SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the Fiscal Year Ended December 31, 1994
OR
TRANSITION REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ____________ to ____________
Commission Registrant, State of Incorporation, IRS Employer
File Number Address of Principal Executive Identification No.
Offices and Telephone Number
1-11299 ENTERGY CORPORATION 13-5550175
(a Delaware corporation)
639 Loyola Avenue
New Orleans, Louisiana 70113
Telephone (504) 529-5262
1-10764 ARKANSAS POWER & LIGHT COMPANY 71-0005900
(an Arkansas corporation)
425 West Capitol Avenue, 40th Floor
Little Rock, Arkansas 72201
Telephone (501) 377-4000
1-2703 GULF STATES UTILITIES COMPANY 74-0662730
(a Texas corporation)
350 Pine Street
Beaumont, Texas 77701
Telephone (409) 838-6631
1-8474 LOUISIANA POWER & LIGHT COMPANY 72-0245590
(a Louisiana corporation)
639 Loyola Avenue
New Orleans, Louisiana 70113
Telephone (504) 529-5262
0-320 MISSISSIPPI POWER & LIGHT COMPANY 64-0205830
(a Mississippi corporation)
308 East Pearl Street
Jackson, Mississippi 39201
Telephone (601) 969-2311
0-5807 NEW ORLEANS PUBLIC SERVICE INC. 72-0273040
(a Louisiana corporation)
639 Loyola Avenue
New Orleans, Louisiana 70113
Telephone (504) 529-5262
1-9067 SYSTEM ENERGY RESOURCES, INC. 72-0752777
(an Arkansas corporation)
Echelon One
1340 Echelon Parkway
Jackson, Mississippi 39213
Telephone (601) 368-5000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Registrant Title of Class on Which Registered
Entergy Corporation Common Stock, $0.01 Par Value - 227,410,827 New York Stock Exchange, Inc.
Shares outstanding at February 28, 1995 Midwest Stock Exchange
Incorporated
Pacific Stock Exchange
Incorporated
Arkansas Power & Light Company $2.40 Preferred Stock, Cumulative, $0.01 Par Value New York Stock Exchange, Inc.
($25 Involuntary Liquidation Value)
Gulf States Utilities Company Preferred Stock, Cumulative, $100 Par Value:
$4.40 Dividend Series New York Stock Exchange, Inc.
$4.52 Dividend Series New York Stock Exchange, Inc.
$5.08 Dividend Series New York Stock Exchange, Inc.
$8.80 Dividend Series New York Stock Exchange, Inc.
Adjustable Rate Series B
(Depository Receipts) New York Stock Exchange, Inc.
Preference Stock, Cumulative, without Par Value New York Stock Exchange, Inc.
$1.75 Dividend Series
Louisiana Power & Light Company 9.68% Preferred Stock, Cumulative, $25 Par Value New York Stock Exchange, Inc.
12.64% Preferred Stock, Cumulative, $25 Par Value New York Stock Exchange, Inc.
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Class
Arkansas Power & Light Company Preferred Stock, Cumulative, $100 Par Value
Preferred Stock, Cumulative, $25 Par Value
Preferred Stock, Cumulative, $0.01 Par Value
Louisiana Power & Light Company Preferred Stock, Cumulative, $100 Par Value
Preferred Stock, Cumulative, $25 Par Value
Mississippi Power & Light Company Preferred Stock, Cumulative, $100 Par Value
New Orleans Public Service Inc. Preferred Stock, Cumulative, $100 Par Value
4 3/4% Preferred Stock, Cumulative, $100 Par
Value
Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrants were required to file such
reports), and (2) have been subject to such filing requirements for
the past 90 days. Yes X No ____
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of the registrants' knowledge, in
definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K. [
]
The aggregate market value of Entergy Corporation Common Stock,
$0.01 Par Value, held by non-affiliates, was $5.1 billion based on the
reported last sale price of such stock on the New York Stock Exchange
on February 28, 1995. Entergy Corporation is the sole holder of the
common stock of Arkansas Power & Light Company, Gulf States Utilities
Company, Louisiana Power & Light Company, Mississippi Power & Light
Company, New Orleans Public Service Inc., and System Energy Resources,
Inc.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement of Entergy Corporation to be
filed in connection with its Annual Meeting of Stockholders, to be
held May 26, 1995, are incorporated by reference into Part III hereof.
TABLE OF CONTENTS
Page
Number
Definitions i
Part I
Item 1. Business 1
Item 2. Properties 53
Item 3. Legal Proceedings 53
Item 4. Submission of Matters to a Vote of Security Holders 53
Part II
Item 5. Market for Registrants' Common Equity and Related
Stockholder Matters 54
Item 6. Selected Financial Data 55
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 55
Item 8. Financial Statements and Supplementary Data 56
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 341
Part III
Item 10. Directors and Executive Officers of the Registrants 341
Item 11. Executive Compensation 350
Item 12. Security Ownership of Certain Beneficial Owners
and Management 359
Item 13. Certain Relationships and Related Transactions 363
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 364
Experts 365
Signatures 366
Consents of Experts 373
Reports of Independent Accountants on Financial Statement Schedules 380
Independent Auditors' Report on Financial Statement Schedules 381
Index to Financial Statement Schedules S-1
Exhibit Index E-1
This combined Form 10-K is separately filed by Entergy Corporation,
Arkansas Power & Light Company, Gulf States Utilities Company,
Louisiana Power & Light Company, Mississippi Power & Light Company,
New Orleans Public Service Inc., and System Energy Resources, Inc.
Information contained herein relating to any individual company is
filed by such company on its own behalf. Each company makes no
representation as to information relating to the other companies.
This report (including the material incorporated herein by reference)
must be read in its entirety. No one section of the report deals with
all aspects of the subject matter.
DEFINITIONS
Certain abbreviations or acronyms used in the text and notes are
defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
Algiers 15th Ward of the City of New Orleans, Louisiana
ALJ Administrative Law Judge
Alliance Alliance for Affordable Energy, Inc.
ANO Arkansas Nuclear One Steam Electric
Generating Station (nuclear)
ANO 1 Unit No. 1 of ANO
ANO 2 Unit No. 2 of ANO
AP&L Arkansas Power & Light Company
APSC Arkansas Public Service Commission
Arkansas District
Court United States District Court for the Western
District of Arkansas
Availability
Agreement Agreement, dated as of June 21, 1974, as
amended, among System Energy and AP&L, LP&L, MP&L,
and NOPSI, and the assignments thereof
Cajun Cajun Electric Power Cooperative, Inc.
Capital Funds
Agreement Agreement, dated as of June 21, 1974, as
amended, between System Energy and Entergy
Corporation, and the assignments thereof
CCLM Customer-Controlled Load Management (a DSM
activity utilizing residential time-of-use rates)
City of New
Orleans or City New Orleans, Louisiana
CounciL Council of the City of New Orleans, Louisiana
D.C. Circuit United States Court of Appeals for the District of
Columbia Circuit
DOE United States Department of Energy
DSM Demand-Side Management (Least Cost Plan
activities that influence electricity usage by
consumers)
Eighth Circuit United States Court of Appeals for the Eighth
Circuit
EPAct Energy Policy Act of 1992
Entergy or System Entergy Corporation and its various direct and
indirect subsidiaries
Entergy Corporation Entergy Corporation, a Delaware corporation,
successor to Entergy Corporation, a Florida
corporation
Entergy Enterprises Entergy Enterprises, Inc.
Entergy Operations Entergy Operations, Inc.
Entergy Power Entergy Power, Inc.
Entergy Services Entergy Services, Inc.
EPA Environmental Protection Agency
EWG Exempt Wholesale Generator
February 4
Resolution The Resolution (including the Determinations
and Order referred to therein) adopted by the
Council on February 4, 1988, disallowing the
recovery by NOPSI of $135 million of previously
deferred Grand Gulf 1 related costs
FERC Federal Energy Regulatory Commission
Grand Gulf Station Grand Gulf Steam Electric Generating Station
(nuclear)
Grand Gulf 1 Unit No. 1 of the Grand Gulf Station (nuclear)
Grand Gulf 2 Unit No. 2 of the Grand Gulf Station (nuclear)
GSU Gulf States Utilities Company (including
wholly owned subsidiaries - Varibus Corporation,
GSG&T, Inc., Prudential Oil & Gas, Inc., and
Southern Gulf Railway Company)
Holding Company
Act Public Utility Holding Company Act of 1935, as
amended
Independence
Station Independence Steam Electric Generating
Station (coal)
Independence 2 Unit No. 2 of the Independence Station
IRS Internal Revenue Service
KV Kilovolts
KWH Kilowatt-Hour(s)
Least Cost Plan Least Cost Integrated Resource Plan (combination
of demand- and supply-side resources to be used by
Entergy to satisfy electricity demand)
LP&L Louisiana Power & Light Company
LPSC Louisiana Public Service Commission
MCF 1,000 cubic feet of gas
Merger The combination transaction, consummated on
December 31, 1993, by which GSU became a
subsidiary of Entergy Corporation and Entergy
Corporation became a Delaware corporation
MP&L Mississippi Power & Light Company
MPSC Mississippi Public Service Commission
MW Megawatt(s)
Nelson Unit 6 Unit No. 6 (coal) of the Nelson Steam Electric
Generating Station
NISCO Nelson Industrial Steam Company
1986 NOPSI
Settlement Settlement, effective March 25, 1986, between
NOPSI and the Council regarding NOPSI's Grand Gulf-
related rate issues
1991 NOPSI
Settlement Settlement, retroactive to October 4, 1991,
among NOPSI, the Council, and the Alliance that
settled certain Grand Gulf 1 prudence issues and
certain litigation related to the February 4
Resolution
NOPSI New Orleans Public Service Inc.
NRC Nuclear Regulatory Commission
PRP Potentially Responsible Party (a person or
entity that may be responsible for remediation of
environmental contamination)
PUCT Public Utility Commission of Texas
PURPA Public Utility Regulatory Policies Act
Rate Cap The level of GSU's retail electric base rates in
effect at December 31, 1993, for the Louisiana
retail jurisdiction, and the level in effect prior
to the Texas Cities Rate Settlement for the Texas
retail jurisdiction, that may not be exceeded for
the five years following December 31, 1993
Reallocation
Agreement 1981 Agreement, superseded in part by a
June 13, 1985 decision of FERC, among AP&L, LP&L,
MP&L, NOPSI, and System Energy relating to the
sale of capacity and energy from the Grand Gulf
Station
Ritchie 2 Unit No. 2 of the R. E. Ritchie Steam Electric
Generating Station (gas/oil)
River Bend River Bend Steam Electric Generating Station
(nuclear), owned 70% by GSU.
RUS Rural Utility Services (formerly the Rural
Electrification Administration or "REA")
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards,
promulgated by the Financial Accounting Standards
Board
SRG&T Sam Rayburn G&T, Inc.
SRMPA Sam Rayburn Municipal Power Agency
System Agreement Agreement, effective January 1, 1983, as modified,
among the System operating companies relating to
the sharing of generating capacity and other power
resources
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively
Unit Power Sales
Agreement Agreement, dated as of June 10, 1982, as
amended and approved by FERC, among AP&L, LP&L,
MP&L, NOPSI, and System Energy, relating to the
sale of capacity and energy from System Energy's
share of Grand Gulf 1
Waterford 3 Unit No. 3 (nuclear) of the Waterford Steam
Electric Generating Station
PART I
Item 1. Business
BUSINESS OF ENTERGY
General
Entergy Corporation was originally incorporated under the laws of
the State of Florida on May 27, 1949. On December 31, 1993, Entergy
Corporation merged with and into Entergy-GSU Holdings, Inc., a
Delaware corporation, which then changed its name to Entergy
Corporation. Entergy Corporation is a holding company registered
under the Holding Company Act and does not own or operate any
significant physical properties. Entergy Corporation owns all of the
outstanding common stock of five retail operating electric utility
subsidiaries, AP&L, GSU, LP&L, MP&L, and NOPSI. AP&L was incorporated
under the laws of the State of Arkansas in 1926; GSU was incorporated
under the laws of the State of Texas in 1925; LP&L and NOPSI were
incorporated under the laws of the State of Louisiana in 1974 and
1926, respectively; and MP&L was incorporated under the laws of the
State of Mississippi in 1963. As of December 31, 1994, these
operating companies provided electric service to approximately
2.4 million customers in the States of Arkansas, Louisiana,
Mississippi, Tennessee and Texas. In addition, GSU furnished gas
service in the Baton Rouge, Louisiana area, and NOPSI furnished gas
service in the New Orleans, Louisiana area. GSU produces and sells,
on an unregulated basis, process steam and by-product electricity
supplied from its steam electric extraction plant to a large
industrial customer. The business of the System is subject to
seasonal fluctuations with the peak period occurring during the third
quarter. During 1994, the System's electricity sales as a percentage
of total System energy sales were: residential - 26.9%; commercial -
20.6%; and industrial - 42.1%. Electric revenues from these sectors
as a percentage of total System electric revenues were: 36.3% -
residential; 25.6% - commercial; and 31.3% - industrial. Sales to
governmental and municipal sectors and to nonaffiliated utilities
accounted for the balance of energy sales. The System's major
industrial customers are in the chemical processing, petroleum
refining, paper products, and food products industries.
Entergy Corporation also owns all of the outstanding common stock
of System Energy, Entergy Services, Entergy Operations, Entergy Power,
and Entergy Enterprises. System Energy is a nuclear generating
company that was incorporated under the laws of the State of Arkansas
in 1974. System Energy sells the capacity and energy at wholesale
from its 90% interest in Grand Gulf 1 to its only customers, AP&L,
LP&L, MP&L, and NOPSI (see "Capital Requirements and Future Financing
- Certain System Financial and Support Agreements - Unit Power Sales
Agreement," below). System Energy has approximately a 78.5% ownership
interest and an 11.5% leasehold interest in Grand Gulf 1. Entergy
Services, a Delaware corporation, provides general executive,
advisory, administrative, accounting, legal, engineering, and other
services to the System companies, generally at cost. Entergy
Operations, a Delaware corporation, is a nuclear management company
that operates ANO, River Bend, Waterford 3, and Grand Gulf 1, subject
to the owner oversight of AP&L, GSU, LP&L, and System Energy,
respectively. Entergy Power, a Delaware corporation, is an
independent power producer that owns 809 MW of generating capacity and
markets its capacity and energy in the wholesale market outside
Arkansas and Missouri and in markets not otherwise presently served by
the System. (For further information on regulatory proceedings
related to Entergy Power, see "Rate Matters and Regulation - Rate
Matters - Wholesale Rate Matters - Entergy Power," below). Entergy
Enterprises is a nonutility company incorporated under Delaware law
that investigates and develops energy-related projects and other
businesses whose products and activities are or may be of benefit to
the System's utility business (see "Corporate Development," below).
Entergy Enterprises also markets outside the System technical
expertise, products, and services developed by the System companies
that have commercial value beyond their use in the System's operations
and provides services to certain nonutility companies in the System.
Entergy Corporation has formed subsidiaries to participate in utility
projects located outside the System's retail service territory, both
domestically and in foreign countries (see "Corporate Development,"
below).
AP&L, LP&L, MP&L, and NOPSI own 35%, 33%, 19%, and 13%,
respectively, of all the common stock of System Fuels, a non-profit
subsidiary incorporated in Louisiana that implements and/or maintains
certain programs to procure, deliver, and store fuel supplies for the
System.
GSU has four wholly-owned subsidiaries: Varibus Corporation,
GSG&T, Inc., Southern Gulf Railway Company, and Prudential Oil & Gas,
Inc. Varibus Corporation operates intrastate gas pipelines in
Louisiana, which are used primarily to transport fuel to two of GSU's
generating stations. GSG&T, Inc. owns the Lewis Creek Station, a gas-
fired generating plant, which is leased to and operated by GSU.
Southern Gulf Railway Company owns and will operate several miles of
rail track being constructed in Louisiana for the purpose of
transporting coal for use as a boiler fuel at Nelson Unit 6.
Prudential Oil & Gas, Inc., which was formerly in the business of
exploring, developing, and operating oil and gas properties in Texas
and Louisiana, is presently inactive.
Entergy Corporation-GSU Merger
On December 31, 1993, GSU became a wholly-owned subsidiary of
Entergy Corporation. As consideration to GSU's shareholders, Entergy
Corporation paid $250 million in cash and issued 56,695,724 shares of
its common stock, based upon a valuation of $35.8417 per share, in
exchange for outstanding shares of GSU common stock. See "Rate
Matters and Regulation - Regulation - Other Regulation and
Litigation," for information on requests for rehearing and appeals of
certain regulatory approvals of the Merger.
Unless otherwise noted, consolidated financial and statistical
information contained in this report for the years ended December 31,
1994 and 1993 (such as assets, liabilities, and property) includes the
associated GSU amounts. Consolidated financial and statistical
information (such as revenues, sales, and expenses) for the year ended
December 31, 1994 includes such GSU amounts, while periods ending
before January 1, 1994 do not include GSU amounts; those amounts are
presented separately for GSU herein.
Certain Industry and System Challenges
The System's business is affected by various challenges and
issues including those that confront the electric utility industry in
general. These issues and challenges include:
- an increasingly competitive environment (see
"Competition," below);
- adaptation to structural changes in the electric
utility industry and changes in the regulation of generation
and transmission of electricity (see "Competition - General"
below);
- continued cost management (particularly in the area of
operation and maintenance costs at nuclear units) to improve
financial results and to minimize or eliminate the need for
rate increase requests and, to the extent possible,
accommodate rate reductions while maintaining profitability
(see "Rate Matters and Regulation - Rate Matters - Retail
Rate Matters," below);
- achieving cost savings anticipated with the Merger;
- compliance with regulatory requirements with respect to
nuclear operations (see "Rate Matters and Regulation -
Regulation - Regulation of the Nuclear Power Industry,"
below) and environmental matters (see "Rate Matters and
Regulation - Regulation - Environmental Regulation," below);
- achieving enhanced earnings despite lower authorized
returns and slow growth in the domestic utility business (see
"Corporate Development," below);
- resolving GSU's major contingencies, including
potential write-offs and refunds related to River Bend (see
"Rate Matters and Regulation - Rate Matters - Retail Rate
Matters - GSU," below), litigation with Cajun relating to its
ownership interest in River Bend, and Cajun's bankruptcy
proceedings (see "Rate Matters and Regulation - Regulation -
Other Regulation and Litigation - GSU," below); and
- the implementation of a proposed accounting standard
that describes the circumstances in which assets are
determined to be impaired, which may eventually be applied to
stranded investments as discussed below. (see Entergy
Corporation and Subsidiaries' "Management's Financial
Discussion and Analysis - Significant Factors and Known
Trends").
Corporate Development
Entergy Corporation continues to consider opportunities to expand
its utility and utility related businesses that are not regulated by
state and local regulatory authorities (nonregulated businesses).
Entergy Corporation's investment strategy is to invest in nonregulated
business opportunities that have the potential to earn a greater rate
of return than its regulated utility operations, and Entergy
Corporation may invest up to approximately $150 million per year for
the next several years in nonregulated businesses. Entergy
Corporation's nonregulated businesses currently fall into two broad
categories: power development and new technology related to the
utility business. Entergy Corporation made investments in Argentina's
and Pakistan's electric energy infrastructure, as described below, and
is pursuing additional projects in North America, Central America,
South America, Europe, and Asia. Entergy Corporation opened an office
in Hong Kong in 1994 and expects to open offices in South America and
Europe in 1995. Entergy Corporation is negotiating in China to
participate in two power generation projects, Datong and Taishan,
which are expected to receive final approval in 1995 or 1996. The
Datong and Taishan projects involve the expansion of an existing coal-
fired plant and construction of additional coal-fired plants. To
date, Entergy Corporation has made no investment in these projects;
however, Entergy Corporation's share of these projects may total
approximately $115 million. In addition, Entergy Corporation is
exploring the possibility to provide telecommunications services that
allow customers to control energy usage.
Current investments in nonregulated businesses include the
following:
(1) In 1990, Entergy Power purchased from AP&L 100% of
Ritchie 2 and 31 1/2% of Independence 2. Entergy Power is
currently selling capacity and energy from both plants. Entergy
Corporation originally financed Entergy Power principally with a
note between itself and Entergy Power. This note is scheduled to
expire on June 30, 1995. As of December 31, 1994, this note
amounted to $221.5 million. In 1994, Entergy Power requested,
but has not yet received, authorization from the SEC to convert
amounts outstanding under the note plus accrued interest to a
capital contribution.
(2) Entergy Corporation's subsidiary, Entergy Power
Development Corporation an EWG under the provisions of the EPAct,
through its subsidiary, Entergy Richmond Power Corporation (which
is also an EWG), owns a 50% interest in an independent power
plant in Richmond, Virginia. The power plant is jointly-owned
and operated by the Enron Power Corporation (Enron), a developer
of independent power projects. The plant has a 25-year contract
to sell electricity to Virginia Electric & Power Company (VEPCO).
Entergy Corporation's investment in the project totals
approximately $13.5 million. Entergy Corporation has been
notified by Enron that, prior to 1994, the facility did not met
the FERC efficiency test to maintain qualifying facility status
as required by the contract with VEPCO. Enron has indicated that
the facility has met the test in 1994. The failure to meet the
test prior to 1994 could result in a default under the VEPCO
contract. However, Entergy Richmond Power Corporation, Enron,
and VEPCO are currently involved in negotiations to amend the
contract to resolve this issue.
(3) Entergy Enterprises has a 7.9% equity interest in First
Pacific Networks, Inc. (FPN), a communications company, and has a
license from FPN in connection with utility applications being
jointly developed by Entergy Enterprises and FPN, for FPN's
patented communications technology. Entergy Enterprises'
investment in FPN is approximately $11.8 million, of which $9.5
million is equity investment.
