994, and 1993 for Mississippi Power & Light Company 100 Statements of Cash Flows For the Years Ended December 31, 1995, 1994, and 1993 for Mississippi Power & Light Company 101 Balance Sheets, December 31, 1995 and 1994 for Mississippi 102 Power & Light Company Statements of Retained Earnings for the Years Ended December 31, 1995, 1994, and 1993 for Mississippi Power & Light Company 104 Selected Financial Data - Five-Year Comparison for 105 Mississippi Power & Light Company Report of Independent Accountants for New Orleans Public 106 Service Inc. Independent Auditors' Report for New Orleans Public Service 107 Inc. Management's Financial Discussion and Analysis for New 108 Orleans Public Service Inc. Statements of Income For the Years Ended December 31, 1995, 1994, and 1993 for New Orleans Public Service Inc. 110 Statements of Cash Flows For the Years Ended December 31, 1995, 1994, and 1993 for New Orleans Public Service Inc. 111 Balance Sheets, December 31, 1995 and 1994 for New Orleans 112 Public Service Inc. Statements of Retained Earnings for the Years Ended December 31, 1995, 1994, and 1993 for New Orleans Public Service Inc. 114 Selected Financial Data - Five-Year Comparison for New 115 Orleans Public Service Inc. Report of Independent Accountants for System Energy 116 Resources, Inc. Independent Auditors' Report for System Energy Resources, 117 Inc. Management's Financial Discussion and Analysis for System 119 Energy Resources, Inc. Statements of Income For the Years Ended December 31, 1995, 1994, and 1993 for System Energy Resources, Inc. 120 Statements of Cash Flows For the Years Ended December 31, 1995, 1994, and 1993 for System Energy Resources, Inc. 121 Balance Sheets, December 31, 1995 and 1994 for System Energy 122 Resources, Inc. Statements of Retained Earnings for the Years Ended December 31, 1995, 1994, and 1993 for System Energy Resources, Inc. 124 Selected Financial Data - Five-Year Comparison for System 125 Energy Resources, Inc.. Notes to Financial Statements for Entergy Corporation and 126 Subsidiaries
ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENT
The management of Entergy Corporation and Subsidiaries 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/Ed Lupberger /s/Gerald D. McInvale ED LUPBERGER GERALD D. MCINVALE Chairman, President, and Chief Executive Vice President and Executive Officer of Entergy Chief Financial Officer Corporation, AP&L, GSU, LP&L, MP&L and NOPSI
/s/Donald C. Hintz DONALD C. HINTZ President and Chief Executive Officer of System Energy
ENTERGY CORPORATION AND SUBSIDIARIES
AUDIT COMMITTEE CHAIRPERSON'S LETTER
The Entergy Corporation Board of Directors' Audit Committee is comprised of four directors who are not officers of Entergy Corporation: Lucie J. Fjeldstad, Chairperson, Dr. Norman C. Francis, James R. Nichols, and H. Duke Shackelford. The committee held four meetings during 1995.
The Audit Committee oversees Entergy Corporation'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 Entergy Corporation's 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 private communication between the committee and the internal auditors and independent public accountants.
/s/Lucie J. Fjeldstad LUCIE J. FJELDSTAD Chairperson, Audit Committee
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Entergy, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy
Cash Flows
Entergy is involved in capital-intensive businesses, which require large investments in long-lived assets. While 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 debt and preferred stock, ongoing construction expenditures, and increasing investments in domestic and foreign energy- related businesses. Net cash flow from operations totaled $1.397 billion, $1.538 billion, and $1.074 billion in 1995, 1994, and 1993, respectively. Net cash flow from operations for the Operating Companies and System Energy was as follows:
In 1995, AP&L's net cash flow from operations decreased because of increases in customer accounts receivables due to increased 1995 sales and the replenishment of coal inventory which was depleted in 1994. This decrease was partially offset by lower other operation and maintenance expense. GSU's net cash flow from operations increased in 1995 due to higher revenues and lower operation and maintenance expenses. This increase was partially offset by a Texas retail rate refund, recorded in 1994 and paid in 1995. LP&L's net cash flow from operations increased in 1995 as a result of lower operation and maintenance expenses partially offset by a rate reduction in April 1995. MP&L's net cash flow from operations decreased in 1995 because of increased accounts receivable balances due to increased 1995 sales, partially offset by lower other operation and maintenance expenses. NOPSI's net cash flow from operations was higher in 1995 than 1994 because refunds that were made in 1994 as a result of the NOPSI settlement did not impact 1995 cash flow. Lower operation and maintenance expenses in 1995 for NOPSI also contributed to the increase. System Energy's net cash flow from operations decreased in 1995 due to refunds made to associated companies in 1995 as the result of a 1994 FERC audit settlement, and higher income tax payments in 1995.
Financing Sources
In recent years, cash flows of the Operating Companies, supplemented by cash on hand, have 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 from collections under rate phase-in plans that exceed current cash requirements for the 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. Specifically, the Grand Gulf 1 phase-in plans will expire in 1998 for AP&L and MP&L, and in 2001 for NOPSI.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
GSU's phase-in plan for River Bend will expire in 1998, and LP&L's phase-in plan for Waterford 3 expires in 1996. In addition, the Operating Companies and System Energy have the ability to meet future capital requirements through future debt or preferred stock issuances, as discussed below. Also, to the extent current market interest and dividend rates allow, the Operating Companies and System Energy may continue to refinance high-cost debt and preferred stock prior to maturity. See Notes 5, 6, and 8 for additional information on the System's capital and refinancing requirements in 1996 - 2000.
Entergy Corporation periodically reviews its capital structure to determine its future needs for debt and equity financing. Certain agreements and restrictions limit the amount of mortgage bonds and preferred stock that can be issued by the Operating Companies and System Energy. Based on the most restrictive applicable tests as of December 31, 1995, and assumed annual interest or dividend rates of 8.25% for bonds and 8.50% for preferred stock, each of the Operating Companies and System Energy could have issued mortgage bonds or preferred stock in the following amounts:
(a) GSU was precluded from issuing preferred stock at December 31, 1995. (b) System Energy's charter does not presently provide for the issuance of preferred stock.
In addition to these amounts, the Operating Companies and System Energy have the ability, subject to certain conditions, to issue bonds against retired bonds. Such amounts may be significant in some instances, and, in some cases, no earnings coverage test is required. AP&L may also issue preferred stock to refund outstanding preferred stock without meeting an earnings coverage test. GSU has no earnings coverage limitations on the issuance of preference stock. In January of 1996, the Boards of Directors of AP&L and LP&L authorized the officers of those companies to deposit cash with the trustees under their respective first mortgage indentures to satisfy the annual maintenance and replacement fund requirements thereunder, and to require the trustees to use such cash to redeem all or a part of certain series of first mortgage bonds at par as permitted by the respective first mortgage indentures. See Notes 5 and 6 for long-term debt and preferred stock issuances and retirements. See Note 4 for information on the System's short-term borrowings.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Financing Requirements
Productive investment by Entergy Corporation is necessary to enhance the long-term value of its common stock. Entergy Corporation has been expanding its investments in nonregulated business opportunities overseas as well as in the United States. Through the end of 1995, Entergy Corporation had participated in foreign non regulated electric ventures in Pakistan, Argentina, and Peru. As of December 31, 1995, Entergy Corporation had invested $555.5 million in equity capital (reduced by $169 million of accumulated losses) in nonregulated businesses. See Note 15 for a discussion of Entergy Corporation's acquisition of CitiPower on January 5, 1996.
In addition to investing in nonregulated businesses, Entergy Corporation's capital requirements include periodically investing in, or making loans to, its subsidiaries, and sustaining its dividends. To meet such capital requirements, Entergy Corporation will utilize internally generated funds, cash on hand, and the $70 million remaining on its $300 million credit facility ($230 million of this credit facility was used for the CitiPower acquisition). Entergy Corporation receives funds through dividend payments from its subsidiaries. During 1995, such common stock dividend payments from subsidiaries totaled $565.6 million, none of which was contributed by GSU. Entergy Corporation, in turn, paid $408.6 million of dividends on its common stock. Declarations of dividends on common stock are made at the discretion of Entergy Corporation's Board of Directors. 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. See Note 7 for information on dividend restrictions.
Entergy Corporation and GSU
See Notes 2 and 8 regarding River Bend rate appeals and litigation with Cajun. Adverse rulings in the River Bend rate appeal could result in approximately $289 million of potential write-offs (net of tax) and $182 million in refunds of previously collected revenue. Such write- offs and charges, as well as the application of SFAS 121 (see Note 1), could result in substantial net losses being reported in the future by Entergy Corporation and GSU, with resulting adverse adjustments to common equity of Entergy Corporation and GSU. Adverse resolution of these matters could adversely affect GSU's ability to obtain financing, which could in turn affect GSU's liquidity and ability to pay dividends. Although Entergy Corporation's 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.
Entergy Corporation and System Energy
Under the Capital Funds Agreement, Entergy Corporation has agreed to supply to System Energy sufficient capital to maintain System Energy's equity capital at a minimum of 35% of its total capitalization (excluding short-term debt), to permit the continued 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, if required, to enable System Energy to make payments on such debt when due. The Capital Funds Agreement can be terminated by the parties thereto, subject to consent of certain creditors.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Competition and Industry Challenges
Electric utilities traditionally have operated as regulated monopolies in which there was little opportunity for direct competition in the provision of electric service. In return for the ability to receive a reasonable return on and of their investments, utilities were obligated to provide service and meet future customer requirements. However, the electric utility industry is now undergoing a transition to an environment of increased retail and wholesale competition.
Pressures that underlie the movement toward increasing competition are numerous and complex. They include legislative and regulatory changes, technological advances, consumer demands, greater availability of natural gas, environmental needs, and other factors. The increasingly competitive environment presents opportunities to compete for new customers, as well as the risk of loss of existing customers. Competition presents Entergy with many challenges. The following have been identified by Entergy as its major competitive challenges.
The Energy Policy Act of 1992
The EPAct addresses a wide range of energy issues and is being implemented by both FERC and state regulators. The EPAct is designed to promote competition among utility and non utility generators by amending PUHCA to exempt from regulation a class of EWGs, among others, consisting of utility affiliates and non utilities that own and operate facilities for the generation and transmission of power for sale at wholesale. The EPAct also gave FERC the authority to order investor- owned utilities to transmit power and energy to or for wholesale purchasers and sellers. This creates potential for electric utilities and other power producers to gain increased access to the transmission systems of other utilities to facilitate wholesale sales.
In response to the EPAct, FERC issued a notice of proposed rulemaking in mid-1994. This rulemaking concerns a regulatory framework for dealing with recovery of costs that were prudently incurred by electric utilities to serve customers under the traditional regulatory framework. These costs may become "stranded" as a result of increased competition. On March 29, 1995, FERC issued a supplemental notice of proposed rulemaking in this proceeding that would require public utilities to provide nondiscriminatory open access transmission service to wholesale customers and would also provide guidance on the recovery of wholesale and retail stranded costs. The risk of exposure to stranded costs that 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.
With regard to pending proceedings, including Entergy's open access transmission tariff proceedings originally filed in 1991 and amended in 1994 and 1995, FERC directed the parties to proceed with their cases while taking into account FERC's proposed rule. Comments and reply comments on the proposed rulemaking have now been filed with FERC by interested parties. Certain of the parties filing comments have proposed that FERC should order the immediate unbundling of all retail services as part of the final rulemaking in this proceeding, which is expected in the second quarter of 1996. In its comments in the proposed rulemaking, Entergy urged FERC to exercise its authority and responsibility to serve as a "backstop" in the event a state is unable or unwilling to provide for stranded-cost recovery -- particularly in the case of multi state utilities (such as the System), where cost shifting among jurisdictions might otherwise occur.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
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 March 1994 and, in June 1995, the LPSC implemented a performance-based formula rate plan for LP&L. The continuing pattern of rate reductions is a characteristic of the competitive environment in which Entergy operates.
Several of the Operating Companies have recently been ordered to grant base rate reductions and have refunded or credited customers for previous overcollections of rates. See Note 2 for additional discussion of rate reductions and incentive-rate regulation.
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 and ordered rate reductions. See Note 2 for additional discussion of GSU's post-Merger filings with the LPSC and the PUCT.
System Energy implemented a $65.5 million rate increase, subject to refund, in December 1995.
Potential Changes in the Electric Utility Industry
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, continues to evolve. Approximately 40 states have initiated studies of the concept of retail competition or are considering it as part of industry restructuring. Within the area served by the Operating Companies, the City of New Orleans, Louisiana, and Texas are conducting such studies.
In January 1996, the Council voted to investigate retail utility service competition. Although no date has been set, the investigation will focus on the impact of competition, service unbundling, and utility restructuring on consumers of retail electric and gas utility service in New Orleans. Earlier in 1995, a newly incorporated entity, Crescent City Utilities, Inc., submitted to the Council a draft resolution intended to permit the use of NOPSI's gas and electric transmission and distribution facilities by any other franchised utility to supply electricity and gas to retail customers in New Orleans. The Council has not scheduled hearings relating to this resolution.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
The PUCT is currently developing rules that will permit greater wholesale electric competition in Texas, as mandated by the Texas legislature in its 1995 session. These wholesale transmission access rules are expected to be in place by the first quarter of 1996. In addition, the PUCT is developing information to be contained in reports that will be submitted to the 1997 legislature concerning broader competitive issues such as the unbundling of electric utility operations, market-based pricing, performance-based ratemaking, and the identification and recovery of potential stranded costs as part of the transition to a more competitive electric industry environment. This information will be developed through a series of workshops and comments by interested parties throughout 1996. In addition, during 1995, the Texas legislature revised the Public Utility Regulatory Act, the law regulating electric utilities in Texas. The revised law permits utility and non utility EWGs and power marketers to sell wholesale power in the state. The revised law also permits the discounting of rates with certain conditions, but does not change the current law governing retail wheeling or the treatment of federal income taxes.
During the second quarter of 1995, the Louisiana legislature considered a bill permitting local retail wheeling. The bill was defeated, but similar bills are likely to be introduced in the future. During the same time period, the LPSC initiated a generic docket to investigate retail, wholesale, and affiliate wheeling of electricity. Currently, no procedural schedule has been set for this docket.
During January 1996, a bill entitled the "Electric Power Competition Act of 1996" was introduced into the United States House of Representatives. The bill proposes to amend certain provisions under PURPA for the purpose of facilitating future deregulation of the electric power industry.
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 electric distribution systems, or extending existing ones. In some cases, municipalities are also seeking new delivery points in order to serve retail customers, especially large industrial customers, which currently receive service from an investor-owned utility. 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 utility's inability to recover costs that it has incurred for the purpose of serving those customers.
Significant Industrial Cogeneration Effects
Many of Entergy's industrial customers, whose costs structures are energy-sensitive, have energy alternatives available to them such as fuel switching, cogeneration, and production shifting. Cogeneration is generally defined as the combined production of electricity and some other useful form of heat, typically steam. Cogenerated power may either be 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. It is the practice of the Operating Companies to negotiate the renewal of contracts with large industrial customers prior to their expiration. In certain cases (particularly for GSU and LP&L), contracts or special tariffs that use flexible pricing have been negotiated with industrial customers to keep these customers on the System. The pricing agreements are not at full cost of service. Such rates may fully recover all related costs, but provide only a minimal return, if any, on investment. In 1995, KWh sales to GSU's and LP&L's industrial customers at less than full cost- of-service rates made up approximately 27% and 39% of GSU's and LP&L's total industrial class sales, respectively.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Since PURPA was enacted in 1978, the Operating Companies have been largely successful in retaining industrial load. The Operating Companies anticipate they will be successful in renegotiating such contracts with large industrial customers. However, this competitive challenge will likely increase. There can be no assurance that the Operating Companies will be successful or that future revenues will not be lost to other forms of generation.
The Council has recently approved a resolution requiring its prior approval of regulatory treatment of any lost contribution to fixed costs as a result of incentive-rate agreements with large industrial or commercial customers entered into for the purposes of retaining those customers. The resolution also requires prior approval by the Council of the regulatory treatment of stranded costs resulting from the loss of large customers.
During 1995, LP&L received separate notices from two large industrial customers that will proceed with proposed cogeneration projects for the purpose of fulfilling their future electric energy needs. These customers will continue to purchase their energy requirements from LP&L until their cogeneration facilities are completed and operational, which is expected to occur between the years 1997 and 1998. After that time these customers will still purchase energy from LP&L, but at a reduced level. During 1995, these two customers represented an aggregate of approximately 18% of total LP&L industrial sales, and provided 12% of total industrial base revenues.
Domestic and Foreign Energy-Related Investments
Entergy Corporation seeks opportunities to expand its domestic energy-related businesses that are not regulated by state and local regulatory authorities, as well as foreign power investments that provide returns in excess of similar domestic investments. Such business ventures currently include power development and new technology related to the utility business. Entergy Corporation's strategy is to identify and pursue business opportunities that have the potential to earn a greater return than its regulated utility operations. Refer to "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - LIQUIDITY AND CAPITAL RESOURCES" for a discussion of Entergy Corporation's 1995 investment in domestic and foreign energy-related businesses. These investments may involve a greater risk than domestically regulated utility enterprises. In 1995, Entergy Corporation's investments in domestic and foreign energy-related investments reduced consolidated net income by approximately $64.8 million. While such investments did not have a positive effect on 1995 earnings, management believes they will show profits in the near term.
In an effort to expand into new energy-related businesses, Entergy plans to commercialize its fiber optic telecommunications network that connects system facilities and supports its internal business needs. Entergy will provide long-haul fiber optic capacity to major telecommunications carriers, which in turn will market that service to third parties. The recently enacted Telecommunications Act of 1996 permits Entergy to market such a service, pending state and local regulatory approval. On February 8, 1996, the President of the United States signed the Telecommunications Act into law. This new law contains an exemption from PUHCA that will permit registered utility holding companies to form and capitalize subsidiaries to engage in telephone, telecommunications, and information service businesses without SEC approval. However, the law requires that such telecommunications subsidiaries file for exemption with the Federal Communications Commission, and that they not engage in transactions with utility affiliates within their holding company systems or acquire utility affiliates' property without state or local regulatory approval. Entergy Corporation has requested approval from the SEC to form a new nonregulated subsidiary named Entergy Technologies Company to commercialize the Entergy telecommunications network.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
In early October 1995, FERC issued an order granting EWG status to Entergy Power Marketing Corporation (EPM), a wholly owned subsidiary of Entergy Corporation. EPM was created during 1995 to become a buyer and seller of electrical energy and its generating fuels. In February 1996, FERC approved market-based rate sales of electricity by EPM. Such approval will allow EPM to begin providing wholesale customers with a variety of services including physical and financial trading. Pending approval from the SEC, EPM expects to begin financial trading by the summer of 1996.
On January 5, 1996, Entergy Corporation finalized its acquisition of CitiPower, an electric distribution company serving Melbourne, Australia, and surrounding suburbs. The purchase price of CitiPower was approximately $1.2 billion, of which $294 million represented an equity investment by Entergy Corporation, and the remainder represented debt. Entergy Corporation funded the majority of the equity portion of the investment by using $230 million of its $300 million line of credit. CitiPower serves approximately 234,500 customers, the majority of which are commercial customers. At the time of the acquisition, CitiPower had 846 employees.