(4) Entergy Enterprises' subsidiary, Entergy Systems and
Service, Inc. (Entergy SASI), holds a 9.95% equity interest in
Systems and Service International, Inc. (SASI), a manufacturer of
efficient lighting products. Entergy SASI distributes such
products in conjunction with providing various energy management
services to its customers. Entergy SASI also made a loan to
SASI, acquired the business and assets of SASI's distribution
subsidiary, and entered into an agreement to distribute SASI's
products. Entergy Enterprises' investment in Entergy SASI is
approximately $13.5 million of which $2.3 million is invested in
SASI common stock. Entergy Corporation has provided to Entergy
SASI $72.3 million in loans, as of December 31, 1994, to fund
Entergy SASI's installment sale agreements with its customers.
(5) Entergy Corporation's subsidiary, Entergy, S.A.,
participated in a consortium with other nonaffiliated companies
that acquired a 60% interest in Argentina's Costanera steam
electric generating facility consisting of seven natural gas- and
oil-fired generating units, with a total installed capacity of
1,260 MW. Entergy Corporation's initial investment to acquire
its 10% interest in the consortium was approximately
$10.5 million and its maximum financial obligation currently
authorized by the SEC in connection with this investment is
$22.5 million.
(6) Entergy Corporation, through two subsidiaries, Entergy
Argentina, S.A., and Entergy Argentina, S.A. Ltd., participated
in a consortium with other nonaffiliated companies that acquired
a 51% interest in a foreign electric distribution company
providing service to Buenos Aires, Argentina. Entergy
Corporation's initial investment to acquire its 10% interest in
the consortium was approximately $58.2 million and its maximum
financial obligation currently authorized by the SEC in
connection with this investment is $77.5 million.
(7) Entergy Corporation, through its subsidiary, Entergy
Transener, S.A., participated in a consortium with other
nonaffiliated companies that acquired a 65% interest in a foreign
transmission system providing service in Argentina. Entergy
Corporation's initial investment in the project totals
approximately $20.5 million. Depending upon the
consortium's ability to continue its financing of a portion of
its investment in the transmission system, Entergy Corporation
could be required in 1995 to increase its investment by
approximately $9 million.
(8) In 1994, Entergy Corporation, through a new subsidiary,
Entergy Pakistan, Ltd., acquired a 10% interest in the Hub River
steam electric generating facility under development in Pakistan.
Entergy Corporation's initial investment to acquire its 10%
interest in the consortium was $50.2 million.
In 1994, Entergy Corporation's nonregulated investments reduced
consolidated net income by approximately $31.7 million. In the near
term, these investments are unlikely to have a positive effect on
Entergy Corporation's earnings; but management believes that these
investments will contribute to future earnings growth. These
investments may involve a higher degree of risk than domestic
regulated utility enterprises.
International operations are subject to the risks inherent in
conducting business abroad, including possible nationalization or
expropriation, price and exchange controls, limitations on foreign
participation in local governmental enterprises, and other restrictive
actions. Changes in the relative value of currencies take place from
time to time and their effects may be favorable or unfavorable on
results of operations. In addition, there are exchange control
restrictions in certain countries relating to repatriation of
earnings.
Selected Data
Selected customer and sales data for 1994 are summarized in the
following tables:
1994 - Selected Customer Data
Customers as of
December 31, 1994
Area Served Electric Gas
AP&L Portions of Arkansas 599,702 -
GSU Portions of Texas and Louisiana 595,348 86,416
LP&L Portions of Louisiana 607,002 -
MP&L Portions of Mississippi 367,692 -
NOPSI City of New Orleans, except Algiers, which
is provided electric service by LP&L 189,836 153,259
--------- -------
System 2,359,580 239,675
========= =======
1994 - Selected Electric Energy Sales Data
System Entergy
AP&L GSU LP&L MP&L NOPSI Energy System
(Millions of KWH)
Electric Department:
Sales to retail
customers 15,841 28,763 29,064 10,480 5,396 - 89,544
Sales for resale:
- Affiliates 10,428 2,676 10 1,079 92 8,653 -
- Others 5,069 840 776 512 202 - 7,908
------------------------------------------------------
Total 31,338 32,279 29,850 12,071 5,690 8,653 97,452
Steam Department:
- Sales to steam
products customer - 1,659 - - - - 1,659
------------------------------------------------------
TOTAL 31,338 33,938 29,850 12,071 5,690 8,653 99,111
======================================================
Average use per
residential
customer (KWH) 10,743 14,220 13,945 12,777 11,076 - 12,793
======================================================
NOPSI sold 16,982,648 MCF of natural gas to retail customers in
1994. Revenues from natural gas operations for each of the three
years in the period ended December 31, 1994 were material for NOPSI,
but not material for the System (see "Industry Segments" below for a
description of NOPSI's business segments).
GSU sold 6,967,018 MCF of natural gas to retail customers in
1994. Revenues from natural gas operations for each of the three
years in the period ended December 31, 1994 were not material for GSU.
See "Entergy Corporation and Subsidiaries Selected Financial Data
- Five-Year Comparison," and "Selected Financial Data - Five-Year
Comparison of AP&L, GSU, LP&L, MP&L, NOPSI and System Energy," (which
follow each company's notes to financial statements herein) for
further information with respect to operating statistics.
Employees
As of December 31, 1994, Entergy had 16,037 employees as
follows:
Full-time:
Entergy Corporation -
AP&L 2,423
GSU 2,656
LP&L 1,539
MP&L 1,186
NOPSI 660
System Energy -
Entergy Operations 4,313
Entergy Services 2,631
Other Subsidiaries 494
------
Total Full-time 15,902
Part-time 135
------
Total Entergy System 16,037
======
Competition
General. Entergy and the electric utility industry are
experiencing increased competitive pressures in both the retail and
wholesale markets. The economic, social, and political forces behind
these competitive pressures are numerous and complex. These pressures
include legislative and regulatory changes, technological advances,
consumer demands, greater availability of natural gas, environmental
needs, and other factors. These competitive pressures present
opportunities to compete for new customers, as well as risks for loss
of customers.
On October 24, 1992, Congress passed the EPAct. The EPAct
addresses a wide range of energy issues and alters the way Entergy and
the rest of the electric utility industry will operate in the future.
The EPAct creates exemptions from regulation under the Holding Company
Act and creates a class of EWG's consisting of utility affiliates and
nonutilities that own and operate facilities for the generation and
transmission of power for sales at wholesale. The EPAct also gives
FERC the authority to order investor-owned utilities, including the
System operating companies, to transmit power and energy to or for
wholesale purchasers and sellers. This creates the potential for
electric utilities and other power producers to gain increased access
to the transmission systems of other entities to facilitate wholesale
sales. FERC may also require electric utilities to increase their
transmission capacity to provide these services. The System operating
companies jointly filed open access transmission service tariffs with
FERC, and subsequent modifications to such tariffs were filed in
October 1994 in order to bring the companies into compliance with
FERC's evolving "comparability" standard for transmission. For
further information, see "Rate Matters and Regulation - Rate Matters -
Wholesale Rate Matters," below.
Retail wheeling, the transmission by an electric utility of
energy produced by another entity over the utility's transmission and
distribution system to a retail customer in the electric utility's
area of service, is also evolving. Over a dozen states have been or
are studying the concept of retail competition. In April 1994, the
state of Michigan initiated a five-year experiment that allows limited
competition among public utilities. During the same month, the
California Public Utilities Commission proposed to deregulate that
state's electric power industry, starting on January 1, 1996, to allow
the largest industrial customers to select the lowest cost supplier
for electricity service. Under the proposal, by the year 2002,
smaller companies and residential customers in California would also
be able to buy power from any suppliers. The California Public
Utilities Commission is currently reviewing its proposal and is
expected to make a ruling in the first half of 1995. The retail market
for electricity is expected to become more competitive with such moves
toward deregulation.
In some areas of the country, municipalities (or comparable
entities) whose residents are served at retail by an investor-owned
utility pursuant to a franchise are exploring the possibility of
establishing new or extending existing distribution systems or seeking
new delivery points in order to serve retail customers, especially
large industrial customers, that currently receive service from an
investor-owned utility. These options depend on the terms of a
utility's franchise as well as on state law and regulation. In
addition, FERC's authority to order utilities to transmit for a new or
expanding municipal system is limited in certain respects. Where
successful, however, the establishment of a municipal system or the
acquisition by a municipal system of a utility's customers could
result in the inability to recover costs that the utility has incurred
in serving those customers.
In mid-1994, FERC issued a notice of proposed rulemaking
concerning a regulatory framework for dealing with recovery of
stranded costs, such as high cost nuclear generating units, which may
be incurred by electric utilities as a result of increased
competition. In addition to addressing recovery of stranded costs
related to wholesale service, the proposal requested comment as to
recovery of retail stranded costs in transmission rates where state
regulatory authorities failed to address the issue or were in
conflict. Comments and reply comments have been filed, and the matter
is pending. The risk of exposure to stranded costs which may result
from competition in the industry will depend on the extent and timing
of retail competition, the resolution of jurisdictional issues
concerning stranded cost recovery, and the extent to which such costs
are recovered from departing or remaining customers, among other
matters.
Wholesale Competition. Entergy, like other utility systems, has
generating capacity and energy available from time to time for sale to
other utility systems. Entergy Power owns 809 MW of generating
capacity, and the first priority of use for this capacity is for
wholesale sales. The System operating companies may use energy from
Entergy Power's capacity for native load needs if no wholesale
transactions have been scheduled. The System is in competition with
other utilities to sell capacity and energy. Given this competition,
the ability of the System to sell capacity and energy to other
utilities is limited. However, in 1994, the System sold 7,908 million
KWH of energy (compared to 8,291 million KWH in 1993) to nonaffiliated
utilities. The System also sold 1,213 MW of long-term capacity
(compared to 1,234 MW in 1993) to nonaffiliated utilities outside of
the area served by the System. These capacity sales represent 6% of
the System's net capability at year-end 1994. Under AP&L's and LP&L's
Grand Gulf 1 rate orders, and under GSU's River Bend rate order in
Louisiana, a portion of the capacity of Grand Gulf 1 and River Bend
represents capacity that is available for sale, subject to regulatory
approval, to nonaffiliated parties. In some cases, profits from such
sales must be shared between ratepayers and shareholders.
As discussed in "Rate Matters and Regulation - Rate Matters -
Wholesale Rate Matters - Open Access Transmission," below, Entergy
Power and the System operating companies have been permitted by FERC
to make wholesale capacity sales in bulk power markets at rates based
primarily upon negotiation and market conditions rather than cost of
service. In order to receive authorization to make such sales, AP&L,
LP&L, MP&L, and NOPSI also filed with FERC open access transmission
service tariffs. FERC approved this filing, subject to certain
modifications. Revisions to the tariffs were filed in December 1993
to recognize GSU's inclusion in the Entergy System. On July 12, 1994,
the D.C. Circuit issued an opinion finding that FERC's failure to
conduct an evidentiary hearing with respect to the proposed
transmission tariffs and related matters was arbitrary and capricious,
and that FERC failed to adequately explain its approval of certain
provisions in the tariffs, including a provision allowing Entergy to
seek recovery in transmission rates of "stranded investment" costs
resulting from the provision of transmission service. The case was
remanded to FERC for further proceedings. On October 31, 1994,
Entergy Services filed revised transmission tariffs with FERC in
response to the D.C. Circuit's remand. These tariffs provide both
point-to-point and network transmission services and are intended to
provide "comparability of service" over the Entergy transmission
network. On January 6, 1995, FERC issued an order accepting the
tariffs for filing and making them effective, subject to refund. On
January 25, 1995, Entergy Services filed revised transmission tariffs
in response to FERC's order. In addition, FERC set Entergy's market
pricing authority for investigation, thereby making Entergy's market
price rate schedules subject to refund. The market price rate
investigation has been deferred by FERC until conclusion of the
transmission tariff case, and an order is expected to be issued no
later than January 15, 1997. It is anticipated that these tariffs
will enable any electric utility (as defined in such tariffs) to use
Entergy `s integrated transmission system for the transmission of
capacity and energy produced and sold by such electric utility or by
third parties. Other similar open access transmission tariffs have
also been filed with FERC by several large utility companies or
systems and more open access transmission tariffs are anticipated.
Concurrently, capacity resources are being developed and used to make
wholesale sales from a range of non-traditional sources, including
nonutility generators as well as cogenerators and small power
producers qualifying under PURPA.
These developments simultaneously produce increased marketing
opportunities for utility systems such as Entergy and expose the
System to loss of load or reduced sales revenues due to displacement
of System sales by alternative suppliers with access to the System's
primary areas of service. Entergy Power was formed to compete with
other utilities and independent power producers in the bulk power
market. As of December 31, 1994, Entergy Power has accumulated total
losses from operations of $67.1 million. Entergy Power has entered
into several long-term contracts for the sale of capacity and
associated energy from its resources and has also made short-term
capacity and energy sales. In 1994, Entergy Power sold 460 million
KWH of energy to nonaffiliated utilities, and sold 332 MW of capacity,
at the time of the Entergy system peak, to nonaffiliated utilities.
Entergy Power actively markets its capacity and energy in the bulk
power market. The System operating companies and Entergy Power have
separate marketing staffs and may on occasion compete for the same
bulk power sale opportunities. (See "Corporate Development," above,
for information with respect to a wholly-owned subsidiary of Entergy,
Entergy Power Development Corporation, organized as an EWG to compete
in the wholesale power market.)
Retail Competition. Many of Entergy's industrial customers,
whose costs of production are energy-sensitive, have energy
alternatives such as fuel switching, cogeneration, and production
shifting. Entergy is constantly working with these customers to
address their needs. It is the practice of the System operating
companies to negotiate the renewal of contracts with large industrial
customers prior to their expiration. In certain cases (particularly
for GSU), contracts or special tariffs that use flexible pricing have
been negotiated with industrial customers to keep these customers on
the System. These contracts and tariffs have generally resulted in
increased KWH sales at lower margins over incremental cost. While the
System operating companies anticipate they will be successful in
renegotiating such contracts, there can be no assurance that they will
be successful or that future revenues will not be lost to other forms
of generation. Since PURPA was enacted in 1978, the System operating
companies have been largely successful in retaining industrial load.
This competitive challenge will likely increase.
Cogeneration is generally defined as the combined production of
electricity and some other useful form of heat, typically steam.
Cogenerated power may be either sold by its producer to the local
utility at its avoided cost under PURPA, and/or utilized by the
cogenerator to displace purchases from the utility. To the extent
that cogeneration is used by industrial customers to meet their own
power requirements, the System may suffer loss of industrial load.
Cogenerated power delivered to the System would be purchased at
avoided cost, which for a number of years is expected to be equivalent
to avoided energy cost, and, as such, the cost of these purchases
would not impact earnings. To date, only a few cogeneration
facilities have been installed in areas served by the System,
excluding the GSU area of service. Since PURPA was enacted in 1978,
the primary purpose of these facilities is to displace power that was
purchased from the System. The economic advantage to the customer is
generally due to the customer having waste products that can be used
as fuel and/or customers that have an attractive electrical thermal
ratio. Presently, the loss of load to cogeneration and the amount of
cogenerated power delivered under PURPA to the System are not
significant, except in GSU's area of service. The System is prepared
to participate (subject to regulatory approval) in various phases of
the design, construction, procurement, and ownership of cogeneration
facilities. The System has entered into several cogeneration deferral
agreements with certain of its retail customers, which give the System
the right of first refusal to participate in any of such customers'
cogeneration activities. Such participation could occur in the event
there are individual customers whose long-term interests, along with
Entergy's, can best be served by installing cogeneration facilities.
No such participation has occurred to date, except by GSU.
Existing qualifying facilities in GSU's area of service are
estimated to total approximately 2,400 MWs or over 10% of Entergy's
total owned and leased generating capability as of December 31, 1994.
GSU believes that no significant load will be lost to cogeneration
projects during the next several years; however, GSU is currently
negotiating with a large industrial customer whose contract is
scheduled to expire in 1997. If the contract is not renewed, GSU
would lose approximately $40 million in annual base revenues.
Although GSU has competed in the past for various retail and
wholesale customers, the System is not otherwise generally in direct
competition with privately-owned or municipally-owned electric
utilities for retail sales. A few municipalities within the area of
service of the System operating companies distribute electricity
within their corporate limits and some of these municipalities
generate all or a portion of their requirements. A number of electric
cooperative associations or corporations serve a substantial number of
retail customers in or adjacent to areas served by the System
operating companies. Sales of energy by the System to privately- or
municipally-owned utilities amounted to approximately 3.3% of total
System energy sales in 1994. As noted above, municipalities in other
areas of the country are seeking to expand their customers bases, to
find alternate sources of electricity, and/or to set up new
distribution systems.
Legislatures and regulatory commissions in several states have
considered, or are considering, retail wheeling. Retail wheeling
would permit retail customers to purchase electric capacity and/or
energy from the electric utility in whose area of service they are
located or from other electric utilities or independent power
producers. Retail wheeling is not currently required within the
Entergy System's area of service. See "Rate Matters and Regulation -
Regulation - Other Regulation and Litigation," below for information
on proceedings brought by Cajun seeking transmission access to certain
of GSU's industrial customers.
Least Cost Planning. The System continues to pursue least cost
planning, also known as integrated resource planning, in order to
compete more effectively in both retail and wholesale markets. Least
cost planning is the development of strategies to add resources to
meet future electricity demands reliably and at the lowest possible
cost. The least cost planning process includes the study of electric
supply- and demand-side options. The resulting plan uses demand-side
options, such as changing customer consumption patterns, to limit
electricity usage during times of peak demand, thus delaying the need
for new capacity resources. Least cost planning offers the potential
for the System to minimize customer costs, while providing an
opportunity to earn a return.
On December 1, 1992, AP&L, LP&L, MP&L, and NOPSI each filed a
Least Cost Plan with its respective regulator, and on July 1, 1993,
each company filed a refined action plan with its respective
regulator. Each Least Cost Plan detailed the resources that the
System intended to use to provide reasonably priced, reliable electric
service to its customers over the next 20 years. Such plans included
925 MW of DSM resources, such as programs for efficient air
conditioning and heating, high efficiency lighting, and CCLM. The
plans also included significant resource additions, but did not
contemplate construction of any new generating facilities. All
incremental supply-side resources would come from either delayed
retirements or repowering of existing generating units. Each Least
Cost Plan included specific actions that the System would undertake
pursuant to regulatory approval, including the recovery of costs
associated with DSM.
In 1994, the System substantially revised the approach to least
cost planning that was used to prepare the above December 1, 1992 and
July 1, 1993 filings made with the APSC, LPSC, MPSC, and the Council.
At MP&L's request, the MPSC dismissed MP&L's Least Cost Plan filing
without prejudice. AP&L and LP&L have requested that their respective
retail regulators allow the withdrawal of their Least Cost Plans.
Furthermore, AP&L, LP&L, MP&L, and NOPSI have requested that their
retail regulators allow for significant changes in the integrated
planning process and filings.
The System remains committed to employing integrated resource
planning tools. However, the increasingly competitive nature of the
market place for electric services mandates changes in the planning
process. First, the System has indicated that it intends to use the
Ratepayer Impact Measure (RIM) as the screening criterion for all DSM
programs, including those DSM measures targeted at strategic load
growth. This criterion was adopted because programs selected under
this screen will minimize the rate impacts of any programs on all
customers. Second, the System has indicated that it will not seek
special rate treatment, such as rate riders, for the costs of programs
or to compensate for lost revenues as a result of DSM for programs
selected using the RIM criterion. Finally, the System has indicated
that it will file with the retail regulators, for informational
purposes only, a revised integrated resource plan in the fourth
quarter of 1995 (for further information, see "Rate Matters and
Regulation - Rate Matters - Retail Rate Matters," below).
CAPITAL REQUIREMENTS AND FUTURE FINANCING
Construction expenditures by company (including environmental
expenditures, which are immaterial, and AFUDC, but excluding nuclear
fuel) for the period 1995-1997 are estimated as follows:
1995 1996 1997 Total
(In Millions)
AP&L $155 $155 $155 $ 465
GSU 177 177 177 531
LP&L 115 115 115 345
MP&L 68 68 68 204
NOPSI 29 29 29 87
System Energy 22 22 19 63
Entergy Power 2 2 2 6
---- ---- ---- ------
System $568 $568 $565 $1,701
==== ==== ==== ======
No significant construction costs are expected in connection with
the System's generating facilities. Actual construction costs may
vary from these estimates because of a number of factors, including
changes in load growth estimates, changes in environmental
regulations, modifications to nuclear units to meet regulatory
requirements, increasing costs of labor, equipment and materials, and
cost of capital.
In addition to construction expenditure requirements, the
estimated amounts required during 1995-1997 to meet scheduled long-
term debt and preferred stock maturities and cash sinking fund
requirements are: AP&L - $107 million; GSU - $375 million; LP&L - $160
million; MP&L - $253 million; NOPSI - $93 million; and System Energy -
$365 million. A substantial portion of these capital and refinancing
requirements is expected to be satisfied from internally generated
funds and cash on hand, supplemented by the issuance of debt and
preferred stock. Certain System companies may also continue with the
acquisition or refinancing of all, or a portion of, certain
outstanding series of preferred stock and long-term debt in order to
achieve cost savings.
Entergy Corporation's current primary capital requirements are to
invest periodically in, or make loans to, its subsidiaries. Entergy
Corporation has SEC authorization to make additional investments in
Entergy Power, Entergy S.A., and Entergy Argentina, S.A., and has
applied for authorization to make additional investments in Entergy
SASI and Entergy Enterprises. Entergy Corporation expects to meet
these capital requirements in 1995-1997 with internally generated
funds and cash on hand. Entergy receives funds through dividend
distributions from its subsidiaries. Certain restrictions may limit
the amount of these distributions. See Entergy Corporation and
Subsidiaries' Notes to Consolidated Financial Statements, Note 2,
"Rate and Regulatory Matters" and Note 8, "Commitments and
Contingencies," regarding River Bend rate appeals and pending
litigation with Cajun. Substantial write-offs or charges resulting
from adverse rulings in these matters could adversely affect GSU's
ability to continue to pay dividends.
Entergy Corporation continues to consider new opportunities to
expand its electric energy business, including expansion into related
nonregulated businesses. Entergy Corporation may invest up to
approximately $150 million per year over the next several years in
nonregulated business opportunities. Entergy Corporation expects to
fund these investments using internally generated funds and cash on
hand Also, Entergy Corporation may repurchase, from time to time,
shares of its outstanding common stock. Market conditions and board
authorization determine the amount of repurchases. Entergy
Corporation has requested, but has not yet received, SEC authorization
for a $300 million bank line of credit, the proceeds of which may be
used for common stock repurchases and other investment activities. In
addition, Entergy Corporation's non-regulated businesses may seek
external financing, subject to receipt of any necessary regulatory
approval.
(For further information on the capital and refinancing
requirements, capital resources, and short-term borrowing arrangements
of AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy, respectively,
refer in each case to AP&L's, GSU's, LP&L's, MP&L's, NOPSI's, and
System Energy's "Management's Financial Discussion and Analysis -
Liquidity and Capital Resources," Note 4 of AP&L's, GSU's, LP&L's,
MP&L's, NOPSI's, and System Energy's Notes to Financial Statements,
"Lines of Credit and Related Borrowings," Note 5 of AP&L's and NOPSI's
Notes to Financial Statements, "Preferred Stock," Note 5 of GSU's
Notes to Financial Statements, "Preferred, Preference and Common
Stock," Note 5 of LP&L's and MP&L's Notes to Financial Statements,
"Preferred and Common Stock," Note 6 of AP&L's, GSU's, LP&L's, MP&L's,
and NOPSI's and Note 5 of System Energy's Notes to Financial
Statements, "Long-Term Debt," and Note 8 of AP&L's, GSU's, LP&L's,
MP&L's, and NOPSI's and Note 7 of System Energy's Notes to Financial
Statements, "Commitments and Contingencies - Capital Requirements and
Financing." For further information concerning Entergy Corporation's
capital requirements and resources, refer to Entergy Corporation and
Subsidiaries' "Management's Financial Discussion and Analysis -
Liquidity and Capital Resources," and Note 4 of Entergy Corporation
and Subsidiaries' Notes to Consolidated Financial Statements, "Lines
of Credit and Related Borrowings.")
Certain System Financial and Support Agreements
Unit Power Sales Agreement. The Unit Power Sales Agreement
allocates capacity and energy from System Energy's 90% ownership and
leasehold interests in Grand Gulf 1 (and the costs related thereto) to
AP&L (36%), LP&L (14%), MP&L (33%), and NOPSI (17%), respectively.
AP&L, LP&L, MP&L, and NOPSI pay rates to System Energy for their
respective entitlements of capacity and energy on a full cost-of-
service basis regardless of the quantity of energy delivered, so long
as Grand Gulf 1 remains in commercial operation. Payments under the
Unit Power Sales Agreement are System Energy's only source of
operating revenues. The financial condition of System Energy depends
upon the continued commercial operation of Grand Gulf 1 and upon the
receipt of payments from AP&L, LP&L, MP&L, and NOPSI. (See "Rate
Matters and Regulation - Rate Matters - Wholesale Rate Matters -
System Energy," below for further information with respect to
proceedings relating to the Unit Power Sales Agreement.)
Availability Agreement. The Availability Agreement was entered
into among System Energy and AP&L, LP&L, MP&L, and NOPSI in 1974 in
connection with the financing by System Energy of the Grand Gulf
Station. The agreement provided that System Energy would join in the
agreement among AP&L, LP&L, MP&L, and NOPSI for the sharing of
generating capacity and other capacity and energy resources on or
before the date on which Grand Gulf 1 was placed in commercial
operation. It also provided that System Energy would make available
to AP&L, LP&L, MP&L, and NOPSI all capacity and energy available from
System Energy's share of the Grand Gulf Station. System Energy and
AP&L, LP&L, MP&L, and NOPSI further agreed that if the Availability
Agreement were terminated, or if any of the parties thereto withdrew
from it, then System Energy would enter into a separate agreement with
all such parties or the withdrawing party, as the case may be, with
respect to the purchase of capacity and energy on the same terms as if
the Availability Agreement were still controlling.
AP&L, LP&L, MP&L, and NOPSI also agreed severally to pay System
Energy monthly for the right to receive capacity and energy available
from the Grand Gulf Station in amounts that (when added to any amounts
received by System Energy under the Unit Power Sales Agreement, or
otherwise) would be at least equal to System Energy's total operating
expenses for the Grand Gulf Station (including depreciation at a
specified rate) and interest charges.
As amended to date, the Availability Agreement provides that:
- the obligations of AP&L, LP&L, MP&L, and NOPSI for
payments for Grand Gulf 1 became effective upon commercial
operation of Grand Gulf 1 on July 1, 1985;
- the sale of capacity and energy generated by the Grand
Gulf Station may be governed by a separate power purchase
agreement among System Energy and AP&L, LP&L, MP&L, and NOPSI;
- the September 1989 write-off of System Energy's
investment in Grand Gulf 2, amounting to approximately $900
million, will be amortized for Availability Agreement purposes
over 27 years rather than in the month the write-off was
recognized on System Energy's books; and
- the allocation percentages under the Availability
Agreement are fixed as follows: AP&L - 17.1%; LP&L - 26.9%;
MP&L - 31.3%; and NOPSI - 24.7%.
As noted above, the Unit Power Sales Agreement provides for
different allocation percentages for sales of capacity and energy from
Grand Gulf 1. However, the allocation percentages under the
Availability Agreement remain in effect and would govern payments made
thereunder in the event of a shortfall of funds available to System
Energy from other sources, including payments by AP&L, LP&L, MP&L, and
NOPSI to System Energy under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances
from AP&L, LP&L, MP&L, and NOPSI under the Availability Agreement as
security for its first mortgage bonds and reimbursement obligations to
certain banks providing the letters of credit in connection with the
equity funding of the sale and leaseback transactions described under
"Sale and Leaseback Arrangements - System Energy," below. In these
assignments, AP&L, LP&L, MP&L, and NOPSI further agreed that, in the
event they were prohibited by governmental action from making payments
under the Availability Agreement (if, for example, FERC reduced or
disallowed such payments as constituting excessive rates; see the
second succeeding paragraph), they would then make subordinated
advances to System Energy in the same amounts and at the same times as
the prohibited payments. System Energy would not be allowed to repay
these subordinated advances so long as it remained in default under
the related indebtedness or in other similar circumstances.
Each of the assignment agreements relating to the Availability
Agreement provides that AP&L, LP&L, MP&L, and NOPSI shall make
payments directly to System Energy. However, if there is an event of
default, AP&L, LP&L, MP&L, and NOPSI must make those payments directly
to the holders of indebtedness secured by such assignment agreements.
The payments must be made pro rata according to the amount of the
respective obligations secured.
The obligations of AP&L, LP&L, MP&L, and NOPSI to make payments
under the Availability Agreement are subject to the receipt and
continued effectiveness of all necessary regulatory approvals. Sales
of capacity and energy under the Availability Agreement would require
that the Availability Agreement be submitted to FERC for approval with
respect to the terms of such sale. No filing with FERC has been made
because sales of capacity and energy from the Grand Gulf Station are
being made pursuant to the Unit Power Sales Agreement. Other aspects
of the Availability Agreement, including the obligations of AP&L,
LP&L, MP&L, and NOPSI to make subordinated advances, are subject to
the jurisdiction of the SEC under the Holding Company Act, whose
approval has been obtained. If, for any reason, sales of capacity and
energy are made in the future pursuant to the Availability Agreement,
the jurisdictional portions of the Availability Agreement would be
submitted to FERC for approval. (Refer to the second preceding
paragraph.)
Amounts that have been received by System Energy under the Unit
Power Sales Agreement have exceeded the amounts payable under the
Availability Agreement. Consequently, no payments under the
Availability Agreement by AP&L, LP&L, MP&L, and NOPSI have ever been
required. If AP&L, LP&L, MP&L, or NOPSI became unable in whole or in
part to continue making payments to System Energy under the Unit Power
Sales Agreement, and System Energy were unable to procure funds from
other sources sufficient to cover any potential shortfall between the
amount owing under the Availability Agreement and the amount of
continuing payments under the Unit Power Sales Agreement plus other
funds then available to System Energy, LP&L and NOPSI could become
subject to claims or demands by System Energy or its creditors for
payments or advances under the Availability Agreement (or the
assignments thereof) equal to the difference between their required
Unit Power Sales Agreement payments and their required Availability
Agreement payments. The amount, if any, that these companies would
become liable to pay or advance, over and above amounts they would pay
under the Unit Power Sales Agreement for capacity and energy from
Grand Gulf 1, would depend on a variety of factors, including, but not
limited to, the amount of any such shortfall and System Energy's
access to other funds. It cannot be predicted whether any such claims
or demands, if made and upheld, could be satisfied. In NOPSI's case,
if any such claims or demands were upheld, the holders of certain of
NOPSI's outstanding general and refunding mortgage bonds could require
redemption of their bonds at par. The ability of AP&L, LP&L, MP&L,
and NOPSI to sustain payments under the Availability Agreement and the
assignments thereof in material amounts without substantially
equivalent recovery from their customers would be limited by their
respective available cash resources and financing capabilities at the
time.
The ability of AP&L, LP&L, MP&L, and NOPSI to recover from their
customers payments made under the Availability Agreement, or under the
assignments thereof, would depend upon the outcome of regulatory
proceedings before the state and local regulatory authorities having
jurisdiction. In view of the controversies that arose over the
allocation of capacity and energy from Grand Gulf 1 pursuant to the
Unit Power Sales Agreement, opposition to recovery would be likely and
the outcome of such proceedings, should they occur, is not
predictable.
Reallocation Agreement. On November 18, 1981, the SEC authorized
LP&L, MP&L, and NOPSI to indemnify AP&L against its responsibilities
and obligations with respect to the Grand Gulf Station contained in
the Availability Agreement and the assignments thereof. The revised
percentages of allocated capacity of System Energy's share of Grand
Gulf 1 and Grand Gulf 2 were, respectively: LP&L - 38.57% and 26.23%;
MP&L - 31.63% and 43.97%; and NOPSI - 29.80% and 29.80%. FERC's
decision allocating the capacity and energy of Grand Gulf 1 among
AP&L, LP&L, MP&L, and NOPSI supersedes the Reallocation Agreement
insofar as it relates to Grand Gulf 1. However, responsibility for
any Grand Gulf 2 amortization amounts (see "Availability Agreement,"
above) has been allocated to LP&L - 26.23%, MP&L - 43.97%, and NOPSI -
29.80%, under the terms of the Reallocation Agreement. The
Reallocation Agreement does not affect the obligation of AP&L to
System Energy's lenders under the assignments referred to in the fifth
preceding paragraph, and AP&L would be liable for its share of such
amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual
obligations. No payments of any amortization amounts will be required
as long as amounts paid to System Energy under the Unit Power Sales
Agreement, together with other funds available to System Energy,
exceed amounts required under the Availability Agreement. This is
expected to be the case for the foreseeable future.
Capital Funds Agreement. System Energy and Entergy Corporation
have entered into the Capital Funds Agreement whereby Entergy
Corporation has agreed to supply to System Energy sufficient capital
to (1) maintain System Energy's equity capital at an amount equal to a
minimum of 35% of its total capitalization (excluding short-term
debt), and (2) permit the continuation of commercial operation of
Grand Gulf 1 and to pay in full all indebtedness for borrowed money of
System Energy when due under any circumstances.
Entergy Corporation has entered into various supplements to the
Capital Funds Agreement, and System Energy has assigned its rights
thereunder as security for its first mortgage bonds and reimbursement
obligations to certain banks providing letters of credit in connection
with the equity funding of the sale and leaseback transactions
described below under "Sale and Leaseback Arrangements - System
Energy" . Each such supplement provides that permitted indebtedness
for borrowed money incurred by System Energy in connection with the
financing of the Grand Gulf Station may be secured by System Energy's
rights under the Capital Funds Agreement on a pro rata basis (except
for the Specific Payments, as hereinafter defined). In addition, in
the particular supplements to the Capital Funds Agreement relating to
the specific indebtedness being secured, Entergy Corporation has
agreed to make cash capital contributions to System Energy sufficient
to enable System Energy to make payments when due on such indebtedness
(Specific Payments).
Except with respect to the Specific Payments, which have been
approved by the SEC under the Holding Company Act, the performance by
both Entergy Corporation and System Energy of their obligations under
the Capital Funds Agreement, as supplemented, is subject to the
receipt and continued effectiveness of all governmental authorizations
necessary to permit such performance, including approval by the SEC
under the Holding Company Act. Each of the supplemental agreements
provides that Entergy Corporation shall make its payments directly to
System Energy. However, if there is an event of default, Entergy
Corporation must make those payments directly to the holders of
indebtedness secured by the supplemental agreements. The payments
(other than the Specific Payments) must be made pro rata according to
the amount of the respective obligations secured by the supplemental
agreements.
Sale and Leaseback Arrangements
LP&L. On September 28, 1989, LP&L entered into arrangements for
the sale and leaseback of an approximate aggregate 9.3% ownership
interest in Waterford 3. LP&L has options to terminate the leases and
to repurchase the interests in Waterford 3 at certain intervals during
the basic terms of the leases. Further, at the end of the terms of
the leases, LP&L has options to renew the leases or to repurchase the
interests in Waterford 3. LP&L did not exercise its option to
repurchase the undivided interests in Waterford 3 on the fifth
anniversary (September 1994) of the closing date of the sale and
leaseback transactions. As a result, LP&L was required to provide
collateral to the owner participants for the equity portion of certain
amounts payable by LP&L under the lease. Such collateral was in the
form of a new series of first mortgage bonds in the aggregate
principal amount of $208.2 million issued by LP&L in September 1994
under its first mortgage bond indenture. (For further information on
LP&L's sale and leaseback arrangements, including the required
maintenance by LP&L of specified capitalization and fixed charge
coverage ratios, see Note 9 of LP&L's Notes to Financial Statements,
"Leases - Waterford 3 Lease Obligations." )
System Energy. On December 28, 1988, System Energy entered into
arrangements for the sale and leaseback of an approximate aggregate
11.5% ownership interest in Grand Gulf 1. System Energy has options
to terminate the leases and to repurchase the undivided interest in
Grand Gulf 1 at certain intervals during the basic lease term.
Further, System Energy has an option at the end of the basic lease
term to renew the leases or to repurchase the undivided interest in
Grand Gulf 1. In connection with the equity funding of the sale and
leaseback arrangements, letters of credit are required to be
maintained by System Energy under the leases to secure certain amounts
payable for the benefit of the equity investors. The letters of
credit currently maintained are effective until January 15, 1997.
Under the provisions of a reimbursement agreement, dated December 1,
1988, as amended, entered into by System Energy and various banks in
connection with the sale and leaseback arrangements related to the
letters of credit (Reimbursement Agreement), System Energy has agreed
to a number of covenants relating to, among other things, the
maintenance of certain capitalization and fixed charge ratios. In
connection with an audit of System Energy by FERC, in June 1994,
System Energy, AP&L, LP&L, MP&L, and NOPSI reached a settlement with
the FERC staff and other parties. On November 30, 1994, FERC approved
the settlement. In accordance with the settlement, System Energy
refunded approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI,
which in turn have made or will make refunds or credits to their
customers (except for those portions attributable to AP&L's and LP&L's
retained share of Grand Gulf 1 costs). Additionally, System Energy
will refund a total of approximately $62 million, plus interest, to
AP&L, LP&L, MP&L, and NOPSI over the period through June 2004. AP&L,
LP&L MP&L, and NOPSI also wrote-off certain related unamortized
balances of deferred tax credits. As a result of the charges
associated with the settlement, System Energy obtained the consent of
certain banks (parties to the Reimbursement Agreement) to waive the
fixed charge coverage covenant in the letters of credit and the
Reimbursement Agreement related to the Grand Gulf 1 sale and leaseback
transaction, until November 30, 1995. System Energy expects that upon
expiration of the waiver period, it will be in compliance with the
fixed charge coverage covenant. Absent a waiver, failure by System
Energy to perform this covenant could give rise to a draw under the
letters of credit and/or an early termination of the letters of
credit, and, if such letters of credit were not replaced in a timely
manner, could result in a default under, or other early termination
of, System Energy's leases. (For further information on the effects
of the settlement on System Energy's financial condition, see Note 2
of System Energy's Notes to Financial Statements, "Rate and Regulatory
Matters - FERC Audit," and for a further discussion of the provisions
of System Energy's Reimbursement Agreement, see System Energy's Notes
to Financial Statements, Note 6, "Dividend Restrictions" and Note 7,
"Commitments and Contingencies - Reimbursement Agreement." )
RATE MATTERS AND REGULATION
RATE MATTERS
The System operating companies' retail rates are regulated by
their respective state and/or local regulatory authorities, as
described below, and their rates for wholesale sales (including
intrasystem sales pursuant to the System Agreement) and interstate
transmission of electricity are regulated by FERC. Rates for System
Energy's sales of capacity and energy from Grand Gulf 1 to AP&L, LP&L,
MP&L, and NOPSI pursuant to the Unit Power Sales Agreement are also
regulated by FERC.
Wholesale Rate Matters
GSU. For information, see "Retail Rate Matters - GSU," below and
"Regulation - Other Regulation and Litigation - GSU," below.
System Energy. As described above under "Certain System
Financial and Support Agreements," System Energy recovers costs
related to its interest in Grand Gulf 1 through rates charged to AP&L,
LP&L, MP&L, and NOPSI for Grand Gulf 1 capacity and energy under the
Unit Power Sales Agreement.
In November 1994, FERC approved an agreement settling a long-
standing dispute involving income tax allocation procedures of System
Energy. In accordance with the agreement, System Energy refunded
approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI, which in
turn have made or will make refunds or credits to their customers
(except for those portions attributable to AP&L's and LP&L's retained
share of Grand Gulf 1 costs). Additionally, System Energy will refund
a total of approximately $62 million, plus interest, to AP&L, LP&L,
MP&L, and NOPSI over the period through June 2004. The settlement
also required the write-off of certain related unamortized balances of
deferred investment tax credits by AP&L, LP&L, MP&L, and NOPSI. The
settlement reduced Entergy Corporation's consolidated net income for
the year ended December 31, 1994, by approximately $68.2 million,
offset by the write-off of the unamortized balances of related
deferred investment tax credits of approximately $69.4 million ($2.9
million for Entergy Corporation; $27.3 million for AP&L; $31.5 million
for LP&L; $6 million for MP&L; and $1.7 million for NOPSI). System
Energy also reclassified from utility plant to other deferred debits
approximately $81 million of other Grand Gulf 1 costs. Although
excluded from rate base, System Energy will be permitted to recover
such costs over a 10-year period. Interest on the $62 million refund
and the loss of the return on the $81 million of other Grand Gulf 1
costs will reduce Entergy's and System Energy's net income by
approximately $10 million annually over the next 10 years. For further
information, see Note 2 of System Energy's Notes to Financial
Statements and Note 2 of Entergy Corporation and Subsidiaries' Notes
to Consolidated Financial Statements, "Rate and Regulatory Matters -
FERC Settlement."
Entergy Power. In 1990, authorizations were obtained from the
SEC, FERC, the APSC, and the Public Service Commission of Missouri for
Entergy Power to purchase AP&L's interests in Independence 2 and
Ritchie 2, and to begin marketing the capacity and energy from the
units in certain wholesale markets. The SEC order approving various
aspects of the transaction was appealed by various intervenors in the
proceeding to the D.C. Circuit, which reversed a portion of the order
and remanded the case to the SEC for consideration of the effect of
the transfers on the System's future costs of replacement generating
capacity and fuel. In response to a June 24, 1993 SEC order setting a
procedural schedule for the filing of further pleadings in the
proceeding, in July 1993, the Entergy parties filed a post-effective
amendment to their application addressing the issues specified in the
SEC order. On September 9, 1993, the City of New Orleans and the LPSC
each requested a hearing. However, on January 5, 1994, the City of
New Orleans withdrew from the proceeding, as agreed in its settlement
with NOPSI of various issues related to the Merger. The matter is
pending before the SEC on remand.
System Agreement. AP&L, LP&L, MP&L, and NOPSI engage in the
coordinated planning, construction, and operation of generation and
transmission facilities pursuant to the terms of the System Agreement
(described under "Property - Generating Stations," below). GSU became
a party to the System Agreement upon consummation of the Merger, and
GSU now participates in this System-wide coordination.
In connection with the Merger, FERC approved certain rate
schedule changes to integrate GSU into the System Agreement. Certain
commitments were adopted to provide reasonable assurance that the
ratepayers of AP&L, LP&L, MP&L, and NOPSI will not be allocated higher
costs, including, among other things: (1) a tracking mechanism to
protect operating companies from certain unexpected increases in fuel
costs; (2) excluding GSU from the distribution of profits from power
sales contracts entered into prior to the Merger; (3) a methodology to
estimate the cost of capital in future FERC proceedings; and (4) a
stipulation that the operating companies will be insulated from
certain direct effects on capacity equalization payments should GSU
acquire Cajun's 30% share in River Bend. See "Regulation - Other
Regulation and Litigation," for information on appeals of FERC Merger
orders and related pending rate schedule changes.