ANO Matters
Entergy Operations has made inspections and repairs from time to time on ANO 2's steam generators. During the October 1995 inspection, additional cracks in the tubes were discovered. Currently, Entergy Operations is in the process of gathering information and assessing various options for the repair or replacement of ANO 2's steam generators. See Note 8 for additional information.
Deregulated Utility Operations
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. The operating income (loss) from these operations was $7.2 million in 1995, $(5.2) million in 1994, and $(2.9) million in 1993.
The increase in 1995 net income from deregulated operations was due to increased revenues and reduced operation and maintenance expenses, partially offset by increased depreciation. The larger net loss from deregulated operations in 1994 was principally due to a smaller income tax benefit. The future impact of the deregulated utility operations on Entergy and GSU's results of operations and financial position will depend on future operating costs, the efficiency and availability of generating units, and the future market for energy over the remaining life of the assets. Entergy expects the performance of its deregulated utility operations to improve, due to continued reductions in operation and maintenance expenses. The deregulated operations will be subject to the requirements of SFAS 121, as discussed in Note 1, in determining the recognition of any asset impairment.
Property Tax Exemptions
LP&L and GSU are working with tax authorities to determine the method for calculating the amount of property taxes to be paid once Waterford 3 and River Bend's local property tax exemptions expire. Waterford 3's exemption expired in December 1995 and River Bend's exemption expires in December 1996. LP&L expects that the LPSC will address the accounting treatment and recovery of Waterford 3's property taxes in April 1996, in conjunction with the annual filing required under its performance-based formula rate plan.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Environmental Issues
GSU has been notified by the U. S. Environmental Protection Agency (EPA) that it has been designated as a PRP for the clean-up of certain hazardous waste disposal sites. See Note 8 for additional information.
As a consequence of rules for solid waste regulation issued by the Louisiana Department of Environmental Quality in 1993, LP&L has determined that certain of its power plant wastewater impoundments must be upgraded or closed. See Note 8 for additional information.
Accounting Issues
New Accounting Standard - In March 1995, the FASB issued SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121), effective January 1, 1996. This standard describes circumstances that may result in assets being impaired and provides criteria for recognition and measurement of asset impairment. See Notes 1 and 2 for information regarding the potential impacts of the new accounting standard on Entergy.
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" (SFAS 71). 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 can actually be charged to and collected from customers.
In the event that 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, 1995, and for the foreseeable future, the System's financial statements continue to follow SFAS 71, except for certain portions of GSU's business. See Note 1 for additional discussion of Entergy's application of SFAS 71.
Accounting for Decommissioning Costs - The staff of the SEC has been reviewing the financial accounting practices of the electric utility industry regarding the recognition, measurement, and classification of nuclear decommissioning costs for nuclear generating stations in the financial statements of electric utilities. In February 1996 the FASB issued an exposure draft of the proposed SFAS addressing the accounting for decommissioning costs as well as liabilities related to the closure and removal of all long-lived assets. See Note 8 for a discussion of proposed changes in the accounting for decommissioning/closure costs and the potential impact of these changes on Entergy.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of Entergy Corporation
We have audited the accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries as of December 31, 1995 and 1994, and the related statements of consolidated income, retained earnings and paid-in-capital and cash flows for the years 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 audits. The consolidated financial statements of Entergy Corporation and Subsidiaries for the year ended December 31, 1993, were audited by other auditors, whose report, dated February 11, 1994, included explanatory paragraphs that (i) described changes in 1993 in the method of accounting for revenues by certain of the Corporation's subsidiaries (Note 1); (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 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, 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, 1995 and 1994, and the results of their operations and their cash flows for the years 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, 1995, approximately $482 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, 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 also discussed in Note 2, approximately $187 million of additional deferred River Bend operating costs which exceed those costs currently being recovered through rates are expected to be written-off upon the adoption of Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Adoption of this Statement is required on January 1, 1996.
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.
As discussed in Note 1 to the consolidated financial statements, in 1995 one of the Corporation's subsidiaries changed its method of accounting for incremental nuclear plant outage maintenance costs.
COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 14, 1996
INDEPENDENT AUDITORS' REPORT
To the Board of the Directors and the Shareholders of Entergy Corporation:
We have audited the accompanying statements of consolidated income, retained earnings and paid-in capital, and cash flows of Entergy Corporation and subsidiaries for the year 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 audit. 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 auditors.
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 and the report of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audit and the report of the other auditors, such consolidated financial statements present fairly, in all material respects, the results of Entergy Corporation and subsidiaries' operations and their cash flows for the year ended December 31, 1993 in conformity with generally accepted accounting principles.
The Corporation acquired a 70% interest in River Bend Unit 1 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. 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 revenue 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.
DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994
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 twelve 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 is presented with GSU's 1993 results of operations included for comparative purposes.
Net Income
Consolidated net income increased in 1995 due primarily to increased electric operating revenues, decreased other operation and maintenance expenses, the onetime recording of the cumulative effect of the change in accounting method for incremental nuclear refueling outage maintenance costs at AP&L, and decreased interest expense, partially offset by increased income taxes and decreased miscellaneous income - net.
Consolidated net income decreased 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. 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.
Significant factors affecting the results of operations and causing variances between the years 1995 and 1994, and 1994 and 1993, 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.
The changes in electric operating revenues for the twelve months ended December 31, 1995, are as follows:
Increase/ Description (Decrease) ----------------------- ------------ (In Millions)
Change in base revenues $6.6 Rate riders 15.3 Fuel cost recovery (28.0) Sales volume/weather 141.3 Other revenue (including 4.3 unbilled) Sales for resale 49.5 System Energy-FERC Settlement 120.5 ------- Total $309.5 =======
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Electric operating revenues increased in 1995 as a result of an increase in retail energy sales, the effects of the 1994 FERC Settlement, and increased wholesale revenues, partially offset by rate reductions at GSU, LP&L, and NOPSI and lower fuel adjustment revenues. Warmer weather and non-weather related volume growth contributed equally to the increase in retail electric energy sales. The increase in sales for resale was primarily from increased energy sales outside of Entergy's service area. The increase in other revenues was due to the effects of the 1994 FERC Settlement and the 1994 NOPSI Settlement.
Electric operating revenues decreased in 1994 due primarily to rate reductions 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.
Gas operating revenues decreased in 1995 because of a milder winter than in 1994, gas rate reductions agreed to in the 1994 NOPSI Settlement, and a lower unit price for gas purchased for resale. Gas operating revenues decreased slightly in 1994 as a result of lower weather-related sales.
Expenses
Operating expenses increased in 1995 due to increased income taxes related to higher pre-tax book income and the effects of the 1994 FERC Settlement. In addition, nuclear refueling outage expenses increased due to a 1995 refueling outage at Grand Gulf 1 and the adoption of the change in accounting method at AP&L. The increase in operating expenses was partially offset by a reduction in other operation and maintenance expenses. Other operation and maintenance expenses decreased primarily because of lower payroll-related expenses resulting from the restructuring program discussed in Note 11 and 1994 Merger-related costs.
Operating expenses decreased in 1994 due primarily to decreased power purchases from nonassociated utilities and to changes in generation requirements for the Operating Companies, decreased nuclear refueling outage expenses as the result of Grand Gulf 1 outage expenses incurred in 1993, decreased income taxes due primarily to lower pre-tax book income, and the effects of the FERC Settlement.
Interest charges decreased in 1995 and 1994 as a result of the retirement and refinancing of higher cost long-term debt.
Preferred dividend requirements decreased in 1995 and 1994 due to stock redemption activities.
Other
Miscellaneous other income - net decreased in 1995 due primarily to expansion activities in nonregulated businesses.
Miscellaneous other income - net decreased in 1994 due primarily to the amortization of the plant acquisition adjustment related to the GSU Merger, the adoption of SFAS 116, "Accounting for Contributions Made and Contributions Received," and reduced Grand Gulf 1 carrying charges at AP&L.
ENTERGY CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME
ENTERGY CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES
ENTERGY CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED RETAINED EARNINGS AND PAID-IN CAPITAL
ENTERGY CORPORATION AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
(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.
(1)1994 includes the effects of the FERC Settlement, the 1994 NOPSI Settlement, and a GSU reserve for rate refund.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of Arkansas Power & Light Company
We have audited the accompanying balance sheets of Arkansas Power & Light Company as of December 31, 1995 and 1994, and the related statements of income, retained earnings and cash flows for the years 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 audits. The financial statements of the Company for the year ended December 31, 1993, were audited by other auditors, whose report, dated February 11, 1994, included an explanatory paragraph that described a change in the method of accounting for revenues, which is discussed in Note 1 to these financial statements.
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, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1995 and 1994, and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles.
As discussed in Note 1 to the financial statements, in 1995 the Company changed its method of accounting for incremental nuclear plant outage maintenance costs.
COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 14, 1996
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of Arkansas Power & Light Company:
We have audited the accompanying statements of income, retained earnings, and cash flows of Arkansas Power & Light Company (AP&L) for the year 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 audit.
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, such financial statements present fairly, in all material respects, the results of AP&L's operations and its cash flows for the year 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.
DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994
ARKANSAS POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income increased in 1995 due primarily to the onetime recording of the cumulative effect of the change in accounting method for incremental nuclear refueling outage maintenance costs as discussed in Note 1. Excluding the above mentioned item, net income for 1995 decreased due to an increase in depreciation, amortization, and decommissioning expenses and income tax expense offset by an increase in revenues from retail energy sales and a decrease in other operation and maintenance expenses.
Net income decreased in 1994 due primarily to the onetime 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 other operation and maintenance expenses resulting from restructuring and storm damage costs during 1994.
Significant factors affecting the results of operations and causing variances between the years 1995 and 1994, and 1994 and 1993, are discussed under "Revenues and Sales," "Expenses," and "Other" below.
Revenues and Sales
See "SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON," following the notes to financial statements, for information on operating revenues by source and KWh sales.
The changes in electric operating revenues for the twelve months ended December 31, 1995, are as follows:
Increase/ Description (Decrease) ------------------------- ------------- (In Millions)
Change in base revenues $(3.4) Rate riders 15.9 Fuel cost recovery 25.1 Sales volume/weather 38.2 Other revenue (including unbilled) 9.7 Sales for resale (28.0) ------- Total $57.5 ======
Electric operating revenues increased for 1995 due primarily to increased retail energy sales and fuel adjustment revenues partially offset by a decrease in sales for resale to associated companies. The increase in sales volume/weather resulted from increased customers and associated usage, while the remainder resulted from warmer weather in the summer months. The decrease in sales for resale to associated companies was caused by changes in generation availability and requirements among the Operating Companies.
Total revenues remained relatively unchanged in 1994. Retail revenues decreased primarily due to lower recovery of fuel revenues during the year offset by increased sales for resale to associated companies in 1994, caused by changes in generation availability and requirements among the Operating Companies.
ARKANSAS POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Expenses
Operating expenses increased in 1995 because of an increase in depreciation, amortization, and decommissioning expenses and income tax expense, offset by a decrease in other operation and maintenance expenses. Depreciation, amortization, and decommissioning expenses increased primarily due to additions and upgrades at ANO and additions to transmission lines, substations, and other equipment. Also, decommissioning expense increased due to the implementation of the decommissioning rate rider which resulted from the decommissioning study performed in 1994. Income tax expense increased primarily due to the write-off in 1994 of investment tax credits in accordance with the FERC Settlement, as discussed below. Income tax expense also increased due to higher pre-tax income in 1995. The decrease in other operation and maintenance expenses is largely due to restructuring costs and storm damage costs recorded in 1994 .
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. Other operation and maintenance expenses increased in 1994 primarily due to the storm damage and restructuring costs as discussed in Note 11. The decrease in 1994 purchased power expenses is primarily due to the decrease in the price of purchased power. 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.
Other
Miscellaneous other income - net decreased in 1994 due primarily to reduced Grand Gulf 1 carrying charges. Other income taxes decreased in 1994 primarily due to a lower pretax income as discussed above. Interest on long-term debt decreased in 1994 due primarily to the continued retirement and refinancing of high-cost debt.
ARKANSAS POWER & LIGHT COMPANY STATEMENTS OF INCOME
ARKANSAS POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS
ARKANSAS POWER & LIGHT COMPANY BALANCE SHEETS ASSETS
ARKANSAS POWER & LIGHT COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES
ARKANSAS POWER & LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS
ARKANSAS POWER & LIGHT COMPANY
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
(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 1995 and 1993 .
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, 1995 and 1994 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, 1995. 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.
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, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles.
As discussed in Note 2 to the financial statements, the net amount of capitalized costs for its River Bend Unit I Nuclear Generating Plant (River Bend) exceed those costs currently being recovered through rates. At December 31, 1995, approximately $482 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, 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 also discussed in Note 2, approximately $187 million of additional deferred River Bend operating costs which exceed those costs currently being recovered through rates are expected to be written-off upon the adoption of Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Adoption of this Statement is required on January 1, 1996.
As discussed in Note 8 to the 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.
As discussed in Note 13 to the financial statements, the common stock of the Company was acquired on December 31, 1993.
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.
COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 14, 1996
GULF STATES UTILITIES COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income increased in 1995 principally as the result of an increase in electric operating revenues, a decrease in other operation and maintenance expenses, and an increase in other income. These changes were partially offset by higher income taxes.
Net income decreased in 1994 due primarily to write-offs and charges associated with the resolution of contingencies and additional Merger-related costs aggregating $137 million, a base rate reduction ordered by the PUCT applied retroactively to March 1994, and restructuring costs. See Note 2 and Note 11 for additional information.
Significant factors affecting the results of operations and causing variances between the years 1995 and 1994, and 1994 and 1993, are discussed under "Revenues and Sales," "Expenses," and "Other" below.
Revenues and Sales
See "SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON," following the notes to financial statements, for information on operating revenues by source and KWh sales.
The changes in electric operating revenues for the twelve months ended December 31, 1995, are as follows:
Increase/ Description (Decrease) ------------------------- --------- (In Millions)
Change in base revenues $32.0 Fuel cost recovery (29.6) Sales volume/weather 35.0 Other revenue (including unbilled) 1.1 Sales for resale 31.3 ------- Total $69.8 =======
Electric operating revenues increased in 1995 primarily due to increased sales volume/weather and higher sales for resale. These increases were partially offset by lower fuel adjustment revenues, which do not affect net income. Base revenues also increased in 1995 as a result of rate refund reserves established in 1994, as discussed below, which were subsequently reduced as a result of an amended PUCT order. The increase in base revenues was partially offset by rate reductions in effect for Texas and Louisiana. Sales volume/weather increased because of warmer than normal weather and an increase in usage by all customer classes. Sales for resale increased as a result of changes in generation availability and requirements among the Operating Companies.
Electric operating revenues decreased in 1994 due primarily to a base rate reduction ordered by the PUCT applied retroactively to March 1994, see Note 2 for additional information, 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.
GULF STATES UTILITIES COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Gas operating revenues decreased for 1995 primarily due to a decrease in residential sales. This decrease was the result of a milder winter than in 1994.
Expenses
Operating expenses decreased in 1995 as a result of lower other operation and maintenance expenses and purchased power expenses, partially offset by higher income taxes. Other operation and maintenance expenses decreased primarily due to charges made in 1994 for Merger-related costs, restructuring costs, and certain pre- acquisition contingencies including unfunded Cajun-River Bend costs and environmental clean-up costs. Purchased power expenses decreased because of the availability of less expensive gas and nuclear fuel for use in electric generation as well as changes in the generation requirements among the Operating Companies. In addition, the decrease in purchased power expenses in 1995 was the result of the recording of a provision for refund of disallowed purchased power expenses in 1994. Income taxes increased primarily due to higher pre-tax income in 1995.
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 expenses increased in 1994 due to GSU's participation in joint dispatch through the System power pool resulting from increased energy sales as discussed above. The increase in purchased power expenses 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. Fuel, fuel-related expenses, and gas purchased for resale decreased in 1994 primarily due to lower gas prices.
Other operation and maintenance expenses increased in 1994 due primarily to charges associated with certain pre-acquisition contingencies, additional Merger-related costs and restructuring costs as discussed in Note 11.
Income taxes decreased in 1994 due primarily to lower pretax income resulting from the charges discussed above.
Other
Other miscellaneous income increased in 1995 as the result of certain adjustments made in 1994 related to pre-acquisition contingencies including Cajun-River Bend litigation (see Note 8 for additional information) the write-off of previously disallowed rate deferrals, and plant held for future use. As a result of these charges, income taxes on other income were significantly higher in 1995 compared to 1994.
Other miscellaneous income decreased in 1994 due to the write-off of plant held for future use, establishment of a reserve related to the Cajun-River Bend litigation, the write-off of previously disallowed rate deferrals, and obsolete spare parts. These charges were 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.
GULF STATES UTILITIES COMPANY STATEMENTS OF INCOME (LOSS)
GULF STATES UTILITIES COMPANY STATEMENTS OF CASH FLOWS
GULF STATES UTILITIES COMPANY BALANCE SHEETS ASSETS
GULF STATES UTILITIES COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES
GULF STATES UTILITIES COMPANY STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL
GULF STATES UTILITIES COMPANY
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
(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 Notes 2 and 8 regarding River Bend rate appeals and litigation with Cajun.
(1) 1994 includes the effects of a GSU reserve for rate refund.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of Louisiana Power & Light Company
We have audited the accompanying balance sheets of Louisiana Power & Light Company as of December 31, 1995 and 1994, and the related statements of income, retained earnings and cash flows for the years 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 audits. The financial statements of the Company for the year ended December 31, 1993, were audited by other auditors, whose report, dated February 11, 1994, expressed an unqualified opinion on these financial statements.
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, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1995 and 1994, and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 14, 1996
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of Louisiana Power & Light Company:
We have audited the accompanying statements of income, retained earnings, and cash flows of Louisiana Power & Light Company (LP&L) for the year 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 audit.
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, such financial statements present fairly, in all material respects, the results of LP&L's operations and its cash flows for the year ended December 31, 1993 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994
LOUISIANA POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income decreased in 1995 due to an April 1995 rate reduction and higher income taxes, partially offset by lower other operation and maintenance expenses. Net income increased in 1994 due primarily to the fourth quarter write-off of unamortized balances of deferred investment tax credits, partially offset by lower operating revenues and higher other operation and maintenance expenses.
Significant factors affecting the results of operations and causing variances between the years 1995 and 1994, and 1994 and 1993, are discussed under "Revenues and Sales" and "Expenses" below.
Revenues and Sales
See "SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON," following the notes to financial statements, for information on operating revenues by source and KWh sales.
The changes in operating revenues for the twelve months ended December 31, 1995, are as follows:
Increase/ Description (Decrease) ------------------------ -------------- (In Millions)
Change in base revenues $(29.9) Fuel cost recovery (35.9) Sales volume/weather 40.7 Other revenue (including unbilled) (23.3) Sales for resale 12.9 ------- Total $(35.5) =======
Operating revenues were lower in 1995 due primarily to a base rate reduction in the second quarter of 1995 and to lower fuel adjustment revenues, which do not affect net income. This decrease was partially offset by increased customer usage, principally caused by warmer summer weather. The completion of the amortization of proceeds from litigation with a gas supplier in the second quarter of 1994 also contributed to the decrease in other revenue, partially offset by higher sales to non-associated utilities.
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.