In the December 15, 1993, order approving the Merger, FERC also
initiated a new proceeding to consider whether the System Agreement
permits certain out-of-service generating units to be included in
reserve equalization calculations under Service Schedule MSS-1 of that
agreement. FERC established March 8, 1994, as the refund effective
date. On February 16, 1994, Entergy Corporation filed an Offer of
Settlement to amend the System Agreement prospectively to make it
explicit that certain out-of-service generating units may be included
in reserve equalization calculations under Service Schedule MSS-1.
The LPSC and MPSC contested certain provisions in the proposal, and
also argued that LP&L and MP&L were entitled to refunds for MSS-1
payments made in the past. Subsequently, the LPSC and MPSC submitted
testimony based on estimates, seeking refunds estimated at $22.6
million and $13.2 million, respectively. On March 31, 1994, the ALJ
limited the scope of the hearing to exclude any claims for retroactive
refunds. On April 5, 1994, the LPSC, Mississippi Attorney General
(MAG), and MPSC filed a complaint with FERC claiming that Entergy's
past reserve equalization charges under System Agreement Schedule MSS-
1 violated the System Agreement, sought refunds and requested FERC to
hold a hearing to consider this claim. Responses by Entergy
Corporation and other parties were filed on April 26, 1994. On June
17, 1994, FERC issued an order that clarified the scope of the
proceeding to include a review of whether refunds are due for periods
prior to the refund effective date.
The FERC staff submitted testimony concluding that although
Entergy's treatment was reasonable, because it violated the tariff,
refunds of approximately $7.2 million should be ordered. Entergy
submitted testimony on September 23, 1994, describing the potential
impacts (not including interest) on Service Schedule MSS-1
calculations if extended reserve shutdown units were not included in
the MSS-1 calculations during the period 1987 through 1993. Under
such a theory, LP&L and MP&L would have been overbilled by $10.6 and
$8.8 million, respectively, and AP&L and NOPSI would have been
underbilled by $6.3 and $13.1 million, respectively. The amounts
potentially subject to refund will continue to accrue while the case
is pending. Entergy believes that its calculation of MSS-1 charges
has been and will continue to be, in compliance with the System
Agreement, and that no refunds are due. An initial decision is
expected in March 1995.
On August 20, l990, the City of New Orleans filed a complaint
against Entergy Corporation, AP&L, LP&L, MP&L, NOPSI, and System
Energy requesting that FERC investigate AP&L's transfer of its
interest in Independence 2 and Ritchie 2 to Entergy Power (see
"Entergy Power," above) and the effect of the transfer on AP&L, LP&L,
MP&L, NOPSI, and their ratepayers. Various parties, including certain
of the System's state regulators, intervened in the proceeding. FERC
issued an order on March 19, 1991, setting for investigation (l) the
question of whether overall billings under the System Agreement will
increase as a result of the transfer to Entergy Power, and (2) if so,
whether such increased billings reflect prudently incurred costs that
may reasonably be charged under the System Agreement. In two separate
decisions the FERC ALJ ruled on May 14, l992 and October 30, 1992,
respectively, that there was sufficient evidence to show that overall
billings would increase as a result of the transfer, but that the
transfer was prudent. On December 15, 1993, FERC issued an opinion
declining to address the prudence issue until a future time when
replacement capacity has been added or planned and finding that, until
such time, billings under the System Agreement as affected by the
transfer of the two units are reasonable. The Entergy parties and the
City each filed a request for rehearing of this order, which was
denied by FERC on February 28, 1994. The Entergy parties and the City
each filed an appeal of the FERC's orders with the D.C. Circuit.
Various parties have intervened. If FERC's decision were reversed and
any refunds were ordered, they would be retroactive to October 19,
1990.
On March 15, 1995, the LPSC filed a complaint with FERC alleging
that the System Agreement results in unjust and unreasonable rates and
requested that FERC order a hearing on this matter. The LPSC contends
that the failure of the System Agreement to exclude curtailable load
from the determination of a System operating company's responsibility
for reserve equalization and transmission equalization costs results
in an unjust and unreasonable cost allocation to the companies that do
not cause these costs to be incurred, and also results in cross-
subsidization among the System operating companies. Further, the LPSC
alleges that the mechanism by which the System operating companies
purchase energy under the System Agreement results in unjust and
unreasonable rates because it does not permit companies that engage in
real time pricing to be charged the marginal cost of the energy
generated for the real time pricing customer. The System is currently
evaluating the merits of the LPSC's complaint.
Open Access Transmission. On August 2, 1991, Entergy Services,
as agent for AP&L, LP&L, MP&L, NOPSI, and Entergy Power, submitted to
FERC (1) proposed tariffs that, subject to certain conditions, would
provide to electric utilities "open access" to the System's integrated
transmission system, and (2) rate schedules providing for sales of
wholesale power at market-based rates. Under FERC policy, sales of
power at market-based rates would be permitted only if FERC found,
among other things, that Entergy did not have market power over
transmission. Permitting "open access" to the System's transmission
system helps support such a finding. Various parties, including the
Council, the APSC, the MPSC, and the LPSC, intervened in the
proceeding. On March 3, 1992, FERC approved the filing, with some
modifications, and on August 7, l992, FERC denied rehearing of its
March 1992 order. On August 24, l992, various parties filed petitions
with the D.C. Circuit for review of FERC's 1992 orders, and these
petitions were consolidated. The revised tariffs, submitted by
Entergy Services in response to FERC's 1992 orders, were accepted for
filing and made effective, subject to further modifications, by order
dated April 5, l993. Entergy Services made a further compliance
filing on May 5, l993, reflecting these modifications and requesting
reconsideration of certain limited matters, which is subject to
approval by FERC. On December 31, 1993, Entergy Services filed
revisions to the transmission service tariff to recognize GSU's
inclusion in the Entergy System.
On July 12, 1994, the D.C. Circuit issued an opinion finding that
FERC's failure to conduct an evidentiary hearing with respect to the
proposed transmission tariffs and related matters was arbitrary and
capricious, and that FERC failed to adequately explain its approval of
certain provisions in the tariffs, including a provision allowing
Entergy to seek recovery in transmission rates of "stranded
investment" costs resulting from the provision of transmission
service. The case was remanded to FERC for further proceedings. On
October 31, 1994, Entergy Services filed revised transmission tariffs
with FERC in response to the D.C. Circuit's remand. These tariffs
provide both point-to-point and network transmission services and are
intended to provide "comparability of service" over the Entergy
transmission network. On January 6, 1995, FERC issued an order
accepting the tariffs for filing and making them effective, subject to
refund. On January 25, 1995, Entergy Services filed revised
transmission tariffs in response to FERC's order. In addition, FERC
set Entergy's market pricing authority for investigation, thereby
making Entergy's market price rate schedules subject to refund. The
market price rate investigation has been deferred by FERC until
conclusion of the transmission tariff case, and an order is expected
to be issued no later than January 15, 1997.
Wholesale Contract. In March 1994, North Little Rock, Arkansas,
awarded AP&L a wholesale power contract that will provide estimated
revenues of $347 million over 11 years. Under the contract, the price
per KWH was reduced 18%, with increases in price through the year
2004. AP&L, which has been serving North Little Rock for over 40
years, was awarded the contract after intense bidding with several
competitors. On May 22, 1994, FERC accepted the contract. Rehearings
were requested by one of AP&L's competitors and were held in February
1995. The matter is pending.
Retail Rate Matters
General. AP&L, LP&L, MP&L, and NOPSI currently have retail rate
structures sufficient to recover their costs, including costs
associated with their allocated shares of capacity and energy from
Grand Gulf 1 under the Unit Power Sales Agreement, and a return on
equity. Certain costs related to Grand Gulf 1 (and in LP&L's case,
Waterford 3) are being phased into retail rates over a period of time,
in order to avoid the "rate shock" associated with increasing rates to
reflect all such costs at once. The deferral period in which costs
are incurred but not currently recovered has expired for all of these
programs, and AP&L, LP&L, MP&L, and NOPSI are now recovering those
costs that were previously deferred. Also, AP&L and LP&L have
retained a portion of their shares of Grand Gulf 1 capacity and GSU is
operating under a deregulated asset plan for a portion of its share of
River Bend.
GSU is involved in several rate proceedings involving recovery,
among other things, of costs associated with River Bend. Some rate
relief has been received, but GSU has been unable to obtain
recognition in rates for a substantial portion of its River Bend
investment. Recovery of certain costs has been disallowed, while
other costs are being deferred for future recovery, held in abeyance
pending further regulatory action, or treated as investments in
deregulated assets. Rate proceedings and appeals relating to these
issues are ongoing (see "GSU," below).
The System is committed to taking actions that will stabilize
retail rates and avoid the need for future rate increases. In the
short-term, this involves containing costs to the greatest degree
practicable, thereby avoiding erosion of earnings and delaying for as
long as possible the need for general rate increases. In accordance
with this retail rate policy, the System operating companies have
agreed to retail rate caps and/or rate freezes for specified periods
of time. Also, NOPSI reached a settlement with the Council to reduce
electric and gas rates and issue credits and refunds to customers.
For further information, see "NOPSI" below.
The retail regulatory philosophy is shifting in some
jurisdictions from traditional cost of service regulation to incentive
rate regulation. Incentive and performance-based rate plans encourage
efficiencies and productivity while permitting utilities and their
customers to share in the results. MP&L implemented an incentive rate
plan in 1994 and LP&L filed a performance-based formula rate plan with
the LPSC in August 1994. For further information, see "LP&L" and
"MP&L" below.
In the longer term, as discussed in "Business of Entergy -
Competition - Least Cost Planning" above, and also as discussed
specifically for each applicable company below, the System remains
committed to employing integrated resource planning to minimize the
cost of future sources of energy.
AP&L
Rate Freeze. In connection with the settlement of various issues
related to the Merger, AP&L agreed that it will not request any
general retail rate increase that would take effect before November 3,
1998, except for, among other things, increases associated with the
recovery of certain Grand Gulf 1-related costs, excess capacity costs,
and costs related to the adoption of SFAS 106 that were previously
deferred; recovery of certain taxes; fuel adjustment recoveries;
recovery of nuclear decommissioning costs; and force majeure (defined
to include, among other things, war, natural catastrophes, and high
inflation).
Recovery of Grand Gulf 1 Costs. Under the settlement agreement
entered into with the APSC in 1985 and amended in 1988, AP&L agreed to
retain a portion of its Grand Gulf l-related costs, recover a portion
of such costs currently, and defer a portion of such costs for future
recovery. In 1994 and subsequent years, AP&L will retain 7.92% of
such costs and will recover 28.08% currently. Deferrals ceased in
l990, and AP&L is recovering a portion of the previously deferred
costs each year through l998. As of December 31, l994, the balance of
deferred uncollected costs was $474.1 million. AP&L is permitted to
recover on a current basis the incremental costs of financing the
unrecovered deferrals.
AP&L has the right to sell capacity and energy from its retained
share of Grand Gulf 1 to third parties and to sell such energy to its
retail customers at a price equal to AP&L's avoided energy cost.
Proceeds of sales to third parties of AP&L's retained share of Grand
Gulf l capacity and energy generally accrue to the benefit of AP&L's
stockholder; however, half of the proceeds of such sales to third
parties prior to January 1, 1996, are used to reduce the balance of
uncollected deferrals and thus accrue to the benefit of retail
ratepayers. If AP&L makes sales to third parties prior to that date
in excess of the retained share, the proceeds of such excess are also
split between the stockholder and the ratepayers, except that the
portion of the sale that accrues to the stockholder's benefit cannot
exceed the retained share.
Least Cost Planning. On December 1, 1992, and July 1, 1993, AP&L
filed with the APSC the Least Cost Plan described in "Business of
Entergy - Competition - Least Cost Planning," above. However, in
response to an increasingly competitive electric utility environment
AP&L filed a motion on July 1, 1994, requesting that the APSC approve
the withdrawal of the December 1, 1992, and July 1, 1993, filings and
rescind its directive that AP&L file another Least Cost Plan in March
1995. AP&L will file, for informational purposes only, a revised
Least Cost Plan in the fourth quarter of 1995. In this plan, AP&L
intends to adopt the RIM as the screening criterion for DSM programs
including those DSM measures targeted at strategic load growth. This
is in place of the total resource cost test that had been used in
developing the initial Least Cost Plan. This criterion was adopted
because programs selected under this screen will minimize the rate
impact of any programs on all customers. AP&L has indicated that it
will not seek special rate treatment, such as rate riders, for the
cost of programs or loss of revenues due to DSM programs selected
using the RIM criterion. On October 5, 1994, the APSC issued an order
that suspended the initial Least Cost Plan dockets and established a
new docket to consider the need for integrated resource planning
standards as required by the EPAct. Hearings are scheduled to begin
in April 1995.
Fuel Adjustment Clause. AP&L's retail rate schedules have a fuel
adjustment clause that provides for recovery of the excess cost of
fuel and purchased power incurred in the second preceding month. The
fuel adjustment clause also contains a nuclear reserve fund designed
to cover the cost of replacement energy during scheduled maintenance
and refueling outages at ANO, and an incentive provision that permits
over- or under-recovery of the excess cost of replacement energy when
ANO is operating or down for reasons other than refueling.
GSU
Rate Cap and Other Merger-Related Rate Agreements. In 1993, the
LPSC and the PUCT approved separate regulatory proposals that include
the following elements: (1) a five-year Rate Cap on GSU's retail
electric base rates in the respective states, except for force majeure
(defined to include, among other things, war, natural catastrophes,
and high inflation); (2) a provision for passing through to retail
customers in the respective states the jurisdictional portion of the
fuel savings created by the Merger; and (3) a mechanism for tracking
nonfuel operation and maintenance savings created by the Merger. The
LPSC regulatory plan provides that such nonfuel savings will be shared
60% by the shareholder and 40% by ratepayers during the eight years
following the Merger. The LPSC plan requires regulatory filings each
year by the end of May through 2001. The PUCT regulatory plan
provides that such savings will be shared equally by the shareholder
and ratepayers, except that the shareholder's portion will be reduced
by $2.6 million per year on a total company basis in years four
through eight. The PUCT plan also requires a series of future
regulatory filings in November 1996, 1998, and 2001, to ensure that
ratepayers' share of such savings be reflected in rates on a timely
basis and requires Entergy Corporation to hold GSU's Texas retail
customers harmless from the effects of the removal by FERC of a 40%
cap on the amount of fuel savings GSU may be required to transfer to
other Entergy operating companies under the FERC tracking mechanism
(see below). On January 14, 1994, Entergy Corporation filed a request
for rehearing of FERC's December 15, 1993, order approving the Merger
requesting that FERC restore the 40% cap provision in the fuel cost
protection mechanism. The matter is pending.
Recovery of River Bend Costs. GSU deferred approximately $369
million of River Bend operating costs, purchased power costs, and
accrued carrying charges pursuant to a 1986 PUCT accounting order.
Approximately $182 million of these costs are being amortized over a
20-year period ending in the year 2009, and the remaining $187 million
are not being amortized pending the ultimate outcome of the Rate
Appeal (see "Texas Jurisdiction - River Bend," below). As of December
31, 1994, the unamortized balance of these costs was $321 million.
Further, GSU deferred approximately $400.4 million of similar costs
pursuant to a 1986 LPSC accounting order. These costs, of which
approximately $122 million are unamortized as of December 31, 1994,
are being amortized over a 10-year period ending in 1997.
In accordance with a phase-in plan approved by the LPSC, GSU
deferred $294 million of its River Bend costs related to the period
February 1988 through February 1991. GSU has amortized $129 million
through December 31, 1994, and the remainder of $165 million will be
recovered over approximately 3.2 years.
Texas Jurisdiction - River Bend. In May 1988, the PUCT granted
GSU a permanent increase in annual revenues of $59.9 million resulting
from the inclusion in rate base of approximately $1.6 billion of
company-wide River Bend plant investment and approximately $182
million of related Texas retail jurisdiction deferred River Bend costs
(Allowed Deferrals). In addition, the PUCT disallowed as imprudent
$63.5 million of company-wide River Bend plant costs and placed in
abeyance, with no finding of prudence, approximately $1.4 billion of
company-wide River Bend plant investment and approximately $157
million of Texas retail jurisdiction deferred River Bend operating and
carrying costs. The PUCT affirmed that the ultimate rate treatment of
such amounts would be subject to future demonstration of the prudence
of such costs. GSU and intervening parties appealed this order (Rate
Appeal) and GSU filed a separate rate case asking that the abeyed
River Bend plant costs be found prudent (Separate Rate Case).
Intervening parties filed suit in a Texas district court to prohibit
the Separate Rate Case. The district court's decision was ultimately
appealed to the Texas Supreme Court, which ruled in 1990 that the
prudence of the purported abeyed costs could not be relitigated in a
separate rate proceeding. The Texas Supreme Court's decision stated
that all issues relating to the merits of the original PUCT order,
including the prudence of all River Bend-related costs, should be
addressed in the Rate Appeal.
In October 1991, the Texas district court in the Rate Appeal
issued an order holding that, while it was clear the PUCT made an
error in assuming it could set aside $1.4 billion of the total costs
of River Bend and consider them in a later proceeding, the PUCT,
nevertheless, found that GSU had not met its burden of proof related
to the amounts placed in abeyance. The court also ruled that the
Allowed Deferrals should not be included in rate base. The court
further stated that the PUCT had erred in reducing GSU's deferred
costs by $1.50 for each $1.00 of revenue collected under the interim
rate increases authorized in 1987 and 1988. The court remanded the
case to the PUCT with instructions as to the proper handling of the
Allowed Deferrals. GSU's motion for rehearing was denied and, in
December 1991, GSU filed an appeal of the October 1991 district court
order. The PUCT also appealed the October 1991 district court order,
which served to supersede the district court's judgment, rendering it
unenforceable under Texas law.
In August 1994, the Texas Third District Court of Appeals (the
Appellate Court) affirmed the district court's decision that there was
substantial evidence to support the PUCT's 1988 decision not to
include the abeyed construction costs in GSU's rate base. While
acknowledging that the PUCT had exceeded its authority when it
attempted to defer a decision on the inclusion of those costs in rate
base in order to allow GSU a further opportunity to demonstrate the
prudence of those costs in a subsequent proceeding, the Appellate
Court found that GSU had suffered no harm or lack of due process as a
result of the PUCT's error. Accordingly, the Appellate Court held
that the PUCT's action had the effect of disallowing the company-wide
$1.4 billion of River Bend construction costs for ratemaking purposes.
In its August 1994 opinion, the Appellate Court also held that GSU's
deferred operating and maintenance costs associated with the allowed
portion of River Bend should be included in rate base and that GSU's
deferred River Bend carrying costs included in the Allowed Deferrals
should also be included in rate base. The Appellate Court's August
1994 opinion affirmed the PUCT's original order in this case.
The Appellate Court's August 1994 opinion was entered by two
judges, with a third judge dissenting. The dissenting opinion states
that the result of the majority opinion is, among other things, to
deprive GSU of due process at the PUCT because the PUCT never reached
a finding on the $1.4 billion of construction costs.
In October 1994, the Appellate Court denied GSU's motion for
rehearing on the August 1994 opinion as to the $1.4 billion in River
Bend construction costs and other matters. GSU appealed the Appellate
Court's decision to the Texas Supreme Court, where it is pending.
As of December 31, 1994, the River Bend plant costs disallowed
for retail ratemaking purposes in Texas, the River Bend plant costs
held in abeyance, and the related operating and carrying cost
deferrals totaled (net of taxes) approximately $13 million, $280
million (both net of depreciation), and $170 million, respectively.
Allowed Deferrals were approximately $107 million, net of taxes and
amortization, as of December 31, 1994. GSU estimates it has collected
approximately $158 million of revenues as of December 31, 1994, as a
result of the originally ordered rate treatment by the PUCT of these
deferred costs. If recovery of the Allowed Deferrals is not upheld,
future revenues based upon those allowed deferrals could also be lost,
and no assurance can be given as to whether or not refunds of revenue
received based upon such deferred costs previously recorded will be
required.
No assurance can be given as to the timing or outcome of the
remands or appeals described above. Pending further developments in
these cases, GSU has made no write-offs or reserves for the River Bend-
related costs. Management believes, based on advice from Clark,
Thomas & Winters, a Professional Corporation, legal counsel of record
in the Rate Appeal, that it is reasonably possible that the case will
be remanded to the PUCT, and the PUCT will be allowed to rule on the
prudence of the abeyed River Bend plant costs. Rate Caps imposed by
the PUCT's regulatory approval of the Merger could result in GSU being
unable to use the full amount of a favorable decision to immediately
increase rates; however, a favorable decision could permit some
increases and/or limit or prevent decreases during the period the Rate
Caps are in effect. At this time, management and legal counsel are
unable to predict the amount, if any, of the abeyed and previously
disallowed River Bend plant costs that ultimately may be disallowed by
the PUCT. A net of tax write-off as of December 31, 1994, of up to
$293 million could be required based on an ultimate adverse ruling by
the PUCT on the abeyed and disallowed costs.
In prior proceedings, the PUCT has held that the original cost of
nuclear power plants will be included in rates to the extent those
costs were prudently incurred. Based upon the PUCT's prior decisions,
management believes that its River Bend construction costs were
prudently incurred and that it is reasonably possible that it will
recover in rate base, or otherwise through means such as a deregulated
asset plan, all or substantially all of the abeyed River Bend plant
costs. However, management also recognizes that it is reasonably
possible that not all of the abeyed River Bend plant costs may
ultimately be recovered.
As part of its direct case in the Separate Rate Case, GSU filed a
cost reconciliation study prepared by Sandlin Associates, management
consultants with expertise in the cost analysis of nuclear power
plants, which supports the reasonableness of the River Bend costs held
in abeyance by the PUCT. This reconciliation study determined that
approximately 82% of the River Bend cost increase above the amount
included by the PUCT in rate base was a result of changes in federal
nuclear safety requirements and provided other support for the
remainder of the abeyed amounts.