LOUISIANA POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Expenses
Operating expenses decreased in 1995 due to decreases in fuel expenses, including purchased power, and other operation and maintenance expenses, partially offset by an increase in depreciation and income taxes. The decrease in fuel expenses is due to lower fuel prices partially offset by an increase in generation. Other operation and maintenance expenses decreased because of lower payroll-related expenses as a result of the restructuring program discussed in Note 11, power plant waste water site closures in 1994, and a court settlement reducing legal expense. Depreciation expense increased due to capital improvements to distribution lines and substations and to an increase in the depreciation rate associated with Waterford 3. Income taxes increased due to the write-off in 1994 of deferred investment tax credits in accordance with the 1994 FERC Settlement, a decrease in tax depreciation associated with Waterford 3, and higher pre-tax income.
Operating expenses decreased in 1994 due primarily to a decrease in income tax expense as a result of the write-off of deferred investment tax credits pursuant to a FERC settlement and lower fuel expenses partially offset by higher other operation and maintenance expenses. The decrease in fuel and purchased power expenses is due primarily to lower fuel and purchased power prices. The increase in other operation and maintenance expenses is due primarily to restructuring costs and power plant waste water site closures. Interest expense decreased in 1994 as a result of the retirement and refinancing of high-cost debt.
LOUISIANA POWER & LIGHT COMPANY STATEMENTS OF INCOME
LOUISIANA POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS
LOUISIANA POWER & LIGHT COMPANY BALANCE SHEETS ASSETS
LOUISIANA POWER & LIGHT COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES
LOUISIANA POWER & LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS
LOUISIANA POWER & LIGHT COMPANY
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
(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.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of Mississippi Power & Light Company
We have audited the accompanying balance sheets of Mississippi Power & Light Company as of December 31, 1995 and 1994, and the related statements of income, retained earnings and cash flows for the years 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 audits. The financial statements of the Company for the year ended December 31, 1993, were audited by other auditors, whose report, dated February 11, 1994, included an explanatory paragraph that described a change in the method of accounting for revenues, which is discussed in Note 1 to these financial statements.
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, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1995 and 1994, and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 14, 1996
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of Mississippi Power & Light Company:
We have audited the accompanying statements of income, retained earnings, and cash flows of Mississippi Power & Light Company (MP&L) for the year 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 audit.
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, such financial statements present fairly, in all material respects, the results of MP&L's operations and its cash flows for the year 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.
DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994
MISSISSIPPI POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income increased in 1995 primarily due to increased revenues and a decrease in other operation and maintenance expenses partially offset by an increase in income tax expense. Net income decreased in 1994 due primarily to the onetime 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.
Significant factors affecting the results of operations and causing variances between the years 1995 and 1994, and 1994 and 1993, are discussed under "Revenues and Sales," "Expenses," and "Other" below.
Revenues and Sales
See "SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON," following the notes to financial statements, for information on operating revenues by source and KWh sales.
The changes in electric operating revenues for the twelve months ended December 31, 1995, are as follows:
Increase/ Description (Decrease) ------------------------ ------------- (In Millions)
Change in base revenues $(6.1) Grand Gulf Rate Rider (0.6) Fuel cost recovery 12.8 Sales volume/weather 14.9 Other revenue (including unbilled) 5.6 Sales for resale 3.4 ------ Total $30.0 ======
Operating revenues increased in 1995 primarily due to an increase in retail and wholesale energy sales and higher fuel adjustment revenues, partially offset by rate reductions. Retail energy sales increased primarily due to the impact of weather and increased customer usage. Fuel adjustment revenues increased in response to higher fuel costs and do not impact net income. 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 commercial and industrial retail sales.
Expenses
Operating expenses increased in 1995 due primarily to an increase in income tax expense partially offset by a decrease in other operation and maintenance expenses. Operating expenses increased in 1994 due primarily to increased amortization of rate deferrals partially offset by lower fuel/purchased power and income tax expenses.
MISSISSIPPI POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Income tax expense increased in 1995 due primarily to the 1994 write-off of unamortized deferred investment tax credits and higher pretax income in 1995. 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.
Other operation and maintenance expense decreased in 1995 due primarily to 1994 Merger-related costs allocated to MP&L and payroll expenses. No significant Merger-related costs were allocated to MP&L during the current year. Payroll expenses decreased as a result of the restructuring program announced and accrued for during the third quarter of 1994. The restructuring program included a reduction in the number of MP&L employees during 1995. In addition, maintenance expenses decreased at various power plants.
Purchased power expense decreased in 1994 due primarily to changes in generation availability and requirements among the Operating Companies and a lower per unit price for power purchased.
The amortization of rate deferrals increased in 1994 reflecting the fact that MP&L, based on the Revised Plan, collected more Grand Gulf 1-related costs from its customers in 1994 than in 1993.
Other
Interest expense decreased in 1994 due primarily to the retirement and refinancing of high-cost debt.
MISSISSIPPI POWER & LIGHT COMPANY STATEMENTS OF INCOME
MISSISSIPPI POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS
MISSISSIPPI POWER & LIGHT COMPANY BALANCE SHEETS ASSETS
MISSISSIPPI POWER & LIGHT COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES
MISSISSIPPI POWER & LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS
MISSISSIPPI POWER & LIGHT COMPANY
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
(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.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of New Orleans Public Service Inc.
We have audited the accompanying balance sheets of New Orleans Public Service Inc. as of December 31, 1995 and 1994, and the related statements of income, retained earnings and cash flows for the years 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 audits. The financial statements of the Company for the year ended December 31, 1993, were audited by other auditors, whose report, dated February 11, 1994, included an explanatory paragraph that described a change in the method of accounting for revenues, which is discussed in Note 1 to these financial statements.
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, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1995 and 1994, and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 14, 1996
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of New Orleans Public Service Inc.
We have audited the accompanying statements of income, retained earnings, and cash flows of New Orleans Public Service Inc. (NOPSI) for the year 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 audit.
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, such financial statements present fairly, in all material respects, the results of NOPSI's operations and its cash flows for the year 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.
DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994
NEW ORLEANS PUBLIC SERVICE INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income increased in 1995 principally due to 1994 refunds associated with the 1994 NOPSI Settlement and a decrease in other operation and maintenance expense, partially offset by a permanent rate reduction that took place January 1, 1995. Net income decreased in 1994 due to the effects of the 1994 NOPSI Settlement 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. See Note 2 for a discussion of the 1994 NOPSI Settlement.
Significant factors affecting the results of operations and causing variances between the years 1995 and 1994, and 1994 and 1993, are discussed under "Revenues and Sales" and "Expenses" below.
Revenues and Sales
See "SELECTED FINANCIAL DATA-FIVE-YEAR COMPARISON," following the notes to financial statements, for information on electric operating revenues by source and KWh sales.
The changes in electric operating revenues for the twelve months ended December 31, 1995, are as follows:
Increase/ Description (Decrease) -------------------- ------------- (In Millions)
Change in base revenues $12.2 Fuel cost recovery (0.3) Sales volume/weather 12.5 Other revenue (including 6.1 unbilled) Sales for resale 3.5 ------ Total $34.0 ======
Electric operating revenues increased in 1995 as a result of refunds in 1994 associated with the 1994 NOPSI Settlement and an increase in energy sales. The increase in energy sales is primarily due to weather effects on retail sales and an increase in sales for resale. 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.
Gas operating revenues decreased in 1995 primarily due to the rate reduction agreed to in the NOPSI Settlement effective January 1, 1995, and a lower unit purchase price for gas purchased for resale. Gas operating revenues decreased slightly in 1994 as a result of lower gas sales.
Expenses
Operating expenses increased in 1995 due primarily to an increase in income taxes and the increased amortization of rate deferrals, partially offset by a decrease in fuel and other operation and maintenance expenses. Fuel expenses decreased in 1995 primarily due to a decrease in fuel prices. Other operation and maintenance expenses decreased primarily due to a decrease in maintenance activity and lower payroll expenses. The decrease in payroll expenses is the result of the 1994 restructuring and the related decrease in employees. Operating expenses decreased in 1994 due primarily to lower purchased power expenses and lower income tax expenses.
NEW ORLEANS PUBLIC SERVICE INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Purchased power expenses decreased in 1994 due primarily to changes in generation availability and requirements among the Operating Companies and lower costs.
Gas purchased for resale decreased in 1995 due lower gas prices. Gas purchased for resale decreased in 1994 due to decreased gas sales.
Income taxes increased in 1995 as a result of lower pretax income in 1994 due to the 1994 NOPSI Settlement and the write-off of the unamortized balances of deferred investment tax credits pursuant to the FERC Settlement in 1994. 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.
The increases in the amortization of rate deferrals in 1995 and 1994 are 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. STATEMENTS OF INCOME
NEW ORLEANS PUBLIC SERVICE INC. STATEMENTS OF CASH FLOWS
NEW ORLEANS PUBLIC SERVICE INC. BALANCE SHEETS ASSETS
NEW ORLEANS PUBLIC SERVICE INC. BALANCE SHEETS CAPITALIZATION AND LIABILITIES
NEW ORLEANS PUBLIC SERVICE INC. STATEMENTS OF RETAINED EARNINGS
NEW ORLEANS PUBLIC SERVICE INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
(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.
(1) 1994 includes the effects of the 1994 NOPSI Settlement.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholder of System Energy Resources, Inc.
We have audited the accompanying balance sheets of System Energy Resources, Inc. as of December 31, 1995 and 1994, and the related statements of income, retained earnings and cash flows for the years 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 audits. The financial statements of the Company for the year ended December 31, 1993, were audited by other auditors, whose report, dated February 11, 1994, expressed an unqualified opinion on these financial statements.
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, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1995 and 1994, and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P. New Orleans, Louisiana February 14, 1996
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of System Energy Resources, Inc.
We have audited the accompanying statements of income, retained earnings, and cash flows of System Energy Resources, Inc. (System Energy) for the year 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 audit.
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, such financial statements present fairly, in all material respects, the results of System Energy's operations and its cash flows for the year ended December 31, 1993 in conformity with generally accepted accounting principles.
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.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income increased in 1995 primarily due to the effect of the FERC Settlement which reduced 1994 net income by $80.2 million. See Note 2 for a discussion of the FERC Settlement. This was partially offset by revenues being adversely impacted by a lower return on System Energy's decreasing investment in Grand Gulf 1. These factors also resulted in the decrease in 1994 net income.
Significant factors affecting the results of operations and causing variances between the years 1995 and 1994, and 1994 and 1993, are discussed under "Revenues" and "Expenses" below.
Revenues
Operating revenues increased in 1995 due primarily to the effect of the FERC Settlement on 1994 revenues as discussed in "Net Income" above and the recovery of increased expenses in connection with a Grand Gulf 1 refueling outage offset by a lower return on System Energy's decreasing investment in Grand Gulf 1. Revenues attributable to the return on investment are expected to continue to decline each year as a result of the depreciation of System Energy's 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, and decreased operation and maintenance expenses. See Note 1 for a description of the components of System Energy's operating revenues.
Expenses
Operating expenses increased in 1995 due primarily to higher nuclear refueling outage expenses, higher depreciation, amortization, and decommissioning, and higher income taxes, partially offset by lower fuel expenses as a result of the refueling outage. Grand Gulf 1 was on-line for 285 days in 1995 as compared with 345 days in 1994. The difference in the on-line days was primarily due to the unit's seventh refueling outage that lasted from April 15, 1995, to June 21, 1995 (68 days), and, to a lesser extent, unplanned outages in 1995 totaling 12 days, compared to 20 days in 1994. Depreciation, amortization, and decommissioning increased due to a $4 million increase in amortization (as a result of the reclassification of $81 million of Grand Gulf 1 costs and the accelerated amortization of the reclassified costs over a ten-year period in accordance with the 1994 FERC Settlement) and $1 million in decommissioning. Total income taxes increased in 1995 due primarily to higher pretax book income.
Operating expenses decreased in 1994 due primarily to lower other operation and maintenance expenses and lower income taxes. The lower level of outages for 1994 increased fuel for electric generation, but was partially offset by less expensive nuclear fuel and increased operating efficiency. Nonfuel operation and maintenance expenses decreased significantly in 1994 due to declines in contract work expenses, employee benefits, and materials and supplies expenses. Total income taxes decreased in 1994 due primarily to lower pretax book income
Interest charges decreased in both 1995 and 1994 due primarily to the retirement and refinancing of high-cost long-term debt partially offset by interest associated with the FERC Settlement refunds.
SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF INCOME
SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF CASH FLOWS
SYSTEM ENERGY RESOURCES, INC. BALANCE SHEETS ASSETS
SYSTEM ENERGY RESOURCES, INC. BALANCE SHEETS CAPITALIZATION AND LIABILITIES
SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF RETAINED EARNINGS
SYSTEM ENERGY RESOURCES, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
(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.
ENTERGY CORPORATION AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy)
The accompanying consolidated financial statements include the accounts of Entergy Corporation and its direct subsidiaries: AP&L, GSU, LP&L, MP&L, NOPSI, System Energy, Entergy Services, Entergy Operations, Entergy Power, Entergy Enterprises, System Fuels, Entergy S.A., Entergy Argentina S.A., Entergy Power Marketing Corporation, Entergy Power Development Corporation, Entergy Argentina S.A., Ltd., Entergy Transener S.A., Entergy Power Development International Holdings, Inc., and Entergy Power Development International Holdings. A number of these subsidiaries have additional subsidiaries.
Because the acquisition of GSU was consummated on December 31, 1993, under the purchase method of accounting, GSU's operations were not included in the consolidated amounts for the year ended December 31, 1993. GSU is included in all of the consolidated financial statements for 1994 and 1995. 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 with no effect on net income or shareholders' equity.
Use of Estimates in the Preparation of Financial Statements - - - - -----------------------------------------------------------
The preparation of Entergy Corporation and its subsidiaries' financial statements, in conformity with generally accepted accounting principles, requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 1995 and 1994, and the reported amounts of revenues and expenses during fiscal years 1995, 1994, and 1993. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used in 1995 financial statements.
Revenues and Fuel Costs - - - - -----------------------
AP&L, LP&L, and MP&L generate, transmit, and distribute electricity (primarily to retail customers) in the States of Arkansas, Louisiana, and Mississippi, respectively. GSU generates, transmits, and distributes electricity primarily to retail customers in the States of Texas and Louisiana; distributes gas at retail in the City of Baton Rouge, Louisiana, and vicinity; and also sells steam to a large refinery complex in Baton Rouge. NOPSI sells both electricity and gas to retail customers in the city of New Orleans (except for Algiers where LP&L is the electricity supplier).
System Energy's operating revenues recover operating expenses, depreciation, and capital costs attributable to Grand Gulf 1 from AP&L, LP&L, MP&L, and NOPSI. Capital costs are computed by allowing a return on System Energy's common equity funds allocable to its net investment in Grand Gulf 1, plus System Energy's effective interest cost for its debt allocable to its investment in Grand Gulf 1. See Note 2 for a discussion of System Energy's proposed rate increase.
A portion of AP&L's and LP&L's purchase of power from Grand Gulf has not been included in the determination of the cost of service to retail customers by the APSC and LPSC, respectively, as described in Note 2.
The 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 the accrual of estimated unbilled revenues. The cumulative effect (excluding GSU) of this accounting change as of January 1, 1993, increased System 1993 net income by $93.8 million (net of income taxes of $57.2 million), or $0.54 per share. The impacts on the individual operating companies are shown below:
Net of Tax Total Tax Effect ------------ ---------- --------- (In Thousands)
AP&L $81,327 $31,140 $50,187 MP&L 52,162 19,456 32,706 NOPSI 17,540 6,592 10,948 ------------ ---------- --------- System $151,029 $57,188 $93,841 ============= =========== ==========
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 GSU's subsequent appeals of the LPSC order regarding deferred unbilled revenues.
The 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 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 currently are leased back. For financial reporting purposes, these sale and leaseback transactions are reflected as financing transactions.
Net electric utility plant in service, by company and functional category, as of December 31, 1995 (excluding owned and leased nuclear fuel and the plant acquisition adjustment related to the Merger), is shown below:
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 rates on average depreciable property are shown below:
AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is only realized in cash through depreciation provisions included in rates.
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, 1995, the subsidiaries' investment and accumulated depreciation in each of these generating stations were as follows:
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 paid if a separate income tax return had been filed. Deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities and for certain credits available for carryforward.
Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.
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, "Accounting for Income Taxes."
Acquisition Adjustment - - - - ----------------------
Entergy Corporation, upon completion of the Merger in December 1993, recorded an acquisition adjustment in utility plant in the amount of $380 million, representing the excess of the purchase price over the historical cost of the GSU net assets acquired. During 1994, Entergy recorded an additional $124 million of acquisition adjustment related to the resolution of certain preacquisition contingencies and appropriate allocation of purchase price.
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. As of December 31, 1995, the unamortized balance of the acquisition adjustment was $472 million. 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, other Federal laws, and actions of regulatory commissions, the electric utility industry is moving toward a combination of competition and a modified regulatory environment. The Operating Companies' and System Energy's financial statements currently reflect, for the most part, assets and costs based on cost- based ratemaking regulation, 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 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 would 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, 1995, 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 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 its steam department during 1989 and for the Louisiana retail deregulated portion of River Bend in 1991. The results of Entergy's deregulated operations (before interest charges) for the years ended December 31, 1995, 1994, and 1993 are as follows:
SFAS 121 - - - - --------
In March 1995, the FASB issued SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121), which became effective January 1, 1996. This statement describes circumstances that may result in assets (including goodwill such as the Merger acquisition adjustment, discussed above) being impaired. The statement also provides criteria for recognition and measurement of asset impairment. Note 2 describes regulatory assets of $169 million (net of tax) related to Texas retail deferred River Bend operating and carrying costs. These deferred costs will be required to be written off upon the adoption of SFAS 121.
Certain other assets and operations of the Operating Companies totaling approximately $1.7 billion (pre-tax) could be affected by SFAS 121 in the future. Those assets include AP&L's and LP&L's retained shares of Grand Gulf 1, GSU's Louisiana deregulated asset plan, and its Texas jurisdiction abeyed portion of the River Bend plant, in addition to the wholesale jurisdiction and steam department operations of GSU. As discussed above, GSU has previously discontinued the application of SFAS 71 for the Louisiana deregulated asset plan, operations under the wholesale jurisdiction, and the steam department.
Entergy periodically reviews these assets and operations in order to determine if the carrying value of such assets will be recovered. Generally, this determination is based on the net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets. Based on current estimates of future cash flows as prescribed under SFAS 121, management anticipates that future revenues from such assets and operations of Entergy will fully recover all related costs.
Change in Accounting for Nuclear Refueling Outage Costs (Entergy - - - - ------------------------------------------------------- Corporation and AP&L)
In December 1995, at the recommendation of FERC, AP&L changed its method of accounting for nuclear refueling outage costs. The change, effective January 1, 1995, results in AP&L deferring incremental maintenance costs incurred during an outage and amortizing those costs over the operating period immediately following the nuclear refueling outage, which is the period that the charges are billed to customers. Previously, estimated costs of refueling outages were accrued over the period (generally 18 months) preceding each scheduled outage. The effect of the change for the year ended December 31, 1995, was to decrease net income by $5.1 million (net of income taxes of $3.3 million) or $.02 per share. The cumulative effect of the change was to increase net income $35.4 million (net of income taxes of $22.9 million) or $.15 per share. The pro forma effects of the change in accounting for nuclear refueling outages in 1994 and 1993, assuming the new method was applied retroactively to those years, would have been to decrease net income $3.2 million (net of income taxes of $2.1 million) and $6.5 million (net of income taxes of $4.2 million), respectively, or $.01 per share and $.04 per share, respectively.
Fair Value Disclosures - - - - ----------------------
The estimated fair value of financial instruments was determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. 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 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 disclosure concerning fair value methodologies.
NOTE 2. RATE AND REGULATORY MATTERS
Merger-Related Rate Agreements (Entergy Corporation, AP&L, GSU, LP&L, - - - - ------------------------------ MP&L, and NOPSI)
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 catastrophic events, 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 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.
In 1993, the LPSC and the PUCT approved separate regulatory proposals for GSU 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 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 shareholders and 40% by ratepayers during the eight years following the Merger. The LPSC plan requires annual regulatory filings by the end of May through the year 2001. The PUCT regulatory plan provides that such savings will be shared equally by shareholders and ratepayers, except that the shareholders' 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 the ratepayers' share of such savings be reflected in rates on a timely basis. In addition, the plan 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 Operating Companies under the FERC tracking mechanism (see below). On January 14, 1994, Entergy Corporation filed a petition for review before the D.C. Circuit seeking review of FERC's deletion of the 40% cap provision in the fuel cost protection mechanism. The matter is currently being held in abeyance.
FERC approved GSU's inclusion in the System Agreement. 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 if GSU were to acquire Cajun's 30% share in River Bend. The Operating Companies' regulatory authorities can elect to "opt out" of the fuel tracker, but are not required to make such an election until FERC has approved the respective Operating Company's compliance filing. The City and the MPSC have made such an election.
River Bend (Entergy Corporation and GSU) - - - - -----------
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 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, among other things, 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 and prevailed. The district court's decision in favor of the intervenors 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 in attempting 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, as well as GSU's deferred River Bend carrying costs included in the Allowed Deferrals, should 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 stated that the result of the majority opinion was, 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. On February 9, 1996, the Texas Supreme Court agreed to hear the appeal. Oral arguments are scheduled for March 19, 1996.
As of December 31, 1995, 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, $276 million (both net of depreciation), and $169 million, respectively. Allowed Deferrals were approximately $83 million, net of taxes and amortization, as of December 31, 1995. GSU estimates it has collected approximately $182 million of revenues as of December 31, 1995, 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 to customers of revenue received based upon such deferred costs 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. See below for a discussion of the write-off of deferred operating and carrying cost required under SFAS 121 in 1996. Based on advice from Clark, Thomas & Winters, A Professional Corporation, legal counsel of record in the Rate Appeal, management believes 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. 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, 1995, of up to $289 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 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. Disallowed investment in the plants ranged from 0% to 15%. Each case was unique, and the disallowances in each were made 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. Analysis by Sandlin Associates, 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; and 4. The analysis of GSU's legal staff, which has considerable experience in Texas rate case litigation.
Based on advice from Clark, Thomas & Winters, A Professional Corporation, legal counsel of record in the Rate Appeal, management believes that it is reasonably possible that the Allowed Deferrals will continue to be recovered in rates, and 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.
The adoption of SFAS 121 became effective January 1, 1996. SFAS 121 changes the standard for continued recognition of regulatory assets and, as a result GSU will be required to write-off $169 million of rate deferrals in 1996. The standard also describes circumstances that may result in assets being impaired and provides criteria for recognition and measurement of asset impairment. See Note 1 for further information regarding SFAS 121.
Filings with the PUCT and Texas Cities (Entergy Corporation and GSU) - - - - --------------------------------------
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. 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 was applied retroactively to March 31, 1994.
On May 26, 1995, the PUCT amended its previously issued March 20, 1995 rate order, reducing the $52.9 million annual base rate reduction to an annual level of $36.5 million. The PUCT's action was based, in part, upon a Texas Supreme Court decision not to require a utility to use the prospective tax benefits generated by disallowed expenses to reduce rates. The PUCT's May 26, 1995, amended order no longer required GSU to pass such prospective tax benefits onto its customers. The rate refund, retroactive to March 31, 1994, was approximately $61.8 million (including interest) and was refunded to customers in September, October, and November 1995. GSU and other parties have appealed the PUCT order, but no assurance can be given as to the timing or outcome of the appeal.
Filings with the LPSC - - - - --------------------- (Entergy Corporation and GSU)
In May 1994, GSU filed a required earnings analysis with the LPSC for the test year preceding the Merger (1993). On December 14, 1994, the LPSC ordered a $12.7 million annual rate reduction for GSU, effective January 1995. GSU received a preliminary injunction from the District Court regarding $8.3 million of the reduction relating to the earnings effect of a 1994 change in accounting for unbilled revenues. On January 1, 1995, GSU reduced rates by $4.4 million. GSU filed an appeal of the entire $12.7 million rate reduction with the District Court, which denied the appeal in July 1995. GSU has appealed the order to the Louisiana Supreme Court. The preliminary injunction relating to $8.3 million of the reduction will remain in effect during the appeal.
On May 31, 1995, GSU filed its second required post-Merger earnings analysis with the LPSC. Hearings on this review were held and a decision is expected in mid-1996.
(Entergy Corporation and LP&L)
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 a financial incentive to reduce costs and maintain high levels of customer satisfaction and system reliability. 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 would provide a financial incentive for LP&L to continuously improve in all three performance categories (price, customer satisfaction, and service reliability).
On June 2, 1995, as a result of the LPSC's earnings review of LP&L's performance-based formula rate plan, a $49.4 million reduction in base rates was ordered. This included $10.5 million of rate reductions previously made through the fuel adjustment clause. The net effect of the LPSC order was to reduce rates by $38.9 million. The LPSC approved LP&L's proposed formula rate plan with the following modifications. An earnings band was established with a range from 10.4% to 12% for return on equity. If LP&L's earnings fall within the bandwidth, no adjustment in rates occurs. However, if LP&L's earnings are above or below the established earnings band, prospective rate decreases or increases will occur. The LPSC also reduced LP&L's authorized rate of return from 12.76% to 11.2%. The LPSC rate order was retroactive to April 27, 1995.
On June 9, 1995, LP&L appealed the $49.4 million rate reduction and filed a petition for injunctive relief from implementation of $14.7 million of the reduction. The $14.7 million portion of the rate reduction represents revenue imputed to LP&L as a result of the LPSC's conclusion that LP&L charged unreasonably low rates to three industrial customers. Subsequently, a request for a $14.7 million rate increase was filed by LP&L. On July 13, 1995, LP&L was granted a preliminary injunction by the District Court on $14.7 million of the rate reduction pending a final LPSC order. Exclusive of the $14.7 million stayed under the preliminary injunction, the rate refund was retroactive to April 27, 1995, and amounted to approximately $8.2 million. Customers received the refunds in the months of September and October 1995.
In an order issued on January 31, 1996, the LPSC approved a settlement reducing the $14.7 million portion of the rate reduction to $12.35 million. Rate refunds subject to this settlement were retroactive to April 27, 1995, and were made in the months of January and February 1996. The refunds and related interest resulting from the settlement amounted to $8.9 million. The District Court case discussed above was dismissed as part of the settlement.
LPSC Fuel Cost Review (Entergy Corporation and GSU) - - - - ---------------------
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 was made through a billing credit on August 1994 bills. In August 1994, GSU appealed the remaining $13.9 million 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.
The LPSC is currently conducting the second phase of its review of GSU's fuel costs for the period October 1991 through December 1994. On June 30, 1995, the LPSC consultants filed testimony recommending a disallowance of $38.7 million of fuel costs. Hearings began in December 1995 and are expected to be completed in early March 1996.
Deregulated Asset Plan (Entergy Corporation and GSU) - - - - ----------------------
A deregulated asset plan representing an unregulated portion (approximately 24%) 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 sharing such incremental revenue above 4.6 cents per KWh between ratepayers and shareholders.
River Bend Cost Deferrals (Entergy Corporation and GSU) - - - - -------------------------
GSU deferred approximately $369 million of River Bend operating and 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 outcome of the Rate Appeal. As of December 31, 1995, the unamortized balance of these costs was $312 million. GSU deferred approximately $400.4 million of similar costs pursuant to a 1986 LPSC accounting order, of which approximately $83 million were unamortized as of December 31, 1995, and are being amortized over a 10-year period ending in 1998.
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 $172 million through December 31, 1995. The remainder of $122 million will be recovered over approximately 2.2 years.
Grand Gulf 1 and Waterford 3 Deferrals - - - - -------------------------------------- (Entergy Corporation and AP&L)
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 1-related costs, recover a portion of such costs currently, and defer a portion of such costs for future recovery. In 1995 and subsequent years, AP&L retains 22% of its 36% interest in Grand Gulf 1 costs and recovers the remaining 78%. The deferrals ceased in l990, and AP&L is recovering a portion of the previously deferred costs each year through l998. As of December 31, l995, the balance of deferred costs was $360 million. AP&L is permitted to recover on a current basis the incremental costs of financing the unrecovered deferrals. 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 energy from its retained share.
(Entergy Corporation and LP&L)
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 1, 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 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, 1995, LP&L's unrecovered deferral balance was $26 million.
With respect to Grand Gulf 1, in November 1988, LP&L agreed to retain and not recover from retail ratepayers, 18% of its 14% share (approximately 2.52%) of the costs of Grand Gulf 1 capacity and energy. LP&L is allowed to recover through the fuel adjustment clause 4.6 cents per KWh for the energy related to its retained portion of these costs. Alternatively, LP&L may sell such energy to nonaffiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC's approval.
(Entergy Corporation and MP&L)
MP&L entered into a revised plan with the MPSC that 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 a final order by the MPSC. Additionally, the plan provides 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. As of December 31, 1995, the uncollected balance of MP&L's deferred costs was approximately $378 million. The plan also allows for the current recovery of carrying charges on all deferred amounts.
(Entergy Corporation and NOPSI)
Under NOPSI's various Rate Settlements with the Council in 1986, 1988, and 1991, NOPSI agreed to absorb and not recover from ratepayers a total of $96.2 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, 1995, the uncollected balance of NOPSI's deferred costs was $171 million.
February 1994 Ice Storm/Rate Rider (Entergy Corporation and MP&L) - - - - ---------------------------------- 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.
Subsequent to a request by MP&L for rate recovery, the MPSC approved a stipulation in September 1994, with respect to the recovery of ice storm costs recorded through April 30, 1994. Under the stipulation, MP&L implemented an ice storm rate rider, which increased rates approximately $8 million for a period of five years beginning on September 29, 1994. This stipulation also stated that 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.
In September 1995, the MPSC approved a second stipulation which allows for a $2.5 million rate increase for a period of four years beginning September 28, 1995, to recover costs related to the ice storm that were recorded after April 30, 1994. The stipulation also allows for undepreciated ice storm capital costs recorded after April 30, 1994, to be treated as described above.
1994 NOPSI Settlement (Entergy Corporation and NOPSI) - - - - --------------------- 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 match more accurately 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, which was 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 Grand Gulf 1 phase-in rate increase in the amount of $4.4 million on October 31, 1995, was not affected by the 1994 NOPSI Settlement.
The 1994 NOPSI Settlement also required 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.
Pursuant to the 1994 NOPSI Settlement, NOPSI is required to make earnings filings with the Council for the 1995 and 1996 rate years. A review of NOPSI's earnings for the test year ending September 30, 1995, will require NOPSI to credit customers $6.2 million over a 12-month period beginning March 11, 1996. Hearings with the Council as to the reasonableness and prudence of NOPSI's deferred Least Cost Intergrated Resource Planning expenses for cost recovery purposes are scheduled for April 1996.
Proposed Rate Increase - - - - ---------------------- (System Energy)
System Energy filed an application with FERC on May 12, 1995, for a $65.5 million rate increase. The request seeks changes to System Energy's rate schedule, including increases in the revenue requirement associated with decommissioning costs, the depreciation rate, and the rate of return on common equity. On December 12, 1995, System Energy implemented a $65.5 million rate increase, subject to refund. Hearings on System Energy's request began in January 1996 and were completed in February 1996. The ALJ's initial decision is expected in 1996.
(MP&L)
MP&L's allocation of the proposed System Energy wholesale rate increase is $21.6 million. In July 1995, MP&L filed a schedule with the MPSC that will defer the ultimate amount of the System Energy rate increase. The deferral plan, which was approved by the MPSC, began in December 1995, the effective date of the System Energy rate increase, and will end after the issuance of a final order by FERC. The deferred rate increase is to be amortized over 48 months beginning October 1998.
(NOPSI)
NOPSI's allocation of the proposed System Energy wholesale rate increase is $11.1 million. In February 1996, NOPSI filed a plan with the City to defer 50% of the amount of the System Energy rate increase. The deferral began with the February 1996 bill to NOPSI from System Energy and will end after the issuance of a final order by FERC.
FERC Settlement (Entergy Corporation and System Energy)
In November 1994, FERC approved an agreement settling a long- standing dispute involving income tax allocation procedures of System Energy. In accordance with the agreement, System Energy refunded approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI, each of which in turn has made refunds or credits to its 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 such costs are excluded from rate base, System Energy is recovering them 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.
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. 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%.
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. 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. The Unit Power Sales Agreement formula rate, including the 11.0% ROE component, currently remains in effect. However, in December 1995, System Energy implemented a rate increase subject to refund, which included an increased return on common equity. Refer to above for a discussion of the proposed System Energy rate increase.
NOTE 3. INCOME TAXES
Entergy Corporation - - - - ------------------- Entergy Corporation's income tax expense consists of the following:
Entergy Corporation's 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 are:
Significant components of Entergy Corporation's net deferred tax liabilities as of December 31, 1995 and 1994, are as follows:
Arkansas Power & Light Company - - - - ------------------------------
AP&L's income tax expense consists of the following:
AP&L's 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 are:
Significant components of AP&L's net deferred tax liabilities as of December 31, 1995 and 1994,are as follows:
Gulf States Utilities Company - - - - -----------------------------
GSU's income tax expense consists of the following:
GSU's 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 are:
Significant components of GSU's net deferred tax liabilities as of December 31, 1995 and 1994, are as follows:
Louisiana Power & Light Company - - - - -------------------------------
LP&L's income tax expense consists of the following:
LP&L's 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 are:
Significant components of LP&L's net deferred tax liabilities as of December 31, 1995 and 1994, are as follows:
Mississippi Power & Light Company - - - - ---------------------------------
MP&L's income tax expense consists of the following:
MP&L's 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 are:
Significant components of MP&L's net deferred tax liabilities as of December 31, 1995 and 1994, are as follows:
New Orleans Public Service Inc. - - - - -------------------------------
NOPSI's income tax expense consists of the following:
NOPSI's 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 are:
Significant components of NOPSI's net deferred tax liabilities as of December 31, 1995 and 1994, are as follows:
System Energy Resources, Inc. - - - - -----------------------------
System Energy's income tax expense consists of the following:
System Energy's 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 are:
Significant components of System Energy's net deferred tax liabilities as of December 31, 1995 and 1994, are as follows:
As of December 31, 1995, Entergy had investment tax credit (ITC) carryforwards of $167.7 million, federal net operating loss (NOL) carryforwards of $384.6 million and state NOL carryforwards of $355.0 million, all related to GSU operations. The ITC carryforwards include the 35% reduction required by the Tax Reform Act of 1986 and may be applied against federal income tax liability of only GSU and, if not utilized, will expire between 1996 and 2002. It is currently anticipated that approximately $44.6 million of ITC carryforward 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, 1995, were $130.7 million, including $39.7 million at GSU, $27.4 million at LP&L, and $63.6 million at SERI. 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, including $27.3 million at AP&L, $31.5 million at LP&L, $6.0 million at MP&L, and $1.7 million at NOPSI.
In 1993, the System adopted SFAS 109. SFAS 109 required that deferred income taxes be recorded for all carryforwards and temporary differences between the book and tax basis of assets and liabilities, 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, Entergy's 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. The following table shows the effect of the adoption of SFAS 109 on 1993 net income, assets and liabilities for AP&L, LP&L, MP&L, NOPSI, and SERI.
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.
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 (Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy)
The SEC has authorized AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy to effect short-term borrowings up to $125 million, $125 million, $150 million, $100 million, $39 million, and $125 million, respectively (for a total of $664 million). These limits may be increased to as much as $1.216 billion in total (subject to individual authorizations for each company) after further SEC approval. These authorizations are effective through November 30, 1996. Of these companies, only LP&L and System Energy had borrowings outstanding as of December 31, 1995. LP&L had $76.5 million of borrowings outstanding, including $61.5 million under the money pool, an intra-System borrowing arrangement designed to reduce the System's dependence on external short-term borrowings. LP&L had unused bank lines of credit in the amount of $2.7 million. System Energy had money pool borrowings outstanding of approximately $3 million at December 31, 1995. AP&L and MP&L had undrawn lines of credit as of December 31, 1995, of $34 million and $30 million, respectively.
On July 27, 1995, Entergy Corporation received SEC authorization for a $300 million bank credit facility. Thereafter, a three-year credit agreement was signed with a group of banks on October 10, 1995, to provide up to $300 million of loans to Entergy Corporation. As of December 31, 1995, no amounts were outstanding against this credit facility. However, on January 4, 1996, $230 million was borrowed against the facility for use in the acquisition of CitiPower. See Note 15 for a discussion of the acquisition.
Other Entergy companies have financing agreements and facilities permitting them to borrow up to $135 million, of which $30 million was outstanding as of December 31, 1995. Some of these borrowings are restricted as to use, and are secured by certain assets.
In total, the System had commitments in the amount of $516.7 million at December 31, 1995, of which $471.7 million was unused. The weighted average interest rate on the outstanding borrowings at December 31, 1995, and December 31, 1994, was 6.35% and 7.18%, respectively. Commitment fees on the lines of credit for AP&L, LP&L, and MP&L are 0.125% of the undrawn amounts. The commitment fee for Entergy Corporation's $300 million credit facility is currently 0.17%, but can fluctuate depending on the senior debt ratings of the Operating Companies.
NOTE 5. PREFERRED, PREFERENCE, AND COMMON STOCK (Entergy Corporation, AP&L, GSU, LP&L, MP&L, and NOPSI)
The number of shares, authorized and outstanding, and dollar value of preferred and preference stock for Entergy, AP&L, GSU, LP&L, MP&L, and NOPSI as of December 31, 1995, and 1994 were:
(a) The total dollar value represents the involuntary liquidation value of $25 per share. (b) These series are not redeemable as of December 31, 1995. (c) Rates are as of December 31, 1995. (d) Fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. See Note 1 for additional disclosure of fair value of financial instruments.
Changes in the preferred stock, with and without sinking fund, preference stock, and common stock of AP&L, GSU, LP&L, MP&L, and NOPSI during the last three years were:
Cash sinking fund requirements for the next five years for preferred stock, outstanding as of December 31, 1995 are:
(a) AP&L, GSU, LP&L, and MP&L have the annual noncumulative option to redeem, at par, additional amounts of certain series of their outstanding preferred stock.