There have been four other rate proceedings in Texas involving
nuclear power plants. Investment in the plants ultimately disallowed
ranged from 0% to 15%. Each case was unique, and the disallowances in
each were made on a case-by-case basis for different reasons. Appeals
of two of these PUCT decisions are currently pending.
The following factors support management's position that a loss
contingency requiring accrual has not occurred, and its belief that
all, or substantially all, of the abeyed plant costs will ultimately
be recovered:
1. The $1.4 billion of abeyed River Bend plant costs have never
been ruled imprudent and disallowed by the PUCT.
2. Sandlin Associates' analysis which supports the prudence of
substantially all of the abeyed construction costs.
3. Historical inclusion by the PUCT of prudent construction
costs in rate base.
4. The analysis of GSU's internal legal staff, which has
considerable experience in Texas rate case litigation.
Additionally, management believes, based on advice from Clark,
Thomas & Winters, a Professional Corporation, legal counsel of record
in the Rate Appeal, that it is reasonably possible that the Allowed
Deferrals will continue to be recovered in rates. Management also
believes, based on advice from Clark, Thomas & Winters, a Professional
Corporation, legal counsel of record in the Rate Appeal, that it is
reasonably possible that the deferred costs related to the $1.4
billion of abeyed River Bend plant costs will be recovered in rates to
the extent that the $1.4 billion of abeyed River Bend plant is
recovered. However, a net of tax write-off of the $170 million of
deferred costs related to the $1.4 billion of abeyed River Bend plant
costs would be required if they are not allowed to be recovered in
rates.
Texas Fuel Cost Review. ( December 1, 1986 - September 30, 1991)
In January 1992, GSU applied to the PUCT for a new fixed fuel factor
and requested a final reconciliation of fuel and purchased power costs
incurred between December 1, 1986 and September 30, 1991. GSU
proposed to recover net underrecoveries and interest (including
underrecoveries related to NISCO, discussed below) over a twelve month
period.
In April 1993, the presiding PUCT ALJ issued a report concluding
that GSU incurred approximately $117 million of nonreimbursable fuel
costs on a company-wide basis (approximately $50 million on a Texas
retail jurisdictional basis) during the reconciliation period.
Included in the nonreimbursable fuel costs were payments above GSU's
avoided cost rate for power purchased from NISCO. The PUCT ordered in
1986 that the purchased power costs from NISCO in excess of GSU's
avoided costs be disallowed. The PUCT disallowance resulted in
approximately $12 million to $15 million of unrecovered purchased
power costs on an annual basis, which GSU continued to expense as the
costs were incurred. In April 1991, the Texas Supreme Court, in the
appeal of such order, ordered the PUCT to allow GSU to recover
purchased power payments in excess of its avoided cost in future
proceedings, if GSU established to the PUCT's satisfaction that the
payments were reasonable and necessary expenses.
In June 1993, the PUCT concluded that the purchased power
payments made to NISCO in excess of GSU's avoided cost were not
reasonably incurred. As a result of the order, GSU recorded
additional fuel expenses (including interest) of $2.8 million for non-
NISCO related items. The PUCT's order resulted in no additional
expenses related to the NISCO issue, or for overcollections related to
the fixed fuel factor, as those charges were expensed by GSU as they
were incurred. The PUCT concluded that GSU had over-collected its
fuel costs in Texas and ordered GSU to refund approximately $33.8
million to its Texas retail customers, including approximately $7.5
million of interest. In that proceeding, the PUCT also set GSU's
fixed fuel factor in Texas at 1.84 cents per KWH in response to GSU's
request that the factor be set at 2.02 cents per KWH. In October
1993, GSU appealed the PUCT's order to the Travis County District
Court where the matter is still pending. No assurance can be given as
to the timing or outcome of that appeal. In a subsequent proceeding
to review GSU's fuel factor, the PUCT approved GSU's request to
further reduce its fixed fuel factor in Texas to 1.78 cents per KWH
from 1.84 cents per KWH.
Texas Fuel Cost Review. (October 1, 1991 - December 31, 1993)
On January 9, 1995, GSU and various parties reached an agreement for
the reconciliation of over- and under-recovery of fuel and purchased
power expenses for the period October 1, 1991, through December 31,
1993. While the settlement still requires PUCT approval, GSU believes
it will ultimately be approved and has accordingly recorded a reserve
of $7.6 million.
Filings with the PUCT and Texas Cities. In March 1994, the Texas
Office of Public Utility Counsel and certain cities served by GSU
instituted an investigation of the reasonableness of GSU's rates. In
June 1994, GSU provided the cities with information that GSU believed
supported the current rate level. GSU filed the same information with
the PUCT in June 1994, pursuant to provisions of the Merger. In
September 1994, certain cities adopted ordinances directing GSU to
reduce its Texas retail rates by $45.9 million. GSU appealed the
cities' ordinances to the PUCT for a determination of reasonableness
of GSU's rates.
In November 1994, those cities that intervened in the PUCT appeal
filed testimony with the PUCT supporting a $118 million base rate
reduction in lieu of the previously proposed $45.9 million reduction.
In November 1994, the PUCT staff filed testimony that supported a
$38.2 million base rate reduction. GSU filed information with the
PUCT that it believed supported the current level of rates. Hearings
were held in December 1994 and on March 20, 1995, the PUCT ordered a
$72.9 million annual base rate reduction for the period March 31,
1994, through September 1, 1994, decreasing to an annual base rate
reduction of $52.9 million after September 1, 1994. In accordance
with the Merger agreement, the rate reduction is applied retroactively
to March 31, 1994. As a result, GSU recorded a $57 million reserve
for rate refund in 1994 which reduced net income after tax by $41.6
million. The rate reduction is being appealed and no assurance can be
given as to the timing or outcome of the appeal.
Texas Cities Rate Settlement - 1993. In June 1993, 13 cities
within GSU's Texas service area instituted an investigation to
determine whether GSU's current rates were justified. In October
1993, the general counsel of the PUCT instituted an inquiry into the
reasonableness of GSU's rates. In November 1993, a settlement
agreement was filed with the PUCT which provided for an initial
reduction in GSU's annual retail base revenues in Texas of
approximately $22.5 million effective for electric usage on or after
November 1, 1993, and a second reduction of $20 million effective
September 1994. Pursuant to the settlement, GSU reduced rates with a
$20 million one-time bill credit in December 1993, and refunded
approximately $3 million to Texas retail customers on bills rendered
in December 1993. The PUCT approved the settlement agreement on July
21, 1994. The cities' rate inquiries were settled earlier on the same
terms.
LPSC Rate Review Order - 1994. In May 1994, GSU made the
required first post-Merger earnings analysis filing with the LPSC. On
December 14, 1994, the LPSC ordered a $12.7 million annual rate
reduction for GSU effective January 1995. The rate order included,
among other things, a reduction in GSU's Louisiana jurisdictional
authorized return on equity from 12.75% to 10.95% and the amortization
for the benefit of the customers of $8.3 million of previously
deferred unbilled revenue, representing one-half of the total
resulting from a change in accounting discussed in Note 1 of Entergy
Corporation and Subsidiaries' Notes to Consolidated Financial
Statements. On December 28, 1994, GSU received a preliminary
injunction from the 19th Judicial District Court regarding $8.3
million of the reduction. On January 1, 1995, GSU reduced rates by
$4.4 million. The entire $12.7 million reduction is being appealed
and no assurance can be given as to the timing or outcome of the
appeal.
LPSC Fuel Cost Review. In November 1993, the LPSC ordered a
review of GSU's fuel costs for the period October 1988 through
September 1991 (Phase 1) based on the number of outages at River Bend
and the findings in the June 1993 PUCT fuel reconciliation case. In
July 1994, the LPSC ruled in the Phase 1 fuel review case and ordered
GSU to refund approximately $27 million to its customers. Under the
order, a refund of $13.1 million, which was not contested under a
Louisiana Supreme Court decision as discussed below, was made through
a billing credit on August 1994 bills. In August 1994, GSU appealed
the remaining portion of the LPSC ordered refund to the district
court. GSU has made no reserve for the remaining portion, pending
outcome of the district court appeal, and no assurance can be given as
to the timing or outcome of the appeal.
On January 18, 1995, GSU met with the Special Counsel of the LPSC
to discuss the procedural schedule for the upcoming fuel review (Phase
II). The period under investigation was determined to be from October
1991 to December 1994. Hearings are scheduled to begin in July 1995.
In February 1990, the LPSC disallowed the pass-through to
ratepayers for the portion of GSU's cost to purchase power from NISCO
representing the excess of NISCO's purchase price of the units over
GSU's depreciated cost of the units. GSU appealed the 1990 order. In
March 1994, the Louisiana Supreme Court ruled in favor of the LPSC.
GSU recorded an estimated refund provision of $13.1 million, before
related income taxes of $5.3 million.
Least Cost Planning. Currently, the PUCT does not have least
cost planning rules in place, and GSU has not filed a Least Cost Plan
with the PUCT. However, the PUCT staff has begun a rulemaking process
for such rules, and GSU is actively participating in this process.
GSU has not yet filed a Least Cost Plan with the LPSC. GSU intends
to adopt the RIM as the screening criterion for DSM measures programs
including those DSM measures targeted at strategic load growth. This
criterion was adopted because programs selected under this screen will
minimize the rate impact of any programs on all customers. GSU has
indicated that it will not seek special rate treatment, such as rate
riders, for the cost of programs or the loss of revenue due to DSM for
programs selected using the RIM criterion.
Fuel Recovery. In January 1993, the PUCT adopted a new rule for
setting a fixed fuel factor, which is intended to recover projected
allowable fuel and purchased power costs not covered by base rates.
To the extent actual costs vary from the fixed factor, the PUCT may
require refunds of overcharges or permit recovery of undercharges.
Under the new rule, fuel factors are to be revised every six months,
and GSU is on a schedule providing for revision each March and
September. The PUCT is required to act within 60 or 90 days,
depending on whether or not a hearing is required, and refunds and
surcharges will be required based upon a materiality threshold of 4%
of Texas retail fuel revenues. Fuel charges will also be subject to
reconciliation proceedings every three years, at which time additional
adjustments may be required (see " Texas Fuel Cost Review," above).
All of GSU's rate schedules in Louisiana include a fuel adjustment
clause to recover the cost of fuel and purchased power energy costs.
The fuel adjustment reflects the delivered cost of fuel for the second
preceding month.
LP&L
LPSC Jurisdiction. In a series of LPSC orders, court decisions,
and agreements from late 1985 to mid-1988, LP&L was granted rate
relief with respect to costs associated with Waterford 3 and LP&L's
share of capacity and energy from Grand Gulf l, subject to certain
terms and conditions. With respect to Waterford 3, LP&L was granted
an increase aggregating $170.9 million over the period 1985-1988, and
LP&L agreed to permanently absorb, and not recover from retail
ratepayers, $284 million of its investment in the unit and to defer
$266 million of its costs related to the years 1985-1988 to be
recovered over approximately 8.6 years beginning in April 1988. As of
December 31, 1994, LP&L's unrecovered deferral balance was $54.0
million. With respect to Grand Gulf l, LP&L agreed to absorb, and not
recover from retail ratepayers, 18% of its 14% share (approximately
2.52%) of the costs of Grand Gulf l capacity and energy. LP&L is
allowed to recover through the fuel adjustment clause 4.6 cents per
KWH (as of May 1994) for the energy related to its retained portion of
these costs. Alternatively, LP&L may sell such energy to nonaffiliated
parties at prices above the fuel adjustment clause recovery amount,
subject to LPSC approval. (See Note 2 of LP&L's Notes to Financial
Statements, "Rate and Regulatory Matters - Waterford 3 and Grand Gulf
1," for further information on LP&L's Grand Gulf 1 and Waterford 3-
related rates.)
In a subsequent rate proceeding, on March 1, l989, the LPSC
issued an order providing that, in effect, LP&L was entitled to an
approximately $45.9 million annual retail rate increase, but that, in
lieu of a rate increase, LP&L would be permitted to retain $188.6
million of the proceeds of a 1988 settlement of litigation with a gas
supplier, and to amortize such proceeds into revenues over a period of
approximately 5.3 years. The amortization of the proceeds expired in
mid-1994. LP&L believes that the amortization resulted in
approximately the same amount of additional net income as an annual
rate increase of $45.9 million would have provided over the same
period. In connection with this order, LP&L agreed to a five-year
base rate freeze which expired in March 1994.
Performance-Based Formula Rate Plan. In August 1994, LP&L filed
a performance-based formula rate plan with the LPSC. The proposed
formula rate plan would continue existing LP&L rates at current
levels, while providing financial incentive to reduce costs and
maintain high levels of customer satisfaction and system reliability.
A performance rating adjustment feature of the plan would allow LP&L
the opportunity to earn a higher rate of return if it improves
performance over time. Conversely, if performance declines, the rate
of return LP&L could earn would be lowered. This provides financial
incentive for LP&L to maintain continuous improvement in all three
performance categories (customer price, customer satisfaction, and
customer reliability). Under the proposed plan, if LP&L's earnings
fall within a bandwidth around a benchmark rate of return, there would
be no adjustment in rates. If LP&L's earnings are above the
bandwidth, the proposed plan would automatically reduce LP&L's base
rates. Alternatively, if LP&L's earnings are below the bandwidth, the
proposed plan would automatically increase LP&L's base rates. The
reduction or increase in base rates would be an amount representing
50% of the difference between the earned rate of return and the
nearest limit of the bandwidth. In no event would the annual
adjustment in rates exceed 2% of LP&L's retail revenues. Hearings were
held in March 1995.
Least Cost Planning. On December l, l992, and July 1, l993, LP&L
filed with the LPSC and the Council the Least Cost Plan and amendments
described under "Business of Entergy - Competition - Least Cost
Planning," above. In response to an increasingly competitive electric
utility environment LP&L intends to adopt the RIM as the screening
criterion for DSM programs, including those DSM measures targeted at
strategic load growth. This is in place of the total resource cost
test that had been used in developing the initial Least Cost Plan.
This criterion was adopted because programs selected under this screen
will minimize the rate impact of any programs on all customers. LP&L
has indicated that it will not seek special rate treatment, such as
rate riders, for the cost of programs selected using the RIM
criterion. On September 28, 1994, LP&L filed a report with the
Council that discussed Entergy's Least Cost Plan activities in other
jurisdictions and described the motivations for these activities. LP&L
also filed a motion requesting that the Council defer the filing of a
new Least Cost Plan, which the existing Least Cost Plan ordinance
required on December 1, 1994. On October 6, 1994, the Council
approved an amendment to the City Code that rescinded the December 1,
1994 filing requirement and allowed the Council to set a future date
for a new filing. The Council's actions also established that there
would be a set of hearings to consider a wide range of Least Cost Plan
issues, and that a new filing date would be established following
these hearings. These rulings do not affect the ongoing DSM programs
that LP&L is currently implementing in the City.
Regarding the activities of LP&L within the jurisdiction of the
LPSC, on June 30, 1994, LP&L filed rebuttal testimony with the LPSC
explaining LP&L's new direction for least cost planning. On July 18,
1994, LP&L filed a motion to withdraw its Least Cost Plan and for
approval of an experimental time-of-use-rate. LP&L will file, for
informational purposes only, a revised Least Cost Plan in the fourth
quarter of 1995. The LPSC responded to LP&L's request by placing
LP&L's application for approval in abeyance. However, the LPSC did
require LP&L to file a set of proposed pilot programs. In December
1994, LP&L filed a set of proposed pilot programs with the LPSC. LP&L
has agreed not to seek special treatment of the costs or loss of
revenues due to DSM measures associated with these pilot programs.
The LPSC has also ordered that a set of generic hearings be held to
address integrated resource planning issues for all electric utilities
within its jurisdiction. No procedural schedule has been issued for
these proceedings.
Fuel Adjustment Clause. LP&L's rate schedules include a fuel
adjustment clause to reflect the (1) delivered cost of fuel in the
second preceding month and (2) purchased power energy costs. The fuel
adjustment also reflects a surcharge for deferred fuel expense arising
from the monthly reconciliation of actual fuel cost incurred with fuel
cost revenues billed to customers. LP&L defers on its books fuel costs
that will be reflected in customer billings in the future under the
fuel adjustment clause.
MP&L
Rate Freeze. In a stipulation entered into by MP&L in connection
with the settlement of various issues related to the Merger, MP&L
agreed that (1) for a period of five years beginning on November 9,
1993, retail base rates under MP&L's formulary rate plan would not be
increased above the level of rates in effect on November 1, 1993, and
(2) MP&L would not request any general retail rate increase that would
increase retail rates above the level of MP&L's rates in effect as of
November l, 1993, and that would become effective in such five-year
period except for, among other things, increases associated with the
recovery of deferred Grand Gulf 1-related costs, recovery under the
fuel adjustment clause, adjustments for certain taxes, and force
majeure (defined to include, among other things, war, natural
catastrophes, and high inflation).
Recovery of Grand Gulf 1 Costs. The MPSC's Final Order on
Rehearing, issued in 1985, affirmed by the United States Supreme Court
in 1988, and subsequently revised in 1988, granted MP&L an annual base
rate increase of approximately $326.5 million in connection with its
allocated share of Grand Gulf 1 costs. The Final Order on Rehearing
also provided for the deferral of a portion of such costs that were
incurred each year through 1992, and recovery of these deferrals over
a period of six years ending in 1998. As of December 31, 1994, the
uncollected balance of MP&L's deferred costs was approximately $492.3
million. MP&L is permitted to recover the carrying charges on all
deferred amounts on a current basis.
Formula Rate Plan. Under a formulary incentive rate plan
(Formula Rate Plan) effective March 25, 1994, MP&L's earned rate of
return is calculated automatically every 12 months and compared to and
adjusted against a benchmark rate of return (calculated under a
separate formula within the Formula Rate Plan). The Formula Rate Plan
allows for periodic small adjustments in rates based on a comparison
of earned to benchmark returns and upon certain performance factors.
In the same proceeding, the MPSC conducted a general review of MP&L's
current rates and on March 1, 1994, issued a final order adopting the
Formula Rate Plan and previously agreed-upon stipulations of (1) a
required return on equity of 11% and (2) certain accounting
adjustments that resulted in a 4.3% ($28.1 million) reduction in
MP&L's June 30, 1993, test-year base revenues. The MPSC's order
required MP&L to file rates designed to provide for this reduction in
operating revenues for the test year on or before March 18, 1994,
which became effective March 25, 1994. The final order was appealed
to the Mississippi Supreme Court on May 17, 1994, by Mississippi
Valley Gas Company (MVG) on the grounds that the MPSC issued the final
order without having reviewed the cost of MP&L's promotional
practices, some of which MVG alleged to be improper. MVG filed a
motion to dismiss the appeal, and on October 28, 1994, the Mississippi
Supreme Court granted MVG's motion.
February 1994 Ice Storm/Rate Rider In early February 1994, an
ice storm left more than 80,000 MP&L customers without electric power
across the service area. The storm was the most severe natural
disaster ever to affect the System, causing damage to transmission and
distribution lines, equipment, poles, and facilities in certain areas,
primarily in Mississippi. Repair costs totaled approximately $77.2
million, with $64.6 million of these amounts capitalized as plant-
related costs. The remaining balances were recorded as a deferred
debit. On April 15, 1994, MP&L filed for rate recovery of costs
related to the ice storm. MP&L's filing, as subsequently amended,
requested recovery of the revenue requirement associated with MP&L's
ice storm costs recorded through April 30, 1994, representing
approximately 86% of the total estimated ice storm costs. MP&L may
make another ice storm rate filing with the MPSC during 1995 to
recover ice storm costs recorded by MP&L after April 30, 1994. In
August 1994, MP&L and the MPSC's Public Utilities Staff entered into a
stipulation with respect to the recovery of ice storm costs recorded
through April 30, 1994, and in September 1994, the MPSC approved the
stipulation. Under the stipulation, MP&L implemented an ice storm
rider schedule, which went into effect on September 29, 1994, that
will increase rates approximately $8 million annually for five years.
At the end of the five-year period, the revenue requirement associated
with the undepreciated ice storm capitalized costs will be included in
MP&L's base rates to the extent that this revenue requirement does not
result in MP&L's rate of return on rate base being above the benchmark
rate of return under MP&L's formula rate plan.
Least Cost Planning. On December 1, 1992, and July 1, 1993, MP&L
filed with the MPSC the Least Cost Plan described in "Business of
Entergy - Competition - Least Cost Planning," above. In response to
an increasingly competitive electric utility environment MP&L filed a
motion on June 20, 1994, with the MPSC to lift a currently effective
stay order and dismiss without prejudice the proposed Least Cost Plan.
On July 28, 1994, the MPSC issued an order that lifted the stay and
dismissed, without prejudice, the Least Cost Plan filing. MP&L will
file, for informational purposes only, a revised Least Cost Plan in
the fourth quarter of 1995. In this plan, MP&L intends to adopt the
RIM as the screening criterion for DSM programs including those DSM
measures targeted at strategic load growth. This is in place of the
total resource cost test that had been used in developing the initial
Least Cost Plan. This criterion was adopted because programs selected
under this screen will minimize the rate impact of any programs on all
customers. MP&L has indicated that it will not seek special rate
treatment, such as rate riders, for the cost of programs or loss of
revenue due to DSM for programs selected using the RIM criterion.
Fuel Adjustment Clause. MP&L's rate schedules include a fuel
adjustment clause that permits recovery from customers of changes in
the cost of fuel and purchased power. The monthly fuel adjustment
rate is based on projected sales and costs for the month, adjusted for
differences between actual and estimated costs for the second prior
month.
NOPSI
Recovery of Grand Gulf 1 Costs. Under NOPSI's various Rate
Settlements with the Council (which include the 1986 NOPSI Settlement,
the February 4 Resolution relating to prudence issues, and the 1991
NOPSI Settlement of the issues raised in the February 4 Resolution),
NOPSI agreed to absorb and not recover from ratepayers a total of
$186.2 million of its Grand Gulf 1 costs. NOPSI was permitted to
implement annual rate increases in decreasing amounts each year
through 1995, and to defer certain costs and related carrying charges,
for recovery on a schedule extending from 1991 through 2001. As of
December 31, 1994, the uncollected balance of NOPSI's deferred costs
was $204.7 million. NOPSI also agreed to a base rate freeze through
October 31, 1996, excluding the scheduled increases, certain changes
in tax rates, and increases related to catastrophic events. However,
this base rate freeze was amended by the 1994 NOPSI Settlement
discussed below. See Note 2 of NOPSI's Notes to Financial Statements,
"Rate and Regulatory Matters - Prudence Settlement and Finalized Phase-
In Plan."
Electric Retail Rate Reduction. On November 18, 1993, in
connection with the settlement of various issues related to the
Merger, the Council adopted a resolution requiring NOPSI to reduce its
annual electric base rates by $4.8 million on bills rendered on or
after November 1, 1993.
1994 NOPSI Settlement. In a settlement with the Council that was
approved on December 29, 1994, NOPSI agreed to reduce electric and gas
rates and issue credits and refunds to customers. Effective January
1, 1995, NOPSI implemented a $31.8 million permanent reduction in
electric base rates and a $3.1 million permanent reduction in gas base
rates. These adjustments resolved issues associated with NOPSI's
return on equity exceeding 13.76% for the test year September 30,
1994. Under the 1991 NOPSI Settlement, NOPSI recovers from its retail
customers its allocable share of certain costs related to Grand Gulf
1. NOPSI's base rates to recover those costs were derived from
estimates of those costs made at that time. Any overrecovery of costs
is required to be returned to customers. Grand Gulf 1 experienced
lower operating costs than previously estimated, and NOPSI agreed to
reduce its base rates in two steps to more accurately match the
current costs related to Grand Gulf 1. On January 1, 1995, NOPSI
implemented a $10 million permanent reduction in base electric rates
to reflect the reduced costs related to Grand Gulf 1, to be followed
by an additional $4.4 million rate reduction on October 31, 1995.
These Grand Gulf 1 rate reductions, which are expected to be largely
offset by lower operating costs, may reduce NOPSI's after-tax net
income by approximately $1.4 million per year beginning November 1,
1995. The next scheduled Grand Gulf 1 phase-in rate increase in the
amount of $4.4 million on October 31, 1995, will not be affected by
the 1994 NOPSI Settlement.
The 1994 NOPSI Settlement also requires NOPSI to credit its
customers $25 million over a 21-month period, beginning January 1,
1995, in order to resolve disputes with the Council regarding the
interpretation of the 1991 NOPSI Settlement. NOPSI reduced its
revenues by $25 million and recorded a $15.4 million net-of-tax
reserve associated with the credit in the fourth quarter of 1994. The
1994 NOPSI Settlement further required NOPSI to refund, in December
1994, $13.3 million of credits previously scheduled to be made to
customers during the period January 1995 through July 1995. These
credits were associated with a July 7, 1994, Council resolution that
ordered a $24.95 million rate reduction based on NOPSI's overearnings
during the test year ended September 30, 1993. Accordingly, NOPSI
recorded an $8 million net-of-tax charge in the fourth quarter of
1994.
The 1994 NOPSI Settlement also required NOPSI to refund $9.3
million of overcollections associated with Grand Gulf 1 operating
costs and $10.5 million of refunds associated with the settlement by
System Energy of a FERC tax audit. The settlement of the FERC tax
audit by System Energy required refunds to be passed on to NOPSI and
to other Entergy subsidiaries and then on to customers. These refunds
have no effect on current period net income.
Gas Rates. In May 1992, NOPSI and the Council settled a pending
application for gas rate increases. The settlement provided for
annual rate increases of approximately $3.8 million in May 1992 and
1993, and the deferral of an additional $3 million for recovery in the
years beginning in May 1993 through May 1996. NOPSI agreed to a base
rate freeze, except for the scheduled increases and certain other
exceptions, through October 31, 1996. However, this was amended by
the 1994 NOPSI Settlement discussed above.
Least Cost Planning. On December 1, 1992, and July 1, 1993,
NOPSI filed with the Council the Least Cost Plan described under
"Business of Entergy - Competition - Least Cost Planning," above. In
response to an increasingly competitive electric utility environment
NOPSI intends to adopt RIM as the screening criterion for DSM programs
including those DSM measures targeted at strategic load growth. This
is in place of the total resource cost test that had been used in
developing the initial Least Cost Plan. This criterion was adopted
because programs selected under this screen will minimize the rate
impact of any programs on all customers. NOPSI has indicated that it
will not seek special rate treatment, such as rate riders, for the
cost of programs selected using the RIM criterion. NOPSI filed a
report on September 28, 1994, with the Council that discussed
Entergy's Least Cost Plan activities in other jurisdictions and
described the motivations for these activities. NOPSI also filed a
motion requesting that the Council defer the filing of a new Least
Cost Plan, which the existing Least Cost Plan ordinance required on
December 1, 1994. On October 6, 1994, the Council approved an
amendment to the City Code that rescinded the December 1, 1994, filing
requirement and allowed the Council to set a future date for a new
filing. The Council's actions also established that there would be a
set of hearings to consider a wide range of Least Cost Plan issues,
and that a new filing date would be established following these
hearings. These rulings do not affect the ongoing DSM programs that
NOPSI is currently implementing in the City. The Council has
established a proceeding to consider NOPSI's request for significant
changes in the Least Cost Plan Ordinance. NOPSI's initial testimony
in that matter was filed on November 17, 1994, and has been the
subject of discovery requests from the Council's advisors and
intervenors. Initial testimony of the Council's advisors and
intervenors was filed February 10, 1995, and rebuttal testimony of
all parties was due March 10, 1995.
In connection with the settlement of various issues related to
the Merger, the Council adopted a resolution on November 18, 1993,
that provides that the Council will not disallow the first
$3.5 million of costs incurred by NOPSI through October 31, 1993, in
connection with the Least Cost Plan.
Fuel Adjustment Clause. NOPSI's electric rate schedules include
a fuel adjustment clause to reflect the delivered cost of fuel in the
second preceding month, adjusted by a surcharge for deferred fuel
expense arising from the monthly reconciliation of actual fuel cost
incurred with fuel cost revenues billed to customers. The adjustment
clause, on a monthly basis, also reflects the difference between
nonfuel Grand Gulf 1 costs paid by NOPSI and the estimate of such
costs provided in NOPSI's Grand Gulf 1 Rate Settlements. NOPSI's gas
rate schedules include a gas cost adjustment to reflect gas costs in
excess of those collected in rates, adjusted by a surcharge similar to
that included in the electric adjustment clause. NOPSI defers on its
books fuel and purchased gas costs to be reflected in billings to
customers in the future under the fuel adjustment clause.
REGULATION
Federal Regulation
Holding Company Act. Entergy Corporation is a public utility
holding company registered under the Holding Company Act. As such,
Entergy Corporation and its various direct and indirect subsidiaries
(with the exception of its independent power/EWG subsidiaries) are
subject to the broad regulatory provisions of that Act. Except with
respect to investments in certain EWG projects and foreign utility
company projects (see "Business of Entergy - Competition - General,"
above for a discussion of the EPAct), Section 11(b)(1) of the Holding
Company Act limits the operations of a registered holding company
system to a single, integrated public utility system, plus additional
systems and businesses as provided by that section.
Entergy Corporation, along with ten other electric utility
holding companies, recently asked Congress to repeal the Holding
Company Act. The Holding Company Act requires oversight by the SEC of
many business practices and activities of utility holding companies
and their subsidiaries including, among other things, nonutility
activities. Entergy Corporation believes that the Holding Company Act
inhibits its ability to compete in the evolving electric energy
marketplace, and largely duplicates the oversight activities already
performed by FERC and state and local public service commissions.
Federal Power Act. The System operating companies, System
Energy, and Entergy Power are subject to the Federal Power Act as
administered by FERC and the DOE. The Federal Power Act provides for
regulatory jurisdiction over the licensing of certain hydroelectric
projects, the business of, and facilities for, the transmission and
sale at wholesale of electric energy in interstate commerce and
certain other activities of the System operating companies, System
Energy, and Entergy Power as interstate electric utilities, including
accounting policies and practices. Such regulation includes
jurisdiction over the rates charged by System Energy for capacity and
energy provided to AP&L, LP&L, MP&L, and NOPSI, or others, from Grand
Gulf 1.
AP&L holds a license for two hydroelectric projects (70 MW) that
was renewed on July 2, 1980. This license, granted by FERC, will
expire in February 2003.
Regulation of the Nuclear Power Industry
General. Under the Atomic Energy Act of 1954 and the Energy
Reorganization Act of 1974, operation of nuclear plants is intensively
regulated by the NRC, which has broad power to impose licensing and
safety-related requirements. In the event of non-compliance, the NRC
has the authority to impose fines or shut down a unit, or both,
depending upon its assessment of the severity of the situation, until
compliance is achieved. AP&L, GSU, LP&L, and System Energy, as owners
of all or a portion of ANO, River Bend, Waterford 3, and Grand Gulf 1,
respectively, and Entergy Operations, as the operator of these units,
are subject to the jurisdiction of the NRC. Revised safety
requirements promulgated by the NRC have, in the past, necessitated
substantial capital expenditures at System nuclear plants and
additional such expenditures could be required in the future.
The nuclear power industry faces uncertainties with respect to
the cost and availability of long-term arrangements for disposal of
spent nuclear fuel and other radioactive waste, nuclear plant
operational issues, the technological and financial aspects of
decommissioning plants at the end of their licensed lives, and the
effect of certain requirements relating to nuclear insurance. These
matters are briefly discussed below.
Spent Fuel and Other High-Level Radioactive Waste. Under the
Nuclear Waste Policy Act of 1982, the DOE is required, for a specified
fee, to construct storage facilities for, and to dispose of, all spent
nuclear fuel and other high-level radioactive waste generated by
domestic nuclear power reactors. The NRC, pursuant to this Act, also
requires operators of nuclear power reactors to enter into spent fuel
disposal contracts with the DOE, and the affected System companies
have entered into such disposal contracts. However, the DOE has not
yet identified a permanent storage repository and, as a result, future
expenditures may be required to increase spent fuel storage capacity
at the plant sites. Currently the DOE projects it will begin to
accept spent fuel no earlier than 2010. In the meantime, all System
companies are responsible for spent fuel storage. (For further
information concerning spent fuel disposal contracts with the DOE,
schedules for initial shipments of spent nuclear fuel, current on-site
storage capacity, and costs of providing additional on-site storage
capacity, see Note 8 of AP&L's, GSU's, and LP&L's, and Note 7 of
System Energy's, Notes to Financial Statements, "Commitments and
Contingencies - Spent Nuclear Fuel and Decommissioning Costs.")
Low-Level Radioactive Waste. The availability and cost of
disposal facilities for low-level radioactive waste resulting from
normal operation of nuclear units are subject to a number of
uncertainties. Under the Low-Level Radioactive Waste Policy Act of
1980, as amended, each state is responsible for disposal of its own
waste, and states may join in regional compacts to jointly fulfill
their responsibilities. The States of Arkansas and Louisiana
participate in the Central States Compact, and the State of
Mississippi participates in the Southeast Compact. Two disposal sites
are currently operating in the United States, and one of them, which
is located in Washington, is closed to out-of-region generators. The
second site, the Barnwell Disposal Facility (Barnwell) located in
South Carolina, is operated by the Southeast Compact and the State of
Mississippi is expected to have access to this site through December
1995. Barnwell had been open to out-of-region generators (including
generators in Arkansas and Louisiana) in the past; however, on April
14, 1993, the Southeast Compact voted to deny access to Barnwell to
members of the Central States Compact. Such access was reinstated for
the period from October 1993 through June 1994, at which time
legislative action by the State of South Carolina was required to
permit further access to out-of-region generators. The South Carolina
legislature failed to take action to permit further access to out-of-
region generators; therefore, since July 1994, low-level radioactive
waste generators in the Central States Compact, including AP&L, GSU,
and LP&L, have been required to store such waste on-site until a
Central States Compact facility becomes operational or another site
becomes accessible.
Both the Central States Compact and the Southeast Compact are
working to establish additional disposal sites. The System, along
with other waste generators, funds the development costs for new
disposal facilities. The System's expenditures to date are
approximately $30 million; and future levels of expenditures cannot be
predicted. Until such facilities are established, the System will
continue to seek access to existing facilities, which may be available
at costs that are higher than those incurred in the past, or which may
be unavailable. If such access is unavailable, the System will store
low-level waste on-site at the affected units.
Decommissioning. AP&L, GSU, LP&L, and System Energy are
recovering portions of their estimated decommissioning costs for ANO,
River Bend, Waterford 3, and Grand Gulf 1, respectively. These amounts
are being deposited in external trust funds that, together with the
earnings thereon, can only be used for future decommissioning costs.
Estimated decommissioning costs are regularly reviewed and updated to
reflect inflation and changes in regulatory requirements and
technology, and applications will be made to appropriate regulatory
authorities to reflect in rates any future changes in projected
decommissioning costs. (For additional information with respect to
decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf
1, respectively, see Note 8 of AP&L's, GSU's, and LP&L's and Note 7 of
System Energy's Notes to Financial Statements, "Commitments and
Contingencies - Spent Nuclear Fuel and Decommissioning Costs.")
Uranium Enrichment Decontamination and Decommissioning Fees. The
EPAct requires all electric utilities (including AP&L, GSU, LP&L, and
System Energy) that have purchased uranium enrichment services from
the DOE to contribute up to a total of $150 million annually, adjusted
for inflation, up to a total of $2.25 billion over approximately 15
years, for decommissioning and decontamination of enrichment
facilities. AP&L's, GSU's, LP&L's, and System Energy's estimated
annual contributions to this fund are approximately $3.4 million, $0.9
million, $1.3 million, and $1.4 million, respectively, in 1995 dollars
over approximately 15 years. Contributions to this fund are to be
recovered through rates in the same manner as other fuel costs.
Nuclear Insurance. The Price-Anderson Act limits public
liability for a single nuclear incident to approximately $8.92 billion
as of December 31, 1994. AP&L, GSU, LP&L, and System Energy have
protection with respect to this liability through a combination of
private insurance (currently $200 million each) and an industry
assessment program, and also have insurance for property damage, costs
of replacement power, and other risks relating to nuclear generating
units. (For a discussion of insurance applicable to nuclear programs
of AP&L, GSU, LP&L, and System Energy, see Note 7 of System Energy's
and Note 8 of AP&L's, GSU's, and LP&L's Notes to Financial Statements,
and Note 8 of Entergy Corporation and Subsidiaries, Notes to
Consolidated Financial Statements, "Commitments and Contingencies -
Nuclear Insurance.")
Nuclear Operations
General. Entergy Operations operates ANO, River Bend, Waterford
3, and Grand Gulf 1, subject to the owner oversight of AP&L, GSU,
LP&L, and System Energy, respectively. AP&L, GSU, LP&L, and System
Energy, and the other Grand Gulf 1 and River Bend co-owners, have
retained their ownership interests in their respective nuclear
generating units. AP&L, GSU, LP&L, and System Energy have also
retained their associated capacity and energy entitlements, and pay
directly or reimburse Entergy Operations at cost for its operation of
the units.
On June 24, 1992, the NRC issued a bulletin requiring all
utilities using a certain fire barrier material in a nuclear power
plant to take certain actions related to the material. This material
may have been used in as many as 87 nuclear plants in the United
States, including ANO, River Bend, Waterford 3, and Grand Gulf 1 (see
"River Bend," below for additional information).
ANO. ANO 2 experienced a forced outage for repair of certain
steam generator tubes in March 1992. Further inspections and repairs
were conducted at subsequent refueling and mid-cycle outages in
September 1992, May 1993, April 1994, and January 1995. AP&L's
budgeted maintenance expenditures were adequate to cover the cost of
such repairs. Unit 2's output has been reduced 15 megawatts or 1.6%
due to secondary side fouling, tube plugging, and reduction of primary
temperature. Entergy Operations continues to take steps at ANO 2 to
reduce the number and severity of future tube cracks. In addition,
Entergy Operations continues to meet with the NRC to discuss such
steps and results of inspections of the steam generator tubes, as well
as the timing of future inspections. Additional inspections are
planned for the normal refueling outage scheduled for October 1995.
On January 13, 1993, in connection with the Merger, GSU filed two
applications with the NRC to amend the River Bend operating license.
The applications sought the NRC's consent to the Merger and to a
change in the licensed operator of the facility from GSU to Entergy
Operations. On August 6, 1993, Cajun filed a petition to intervene
and a request for a hearing in the proceedings. On January 27, 1994,
the presiding NRC Atomic Safety and Licensing Board (ASLB) issued an
order granting Cajun's petition to intervene and ordered a hearing on
one of Cajun's contentions. On February 15, 1994, GSU filed an appeal
of the ASLB Order with the NRC. On December 16, 1993, prior to this
ASLB ruling, the NRC Staff issued the two license amendments for River
Bend, making them effective immediately upon consummation of the
Merger. On February 14, 1994, Cajun filed with the D.C. Circuit
petitions for review of the two license amendments issued by the NRC.
These two amendments are in full force and effect, but are subject to
the outcome of the two proceedings. On August 23, 1994, the NRC
issued an order disallowing GSU's appeal in the ASLB proceeding and
upholding the ASLB's January 27, 1994 order. A hearing on the
proceeding before the ASLB is scheduled to begin May 9, 1995.
State Regulation
General. Each of the System operating companies is subject to
regulation by its respective state and/or local regulatory authorities
with jurisdiction over the service areas in which each company
operates. Such regulation includes authority to set rates for
electric and gas service provided at retail. (See "Rate Matters and
Regulation - Rate Matters - Retail Rate Matters," above.)
AP&L is subject to regulation by the APSC and the Tennessee
Public Service Commission (TPSC). APSC regulation includes the
authority to set rates, determine reasonable and adequate service, fix
the value of property used and useful, require proper accounting,
control leasing, control the acquisition or sale of any public utility
plant or property constituting an operating unit or system, set rates
of depreciation, issue certificates of convenience and necessity and
certificates of environmental compatibility and public need, and
control the issuance and sale of securities. Regulation by the TPSC
includes the authority to set standards of service and rates for
service to customers in the state, require proper accounting, control
the issuance and sale of securities, and issue certificates of
convenience and necessity.
GSU is subject to the jurisdiction of the municipal authorities
of incorporated cities in Texas as to retail rates and services within
their boundaries, with appellate jurisdiction over such matters
residing in the PUCT. GSU is also subject to regulation by the PUCT
as to retail rates and services in rural areas, certification of new
generating plants, and extensions of service into new areas. GSU is
subject to regulation by the LPSC as to electric and gas service,
rates and charges, certification of generating facilities and power or
capacity purchase contracts, and other matters.
LP&L is subject to the jurisdiction of the LPSC as to rates and
charges, standards of service, depreciation, accounting, and other
matters, and is subject to the jurisdiction of the Council with
respect to such matters within Algiers.
MP&L is subject to regulation as to service, service areas,
facilities, and retail rates by the MPSC. MP&L is also subject to
regulation by the APSC as to the certificate of environmental
compatibility and public need for the Independence Station.
On October 11, 1994, twelve Mississippi cities filed a complaint
in state court against MP&L and eight electric power associations
seeking a judgment from the court declaring unconstitutional certain
Mississippi statutes that establish the procedure that must be
followed before a municipality can acquire the facilities and
certificate rights of a utility serving in the municipality.
Specifically, the suit requests that the court declare
unconstitutional certain 1987 amendments to the Mississippi Public
Utilities Act that require that the MPSC cancel a utility's
certificate to serve in the municipality before a municipality may
acquire a utility's facilities located in the municipality. The suit
also requests that the court find that Mississippi municipalities can
serve any consumer in the boundaries of the municipality and within
one mile thereof. Such a finding would be contrary to Mississippi
Supreme Court decisions that have held that a municipality cannot
serve in another utility's service area even where the municipal
boundaries extend into such service area. On January 6, 1995, MP&L
and the other defendants filed motions to dismiss. The matter is
pending and will be vigorously contested by MP&L.
NOPSI is subject to regulation as to electric and gas service,
rates and charges, standards of service, depreciation, accounting,
issuance of certain securities, and other matters by the Council.
Franchises. AP&L holds exclusive franchises to provide electric
service in 301 incorporated cities and towns in Arkansas, all of which
are unlimited in duration and terminable by either party. In
Arkansas, franchises are considered to be contracts and therefore are
terminable upon breach of the contract.
GSU holds non-exclusive franchises, permits, or certificates of
convenience and necessity to provide electric and gas service in 55
incorporated villages, cities, and towns in Louisiana and 64
incorporated cities and towns in Texas. GSU ordinarily holds 50-year
franchises in Texas towns and 60-year franchises in Louisiana towns.
The current terms of GSU's electric franchises will expire in the
years 2007-2036 in Texas and in the years 2015-2046 in Louisiana. The
natural gas franchise in the City of Baton Rouge will expire in the
year 2015.
LP&L holds non-exclusive franchises to provide electric service
in 116 incorporated villages, cities, and towns. Most of these
franchises have 25-year terms expiring during the period 1995-2015.
However, six of these municipalities have granted 60-year franchises,
with the last one expiring in the year 2040. Of these franchises,
none has expired to date, one is scheduled to expire as early as 1995,
and 37 are scheduled to expire by year-end 2000. LP&L also supplies
electric service in 353 unincorporated communities, all of which are
located in parishes (counties) from which LP&L holds non-exclusive
franchises to serve the areas in which the unincorporated communities
are located.