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 had a program in which it repurchased and retired (returned to authorized but unissued status) 1,230,000 shares of common stock at a cost of $30.7 million in 1994. In addition, 627,000 shares of treasury stock were purchased for cash during 1993 at a cost of $20.6 million. A portion of the treasury shares purchased in 1993 was subsequently reissued, and in connection with the Merger on December 31, 1993, the remaining balance of 579,274 shares of treasury stock was canceled.
Entergy Corporation from time to time acquires 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. Under this program, 2,805,000 of treasury shares were purchased in 1994 at a cost of $88.8 million. 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 9,251, 18,757, and 12,550 during 1995, 1994, and 1993, 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 1995 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 option transactions are summarized as follows:
(a) Options were not exercisable as of December 31, 1995.
The Employee Stock Investment Plan (ESIP) is authorized to issue or 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. Through this program, employees purchased 329,863 shares for the 1994 plan year. The 1995 plan year runs from April 1, 1995, to March 31, 1996.
NOTE 6. LONG - TERM DEBT (Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy)
The long-term debt of Entergy Corporation's subsidiaries, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy, as of December 31, 1995, was:
The long-term debt of Entergy Corporation's subsidiaries, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy, as of December 31, 1994, was:
(a) $20 million of MP&L's 14.95% Series G&R Bonds and $9.2 million of NOPSI's 13.9% Series G&R Bonds were due 2/1/95. All other series are at interest rates within the range of 6.95% - 11.2%.
(b) Consists of pollution control bonds, certain series of which are secured by non-interest bearing first mortgage bonds.
(c) The fair value excludes lease obligations, long-term DOE obligations, and other long-term debt and was 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.
The annual long-term debt maturities (excluding lease obligations) and annual cash sinking fund requirements for the next five years follow:
System Entergy (a) AP&L (b) GSU (c) LP&L (d) MP&L (e) NOPSI Energy (Dollars In Thousands)
1996 558,650 28,700 145,425 35,260 61,015 38,250 250,000 1997 361,270 33,065 160,865 34,325 96,015 27,000 10,000 1998 314,920 18,710 190,890 35,300 20 - 70,000 1999 172,391 1,225 100,915 231 20 - 70,000 2000 143,015 1,825 945 100,225 20 - 40,000
(a) Not included are other sinking fund requirements of approximately $20.4 million annually which may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements.
(b) Not included are other sinking fund requirements of approximately $1.1 million annually which may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements.
(c) Not included are other sinking fund requirements of approximately $13.8 million annually which may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements.
(d) Not included are other sinking fund requirements of approximately $5.5 million annually which may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements.
(e) Not included are other sinking fund requirements of approximately $0.1 million for 1996 which may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements.
GSU has two outstanding series of pollution control bonds 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.
Under MP&L's G&R Mortgage, G&R Bonds are issuable based upon 70% of bondable property additions, based upon 50% of accumulated deferred Grand Gulf 1 related costs, based upon the retirement of certain bonds previously outstanding, or based upon the deposit of cash with the trustee. MP&L's 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 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, 1995, the total amount of Rate Recovery Mortgage Bonds outstanding aggregated $30.0 million, or 17.3% of NOPSI's accumulated deferred Grand Gulf 1-related costs.
NOTE 7. DIVIDEND RESTRICTIONS - (Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy)
Provisions within the Articles of Incorporation or pertinent Indentures and various other agreements related 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 and preferred stock. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. Detailed below are the restricted common equity and restricted retained earnings unavailable for distribution to Entergy Corporation by subsidiary.
Restricted Restricted Company Equity Earnings (In Millions)
AP&L $ 882.6 $ 291.3 GSU 1,266.5 - LP&L 1,084.1 - MP&L 334.8 135.7 NOPSI 85.2 15.2 System Energy 808.1 18.7 ----------- ---------- Entergy $ 4,461.3 $ 460.9 =========== ==========
NOTE 8. COMMITMENTS AND CONTINGENCIES
Cajun - River Bend Litigation (Entergy Corporation and GSU)
GSU has significant business relationships with Cajun, including co-ownership of River Bend (operated by GSU) and Big Cajun 2, Unit 3 (operated by Cajun). GSU and Cajun, respectively, own 70% and 30% undivided interests in River Bend and 42% and 58% undivided interests in Big Cajun 2, Unit 3.
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 (Operating Agreement) entered into on August 28, 1979, 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 on the portion of the suit by Cajun to rescind the Operating Agreement began in April 1994 and was completed in March 1995. On October 24, 1995, the District Court issued a memorandum opinion ruling in favor of GSU. The District Court found that Cajun did not prove that GSU fraudulently induced it to execute the Operating Agreement and that Cajun failed to timely assert its claim. A final judgment on this portion of the suit will not be entered until all claims asserted by Cajun have been heard. The second portion of the suit is scheduled to begin on July 2, 1996. If GSU is ultimately unsuccessful in this litigation and is required to pay substantial damages, GSU would probably be unable to make such payments and could be forced 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.
Cajun has not paid its full share of capital costs, operating and maintenance expenses, or other costs for repairs and improvements to River Bend since 1992. In addition, certain costs and expenses paid by Cajun were paid under protest. These actions were taken by Cajun based on its contention, with which GSU disagrees, that River Bend's operating and maintenance expenses were excessive. Cajun's unpaid portion of River Bend operating and maintenance expenses (including nuclear fuel) and capital costs for 1995 was approximately $58.7 million. Cajun continues to pay its share of decommissioning costs for River Bend.
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.
In view of Cajun's failure to fund its share of River Bend-related operating, maintenance, and capital costs, GSU has (i) credited GSU's share of expenses for Big Cajun 2, Unit 3 against amounts due from Cajun to GSU, and (ii) sought to market Cajun's share of the power from River Bend and apply the proceeds to the amounts due from Cajun to GSU. As a result, on November 2, 1994, Cajun discontinued supplying GSU with its share of power from Big Cajun 2, Unit 3. GSU requested an order from the District Court requiring Cajun to supply GSU with this energy and allowing GSU to credit amounts due to Cajun for Big Cajun 2, Unit 3 energy against amounts Cajun owed to GSU for River Bend. In December 1994, by means of a preliminary injunction, the District Court ordered Cajun to supply GSU with its share of energy from Big Cajun 2, Unit 3 and ordered GSU to make payments for its share of Big Cajun 2, Unit 3 expenses to the registry of the District Court. In October 1995, the Fifth Circuit affirmed the District Court's preliminary injunction. As of December 31, 1995, $38 million had been paid by GSU into the registry of the District Court.
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 Bankruptcy Code. Cajun's bankruptcy could have a material adverse effect on GSU. 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 in December 1994 remains in effect. Cajun filed a Notice of Appeal on January 18, 1995, to 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. Should the court 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 without merit, it is not possible to predict the outcome or ultimate impact of these proceedings.
The cumulative cost (excluding nuclear fuel) to GSU resulting from Cajun's failure to pay its full share of River Bend-related costs, reduced by the proceeds from the sale by GSU of Cajun's share of River Bend power and payments for GSU's portion of expenses for Big Cajun 2, Unit 3 into the registry of the District Court, was $31.1 million as of December 31, 1995. 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.
Cajun - Transmission Service (Entergy Corporation and GSU)
GSU and Cajun are parties to FERC proceedings relating to transmission service charge disputes. In April 1992, FERC issued a final order in these disputes. In May 1992, GSU and Cajun filed motions for rehearings on certain portions of the order, which are still pending at FERC. In June 1992, GSU filed a petition for review in the United States Court of Appeals regarding certain of the other issues decided by FERC. In August 1993, the United States Court of Appeals rendered an opinion reversing FERC's 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 February 1995, FERC eliminated an issue from the remand that GSU believes the Court of Appeals directed FERC to reconsider. In orders issued on August 3, 1995, and October 2, 1995, FERC affirmed an April 1995 ruling by an ALJ in the remanded portion of GSU's and Cajun's ongoing transmission service charge disputes before FERC. Both GSU and Cajun have petitioned for appeal. No hearing dates have been set in the appeals.
Under GSU's interpretation of the 1992 FERC order, as modified by its August 3, 1995, and October 2, 1995, orders, Cajun would owe GSU approximately $64.9 million as of December 31, 1995. GSU further estimates that if it were to prevail in its May 1992 motion for rehearing and on certain other issues decided adversely to GSU in the February 1995, August 1995, and October 1995 FERC orders, which GSU has appealed, Cajun would owe GSU approximately $143.5 million, as of December 31, 1995. 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 Cajun were to prevail in appealing FERC's August and October 1995 orders, GSU estimates it would owe Cajun approximately $96.4 million as of December 31, 1995. 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. Pending FERC's ruling on the May 1992 motions for rehearing, GSU has continued to bill Cajun, utilizing the historical billing methodology, and has recorded underpaid transmission charges, including interest, in the amount of $137.2 million as of December 31, 1995. This amount is reflected in long-term receivables, with an offsetting reserve in other deferred credits. Cajun's bankruptcy may affect GSU's collection of the above amounts. FERC has determined that the collection of the pre-petition debt of Cajun is an issue properly decided in the bankruptcy proceeding.
Capital Requirements and Financing (Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy)
Construction expenditures (excluding nuclear fuel) for the years 1996, 1997, and 1998 are estimated to total $571 million, $510 million, and $507 million, respectively. The System will also require $1.3 billion during the period 1996-1998 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 and the use of its outstanding credit facility. Certain System companies may also continue with the acquisition or refinancing of all or a portion of certain outstanding series of preferred stock and long-term debt. See Notes 5 and 6 for further information.
Grand Gulf 1-Related Agreements
Capital Funds Agreement (Entergy Corporation and System Energy)
Entergy Corporation has agreed to supply System Energy with 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 continued commercial operation of Grand Gulf 1 and 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 they 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.
Unit Power Sales Agreement (AP&L, LP&L, MP&L, NOPSI, and System Energy)
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 purchasing companies' respective entitlement to receive capacity and energy and are payable irrespective of the quantity of energy delivered so long as the unit remains in commercial operation. The agreement will remain in effect until terminated by the parties and approved by FERC, most likely upon Grand Gulf 1's retirement from service. Monthly obligations for payments, including the rate increase which was placed into effect in December 1995, subject to refund, under the agreement are approximately $21 million, $8 million, $19 million, and $10 million for AP&L, LP&L, MP&L, and NOPSI, respectively.
Availability Agreement (AP&L, LP&L, MP&L, NOPSI, and System Energy)
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. (See Reallocation Agreement terms below.) System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Since commercial operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments have ever been required. If AP&L or MP&L fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, 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.
Reallocation Agreement (AP&L, LP&L, MP&L, NOPSI, and System Energy)
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 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 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 (System Energy)
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 9). 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 a bank letter of credit reimbursement agreement, 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 (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 times earnings. As of December 31, 1995, System Energy's equity approximated 34.8% of its adjusted capitalization, and its fixed charge coverage ratio was 2.11.
Fuel Purchase Agreements
(AP&L and MP&L)
AP&L has long-term contracts with mines in the State of Wyoming for the supply of low-sulfur coal for the White Bluff Steam Electric Generating Station and Independence (which is 25% owned by MP&L). These contracts, which expire in 2002 and 2011, provide for approximately 85% of AP&L's expected annual coal requirements. Additional requirements are satisfied by annual spot market purchases.
(GSU)
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 1999 for the operation of Big Cajun 2, Unit 3.
GSU has long-term gas contracts, which will satisfy approximately 75% of its annual requirements. Such contracts generally 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 has a transportation service agreement with a gas supplier that provides flexible natural gas 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.
(LP&L)
In June 1992, LP&L agreed to a renegotiated 20-year natural gas supply contract. LP&L 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 $8.6 million through 1997, and a total of $116.6 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.
Power Purchases/Sales Agreements
(GSU)
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 supply 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, 1995, 1994, and 1993, the purchases by GSU of electricity from the joint venture totaled $59.7 million, $58.3 million, and $62.6 million, respectively.
(LP&L)
LP&L has a long-term agreement through the year 2031 to purchase energy generated by a hydroelectric facility. During 1995, 1994, and 1993, LP&L made payments under the contract of approximately $55.7 million, $56.3 million, and $66.9 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 in 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.
System Fuels (AP&L, LP&L, MP&L, NOPSI, and System Energy)
AP&L, LP&L, MP&L, and NOPSI have interests in System Fuels of 35%, 33%, 19%, and 13%, respectively. The parent companies of System Fuels agreed to make loans to System Fuels to finance its fuel procurement, delivery, and storage activities. As of December 31, 1995, AP&L, LP&L, MP&L, and NOPSI had, respectively, approximately $11 million, $14.2 million, $5.5 million, and $3.3 million in 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.
Nuclear Insurance (Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy)
The Price-Anderson Act limits public liability for a single nuclear incident to approximately $8.92 billion. The System has protection for this liability through a combination of private insurance (currently $200 million each for AP&L, GSU, LP&L, and System Energy) and an industry assessment program. Under the assessment program, the maximum payment requirement 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. The System has five licensed reactors. As a co-licensee of Grand Gulf 1 with System Energy, 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. 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, 1995, AP&L, GSU, LP&L, and System Energy each was insured against such losses up to $2.75 billion. 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, 1995, the maximum amounts of such possible assessments were: AP&L - $36.3 million; GSU - $22.0 million; LP&L - $33.2 million; MP&L - $0.8 million; NOPSI - $0.5 million; and System Energy - $29.0 million. Under its agreement with System Energy, SMEPA would share in System Energy's obligation. Cajun shares approximately $4.6 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 (Entergy Corporation, AP&L, GSU, LP&L, and System Energy)
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 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 onetime 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 onetime fee plus accrued interest, no earlier than 1998, and has recorded a liability as of December 31, 1995, of approximately $111 million for generation subsequent to 1983. 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 2015. 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-1998, 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, about $3 million to $5 million per unit will be required every two to three years subsequent to 2000 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.
Total decommissioning costs at December 31, 1995, for the System nuclear power plants, excluding co-owner shares, have been estimated as follows:
AP&L and LP&L are authorized to recover in rates amounts that, when added to estimated investment income, should be sufficient to meet the above estimated decommissioning costs for ANO and Waterford 3, respectively. In the Texas retail jurisdiction, GSU is recovering in rates decommissioning costs (based on the 1991 cost study) that, with adjustments, total $204.9 million. In the Louisiana retail jurisdiction, GSU is currently recovering in rates decommissioning costs (based on a 1985 cost study) which total $141 million. GSU included decommissioning costs (based on the 1991 study) in the LPSC rate review filed in May 1995 which has not yet been concluded. System Energy was previously recovering in rates amounts sufficient to fund $198 million (in 1989 dollars) of its decommissioning costs. System Energy included decommissioning costs (based on the 1994 study) in its rate increase filing with FERC. Rates in this proceeding were placed into effect in December 1995, subject to refund. AP&L, GSU, LP&L, and System Energy periodically review and update estimated decommissioning costs. Although the System is presently underrecovering based on the above estimates, applications are periodically 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 trust funds and reported at market value as quoted on nationally traded markets. These trust fund assets largely offset the accumulated decommissioning liability that is recorded as accumulated depreciation for AP&L, GSU, and LP&L, and as other deferred credits for System Energy.
The cumulative liabilities and actual decommissioning expenses recorded in 1995 by the System companies were as follows:
Cumulative 1995 1995 Cumulative Liabilities as of Trust Decommissioning Liabilities as of December 31, 1994 Earnings Expenses December 31, 1995 (In Millions)
ANO 1 and ANO 2 $137.4 $13.9 $17.7 $169.0 River Bend 22.2 1.4 8.1 31.7 Waterford 3 28.2 1.7 7.5 37.4 Grand Gulf 1 31.9 2.1 5.4 39.4 ------ ----- ----- ------ $219.7 $19.1 $38.7 $277.5 ====== ===== ===== ======
In 1994 and 1993, ANO's decommissioning expense was $12.2 million and $11.0 million, respectively; River Bend's decommissioning expense was $3.0 million, respectively; Waterford 3's decommissioning expense was $4.8 million and $4.0 million, respectively; and Grand Gulf 1's decommissioning expense was $5.2 million and $4.9 million, respectively. 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 estimated amounts presented above.
The staff of the SEC has questioned certain of the financial 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 has been reviewing the accounting for decommissioning and has expanded the scope of its review to include liabilities related to the closure and removal of all long-lived assets. An exposure draft of the proposed SFAS was issued in February 1996 would be effective in 1997. The proposed SFAS would require measurement of the liability for closure and removal of long- lived assets (including decommissioning) based on discounted future cash flows. Those future cash flows should be determined by estimating current costs and adjusting for inflation, efficiencies that may be gained from experience with similar activities, and consideration of reasonable future advances in technology. It also would require that changes in the decommissioning/closure cost liability resulting from changes in assumptions should be recognized with a corresponding adjustment to the plant asset, and depreciation should be revised prospectively. The proposed SFAS stated that the initial recognition of the decommissioning/closure cost liability would result in an asset that should be presented with other plant costs on the financial statements because the cost of decommissioning/closing the plant is recognized as part of the total cost of the plant asset. In addition there would be a regulatory asset recognized on the financial statements to the extent the initial decommissioning/closure liability has increased due to the passage of time, and such costs are probable of future recovery.
If current electric utility industry accounting practices with respect to nuclear decommissioning and other closure costs are changed, annual provisions for such costs could increase, the estimated cost for decommissioning/closure could be recorded as a liability rather than as accumulated depreciation, and trust fund income from 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, GSU, LP&L, 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. At December 31, 1995, AP&L, GSU, LP&L, and System Energy had recorded liabilities of $35.3 million, $6.0 million, $13.2 million, and $12.8 million, respectively, for decontamination and decommissioning fees in other current liabilities and other noncurrent liabilities, and these liabilities were offset in the consolidated financial statements by regulatory assets. FERC requires that utilities treat these assessments as costs of fuel as they are amortized and are recovered through rates in the same manner as other fuel costs.
ANO Matters (Entergy Corporation and AP&L)
Cracks in steam generator tubes at ANO 2 were discovered and repaired during an outage in March 1992. Further inspections and repairs were conducted at subsequent refueling and mid-cycle outages, including the most recent refueling outage in October 1995. Beginning in January 1995, ANO 2's output was reduced 15 megawatts or 1.6% due to secondary side fouling, tube plugging, and reduction of primary temperature. During the October 1995 inspection, additional cracks in the tubes were discovered. The unit may be approaching the limit for the number of steam generator tubes that can be plugged with the unit in operation. If the currently established limit is reached, Entergy Operations could be required during future outages to insert sleeves in some of the steam generator tubes that were previously plugged. Entergy Operations is monitoring the development of the cracks and assessing various options for the repair or the replacement of ANO 2's steam generators. Certain of these options could, in the future, require significant capital expenditures and result in additional outages. However, a decision as to the repair or replacement of ANO 2's steam generators is not expected prior to 1997. Entergy Operations periodically meets with the NRC to discuss the results of inspections of the generator tubes, as well as the timing of future inspections.
Environmental Issues
(AP&L)
In May 1995, AP&L was named as a defendant in a suit by Reynolds Metals Company (Reynolds), seeking to recover a share of the costs associated with the clean-up of hazardous substances at a site south of Arkadelphia, Arkansas. Reynolds alleges that it has spent $11.2 million to clean-up the site, and that the site was contaminated in part with PCBs for which AP&L bears some responsibility. AP&L, voluntarily, at its expense, has already completed remediation at a nearby substation site and believes that it has no liability for contamination at the site that is subject to the Reynolds suit and is contesting the lawsuit. Regardless of the outcome, AP&L does not believe this matter would have a materially adverse effect on its financial condition or results of operations.
(GSU)
GSU has been designated as a PRP for the clean-up of certain hazardous waste disposal sites. GSU is currently negotiating with the EPA and state authorities regarding the clean-up 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 clean-up efforts and suits may be substantial, GSU believes that its results of operations and financial condition will not be materially adversely affected by the outcome of the suits. Through December 31, 1995, $7.9 million has been expended on the clean-up. As of December 31, 1995, a remaining recorded liability of $21.7 million existed relating to the clean-up of five sites at which GSU has been designated a PRP.
(LP&L)
During 1993, the LDEQ issued new rules for solid waste regulation, including regulation of wastewater impoundments. LP&L has determined that certain of its power plant wastewater impoundments were affected by these regulations and has chosen to upgrade or close them. As a result, a remaining recorded liability in the amount of $10.6 million existed at December 31, 1995, for wastewater upgrades and closures to be completed in 1996. Cumulative expenditures relating to the upgrades and closures of wastewater impoundments were $5.6 million as of December 31, 1995.
City Franchise Ordinances (NOPSI)
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.
NOTE 9. LEASES
General
As of December 31, 1995, the System had capital leases and noncancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities (excluding nuclear fuel leases and the sale and leaseback transactions) with minimum lease payments as follows:
Capital Leases
Year Entergy AP&L GSU (In Thousands)
1996 $ 29,054 $ 11,126 $ 12,475 1997 24,653 8,293 12,475 1998 24,634 8,293 12,475 1999 24,610 8,294 12,475 2000 22,872 6,987 12,049 Years thereafter 113,421 41,708 69,331 Minimum lease payments 239,244 84,701 131,280 Less: Amount representing interest 87,284 34,360 47,921 --------- ---------- ---------- Present value of net minimum lease payments $ 151,960 $ 50,341 $ 83,359 ========= ========== ==========
Operating Leases
Year Entergy AP&L GSU LP&L (In Thousands)
1996 $ 76,866 $ 36,498 $ 12,871 $ 4,820 1997 66,009 29,460 12,566 4,369 1998 65,914 29,047 16,499 4,256 1999 63,198 27,304 16,499 3,990 2000 59,760 25,722 16,326 3,846 Years thereafter 214,577 71,272 60,518 1,905 --------- --------- --------- ---------- Minimum lease payments $ 546,324 $ 219,303 $ 135,279 $ 23,186 ========= ========= ========= ==========
Rental expense for the System leases (excluding nuclear fuel leases and the sale and leaseback transactions) amounted to approximately $67.8 million, $64.8 million, and $62.7 million in 1995, 1994, and 1993, respectively. These amounts include $27.7 million, $26.4 million, and $23.2 million, respectively, for AP&L, $15.1 million, $15.3 million, and $31.9 million, respectively for GSU, and $14.8 million, $12.1 million, and $6.6 million, respectively, for LP&L.
Nuclear Fuel Leases
AP&L, GSU, LP&L, and System Energy each has arrangements to lease nuclear fuel in an aggregate amount up to $395 million as of December 31, 1995. The lessors finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. 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, GSU, LP&L, and System Energy have been extended and now have termination dates of December 1998, December 1998, January 1999, and February 1999, respectively. The debt securities 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 upon the maturity of the current arrangements. 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.
Lease payments are based on nuclear fuel use. Nuclear fuel lease expense charged to operations by the System in 1995, 1994, and 1993 was $153.5 million (including interest of $22.1 million), $163.4 million (including interest of $27.3 million), and $145.8 million (excluding GSU and including interest of $20.5 million), respectively. Specifically, in 1995, 1994, and 1993, AP&L's expense was $46.8 million, $56.2 million, and $69.7 million (including interest of $6.7 million, $7.5 million, and $10.6 million), respectively; GSU's expense was $41.4 million, $37.2 million, and $43.6 million (including interest of $6.0 million, $8.7 million, and $10.2 million), respectively; LP&L's expense was $30.8 million, $32.2 million, and $39.9 million (including interest of $3.7 million, $4.3 million, and $4.9 million), respectively; System Energy's expense was $34.5 million, $37.8 million, and $36.2 million (including interest of $5.7 million, $6.8 million, and $5.1 million), respectively.
Sale and Leaseback Transactions
Waterford 3 Lease Obligations (LP&L)
On September 28, 1989, LP&L entered into three 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 are equivalent on an aggregate cost basis to approximately a 9.3% undivided interest in Waterford 3. LP&L is leasing back the interests 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 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.
Interests were acquired from LP&L with funds obtained from the issuance and sale by the purchasers of intermediate-term and long-term secured lease obligation bonds. The lease payments to be made by LP&L will be sufficient to service such debt.
LP&L did not exercise its option to repurchase the undivided interests in Waterford 3 in September 1994. As a result, LP&L was required to provide collateral for the equity portion of certain amounts payable by LP&L under the leases. 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.
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 termination of the lease transactions and may be required to assume the outstanding indebtedness issued to finance the 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, 1995, LP&L's total equity capital (including preferred stock) was 48.7% of adjusted capitalization and its fixed charge coverage ratio was 3.29.
As of December 31, 1995, 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):
1996 $ 35,165 1997 39,805 1998 41,447 1999 50,530 2000 47,510 Years thereafter 628,704 ----------- Total 843,161 Less: Amount representing interest 489,561 ----------- Present value of net minimum lease payments $ 353,600 ===========
Grand Gulf 1 Lease Obligations (System Energy)
On December 28, 1988, System Energy entered into two arrangements for the sale and leaseback of an 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 8 with respect to certain other terms of 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 $85.8 million and $78.5 million as of December 31, 1995, and 1994, respectively.
As of December 31, 1995, System Energy had future minimum lease payments (reflecting an implicit rate of 7.02% after the above refinancing) as follows (in thousands):
1996 $ 42,753 1997 42,753 1998 42,753 1999 42,753 2000 42,753 Years thereafter 760,067 ----------- Total 973,832 Less: Amount representing interest 473,832 ----------- Present value of net minimum lease payments $ 500,000 ===========
NOTE 10. POSTRETIREMENT BENEFITS (Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy)
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. Prior to January 1, 1995, all System Companies' non-bargaining employees were generally included in a plan sponsored by the System company where they were employed. However, NOPSI was a participating employer in a plan sponsored by LP&L. Effective January 1, 1995, these employees became participants in a new plan with provisions substantially identical to their previous plan.
Total 1995, 1994, and 1993 pension cost of Entergy Corporation and its subsidiaries (excluding GSU for 1993 for the Entergy Corporation total), including amounts capitalized, included the following components (in thousands):
The funded status of Entergy's various pension plans as of December 31, 1995 and 1994 was (in thousands):
The significant actuarial assumptions used in computing the information above for 1995, 1994, and 1993 (only 1995 and 1994 with respect to GSU being included in the Entergy Corporation total), were as follows: weighted average discount rate, 7.5% for 1995, 8.5% for 1994, and 7.5% for 1993, weighted average rate of increase in future compensation levels, 4.6% for 1995, 5.1% for 1994 and 5.6% (5% for GSU) for 1993; 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.
In 1994, GSU recorded an $18.0 million charge related to early retirement programs in connection with the Merger, of which $15.2 million was expensed.
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.
Effective January 1, 1993, Entergy adopted SFAS 106. The new standard required a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. The 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 NOPSI began to fund their postretirement benefit obligation. These assets are invested in a money market fund. 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 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 the difference between its annual cash expenditures for postretirement benefits other than pensions and the SFAS 106 accrual, for up to a five- year period commencing January 1, 1993. 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 continue the use of 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 the PUCT's May 26, 1995, amended order, GSU is currently collecting its SFAS 106 costs in rates.
Total 1995, 1994 and 1993 postretirement benefit cost of Entergy Corporation and its subsidiaries (excluding GSU for the Entergy Corporation total for 1993), including amounts capitalized and deferred, included the following components (in thousands):
The funded status of Entergy's postretirement plans as of December 31, 1995 and 1994, was (in thousands):
The assumed health care cost trend rate used in measuring the APBO of the System companies was 8.4% for 1996, gradually decreasing each successive year until it reaches 5.0% in 2005. 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, 1995, by 11.3% (AP&L-11.8%, GSU-10.4%, LP&L-11.8%, MP&L-12.2% and NOPSI- 10.0%), and the sum of the service cost and interest cost by approximately 14.1% (AP&L-15.0%, GSU-12.8%, LP&L-14.4%, MP&L-14.4% and NOPSI-12.8%). The assumed discount rate and rate of increase in future compensation used in determining the APBO were 7.5% for 1995, 8.5% for 1994 and 7.5% for 1993, and 4.6% for 1995, 5.1% for 1994 and 5.5% (5% for GSU) for 1993, respectively. The expected long-term rate of return on plan assets was 8.5% for 1995.
NOTE 11. RESTRUCTURING COSTS (Entergy Corporation, AP&L, GSU, LP&L, MP&L, and NOPSI)
The restructuring programs announced by Entergy in 1994 and 1995 included anticipated reductions in the number of employees and the consolidation of offices and facilities. The programs are designed to reduce costs, improve operating efficiencies, and increase shareholder value in order to enable Entergy to become a low-cost producer. The balances as of December 31, 1994, and 1995, for restructuring liabilities associated with these programs are shown below by company along with the actual termination benefits paid under the programs.
Restructuring Restructuring Liability as of Additional Payments Liability as of December 31, 1995 Made in December 31, Company 1994 Charges 1995 1995 (In Millions)
AP&L $12.2 $16.2 ($20.1) $8.3 GSU 6.5 13.1 (14.2) $5.4 LP&L 6.8 6.4 (11.0) $2.2 MP&L 6.2 2.9 (6.6) $2.5 NOPSI 3.4 0.2 (3.0) $0.6 Other - 9.6 (4.4) $5.2 ----- ----- ------ ----- Total $35.1 $48.4 ($59.3) $24.2 ===== ===== ====== =====
The restructuring charges shown above primarily included employee severance costs related to the expected termination of approximately 2,750 employees in various groups. As of December 31, 1995, 2,100 employees had either been terminated or accepted voluntary separation packages under the restructuring plan.
Additionally, the System recorded $24.3 million in 1994 (of which $23.8 million was recorded by GSU) for remaining severance and augmented retirement benefits related to the Merger. Actual termination benefits paid under the program during 1995 amounted to $21.6 million. During that same period, adjustments to the allocation of the total liability were made among the System companies. At December 31, 1995, the total remaining System liability for expected future Merger-related outlays was $2.8 million, comprised principally of GSU's liability of $2.3 million.
NOTE 12. TRANSACTIONS WITH AFFILIATES (AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy)
The various Operating Companies purchase electricity from and/or sell electricity to other Operating Companies, System Energy, and Entergy Power (in the case of AP&L) under rate schedules filed with FERC. In addition, the Operating Companies and System Energy purchase fuel from System Fuels, receive technical, advisory, and administrative services from Entergy Services, and receive management and operating services from Entergy Operations.
As described in Note 1, all of System Energy's operating revenues consist of billings to AP&L, LP&L, MP&L, and NOPSI.
The tables below contain the various affiliate transactions among the Operating Companies and System Entergy (in millions).
Intercompany Revenues
System AP&L GSU LP&L MP&L NOPSI Energy
1995 $ 195.5 $62.7 $ 1.6 $ 43.3 $ 3.2 $ 605.6 1994 $ 232.6 $44.4 $ 1.0 $ 45.8 $ 2.1 $ 475.0 1993 $ 175.8 $ - $ 4.8 $ 40.7 $ 2.5 $ 650.8
Intercompany Operating Expenses
System AP&L(1) GSU LP&L MP&L NOPSI Energy
1995 $ 316.0 $ 266.5 $ 335.5 $ 262.6 $ 164.4 $ 6.5 1994 $ 310.7 $ 296.9 $ 365.8 $ 280.2 $ 170.1 $ 10.5 1993 $ 323.2 $ 25.5 $ 322.0 $ 360.5 $ 176.3 $ 12.3
(1) Includes $31.0 million in 1995, $25.7 million in 1994, and $16.8 million in 1993 for power purchased from Entergy Power.
Operating Expenses Paid or Reimbursed to Entergy Operations
System AP&L GSU LP&L Energy
1995 $ 189.8 $ 129.1 $ 122.6 $ 116.9 1994 $ 221.2 $ 210.2 $ 152.5 $ 179.6 1993 $ 226.3 $ - $ 118.9 $ 151.3
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 $51.5 million in 1995, $26.4 million in 1994, and $32.8 million in 1993.
NOTE 13. ENTERGY CORPORATION-GSU MERGER
On December 31, 1993, Entergy Corporation and GSU consummated the Merger. GSU became a wholly owned subsidiary of Entergy Corporation and continues to operate as an electric utility corporation under the regulation of FERC, the SEC, 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. Note 1 describes the accounting for the acquisition adjustment recorded in connection with 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.
Years 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 14. BUSINESS SEGMENT INFORMATION
NOPSI supplies electric and natural gas services in the City. NOPSI's segment information follows:
(1) NOPSI's intersegment transactions are not material (less than 1% of sales to unaffiliated customers).
NOTE 15. SUBSEQUENT EVENT (UNAUDITED)
Acquisition of CitiPower (Entergy Corporation)
On January 5, 1996, Entergy Corporation finalized its acquisition of CitiPower, an electric distribution utility serving Melbourne, Australia. Entergy Corporation made an equity investment of $294 million in CitiPower and the remainder of the total purchase price of approximately $1.2 billion was made up of new CitiPower debt. CitiPower has 234,500 customers, the majority of which are commercial customers.
NOTE 16. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy)
The business of the System is subject to seasonal fluctuations with the peak period occurring during the third quarter. Operating results for the four quarters of 1995 and 1994 were:
(a)See Note 2 for information regarding the recording of a reserve for rate refund in December 1994. (b)See Note 11 for information regarding the recording of certain restructuring costs in 1994 and 1995. (c)See Note 3 for information regarding the write-off of certain unamortized deferred investment tax credits in the fourth quarter of 1994. (d)See Note 2 for information regarding credits and refunds recorded in 1994 as a result of the 1994 NOPSI Settlement. (e)See Note 2 for information regarding the recording of refunds in connection with the FERC Settlement in November 1994. (f)The fourth quarter of 1995 reflects an increase in net income of $35.4 million (net of income taxes of $22.9 million) and an increase in earnings per share of $.15 due to the recording of the cumulative effect of the change in accounting method for incremental nuclear refueling outage maintenance costs. See Note 1 for a discussion of the change in accounting method.
Earnings (Loss) per Average Common Share (Entergy Corporation)
1995 1994
First Quarter $0.40 $ 0.31 Second Quarter $0.71 $ 0.63 Third Quarter $1.16 $ 0.63 Fourth Quarter (f) $0.02 $(0.07)
Item 9.

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.

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 17, 1996, and is incorporated herein by reference.
(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. 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 or until a successor is elected and qualified. Annual meetings are currently expected to be held as follows:
Entergy Corporation - May 17, 1996 AP&L - May 13, 1996 GSU - May 13, 1996 LP&L - May 13, 1996 MP&L - May 13, 1996 NOPSI - May 13, 1996 System Energy - May 13, 1996
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 Exchange Act and Section 17(a) of the Public Utility Holding Company Act of 1935, as amended, require the Corporation's officers, directors and persons who own more than 10% of a registered class of the Corporation's equity securities to file reports of ownership and changes in ownership concerning the securities of the Corporation and its subsidiaries with the SEC and to furnish the Corporation with copies of all Section 16(a) and 17(a) forms they file. Terry L. Ogletree, an officer of Entergy Enterprises, Inc., filed a Form 3 in March of 1995, which inadvertently failed to report ownership of 5,000 restricted shares of the Corporation's stock. This has now been correctly reported.
Item 11.

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 17, 1996, which information is incorporated herein by reference.
AP&L, GSU, LP&L, MP&L, NOPSI, AND SYSTEM ENERGY
Summary Compensation Table
The following table includes the Chief Executive Officers and the four other most highly compensated executive officers in office as of December 31, 1995 at AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy. This determination was based on total annual base salary and bonuses (including bonuses of an extraordinary and nonrecurring nature) from all System sources earned by each officer during the year 1995. 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 Energy
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.
* 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.
(b) Amounts include the value of restricted shares that vested in 1995, 1994, and 1993 (see note (d) below) under Entergy's Equity Ownership Plan.
(c) Includes the following:
(1) 1995 employer payments for Executive Medical Plan premiums as follows: Mr. Bemis $3,019; Mr. Blount $3,019; Mr. Hintz $3,019; Mr. Jackson $3,019; Mr. Lupberger $3,019; Mr. Maulden $3,019; Mr. McInvale $3,019; Mr. Regan $2,013.
(2) 1995 benefit accruals under the Defined Contribution Restoration Plan as follows: Mr. Bemis $4,200; Mr. Hintz $5,250; Mr. Jackson $5,250; Mr. Lupberger $16,500; Mr. Maulden $8,550; Mr. McInvale $3,164.
(3) 1995 employer contributions to the System Savings Plan as follows: Mr. Bemis $4,500; Mr. Blount $3,576; Mr. Hintz $4,500; Mr. Jackson $4,500; Mr. Lupberger $4,500; Mr. Maulden $4,500; Mr. McInvale $4,500; Mr. Regan $877.
(4) 1995 reimbursements under the Executive Financial Counseling Program as follows: Mr. Bemis $2,625; Mr. Jackson $1,225; Mr. Lupberger $3,100; Mr. Maulden $2,715; Mr. McInvale $680.
(5) 1995 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 $6,023; Mr. Maulden $9,720; Mr. McInvale $9,900; Mr. Regan $4,800.
(6) 1995 earnings under the Entergy Stock Investment Plan as follows: Mr. Bemis $3,363; Mr. Blount $1,910.
(7) 1995 reimbursements for moving expenses paid to Mr. Regan in the amount of $6,943.
(d) There were no restricted stock awards in 1995 under the Equity Ownership Plan. At December 31, 1995, the number and value of the aggregate restricted stock holdings were as follows: Mr. Bemis: 4,000 shares, $117,000; Mr. Hintz: 5,429 shares, $158,798; Mr. Jackson: 5,500 shares, $160,875; Mr. Lupberger: 10,900 shares, $318,825; Mr. Maulden: 5,500 shares, $160,875; and Mr. McInvale: 4,000 shares, $117,000. Accumulated dividends are paid on restricted stock when vested. The value of stock for which restrictions were lifted in 1995, 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, 1995 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 29, 1995 ($29.25 per share).
Option Grants in 1995
The following table summarizes option grants during 1995 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
(a) Options were granted on January 26, 1995, 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 26, 1995. These options became exercisable on July 26, 1995.
(b) Options were granted on March 31, 1995, 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 March 31, 1995. These options will become exercisable on March 31, 1998.
(c) Calculation based on the market price of the underlying securities over a ten-year period assuming annual compounding. The column presents 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.
Aggregated Option Exercises in 1995 and December 31, 1995 Option Values
The following table summarizes the number and value of options exercised during 1995, as well as the number and value of unexercised options, as of December 31, 1995, held by the executive officers named in the Summary Compensation Table above.