MP&L has received from the MPSC certificates of public
convenience and necessity to provide electric service to the areas of
Mississippi that MP&L serves, which include a number of
municipalities. MP&L continues to serve in such municipalities upon
payment of a statutory franchise fee, regardless of whether an
original municipal franchise is still in existence.
NOPSI provides electric and gas service in the City of New
Orleans pursuant to city ordinances which state, among other things,
that the City has a continuing option to purchase NOPSI's electric and
gas utility properties.
System Energy has no franchises from any municipality or state.
Its business is currently limited to wholesale sales of power.
Environmental Regulation
General. In the areas of air quality, water quality, control of
toxic substances and hazardous and solid wastes, and other
environmental matters, Entergy's facilities and operations are subject
to regulation by various federal, state, and local authorities.
Entergy considers itself to be in substantial compliance with those
environmental regulations currently applicable to its facilities and
operations. Entergy has incurred increased costs of construction and
other increased costs in meeting environmental protection standards.
Because environmental regulations are continually changing, the
ultimate compliance costs to Entergy cannot be precisely estimated at
any one time. However, Entergy currently estimates that its potential
capital expenditures for environmental control purposes, including
those discussed in "Clean Air Legislation," below, will not be
material for the System as a whole.
Clean Air Legislation. The Clean Air Act Amendments of 1990 (the
Act) set up three programs, acid rain for control of sulfur and
nitrogen oxides (NOx), ozone nonattainment area for control of NOx and
volatile organic compounds, and operating permits for administration
and enforcement of these and other Clean Air Act programs.
Under the acid rain program, no additional control equipment will
be required to control sulfur dioxide. Regarding sulfur dioxide
emissions, the Act provides "allowances" to most Entergy generating
units based upon past emission levels and operating characteristics.
Each allowance is an entitlement to emit one ton of sulfur dioxide per
year. Under the Act, utilities will be required to possess allowances
for sulfur dioxide emissions from affected generating units. All of
Entergy's generating units are classified as "Phase II" units under
the Act and are therefore subject to sulfur dioxide allowance
requirements beginning in the year 2000. Based on Entergy's operating
history, it is considered a "clean" utility and as such has been
allocated more allowances than are currently necessary for normal
operations. Entergy believes that it will be able to operate its units
efficiently without installing scrubbers or purchasing allowances from
outside sources, and may have excess allowances available for sale to
others.
In addition, Entergy has installed additional continuous emission
monitoring (CEM) equipment at its base load and cycling generating
units to comply with EPA regulations under the Act. Additional CEM
equipment will be installed at peaking generating units in 1995 to
comply with the regulations at an estimated cost of $3.0 million.
Under ozone nonattainment programs in the area served by GSU,
control equipment may eventually be required for nitrogen oxide
reductions due to the ozone nonattainment status of the Baton Rouge,
Louisiana and Beaumont and Houston, Texas, areas. These states are
studying the causes of ozone pollution in these areas and will decide
during 1995 whether to require controls in these areas. If the
states decide to regulate NOx, the cost of such control equipment is
estimated at $16.0 million through 1997.
Under Title V of the Act, EPA promulgated operating permit
regulations in 1994 that may set new operating criteria for the fossil
plants relating to fuels, emissions, and equipment maintenance
practices. Entergy may also have to install additional CEM equipment
as a result of these permits. The extent of the cost will be
determined on a state by state basis as plants are granted permits
during 1995 and 1996. Any capital and operation and maintenance costs
will begin in 1996 and 1997. The authority to impose permit fees
under this program has been delegated to the states by EPA and,
depending on the extent of the state program and the fees imposed by
each state regulatory authority, permit fees for the System could
range from $1.6 to $5.0 million annually.
Entergy currently estimates that future capital costs of
approximately $16.0 million for NOx control and approximately $3.0
million for CEM could be required to comply with the Act. During
1994, Entergy incurred capital costs of approximately $5.7 million for
NOx control and approximately $14.7 million for CEM.
There are several other areas, such as air toxins and visibility,
that will require regulatory study and rule promulgation to determine
whether pollution control equipment is necessary.
Other Environmental Matters. The provisions of the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as
amended (Superfund), among other things, authorize the EPA and,
indirectly, the states to require the generators and certain
transporters of certain hazardous substances released from or at a
site, and the owners or operators of such site, to clean up the site
or reimburse the costs therefor. This statute has been interpreted to
impose joint and several liability on responsible parties. In
compliance with applicable laws and regulations in effect at the time,
the System operating companies have sent waste materials to various
disposal sites over the years. Also, past operating procedures and
maintenance practices, which were not subject to regulation at that
time, are now regulated by various environmental laws. Some of these
sites have been the subject of governmental action, thereby causing
one or more of the System operating companies to be involved with site
cleanup activities. The System operating companies have participated
to various degrees in accordance with their potential liability in
these site cleanups and have, therefore, developed experience with
cleanup costs. Their experience in these matters, and their judgments
related thereto, are utilized by them in evaluating these sites. In
addition, the System operating companies have established reserves for
environmental clean-up/restoration activities.
AP&L. AP&L has received notices from time to time between 1989
and 1993, from the EPA, the Arkansas Department of Pollution Control
and Ecology (ADPC&E), and others that it (among numerous others,
including various utilities, municipalities and other governmental
units, and major corporations) may be a PRP for cleanup costs
associated with various sites in Arkansas. Most of these sites are
neither owned nor operated by any System company. Contaminants at the
sites include principally polychlorinated biphenyls (PCBs), lead, and
other hazardous wastes. These sites and others are described below.
AP&L received notices from the EPA and ADPC&E in 1990 and 1991,
identifying it as one of 30 PRPs (along with LP&L and GSU) at one
Saline County site in Arkansas. The site was contaminated with PCBs
and lead. AP&L actively participated with the cleanup of the site,
which was completed in 1994. EPA has reviewed and accepted the site
remediation and closure report. AP&L to date has expended
approximately $1.0 million at the site and does not anticipate any
significant additional expenditures. The EPA has discovered an
additional site in Saline County that is similar to the site mentioned
above and could involve many of the same PRPs. At EPA's request, AP&L
voluntarily performed stabilization activities at the site. EPA has
indicated that the records associated with the site are inconclusive,
therefore no PRPs have been named at this time. AP&L, LP&L and GSU
believe their potential liability for this site, if any, will not be
material.
Reynolds Metals Company (RMC) and AP&L notified the EPA in 1989
of possible PCB contamination at two former RMC plant sites in
Arkansas to which AP&L had supplied power. AP&L completed remediation
at the substations serving the plant sites at a cost of $1.7 million.
Additional PCB contamination was found in a portion of a drainage
ditch that flows from the RMC's Patterson facility to the Ouachita
River. RMC has demanded that AP&L participate in the remediation
efforts with respect to the ditch. AP&L and independent contractors
engaged by AP&L conducted an investigation of the ditch contamination
and the potential migration of PCBs from the electrical equipment that
AP&L maintained at the plant. The investigation concluded that
little, if any, of the contamination was caused by AP&L. AP&L's
expenditures thus far on the ditch have been approximately $150,000.
It is AP&L's understanding that RMC has spent approximately $10.0
million to complete remediation of the ditch contamination. AP&L has
not received a notice from the EPA that it may be a PRP with respect
to remediation costs for this site. However, RMC is seeking
reimbursement of $5.0 million (50% of expenditures) from AP&L. AP&L
continues to deny responsibility for any of such remediation costs and
believes that its potential liability, if any, for this site will not
be material.
AP&L entered into a Consent Administrative Order dated February
21, 1991, with the ADPC&E that named AP&L as a PRP for cleanup of
contamination associated with the Utilities Services, Inc. state
superfund site located near Rison, Arkansas. Such site was found to
have soil contaminated by PCBs and pentachlorophenol (a wood
preservative chemical). Also, containers and drums that contained
PCBs and other hazardous substances were found at the site. AP&L's
share of total remediation costs is estimated to range between $3.0
million and $5.0 million. AP&L is attempting to identify and notify
other PRPs. AP&L has received assurances from the ADPC&E that it will
use its enforcement authority to allocate remediation expenses among
AP&L and any other PRPs that can be identified (approximately 20 have
been identified to date). AP&L has performed the activities necessary
to stabilize the site, which to date has cost approximately $348,000.
AP&L believes that its potential liability for this site will not be
material.
As a result of an internal investigation, AP&L has discovered
soil contamination at two AP&L-owned sites located in Blytheville,
Arkansas, and Pine Bluff, Arkansas. The contamination appears to be a
result of past operating procedures that were performed prior to any
applicable environmental regulation. AP&L has investigated these
sites to determine the full extent of the contamination and has
stabilized the sites at an aggregate cost of approximately $250,000.
AP&L estimates the remediation cost for both sites to be less than
$1.0 million.
GSU. GSU has been notified by the EPA that it has been
designated as a PRP for the cleanup of sites on which GSU and others
have, or have been alleged to have, disposed of hazardous materials.
GSU is currently negotiating with the EPA and various state
authorities regarding the cleanup of some of these sites. Several
class action and other suits have been filed seeking relief from GSU
and others for damages caused by the disposal of hazardous waste and
for asbestos-related disease that allegedly occurred from exposure on
GSU premises or on premises on which GSU allegedly disposed of
materials (see "Other Regulation and Litigation - GSU," below). While
the amounts at issue in the cleanup efforts and suits may be very
substantial sums, management believes that its financial condition and
results of operations will not be materially affected by the outcome
of the clean-ups and the suits. These environmental liabilities are
described below.
In 1971, GSU purchased certain property near its Sabine
generating station for possible cooling water capability expansion.
Although it was not known to GSU at the time of the purchase, the
property was utilized by area industries in the 1950's and 1960's as
an industrial waste dump. GSU sold the property in 1984. In October
1984 the abandoned waste site on the property was included on the
Superfund National Priorities List (NPL) by the EPA. The EPA has
indicated that it believes GSU to be a PRP for cleanup of the site
based on its past ownership. GSU has advised the EPA that it does not
believe that it has such responsibility. GSU has pursued negotiations
with the EPA and is a member of a task force made up of other PRPs for
the voluntary cleanup of the waste site. A Consent Decree has been
signed by all parties. The ultimate costs for the voluntary cleanup
are not known because additional wastes have been discovered at the
site since the original cleanup costs were estimated, however they are
expected to be at least $15.0 million. GSU has negotiated a
responsible share of 2.26% of the estimated cleanup cost. Federal and
state agencies are presently examining potential liabilities
associated with natural resource damages. This matter is currently
under negotiation with the other PRPs and the agencies. GSU does not
presently believe that its ultimate responsibility with respect to
this site will be material after allowance for previously reserved
amounts.
In March 1993, GSU completed its cleanup activities at a site in
Houston, Texas, which is included in the NPL. On September 20, 1993,
GSU received formal notification from the EPA of its acceptance of the
remedial activities conducted at the site. Currently, other parties
are conducting cleanup activities at the site. However, these cleanup
activities are unrelated to GSU's involvement at the site. Through
1994, GSU incurred cleanup costs of approximately $3.3 million.
Pursuant to the Consent Decree, GSU is responsible for oversight costs
incurred by the EPA. GSU has not received a reimbursement request for
outstanding oversight costs, but anticipates these costs may total
between $250,000 and $500,000. GSU is pursuing contribution for the
cleanup costs at the site from other parties believed to be
potentially responsible.
GSU is currently involved in a multi-phased remedial
investigation of an abandoned manufactured gas plant (MGP) site
located in Lake Charles, Louisiana. The property was the site of an
MGP that is believed to have operated during the period from
approximately 1916 to 1931. Coal tar, a by-product of the
distillation process, was apparently routed to a portion of the
property for disposal. Since GSU purchased the property in 1926, the
same area has been filled with soil and used as a landfill for
miscellaneous items including electrical poles, electrical equipment,
and other debris. Under an Order by the Louisiana Department of
Environmental Quality (LDEQ), which is currently stayed, GSU was
required to investigate and, if necessary, take remedial action at the
site. On February 13, 1995 the EPA published a proposed rule adding
the Lake Charles site to the NPL. Another PRP has been identified and
is believed to have had a role in the ownership and operation of the
MGP. Negotiations with that company for joint participation and any
remedial action are expected to continue. GSU currently is awaiting
notification from the EPA before initiating additional cleanup
negotiations or actions. While studies to determine the location of
the coal tar have been conducted, the cleanup costs of the site are
unknown. GSU does not presently believe that its ultimate
responsibility with respect to this site will be material after
allowance for previously reserved amounts.
GSU has also been advised that it has been named as a PRP, along
with a number of other companies (including LP&L), for an abandoned
waste oil recycling plant site in Livingston Parish, Louisiana, which
is included on the NPL. Although significant remediation has been
completed, additional studies are expected to continue in 1995. GSU
and LP&L have been named as defendants in a class action lawsuit
lodged against a group of PRPs associated with the site. (For
information regarding litigation in connection with the Livingston
Parish site, see "Other Regulation and Litigation - GSU," below.) GSU
does not presently believe that its ultimate responsibility with
respect to this site will be material.
GSU received notification in 1992 from the EPA of potential
liability at a site located in Iota, Louisiana. This site accepted a
variety of wastes, including medical and chemical wastes. In addition
to GSU, over 200 parties have been named as PRPs. The EPA is
continuing its investigation of the site and has notified the PRPs of
the possibility of this site being linked to another site. To date,
GSU has not received notification of liability with regard to the
other site. GSU does not presently believe its ultimate
responsibility with respect to this site will be material.
GSU, along with AP&L and LP&L, was notified in 1990 of its
potential liability at a site located in Saline County, Arkansas (see
"AP&L" above). GSU believes its responsibility to be de minimus at
the one site where the cleanup has been completed and also at the
additional site.
LP&L and NOPSI. LP&L and NOPSI have received notices from time
to time between 1986 and 1993 from the EPA and/or the states of
Louisiana and Mississippi that one or both of the companies may be a
PRP for cleanup costs associated with disposal sites that are
currently in various stages of remediation in Arkansas, Illinois,
Louisiana, Mississippi, and Missouri that are neither owned nor
operated by any System company.
As to one Missouri site, LP&L's and NOPSI's aggregate liability
is currently estimated not to exceed $558,000. Because of the type
and the large number of PRPs (over 700, including many large utilities
and national and international corporations), LP&L and NOPSI do not
expect liabilities in excess of this amount.
As to the two Saline County, Arkansas, sites (see "AP&L" above),
LP&L (along with GSU) believes its responsibilities to be de minimus
because of its limited scope of involvement and the number and nature
of PRPs . LP&L received notice from the EPA in November 1992, that it
(along with AP&L) was involved in the Union County, Arkansas, site.
An agreement has been negotiated and settled with the EPA that
determined LP&L to be a de minimus party with a total liability of
approximately $28,000 (see "AP&L," above).
As to one Mississippi site, LP&L (along with System Energy)
understands that EPA has expended approximately $740,000 for this site
(three separate locations being treated administratively as one). The
State of Mississippi has indicated it intends to have PRPs conduct a
cleanup of the site but has not yet taken formal action. LP&L has
expended $22,300 to settle with the EPA for its costs for this site
and, because there are 44 PRPs for this site (including a number of
major oil companies), does not expect its share of future costs to be
material.
NOPSI received notice from the EPA with respect to a second
Mississippi site in the fall of 1994. NOPSI has advised the EPA in
connection with that site that (1) the natural gas condensate NOPSI
sold in 1983 and 1984 is excluded from the definition of "hazardous
waste" under Superfund and (2) NOPSI is not aware that such material
was ever shipped to the site in question. NOPSI believes it is not
liable with regard to the $298,000 which EPA allegedly incurred in
conducting operations at the site.
With respect to the Livingston Parish, Louisiana, site (involving
at least 70 PRPs, including GSU and many other large and creditworthy
corporations), LP&L has found in its records no evidence of its
involvement. (For information regarding litigation in connection with
the Livingston Parish site, see "Other Regulation and Litigation -
LP&L," below.) At a second Louisiana site (also included on the NPL
and involving 57 PRPs, including a number of major corporations),
NOPSI believes it has no liability for the site because the material
it sent to the site was not a hazardous substance.
During 1994, impact assessments were conducted at a power plant
owned and operated by LP&L. Initial groundwater information is being
collected for submittal to LDEQ. Remediation strategies will be
formulated to restore the area to acceptable conditions. LP&L
estimates costs to be approximately $135,000.
From 1992 to 1994, LP&L performed site assessments and remedial
activities at two retired power plants previously owned and operated
by two Louisiana municipalities. LP&L purchased the power plants, as
part of the acquisition of municipal electric systems after operating
them for the last few years of their useful lives. The assessments
indicated some subsurface contamination from fuel oil. LP&L has
completed all remediation work to the LDEQ's satisfaction for these
two former generating plants, and follow-up sampling has been
completed at one site. Sampling at the other site is expected to be
completed in 1996. Because of LDEQ solid waste regulations
promulgated in 1993, LP&L in 1994 began to close a surface impoundment
at another municipal plant site now owned and operated by LP&L. With
regard to hydrocarbons found in some ground water near the
impoundment, additional assessment activities pursuant to LDEQ review
were completed in January 1995. A report on such activities was filed
with the LDEQ in February 1995.
During 1993, the LDEQ issued new rules for solid waste
regulation, including waste water impoundments. LP&L has determined
that certain of its power plant waste water impoundments are affected
by these regulations and has chosen to either upgrade or close them.
The aggregate cost of the upgrades and closures, to be completed by
1996, is estimated to be $16 million.
System Energy. In February 1990, System Energy received an EPA
notice that it may be a PRP along with numerous other parties for
cleanup costs associated with the same site in Mississippi in which
LP&L is involved. Potential liability is based on the alleged
shipment of waste oil to the site from 1981 to 1985. System Energy
does not expect its share of the total expenditures to be material
because there are 44 PRPs for this site, including a number of major
oil companies.
Other Regulation and Litigation
Entergy Corporation and GSU. In July and August 1992, Entergy
Corporation and GSU filed applications with FERC, the LPSC, and the
PUCT, and Entergy Corporation, Entergy Operations, and Entergy
Services filed an application with the SEC under the Holding Company
Act, seeking authorization of various aspects of the Merger. In
January 1993, GSU filed two applications with the NRC seeking approval
of the change in ownership of GSU and an amendment to the operating
license for River Bend to reflect its operation by Entergy Operations.
All regulatory approvals were obtained in 1993 and the Merger was
consummated on December 31, 1993, (see "Business of Entergy - Entergy
Corporation-GSU Merger," above, for further information).
FERC's December 15, 1993, and May 17, 1994, orders approving the
Merger were appealed to the United States Court of Appeals for the
District of Columbia Circuit by Entergy Services, the City, the
Arkansas Electric Energy Consumers (AEEC), the APSC, Cajun, the MPSC,
the American Forest and Paper Association, the State of Mississippi,
the Cities of Benton and others, and Occidental Chemical Corporation
(Occidental). Entergy seeks review of FERC's deletion of a 40% cap on
the amount of fuel savings GSU may be required to transfer to other
Entergy operating companies under a tracking mechanism designed to
protect the other companies from certain unexpected increases in fuel
costs. The other parties are seeking to overturn FERC's decisions on
various grounds, including the issues of whether FERC appropriately
conditioned the Merger to protect various interested parties from
alleged harm and FERC's reliance on Entergy's transmission tariff to
mitigate any potential anticompetitive impacts of the Merger.
On November 18, 1994, the D. C. Circuit denied motions filed by
Cajun, Occidental, and AEEC for a remand to FERC and a partial summary
grant of the petitions for review. At the same time, the D.C. Circuit
ordered that the cases be held in abeyance pending FERC's issuance of
(1) a final order on remand in the proceedings on Entergy's
transmission tariff, citing its July 12, 1994, opinion discussed in
"Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters -
Open Access Transmission," and (2) a final order on competition issues
in the proceedings on the Merger.
On December 30, 1993, Entergy Services submitted to FERC tariff
revisions to comply with FERC's December 15, 1993, order approving the
Merger. On February 4, 1994, the APSC and AEEC filed with FERC a
joint protest to the compliance filing. They alleged that Entergy
must insulate the ratepayers of AP&L, LP&L, MP&L, and NOPSI from all
litigation liabilities related to GSU's River Bend nuclear facility.
In its May 17, 1994, order on rehearing, FERC addressed Entergy's
commitment to insulate the customers of AP&L, LP&L, MP&L, and NOPSI
against liability resulting from certain litigation involving River
Bend. In response to FERC's clarification of Entergy's commitment,
Entergy Services filed a compliance filing on June 16, 1994, which
amended certain System Agreement language submitted with the December
30, 1993, filing. APSC and AEEC subsequently filed protests
questioning the adequacy of Entergy's June 16, 1994, compliance
filing. Entergy filed an answer to the protest reiterating its full
compliance with the requirements of FERC's May 17, 1994, order on
rehearing. FERC has not yet acted on the compliance filings.
On February 14, 1994, Cajun filed with the D. C. Circuit
petitions for review of the NRC's issuance of two Merger-related
license amendments for River Bend. The D. C. Circuit consolidated the
cases and assigned the cases to be heard by the same panel and on the
same day as the petitions to review the SEC Merger-related orders. On
December 29, 1994, the D. C. Circuit, citing its July 12, 1994,
opinion discussed in "Rate Matters and Regulation - Rate Matters -
Wholesale Rate Matters - Open Access Transmission," ordered the
parties to file motions governing further proceedings within thirty
days. Subsequently, the NRC and Entergy requested that the D. C.
Circuit hold the case in abeyance; Cajun asked the D. C. Circuit to
remand the proceedings to the NRC. On March 14, 1995, the D.C.