(a) Based on the difference between the closing price of the Corporation's Common Stock on the New York Stock Exchange Composite Transactions on the exercise date of November 17, 1995, and the option exercise price.
(b) Based on the difference between the closing price of the Corporation's Common Stock on the New York Stock Exchange Composite Transactions on December 29, 1995, and the option exercise price.
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
All of the named officers of AP&L, GSU, LP&L, MP&L, NOPSI and System Energy participate 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, multiplied by (2) 1.5%, multiplied by (3) the final average compensation. Final average compensation is based on the highest consecutive 60 months of covered compensation in the last 120 months of service. The normal form of benefit for a single employee is a lifetime annuity and for a married employee is a 50% joint and survivor annuity. Other actuarially equivalent options are available to each retiree. Retirement benefits are not subject to any deduction for Social Security or other offset amounts. The amount of the named executive officers' annual compensation covered by the plan as of December 31, 1995, is represented by the salary column in the Summary Compensation Table above.
The maximum benefit under each Retirement Income Plan is limited by Sections 401 and 415 of the Internal Revenue Code of 1986, as amended; 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.
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. 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.
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, 1995, for the following executive officers named in the Summary Compensation Table above were: Mr. Bemis 13; Mr. Blount 11; and Mr. Maulden 30.
The credited years of service under the respective Retirement Income Plan, as amended, as of December 31, 1995 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 24; Mr. Jackson 16; Mr. Lupberger 32; and Mr. McInvale 23.
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, Mr. McInvale and Mr. Regan) have entered into PRP participation contracts. Current estimates indicate that the annual payments to a named executive officer under the above plans would be less than the payments to that officer under the System Executive Retirement Plan.
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 Mr. Blount) named in the Summary Compensation Table above. 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 above, for the base salary covered by the SERP as of December 31, 1995) 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 23 years, 22 years, and 14 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 System 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 under such plan 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 none of the current directors is compensated for his responsibilities as director.
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 of years corresponding to the number of years of active service as directors. Retired non- employee directors with over ten years of service receive a lifetime benefit of $200 a month. Years of service as an advisory director are included in calculating this benefit. System Energy has no retired non-employee directors.
Retired non-employee directors of 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
On January 18, 1991, GSU established 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 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, 1995, the balance in the trust had been reduced to $7,678,628. 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 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 compensation of AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy executive officers was set by the Personnel Committee of Entergy Corporation's Board of Directors for 1995. No officers or employees of such companies participated in deliberations concerning compensation during 1995. 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 17, 1996, and is incorporated herein by reference.
Item 12.

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 17, 1996, 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 Table above, 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 cumulative preferred stock of an Operating Company and common stock of Entergy Corporation as indicated:
* 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 as to which the individual has the sole voting power and powers of disposition, or power to direct the voting and disposition.
(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, 767 shares; Joseph L. Blount, 810 shares; John J. Cordaro, 1,082 shares; Frank F. Gallaher, 1,011 shares; William D. Hamilton, 617 shares; Donald C. Hintz, 810 shares; Jerry D. Jackson, 810 shares; R. Drake Keith, 810 shares; Edwin Lupberger, 886 shares; Jerry L. Maulden, 856 shares; Gerald D. McInvale, 118 shares; and Donald E. Meiners, 594 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, 5,140 shares; Joseph L. Blount, 1,809 shares; John J. Cordaro, 2,003 shares; Frank F. Gallaher, 3,930 shares; William D. Hamilton, 1,591 shares; Donald C. Hintz, 1,412 shares; Jerry D. Jackson, 2,427 shares; R. Drake Keith, 4,336 shares; Edwin Lupberger, 6,771 shares; Jerry L. Maulden, 10,460 shares; Gerald D. McInvale, 802 shares; Donald E. Meiners, 4,950 shares; William J. Regan, 15 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, 4,000 shares; John J. Cordaro, 1,200 shares; Frank F. Gallaher, 5,175 shares; Donald C. Hintz, 5,429 shares; Jerry D. Jackson, 5,500 shares; R. Drake Keith, 250 shares; Edwin Lupberger, 10,900 shares; Jerry L. Maulden, 5,500 shares; Gerald D. McInvale, 4,000 shares; and Donald E. Meiners, 250 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, 35,000 shares; John J. Cordaro 7,500 shares; Frank F. Gallaher, 32,500 shares; Donald C. Hintz, 42,500 shares; Jerry D. Jackson, 39,411 shares; R. Drake Keith, 7,174 shares; Edwin Lupberger, 88,824 shares; Jerry L. Maulden, 45,000 shares; Gerald D. McInvale, 35,000 shares; and Donald E. Meiners, 10,000 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 Shackelford, 3,950 shares.
(j) Includes 752 shares of Entergy Corporation common stock held jointly with spouse.
Item 13.

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 17, 1996, which information is incorporated herein by reference.
See Item 10, "Directors and Executive Officers of the Registrants," for information on certain relationships and transactions required to be reported under this item.
Other than as provided under applicable corporate laws, 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.

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 42 and 43)
(a)2. Financial Statement Schedules
Reports of Independent Accountants on Financial Statement Schedules (see pages 218 and 219)
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 NOPSI
A current report on Form 8-K, dated April 20, 1995, was filed with the SEC on April 26, 1995, reporting information under Item 5. "Other Events".
Entergy and GSU
A current report on Form 8-K, dated July 26, 1995, was filed with the SEC on July 26, 1995, reporting information under Item 5. "Other Events".
A current report on Form 8-K, dated October 25, 1995, was filed with the SEC on October 25, 1995, reporting information under Item 5. "Other Events".
EXPERTS
The statements attributed to Clark, Thomas & Winters, a professional corporation, as to legal conclusions with respect to GSU's rate regulation in Texas under Item 1. "Rate Matters and Regulation - Rate Matters - Retail Rate Matters - GSU" and in Note 2 to Entergy Corporation and Subsidiaries Consolidated Financial Statements and GSU's Financial Statements, "Rate and Regulatory Matters," have been reviewed by such firm and are included herein upon the authority of such firm as experts.
The statements attributed to Sandlin Associates regarding the analysis of River Bend Construction costs of GSU under Item 1. "Rate Matters and Regulation - Rate Matters - Retail Rate Matters - GSU" and in Note 2 to Entergy Corporation and Subsidiaries Consolidated Financial Statements and GSU's Financial Statements, "Rate and Regulatory Matters," have been reviewed by such firm and are included herein upon the authority of such firm as experts.
ENTERGY CORPORATION
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ENTERGY CORPORATION
By /s/ Louis E. Buck, Jr. Louis E. Buck, Jr., Vice President and Chief Accounting Officer
Date: March 11, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Signature Title Date
/s/ Louis E. Buck, Jr. Louis E. Buck, Jr. Vice President and March 11, 1996 Chief Accounting Officer (Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Executive Vice President and Chief Financial Officer; Principal Financial Officer); W. Frank Blount, John A. Cooper, Jr., Lucie J. Fjeldstad, N. 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, and Bismark A. Steinhagen (Directors).
By: /s/ Louis E. Buck, Jr. March 11, 1996 (Louis E. Buck, Jr., Attorney-in-fact)
ARKANSAS POWER & LIGHT COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ARKANSAS POWER & LIGHT COMPANY
By /s/ Louis E. Buck, Jr. Louis E. Buck, Jr., Vice President, Chief Accounting Officer and Assistant Secretary
Date: March 11, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Signature Title Date
/s/ Louis E. Buck, Jr. Louis E. Buck, Jr. Vice President, Chief Accounting March 11, 1996 Officer and Assistant Secretary (Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Michael B. Bemis, Donald C. Hintz, Jerry D. Jackson, R. Drake Keith, and Jerry L. Maulden (Directors).
By: /s/ Louis E. Buck, Jr. March 11, 1996 (Louis E. Buck, Jr., Attorney-in-fact)
GULF STATES UTILITIES COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
GULF STATES UTILITIES COMPANY
By /s/ Louis E. Buck, Jr. Louis E. Buck, Jr., Vice President, Chief Accounting Officer and Assistant Secretary
Date: March 11, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Signature Title Date
/s/ Louis E. Buck, Jr. Louis E. Buck, Jr. Vice President, Chief Accounting March 11, 1996 Officer and Assistant Secretary (Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Michael B. Bemis, Frank F. Gallaher, Donald C. Hintz, Jerry D. Jackson, and Jerry L. Maulden (Directors).
By: /s/ Louis E. Buck, Jr. March 11, 1996 (Louis E. Buck, Jr., Attorney-in-fact)
LOUISIANA POWER & LIGHT COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
LOUISIANA POWER & LIGHT COMPANY
By /s/ Louis E. Buck, Jr. Louis E. Buck, Jr., Vice President, Chief Accounting Officer and Assistant Secretary
Date: March 11, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Signature Title Date
/s/ Louis E. Buck, Jr. Louis E. Buck, Jr. Vice President, Chief Accounting March 11, 1996 Officer and Assistant Secretary (Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Michael B. Bemis, John J. Cordaro, Donald C. Hintz, Jerry D. Jackson, and Jerry L. Maulden (Directors).
By: /s/ Louis E. Buck, Jr. March 11, 1996 (Louis E. Buck, Jr., Attorney-in-fact)
MISSISSIPPI POWER & LIGHT COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
MISSISSIPPI POWER & LIGHT COMPANY
By /s/ Louis E. Buck, Jr. Louis E. Buck, Jr., Vice President, Chief Accounting Officer and Assistant Secretary
Date: March 11, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Signature Title Date
/s/ Louis E. Buck, Jr. Louis E. Buck, Jr. Vice President, Chief Accounting March 11, 1996 Officer and Assistant Secretary (Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Michael B. Bemis, Donald C. Hintz, Jerry D. Jackson, Jerry L. Maulden, and Donald E. Meiners (Directors).
By: /s/ Louis E. Buck, Jr. March 11, 1996 (Louis E. Buck, Jr., Attorney-in-fact)
NEW ORLEANS PUBLIC SERVICE INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
NEW ORLEANS PUBLIC SERVICE INC.
By /s/ Louis E. Buck, Jr. Louis E. Buck, Jr., Vice President, Chief Accounting Officer and Assistant Secretary
Date: March 11, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Signature Title Date
/s/ Louis E. Buck, Jr. Louis E. Buck, Jr. Vice President, Chief Accounting March 11, 1996 Officer and Assistant Secretary (Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); John J. Cordaro, Jerry D. Jackson, and Jerry L. Maulden (Directors).
By: /s/ Louis E. Buck, Jr. March 11, 1996 (Louis E. Buck, Jr., Attorney-in-fact)
SYSTEM ENERGY RESOURCES, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
SYSTEM ENERGY RESOURCES, INC.
By /s/ Louis E. Buck, Jr. Louis E. Buck, Jr., Vice President and Chief Accounting Officer
Date: March 11, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Signature Title Date
/s/ Louis E. Buck, Jr. Louis E. Buck, Jr. Vice President and March 11, 1996 Chief Accounting Officer (Principal Accounting Officer)
Donald C. Hintz (President, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Edwin Lupberger (Chairman of the Board), and Jerry L. Maulden (Directors).
By: /s/ Louis E. Buck, Jr. March 11, 1996 (Louis E. Buck, Jr., 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 14, 1996, on our audits of the financial statements and financial statement schedules of Entergy Corporation as of and for the years ended December 31, 1995 and 1994, which reports include emphasis paragraphs related to rate-related contingencies and legal proceedings and a 1995 change of accounting method for incremental nuclear plant outage maintenance costs by one of the Corporation's subsidiaries, 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 Numbers 33-36149, 33-48356, 33-50289 and 333- 00103) of our reports dated February 14, 1996, on our audits of the financial statements and financial statement schedule of Arkansas Power & Light Company as of and for the years ended December 31, 1995 and 1994, which reports include an emphasis paragraph related to the Company's 1995 change in its method of accounting for incremental nuclear plant outage maintenance costs, and 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 14, 1996, on our audits of the financial statements and financial statement schedule of Gulf States Utilities Company as of December 31, 1995 and 1994 and for the three years ended December 31, 1995, which reports include emphasis paragraphs related to rate-related contingencies, legal proceedings and changes in accounting for income taxes, postretirement benefits and unbilled revenue, 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, 33-50937, 333- 00105, and 333-01329) of our reports dated February 14, 1996, on our audits of the financial statements and financial statement schedule of Louisiana Power & Light Company as of and for the years ended December 31, 1995 and 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 14, 1996, on our audits of the financial statements and financial statement schedule of Mississippi Power & Light Company as of and for the years ended December 31, 1995 and 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 New Orleans Public Service Inc. on Form S-3 (File Numbers 33-57926 and 333-00255) of our reports dated February 14, 1996, on our audits of the financial statement and financial statement schedules of New Orleans Public Service Inc. as of and for the years ended December 31, 1995 and 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 System Energy Resources, Inc. on Form S-3 (File Numbers 33-47662 and 33-61189) of our reports dated February 14, 1996, on our audits of the financial statements of System Energy Resources, Inc. as of and for the years ended December 31, 1995 and 1994, which are included in this Annual Report on Form 10- K.
COOPERS & LYBRAND L.L.P. New Orleans, Louisiana March 8, 1996
EXHIBIT 23(b) INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Post-Effective Amendments 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, appearing in this Annual Report on Form 10-K of Entergy Corporation.
We also consent to the incorporation by reference in Registration Statements Nos. 333-00103, 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. 333-01329, 333-00105, 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 Nos. 333-00255 and 33-57926 of New Orleans Public Service Inc. 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 New Orleans Public Service Inc.
We also consent to the incorporation by reference in Registration Statement Nos. 33-61189 and 33-47662 of System Energy Resources, Inc. on Form S-3, and the related Prospectuses, 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.
DELOITTE & TOUCHE LLP New Orleans, Louisiana March 8, 1996
EXHIBIT 23(c)
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.]
CLARK, THOMAS & WINTERS A Professional Corporation
Austin, Texas March 11, 1996
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 (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.
SANDLIN ASSOCIATES Management Consultants
Pasco, Washington March 11, 1996
REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULES
To the Board of Directors and Shareholders 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 years ended December 31, 1995 and 1994, and the financial statements of Gulf States Utilities Company as of December 31, 1995 and 1994, and for each of the three years in the period ended December 31, 1995, and have issued our reports, included elsewhere in this Form 10-K, thereon dated February 14, 1996, which reports as to Entergy Corporation and Gulf States Utilities Company include emphasis paragraphs related to rate-related contingencies and legal proceedings, and which report as to Gulf States Utilities Company includes an emphasis paragraph related to changes in accounting for income taxes, postretirement benefits and unbilled revenue, and which reports as to Entergy Corporation and Arkansas Power & Light Company include an emphasis paragraph related to changes in accounting for incremental nuclear plant outage maintenance expenses. 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.
COOPERS & LYBRAND L.L.P.
New Orleans, Louisiana February 14, 1996
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. for the year 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 audit also included the 1993 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 audit. 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 audit 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.
DELOITTE & TOUCHE LLP New Orleans, Louisiana February 11, 1994
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page
I Financial Statements of Entergy Corporation: Statements of Income - For the Years Ended December 31, 1995, 1994, and 1993 S-2 Statements of Cash Flows - For the Years Ended December 31, 1995, 1994, and 1993 S-3 Balance Sheets, December 31, 1995 and 1994 S-4 Statements of Retained Earnings and Paid-In Capital - For the Years Ended December 31, 1995, 1994, and 1993 S-5 II Valuation and Qualifying Accounts 1995, 1994, and 1993: 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 STATEMENTS OF INCOME
For the Years Ended December 31, 1995 1994 1993 (In Thousands)
Income: Equity in income of subsidiaries $549,144 $369,701 $557,681 Interest on temporary investments 20,641 25,496 18,520 -------- -------- -------- Total 569,785 395,197 576,201 -------- -------- -------- Expenses and Other Deductions: Administrative and general expenses 53,872 57,846 25,129 Income taxes (credit) (5,383) (6,350) 3,587 Taxes other than income (credit) 1,102 465 (696) Interest (credit) 214 1,395 (3,749) -------- -------- -------- Total 49,805 53,356 24,271 -------- -------- -------- Net Income $519,980 $341,841 $551,930 ======== ======== ========
See Entergy Corporation and Subsidiaries Notes to Financial Statements in Part II, Item 8.
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 dated December 31, 1993 (A-1(a) to Rule 24 Certificate in 70-8059).
System Energy
(b) 1 -- Amended and Restated Articles of Incorporation of System Energy and amendments thereto through April 28, 1989 (A-1(a) to Form U-1 in 70-5399).
AP&L
(c) 1 -- Amended and Restated Articles of Incorporation of AP&L and amendments thereto through May 27, 1992 (4(c) in 33-50289).
GSU
(d) 1 -- Restated Articles of Incorporation of GSU and amendments thereto through May 28, 1993 (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 and amendments thereto through July 21, 1994 (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 and amendments thereto through January 19, 1996.
NOPSI
(g) 1 -- Restatement of Articles of Incorporation of NOPSI and amendments thereto through July 21, 1994 (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 effective August 25, 1992, and as presently in effect (A-2(a) to Rule 24 Certificate in 70-8059).
(b) -- By-Laws of System Energy effective May 4, 1989, and as presently in effect (A-2(a) in 70-5399).
(c) -- By-Laws of AP&L as amended effective May 5, 1994, and as presently in effect (4(f) in 33-50289).
(d) -- By-Laws of GSU as amended effective May 5, 1994, and as presently in effect (A-12 in 70-8059).
(e) -- By-Laws of LP&L effective January 23, 1984, and as presently in effect (A-4 in 70-6962).
*(f) -- By-Laws of MP&L effective April 5, 1995, and as presently in effect.
(g) -- By-Laws of NOPSI effective May 5, 1994, and as presently in effect (3(b) to Form 10-Q for the quarter ended September 30, 1989 in 0-5807).
(4) Instruments Defining Rights of Security Holders, Including Indentures
Entergy Corporation
(a) 1 -- See (4)(b) through (4)(g) below for instruments defining the rights of holders of long-term debt of System Energy, AP&L, GSU, LP&L, MP&L and NOPSI.
(a) 2 -- 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) 3 -- 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) 4 -- 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) 5 -- 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) 6 -- 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).
(a) 7 -- Credit Agreement, dated as of October 10, 1995, among Entergy, the Banks (Bank of America National Trust & Savings Association, The Bank of New York, Chemical Bank, Citibank, N.A., Union Bank of Switzerland, ABN AMRO Bank N.V., the Bank of Nova Scotia, Canadian Imperial Bank of Commerce, Bank N.A., First National Bank of Commerce and Whitney National Bank) and Citibank, N.A., as Agent (Exhibit B to Rule 24 Certificate dated October 20, 1995 in File No. 70-8149).
System Energy
(b) 1 -- Mortgage and Deed of Trust, dated as of June 15, 1977, 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 -- Indenture (for Unsecured Debt Securities), dated as of September 1, 1995, between System Energy Resources, Inc., and Chemical Bank (B-10(a) to Rule 24 Certificate in 70-8511).
AP&L
(c) 1 -- Mortgage and Deed of Trust, dated as of October 1, 1944, 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, dated September 1, 1926, as amended by certain Supplemental Indentures (B-a-I-1 in Registration No. 2-2449 (Mortgage); 7-A-9 in Registration No. 2-6893 (Seventh); B to Form 8-K dated September 1, 1959 (Eighteenth); B to Form 8-K dated February 1, 1966 (Twenty-second); B to Form 8-K dated March 1, 1967 (Twenty-third); C to Form 8-K dated March 1, 1968 (Twenty- fourth); B to Form 8-K dated November 1, 1968 (Twenty- fifth); B to Form 8-K dated April 1, 1969 (Twenty-sixth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4-2 to Form 10-K for the year ended December 31, 1984 in 1-2703 (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, dated as of April 1, 1944, as amended by fifty 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); A-3(f) to Rule 24 Certificate dated August 1, 1994 in 70-7822 (Forty-ninth) and A-4(c) to Rule 24 Certificate dated September 28, 1994 in 70-7653 (Fiftieth)).
(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, dated as of September 1, 1944, 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 tenth Supplemental Indentures (A-2(a)-2 to Rule 24 Certificate in 70-7461 (Mortgage); A-2(b)-2 in 70-7461 (First); A-5(b) to Rule 24 Certificate in 70-7419 (Second); A-4(b) to Rule 24 Certificate in 70-7554 (Third); A-1(b)-1 to Rule 24 Certificate in 70-7737 (Fourth); A-2(b) to Rule 24 Certificate dated November 24, 1992 in 70-7914 (Fifth); A-2(e) to Rule 24 Certificate dated January 22, 1993 in 70-7914 (Sixth); A-2(g) to Form U-1 in 70-7914 (Seventh); A-2(i) to Rule 24 Certificate dated November 10, 1993 in 70-7914 (Eighth); A-2(j) to Rule 24 Certificate dated July 22, 1994 in 70-7914 (Ninth); and (A-2(l) to Rule 24 Certificate dated April 21, 1995 in File 70-7914 (Tenth)).
NOPSI
(g) 1 -- Mortgage and Deed of Trust, dated as of July 1, 1944, 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); 4(a) to Form 10-Q for the quarter ended September 30, 1993 in 0-5807 (Fourth); and 4(a) to Form 8-K dated April 26, 1995 in File No. 0-5807 (Fifth)).
(10) Material Contracts
Entergy Corporation
(a) 1 -- Agreement, dated April 23, 1982, among certain System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982, in 1-3517).
(a) 2 -- Middle South Utilities 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 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 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 year ended December 31, 1990, in 1-3517).
(a) 11-- Amendment, dated January 1, 1992, to Service Agreement with Entergy Services (10(a)-11 for the year ended December 31, 1994 in 1-3517).
(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-- 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) 18-- Eighteenth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-2 to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(a) 19-- Nineteenth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-3 to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(a) 20-- 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) 21-- 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) 22-- 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) 23-- 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) 24-- 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) 25-- 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) 26-- 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) 27-- Eighteenth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-2 to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(a) 28-- Nineteenth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-3 to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(a) 29-- Twenty-sixth Supplementary Capital Funds Agreement and Assignment, dated as of October 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(c) to Rule 24 Certificate dated November 2, 1992 in 70-7946).
(a) 30-- Twenty-seventh Supplementary Capital Funds Agreement and Assignment, dated as of April 1, 1993, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(a) 31-- 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) 32-- 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) 33-- 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) 34-- 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) 35-- 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) 36-- Agreement between Entergy Corporation and Edwin Lupberger (10(a)-42 to Form 10-K for the year ended December 31, 1985, in 1-3517).
(a) 37-- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(a) 38-- Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate, dated October 30, 1981, in 70-6337).
(a) 39-- Operating Agreement dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337).
(a) 40-- Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate, dated January 9, 1989, in 70-7561).
(a) 41-- Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate, dated January 9, 1989, in 70-7561).
(a) 42-- Substitute Power Agreement, dated as of May 1, 1980, among MP&L, System Energy and SMEPA (B(3)(a) in 70-6337).
(a) 43-- Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033).
(a) 44-- 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) 45-- Post-Retirement Plan (10(a)37 to Form 10-K for the year ended December 31, 1983, in 1-3517).
(a) 46-- 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 year ended December 31, 1982, in 1-3517).
(a) 47-- 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) 48-- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(a) 49-- 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) 50-- 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) 51-- 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) 52-- 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) 53-- 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) 54-- 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) 55-- 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) 56-- 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) 57-- 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) 58-- 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) 59-- 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) 60-- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form 10-K for the year ended December 31, 1989, in 1-3517).
+(a) 61-- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831).
+(a) 62-- Retired Outside Director Benefit Plan (10(a)63 to Form 10-K for the year ended December 31, 1991, in 1-3517).
+(a) 63-- 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) 64-- 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) 65-- Supplemental Retirement Plan (10(a) 69 to Form 10- K for the year ended December 31, 1992 in 1-3517).
+(a) 66-- 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) 67-- 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) 68-- 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) 69-- 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) 70-- 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) 71-- 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) 72-- 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) 73-- 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) 74-- 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 through (b) 12-- See 10(a)-12 through 10(a)-23 above.
(b) 13 through (b) 24-- See 10(a)-24 through 10(a)-35 above.
(b) 25-- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(b) 26-- 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) 27-- Operating Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337).
(b) 28-- 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) 29-- 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) 30-- 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) 31-- 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) 32-- Amended and Restated Installment Sale Agreement, dated as of May 1, 1995, between System Energy and Claiborne County, Mississippi (B-6(a) to Rule 24 Certificate in 70-8511).
(b) 33-- 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) 34-- 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) 35-- 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) 36-- 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) 37-- 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) 38-- Substitute Power Agreement, dated as of May 1, 1980, among MP&L, System Energy and SMEPA (B(3)(a) in 70-6337).
(b) 39-- Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033).
(b) 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 year ended December 31, 1982, in 1-3517).
(b) 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).
(b) 42-- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(b) 43-- Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(b) to Rule 24 Certificate, dated March 3, 1989, in 70-7604).
(b) 44-- System Energy's Consent, dated January 31, 1995, pursuant to Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(c) to Rule 24 Certificate, dated February 13, 1995 in 70-7604).
(b) 45-- 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) 46-- 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) 47-- 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) 48-- Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(b) 49-- First Amendment, dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
(b) 50-- Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(b) 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).
(b) 52-- Service Agreement with Entergy Services, dated as of July 16, 1974, as amended (10(b)-43 to Form 10-K for the year ended December 31, 1988, in 1-9067).
(b) 53-- Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(b)-45 to Form 10-K for the year ended December 31, 1990, in 1-9067).
(b) 54-- Amendment, dated January 1, 1992, to Service Agreement with Entergy Services (10(a) -11 to Form 10-K for the year ended December 31, 1994 in 1-3517).
(b) 55-- Operating Agreement between Entergy Operations and System Energy, dated as of June 6, 1990 (B-3(b) to Rule 24 Certificate, dated June 15, 1990, in 70-7679).
(b) 56-- Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate, dated September 27, 1990, in 70-7757).
+(b) 57-- Agreement between System Energy and Donald C. Hintz (10(b)47 to Form 10-K for the year ended December 31, 1991, in 1-9067).
+(b) 58-- Agreement between Entergy Corporation and Edwin Lupberger (10(a)-42 to Form 10-K for the year ended December 31, 1985 in 1-3517).
+(b) 59-- Agreement between Entergy Services and Gerald D. McInvale (10(a)-69 to Form 10-K for the year ended December 31, 1992 in 1-3517).
AP&L
(c) 1 -- Agreement, dated April 23, 1982, among AP&L and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the 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 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 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 year ended December 31, 1990, in 1-10764).
(c) 11-- Amendment, dated January 1, 1992, to Service Agreement with Entergy Services (10(a)-11 to Form 10-K for the year ended December 31, 1994 in 1-3517).
(c) 12 through (c) 23-- See 10(a)-12 through 10(a)-23 above.
(c) 24-- Agreement, dated August 20, 1954, between AP&L and the United States of America (SPA)(13(h) in 2-11467).
(c) 25-- Amendment, dated April 19, 1955, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-2 in 2-41080).
(c) 26-- Amendment, dated January 3, 1964, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-3 in 2-41080).
(c) 27-- Amendment, dated September 5, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-4 in 2-41080).
(c) 28-- Amendment, dated November 19, 1970, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-5 in 2-41080).
(c) 29-- Amendment, dated July 18, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-6 in 2-41080).
(c) 30-- Amendment, dated December 27, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-7 in 2-41080).
(c) 31-- Amendment, dated January 25, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-8 in 2-41080).
(c) 32-- Amendment, dated October 14, 1971, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-9 in 2-43175).
(c) 33-- Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-10 in 2-60233).
(c) 34-- Agreement, dated May 14, 1971, between AP&L and the United States of America (SPA) (5(e) in 2-41080).
(c) 35-- Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated May 14, 1971 (5(e)-1 in 2-60233).
(c) 36-- 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) 37-- Agreement, dated April 3, 1972, between Entergy Services and Gulf United Nuclear Fuels Corporation (5(l)-3 in 2-46152).
(c) 38-- 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) 39-- 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) 40-- 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) 41-- Agreement, dated June 29, 1979, between AP&L and City of Conway, Arkansas (5(r)-3 in 2-66235).
(c) 42-- 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) 43-- 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) 44-- 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) 45-- Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c) 51 to Form 10-K for the year ended December 31, 1984, in 1-10764).
(c) 46-- 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) 47-- Amendment, dated December 28, 1979, to the Independence Steam Electric Station Ownership Agreement (5(r)-7(a) in 2-66235).
(c) 48-- Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c) 54 to Form 10-K for the year ended December 31, 1984, in 1-10764).
(c) 49-- 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 year ended December 31, 1984, in 1-10764).
(c) 50-- 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 year ended December 31, 1984, in 1-10764).
(c) 51-- 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) 52-- 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) 53-- Agreement, dated June 21, 1979, between AP&L and Reeves E. Ritchie ((10)(b)-90 to Form 10-K for the year ended December 31, 1980, in 1-10764).
(c) 54-- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
+(c) 55-- Post-Retirement Plan (10(b) 55 to Form 10-K for the year ended December 31, 1983, in 1-10764).
(c) 56-- Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and AP&L, LP&L, MP&L, and NOPSI (10(a) 39 to Form 10-K for the year ended December 31, 1982, in 1-3517).
(c) 57-- 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) 58-- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(c) 59-- 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 year ended December 31, 1983, in 1-10764).
(c) 60-- 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) 61-- 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) 62-- 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) 63-- 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) 64-- 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) 65-- 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) 66-- 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) 67-- 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) 68-- 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) 69-- 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) 70-- 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) 71-- 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) 72-- 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 year ended December 31, 1990, in 1-10764).
+(c) 73-- 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) 74-- Entergy Corporation Annual Incentive Plan (10(a)54 to Form 10-K for the year ended December 31, 1989, in 1-3517).
+(c) 75-- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831).
+(c) 76-- 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) 77-- Supplemental Retirement Plan (10(a)69 to Form 10-K for the year ended December 31, 1992 in 1-3517).
+(c) 78-- 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) 79-- 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) 80-- 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) 81-- 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) 82-- 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) 83-- 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) 84-- 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) 85-- 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) 86-- 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) 87-- 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) 88-- 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) 89-- 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) 90-- System Executive Retirement Plan (10(a) 82 to Form 10-K for the year ended December 31, 1993 in 1-11299).
(c) 91-- 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) 92-- 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) 93-- 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) 94-- 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) 95-- Loan Agreement dated June 15, 1994, between AP&L and Pope County, Arkansas (B-1(b) to Rule 24 Certificate in 70-8405).
*(c) 96-- Loan Agreement dated November 15, 1995, between AP&L and Pope County, Arkansas.
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-- 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) 18-- 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) 19-- 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) 20-- 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) 21-- 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) 22-- 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) 23-- 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) 24-- 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) 25-- 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) 26-- 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) 27-- 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) 28-- 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) 29-- 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) 30-- Trust and Investment Management Agreement between GSU and Morgan Guaranty and Trust Company of New York (the "Decommissioning Trust Agreement) 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) 31-- Amendment No. 2 dated November 1, 1995 between GSU and Mellon Bank to Decommissioning Trust Agreement.
(d) 32-- 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) 34 to Form 10-K for year ended December 31, 1994).
*(d) 33-- Amendment No. 1 dated as of January 31, 1996 to Credit Agreement, dated as of December 31, 1993, among River Bend Fuel Services, Inc. and certain commercial lending institutions and CIBC Inc. as agent for Lenders.
(d) 34-- 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) 35-- 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) 36-- 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) 37-- 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) 38-- 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) 39-- 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) 40-- 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) 41-- 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) 42-- 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) 43-- 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) 44-- 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) 45-- Operating Agreement between Entergy Operations and GSU, dated as of December 31, 1993 (B-2(f) to Rule 24 Certificate in 70-8059).
(d) 46-- Guarantee Agreement between Entergy Corporation and GSU, dated as of December 31, 1993 (B-5(a) to Rule 24 Certificate in 70-8059).
(d) 47-- Service Agreement with Entergy Services, dated as of December 31, 1993 (B-6(c) to Rule 24 Certificate in 70-8059).
+(d) 48-- 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) 49-- Assignment, Assumption and Amendment Agreement to Letter of Credit and Reimbursement Agreement between GSU, Canadian Imperial Bank of Commerce and Westpac Banking Corporation (10(d) 58 to Form 10-K for the year ended December 31, 1993 in 1-2703).
(d) 50-- 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) 51-- 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 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 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 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 year ended December 31, 1990, in 1-8474).
(e) 11-- Amendment, dated January 1, 1992, to Service Agreement with Entergy Services (10(a)-11 to Form 10-K for the year ended December 31, 1994 in 1-3517).
(e) 12 through (e) 23-- See 10(a)-12 through 10(a)-23 above.
(e) 24-- 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) 25-- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(e) 26-- 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) 27-- Post-Retirement Plan (10(c)23 to Form 10-K for the year ended December 31, 1983, in 1-8474).
(e) 28-- 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 year ended December 31, 1982, in 1-3517).
(e) 29-- 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) 30-- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(e) 31-- 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) 32-- 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) 33-- 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) 34-- 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) 35-- 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 year ended December 31, 1984, in 1-8474).
(e) 36-- 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) 37-- 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) 38-- 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) 39-- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form 10-K for the year ended December 31, 1989, in 1-3517).
+(e) 40-- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831).
+(e) 41-- Supplemental Retirement Plan (10(a) 69 to Form 10-K for the year ended December 31, 1992 in 1-3517).
+(e) 42-- 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) 43-- 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) 44-- 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) 45-- 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) 46-- 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) 47-- 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) 48-- 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) 49-- 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) 50-- 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) 51-- 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) 52-- 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) 53-- 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) 54-- System Executive Retirement Plan (10(a) 82 to Form 10-K for the year ended December 31, 1993 in 1-11299).
(e) 55-- 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).
(e) 56-- Installment Sale Agreement, dated November 1, 1995, between LP&L and St. Charles Parish, Louisiana (B- 6(a) to Rule 24 Certificate dated December 19, 1995 in 70- 8487).
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 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 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 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 year ended December 31, 1990, in 0-320).
(f) 11-- Amendment, dated January 1, 1992, to Service Agreement with Entergy Services (10(a)-11 to Form 10-K for the year ended December 31, 1994 in 1-3517).
(f) 12 though (f) 23-- See 10(a)-12 - 10(a)-23 above.
(f) 24-- 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) 25-- 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) 26-- 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) 27-- 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) 28-- 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) 29-- Substitute Power Agreement, dated as of May 1, 1980, among MP&L, System Energy and SMEPA (B-3(a) in 70-6337).
(f) 30-- Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c) 51 to Form 10-K for the year ended December 31, 1984, in 0-375).
(f) 31-- Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c) 54 to Form 10-K for the year ended December 31, 1984, in 0-375).
(f) 32-- 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 year ended December 31, 1984, in 0-375).
(f) 33-- 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 year ended December 31, 1984, in 0-375).
(f) 34-- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
+(f) 35-- Post-Retirement Plan (10(d) 24 to Form 10-K for the year ended December 31, 1983, in 0-320).
(f) 36-- 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 year ended December 31, 1982, in 1-3517).
(f) 37-- 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) 38-- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(f) 39-- 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) 40-- 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) 41-- 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) 42-- 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) 43-- 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) 44-- 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) 45-- 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) 46-- 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) 47-- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form 10-K for the year ended December 31, 1989, in 1-3517).
+(f) 48-- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831).
+(f) 49-- Supplemental Retirement Plan (10(a)69 to Form 10-K for the year ended December 31, 1992 in 1-3517).
+(f) 50-- 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) 51-- 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) 52-- 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) 53-- 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) 54-- 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) 55-- 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) 56-- 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) 57-- 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) 58-- 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) 59-- 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) 60-- 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) 61-- 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) 62-- 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 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 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 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 year ended December 31, 1990, in 0-5807).
(g) 11-- Amendment, dated January 1, 1992, to Service Agreement with Entergy Services (10(a)-11 to Form 10-K for year ended December 31, 1994 in 1-3517).
(g) 12 (g) 23-- See 10(a)-12 - 10(a)-23 above.
(g) 24-- Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
+(g) 25-- Post-Retirement Plan (10(e) 22 to Form 10-K for the year ended December 31, 1983, in 1-1319).
(g) 26-- 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 year ended December 31, 1982, in 1-3517).
(g) 27-- 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) 28-- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(g) 29-- 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) 30-- 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) 31-- 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) 32-- 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) 33-- 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) 34-- 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) 35-- Entergy Corporation Annual Incentive Plan (10(a)54 to Form 10-K for the year ended December 31, 1989, in 1-3517).
+(g) 36-- Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831).
+(g) 37-- Supplemental Retirement Plan (10(a)69 to Form 10-K for the year ended December 31, 1992 in 1-3517).
+(g) 38-- 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) 39-- 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) 40-- 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) 41-- 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) 42-- 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) 43-- 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) 44-- 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) 45-- 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) 46-- 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) 47-- 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) 48-- 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) 49-- 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) 50-- 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.
(18) Letter Re Change in Accounting Principles
*(a) Letter from Coopers & Lybrand L.L.P. regarding change in accounting principles for AP&L.
*(b) Letter from Coopers & Lybrand L.L.P. regarding change in accounting principles for Entergy.
*(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 214.
*(b) The consent of Deloitte & Touche LLP is contained herein at page 215.
*(c) The consent of Clark, Thomas & Winters is contained herein at page 216.
*(d) The consent of Sandlin Associates is contained herein at page 217.
*(24) Powers of Attorney
(27) Financial Data Schedule
*(a) Financial Data Schedule for Entergy Corporation and Subsidiaries as of December 31, 1995.
*(b) Financial Data Schedule for AP&L as of December 31, 1995.
*(c) Financial Data Schedule for GSU as of December 31, 1995.
*(d) Financial Data Schedule for LP&L as of December 31, 1995.
*(e) Financial Data Schedule for MP&L as of December 31, 1995.
*(f) Financial Data Schedule for NOPSI as of December 31, 1995.
*(g) Financial Data Schedule for System Energy as of December 31, 1995.
(99) Additional Exhibits
GSU
(a) 1 Opinion of Clark, Thomas & Winters, a professional corporation, dated September 30, 1992 regarding the effect of the October 1, 1991 judgment in GSU v. PUCT in the District Court of Travis County, Texas (99-1 in Registration No. 33-48889).
(a) 2 Opinion of Clark, Thomas & Winters, a professional corporation, dated 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.
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* Filed herewith. + Management contracts or compensatory plans or arrangements.