Circuit denied the NRC's and Entergy's request, ordered the original
NRC order be set aside, and remanded the case to the NRC for further
consideration.
Requests for rehearing of the SEC order were filed with the SEC
by Houston Industries Incorporated and Houston Lighting & Power
Company on December 28, 1993, and petitions for review seeking to set
aside the SEC order were filed with the D.C. Circuit by these parties
on February 15, 1994, and by Cajun on February 14, 1994. The matter
has been remanded by the D.C. Circuit to the SEC for further
consideration in light of developments at FERC relating to Entergy's
transmission tariffs.
See "Nuclear Operations - River Bend," above for information on
challenges to the NRC's approval of GSU's applications.
Appeals seeking to set aside the LPSC order related to the Merger
were filed in the 19th Judicial District Court for the Parish of East
Baton Rouge, Louisiana, by Houston Lighting & Power Company on August
13, 1993, and by the Alliance for Affordable Energy, Inc. on August
20, 1993. Subsequently, on February 9, 1994, Houston Lighting & Power
Company filed a motion voluntarily dismissing its appeal. On February
9, 1995, the 19th Judicial District Court ruled that there was no duty
on the part of the LPSC to consider environmental issues in this
matter and, accordingly, dismissed the claim of the Alliance based on
those grounds. The Alliance appealed this ruling to the Louisiana
Supreme Court. The matter is pending.
AP&L. Three lawsuits (which have been consolidated) were filed
in the Arkansas District Court by numerous plaintiffs against AP&L and
Entergy Services in connection with the operation of two dams during a
period of heavy rainfall and flooding in May 1990. The consolidated
lawsuits sought approximately $14.4 million in property losses and
other compensatory damages, and $500 million in punitive damages. In
their responses to these complaints, AP&L and Entergy Services
asserted, among other things, that AP&L owns flowage easements giving
it the permanent right to inundate the lands owned or occupied by the
plaintiffs in connection with the operation of the dams. In June
1991, the Arkansas District Court granted summary judgment to AP&L
with respect to the enforceability of its flowage easements. In
November 1991, the Arkansas District Court ruled that Entergy
Services was entitled to the benefit of AP&L's flowage easements, in
effect, removing from consideration damages in the approximate amount
of $13.5 million alleged to have occurred within the areas covered by
the easements. As a result, over 300 plaintiffs claiming damage
within the easements were dismissed from the consolidated case in
December 1991. Certain plaintiffs appealed these orders to the
Eighth Circuit, which appeal was denied in March 1992. Following the
Eighth Circuit's denial of their interlocutory appeal from the
Arkansas District Court's orders, certain of the plaintiffs, without
prejudice to their right to refile, voluntarily dismissed their claims
which had not been disposed of in the Arkansas District Court's
orders, thus making the orders a final adjudication, and appealed
these orders to the Eighth Circuit. The remaining plaintiffs obtained
a stay and an administrative termination of their claims, pending the
outcome of the appeal. In December 1993, a three-judge panel of the
Eighth Circuit filed its opinion affirming the judgment of the
Arkansas District Court and entered judgment accordingly. The
plaintiffs appealing the Arkansas District Court's orders filed
petitions with the Eighth Circuit for a rehearing by the entire Court
sitting en banc, which petitions were denied. These plaintiffs failed
timely to petition the U.S. Supreme Court to issue a writ of
certiorari to permit its review of the Eighth Circuit's decision,
thereby concluding this aspect of the litigation. On February 10,
1995, the plaintiffs who had voluntarily dismissed their claims, and
as to whom the flowage easements did not apply, petitioned the
Arkansas District Court to reopen the proceedings as to their claims.
AP&L and Entergy Services will respond to the petition by opposing the
reopening of this aspect of the litigation on the basis that the
applicable statutes of limitation were not tolled by the order
permitting the voluntary dismissal of the claims and that the delay
since final resolution of the appeals is unreasonable.
GSU. Between 1986 and 1993, GSU and approximately 70 other
defendants, including many national and international corporations,
including LP&L, have been sued in 17 suits in the Livingston Parish,
Louisiana District Court (State District Court) by a number of
plaintiffs who allegedly suffered damage or injury, or are survivors
of persons who allegedly died, as a result of exposure to "hazardous
toxic waste" that emanated from a site in Livingston Parish. The
plaintiffs alleged that the defendants generated, transported, or
participated in the storage of such wastes at the facility, which was
previously operated as a waste oil recycling facility. These State
District Court suits, which seek damages in total amounts ranging from
$1.0 million to $10.0 billion and are now consolidated in a class
action, and three federal suits in three states other than Louisiana
involving issues arising from the same facility, have been removed and
transferred, respectively, to the U.S. District Court for the Middle
District of Louisiana (Federal District Court). On June 23, 1994, the
Federal District Court entered into the record its first case
management and scheduling order, which order, among other things, set
the trial in this matter for September 3, 1996. Such order also
stated the intention of the Federal District Court to facilitate,
prior to the scheduled trial date, appellate review of any significant
decisions. At an April 28, 1994 status conference, the Federal
District Court judge stated that he intended to adopt the Federal
magistrate's recommendation that the class action not be remanded to
the State District Court. On January 26, 1995, the Federal District
Court certified the plaintiffs' lawsuit as a Federal class action. A
trial date of April 11, 1994, previously set by the State District
Court was not met. The matter is pending.
In October 1989, an amended lawsuit petition was filed on behalf
of 985 plaintiffs in the District Court of Jefferson County, Texas,
60th Judicial District in Beaumont, Texas, naming 55 defendants
including GSU. In February 1990, another amended lawsuit petition was
filed in a different state District Court in Jefferson County, Texas,
on behalf of over 200 plaintiffs (subsequently amended to include a
total of 660) naming 127 defendants, including GSU. Possibly 300 to
400 or more of the plaintiffs in Texas may have worked at GSU's
premises. Two similar suits also have been filed in the District
Courts of Jefferson County, Texas, one on behalf of approximately 210
plaintiffs against about 122 defendants, including GSU, and the other
on behalf of about 136 plaintiffs against approximately 63 defendants,
including GSU. In these two suits together, possibly 60 to 70
plaintiffs may have worked at GSU. These two suits have not been
settled. At least five other individual suits have been filed in
Beaumont against GSU and others, seeking damages for alleged asbestos
exposure. All of the plaintiffs in such suits are also suing GSU and
all other defendants on a conspiracy count. There are 25 asbestos-
related law suits filed in the 14th Judicial District Court of
Calcasieu Parish in Lake Charles, Louisiana, on behalf of an aggregate
of 53 plaintiffs naming from 16 to 24 defendants including GSU, and
GSU is aware of as many as 61 additional cases that may be filed. The
suits allege that each plaintiff contracted an asbestos-related
disease from exposure to asbestos insulation products on the premises
of such defendants. Settlements of the two largest of the Jefferson
County suits (involving about 1660 groups of claimants) and all of the
suits in Calcasieu Parish were consummated in the second and third
quarters of 1994. GSU was named as one of a number of defendants in
nearly all of the suits. GSU's share of the settlements was not
material to its financial position or results of operations.
On February 3, 1984, Dow Chemical Company filed a request with
the LPSC for a hearing to consider issues related to the purchase of
cogenerated power by GSU. Other industries subsequently filed similar
requests and the matters were consolidated. In November 1984, the
LPSC completed hearings on rules, policies, and pricing methodologies
applicable to cogeneration. Key issues were whether or not (1) GSU
should be required to pay the industries for avoided capacity costs,
and (2) GSU should be required to wheel power to or from the
industrial plants. Although the matter is still pending before the
LPSC, the LPSC did set interim rates, subject to refund by either Dow
or GSU, which exclude capacity costs.
GSU/Cajun - GSU has significant business relationships with
Cajun, including co-ownership of River Bend and Big Cajun 2, Unit 3.
GSU and Cajun own 70% and 30% undivided interests in River Bend,
respectively, and 42% and 58% undivided interests in Big Cajun 2, Unit
3, respectively.
Cajun/River Bend Litigation - In June 1989, Cajun filed a civil
action against GSU in the United States District Court for the Middle
District of Louisiana (District Court). Cajun's complaint seeks to
annul, rescind, terminate, and/or dissolve the Joint Ownership
Participation and Operating Agreement entered into on August 28, 1979
(Operating Agreement) relating to River Bend. Cajun alleges fraud and
error by GSU, breach of its fiduciary duties owed to Cajun, and/or
GSU's repudiation, renunciation, abandonment, or dissolution of its
core obligations under the Operating Agreement, as well as the lack or
failure of cause and/or consideration for Cajun's performance under
the Operating Agreement. The suit also seeks to recover Cajun's
alleged $1.6 billion investment in the unit as damages, plus
attorneys' fees, interest, and costs. On November 25, 1992, Dixie
Electric Membership Corporation and Southwest Louisiana Electric
Membership Corporation, both members of Cajun, filed suit in the U.S.
District Court for the Western District of Louisiana seeking a
declaration that the Operating Agreement between GSU and Cajun is void
because an allegedly required approval of the LPSC had not been
obtained. This suit was transferred from the Western District to the
Middle District. GSU believes the suits are without merit and is
contesting them vigorously.
A trial without jury on the portion of the suit by Cajun to
rescind the Operating Agreement which began in April 1994 has been
completed, and an order from the District Court is pending. No
assurance can be given as to the outcome of this litigation. If GSU
were ultimately unsuccessful in this litigation and were required to
make substantial payments, GSU would probably be unable to make such
payments and would probably have to seek relief from its creditors
under the United States Bankruptcy Code. If GSU prevails in this
litigation, there can be no assurance that the United States
Bankruptcy Court will allow funding of all required costs of Cajun's
ownership in River Bend.
Since 1992 Cajun has not paid its full share of operating and
maintenance expenses and other costs for repairs and improvements to
River Bend. In addition, certain costs and expenses paid by Cajun
were paid under protest. These actions were taken by Cajun based on
its contention, which GSU disagrees, that River Bend's operating and
maintenance expenses were excessive.
In a letter dated October 21, 1994, and at a subsequent meeting,
Cajun representatives advised Entergy Corporation and GSU that, on
October 25, 1994, Cajun would exhaust its 1994 budget for operating
and maintenance expenses for River Bend, and did not make any further
payments to GSU in 1994 for River Bend operating, maintenance or
capital costs. Cajun also advised that the RUS (which provided
funding to Cajun for its investment in River Bend) would not permit
Cajun to budget funds in 1995 to pay its share of operating and
maintenance expenses or capital costs for River Bend. However, Cajun
stated that it would continue to fund its share of the nuclear
decommissioning trust payments for River Bend, as well as insurance
and safety-related expenses. The unpaid portion of Cajun's River Bend
operating, maintenance, and capital costs for 1994 was approximately
$22.4 million. Cajun's total share of River Bend annual operating
(including nuclear fuel) and maintenance expenses and capital costs
was approximately $76.1 million in 1994.
In view of Cajun's stated expectation that it will fund only a
limited portion of its share of River Bend related operating,
maintenance, and capital costs, GSU notified Cajun that it would (i)
credit GSU's share of expenses for Big Cajun 2, Unit 3 against amounts
due from Cajun to GSU and (ii) seek to market Cajun's share of the
power from River Bend and apply the proceeds to the amounts due from
Cajun to GSU. On November 2, 1994, Cajun discontinued GSU's
entitlement of energy from Big Cajun 2, Unit 3. In response, on
November 3, 1994, GSU filed pleadings in District Court seeking an
order requiring Cajun to provide GSU with the energy from Big Cajun 2,
Unit 3 to which GSU is entitled, and holding that GSU is entitled to
credit amounts due from GSU to Cajun for Big Cajun 2, Unit 3 against
amounts due from Cajun to GSU with respect to River Bend. On December
19, 1994, the District Court issued an injunction prohibiting Cajun
from denying its share of energy from Big Cajun 2, Unit 3 and
stipulating that GSU must make payments for its portion of expenses
for Big Cajun 2, Unit 3 to the registry of the District Court.
Cajun Bankruptcy Filing - On December 14, 1994, the LPSC ordered
Cajun to decrease the rates charged to its member distribution
cooperatives by approximately $30 million per year. The rate decrease
is associated with the LPSC's prior finding of imprudence in Cajun's
participation in River Bend.
On December 21, 1994, Cajun filed a petition in the United
States Bankruptcy Court for the Middle District of Louisiana seeking
bankruptcy relief under Chapter 11 of the United States Bankruptcy
Code. Cajun's bankruptcy could have a material adverse effect on GSU,
including the possibility of an NRC action with respect to the
operation of River Bend. However, GSU is taking appropriate steps to
protect its interests and its claims against Cajun arising from the co-
ownership in River Bend and Big Cajun 2, Unit 3. On December 31,
1994, the District Court issued an order lifting an automatic stay as
to certain proceedings, with the result that the preliminary
injunction granted by the Court on December 19, 1994, remains in
effect. Cajun filed a Notice of Appeal on January 18, 1995, to the
United States Court of Appeals for the Fifth Circuit seeking a
reversal of the District Court's grant of the preliminary injunction.
No hearing date has been set on Cajun's appeal.
In the bankruptcy proceedings, Cajun filed on January 10, 1995, a
motion to reject the Operating Agreement as a burdensome executory
contract. GSU responded on January 10, 1995, with a memorandum
opposing Cajun's motion filed with the District Court. This
memorandum argues that the motion should be denied because (1) the
Operating Agreement is not an executory contract that can be rejected
under the United States Bankruptcy Code, but an agreement establishing
property rights and obligations; (2) Cajun legally cannot have its
payment obligations under the Operating Agreement suspended while
retaining the benefits from co-ownership in River Bend, as the
benefits and obligations are indivisible; (3) Cajun cannot seek to
dispose of its property interest in River Bend or reject the Operating
Agreement with respect thereto without disposing of all of its
property interests and rejecting all of the arrangements under the
River Bend package of agreements consisting of the Operating
Agreement, Big Cajun 2, Unit 3 facility, certain transmission lines
and the buy-back agreement pursuant to when GSU paid Cajun
approximately $600 million for River Bend capacity and energy during
the early years of operation of River Bend; and (4) a legal
determination of Cajun's obligations and interests in River Bend
should only be made as part of a plan of reorganization in bankruptcy
and such determination should be subject to regulatory approvals by
certain agencies with jurisdiction over Cajun, including the NRC. If
the court were to grant Cajun's motion to reject the Operating
Agreement, Cajun would be relieved of its financial obligations under
the contract, while GSU would likely have a substantial damage claim
arising from any such rejection. Although GSU believes that Cajun's
motion to reject the Operating Agreement is non-meritorious, it is not
possible to predict the outcome or ultimate impact of these
proceedings.
During the period in which Cajun is not paying its share of River
Bend costs, GSU intends to fund all costs necessary for the safe,
continuing operation of the unit. The responsibilities of Entergy
Operations as the licensed operator of River Bend, for safely
operating and maintaining the unit are not affected by Cajun's
actions.
The total resulting from Cajun's failure to fund repair projects,
Cajun's funding limitation on refueling outages, and the weekly
funding limitation by Cajun was $55.6 million as of December 31, 1994,
compared with $33.3 million as of December 31, 1993. These amounts
are reflected in long-term receivables with an offsetting reserve in
other deferred credits. Cajun's bankruptcy may affect the ultimate
collectibility of the amounts owed to GSU, including any amounts that
may be awarded in litigation.
In September 1994, in connection with Entergy Corporation's
analysis of certain preacquisition contingencies, Entergy Corporation
increased its acquisition adjustment and GSU recorded a loss provision
associated with the River Bend litigation between GSU and Cajun and
certain underpayments by Cajun of River Bend costs, in accordance with
SFAS 5, "Accounting for Contingencies." See Note 12 of Entergy
Corporation's Notes to Financial Statements, "Entergy Corporation -
GSU Merger" for additional information on provisions for
preacquisition contingencies recorded during 1994.
Cajun/Transmission Service - GSU and Cajun are parties to FERC
proceedings relating to transmission service charge disputes. In
April 1992, FERC issued a final order. In May 1992, GSU and Cajun
filed motions for rehearings which are pending at FERC. In June 1992,
GSU filed a petition for review in the United States Court of Appeals
regarding certain of the issues decided by FERC. In August 1993, the
United States Court of Appeals rendered an opinion reversing the FERC
order regarding the portion of such disputes relating to the
calculations of certain credits and equalization charges under GSU's
service schedules with Cajun. The opinion remanded the issues to FERC
for further proceedings consistent with its opinion. In December
1994, FERC held a hearing to address the issues remanded by the Court
of Appeals. In February 1995, FERC clarified its order, eliminating
an issue that GSU believes the Court of Appeals directed FERC to
reconsider.
GSU interprets the 1992 FERC order and the United States Court of
Appeals' decision to mean that Cajun would owe GSU approximately $93.3
million as of December 31, 1994. However, FERC's February 1995, order
indicates that FERC believes an issue, estimated by GSU to constitute
approximately $26.2 million of this amount, may not be pursued by GSU
in the remand proceedings. GSU further estimates that if it prevails
in its May 1992 motion for rehearing, Cajun would owe GSU
approximately $129.6 million as of December 31, 1994. If Cajun were
to prevail in its May 1992 motion for rehearing to FERC, and if GSU
were not to prevail in its May 1992 motion for rehearing to FERC, and
if FERC does not implement the court's remand as GSU contends is
required, GSU estimates it would owe Cajun approximately $85.6 million
as of December 31, 1994. The above amounts are exclusive of a $7.3
million payment by Cajun on December 31, 1990, which the parties
agreed to apply to the disputed transmission service charges. GSU and
Cajun further agreed that their positions at FERC would remain
unaffected by the $7.3 million payment. Pending FERC's ruling on the
May 1992 motions for rehearing, GSU has continued to bill Cajun
utilizing the historical billing methodology and has booked underpaid
transmission charges, including interest, in the amount of $160.2
million as of December 31, 1994. This amount is reflected in long-
term receivables with an offsetting reserve in other deferred credits.
On December 7, 1993, Cajun filed a complaint in the Middle
District of Louisiana alleging that GSU failed to provide Cajun an
opportunity to construct certain facilities that allegedly would have
reduced its rates under Service Schedule CTOC, and seeking an order
compelling the conveyance of certain facilities and awarding
unspecified damages. GSU has moved to dismiss the complaint on the
basis, among others, that FERC has already addressed the matter in the
proceedings described above.
Cajun/Service Dispute - GSU was requested by Cajun and Jefferson
Davis Electric Cooperative, Inc., (Jefferson Davis) to provide
transmission of power over GSU's system for delivery to the Industrial
Road area near Lake Charles, Louisiana. GSU provides electric service
to industrial and other customers in such area, and Cajun and
Jefferson Davis do not. On October 10, 1989, Cajun filed a complaint
at FERC contending that GSU wrongfully refused to provide Cajun
certain transmission services so that its member, Jefferson Davis,
could provide service to certain industrial customers, and it
requested FERC to order GSU to provide the service. On October 26,
1989, FERC summarily dismissed Cajun's complaint, but the D.C. Circuit
reversed FERC's summary determination and remanded the case to FERC
for a hearing. On June 24, 1992, after a hearing, an ALJ issued an
Initial Decision, again dismissing Cajun's complaint. The ALJ found
that the parties' contract did not require GSU to provide the service
and that Cajun's member, Jefferson Davis, had not sought permission
from the LPSC to serve the end-use customers in question. If
Jefferson Davis secured permission from the LPSC, the ALJ believed
(but did not decide) that FERC would require GSU to provide the
requested transmission service. On March 21, 1994, FERC issued an
order affirming the ALJ and dismissing Cajun's complaint, finding that
GSU properly exercised its contractual right to refuse to provide the
service. On August 3, 1994, FERC denied rehearing. On August 12,
1994, Cajun filed a petition for review of FERC's orders in the United
States Court of Appeals for the District of Columbia Circuit. The
matter is pending.
Cajun and Jefferson Davis also brought a related action in
federal court in the Western District of Louisiana alleging that GSU
breached its obligations under the parties' contract and violated the
antitrust laws by refusing to provide the transmission service
described above. Cajun and Jefferson Davis seek an injunction
requiring GSU to provide the requested service and unspecified treble
damages for GSU's refusal to provide the service. On November 9,
1989, the district court judge denied Cajun's and Jefferson Davis'
motion for a preliminary injunction. On May 3, 1991, the judge stayed
the proceeding pending final resolution of the matters still pending
before FERC.
Cajun/River Bend Repairs - On December 2, 1991, Cajun filed a
complaint seeking declaratory and injunctive relief from the U. S.
District Court for the Middle District of Louisiana. The complaint
concerns GSU's position that Cajun is in default with respect to
paying its share of certain expenditures to repair corrosion damage in
the service water system, to repair a feedwater nozzle crack, and to
repair a turbine rotor. Cajun alleges that it has no obligation to
pay its share of such costs and seeks a declaration that it may elect
not to participate in the funding of such costs and enjoining GSU from
demanding payment therefor or attempting to implement default
provisions in the Operating Agreement with respect thereto. Cajun
alleges that if it is required to pay its share of such costs it would
be forced to default on other obligations. See "Cajun Bankruptcy
Filing," above for information regarding Cajun's bankruptcy filing.
GSU believes that Cajun is in default under the provisions of the
Operating Agreement. No assurance can be given as to the outcome or
timing of this action brought by Cajun.
Cajun/Other - In May 1990, GSU received a subpoena from the
Office of Inspector General - Investigations, United States Department
of Agriculture, seeking production of documents relating to the
construction costs of River Bend. Such office is authorized to
investigate matters relating to programs of the Department of
Agriculture. GSU has been sued by Cajun with respect to its
participation in River Bend with funds made available through
Department programs administered by the RUS. GSU has failed in its
efforts to have the RUS made a party to the Cajun litigation. GSU
does not know the purpose of such Office's investigation, but assumes
that it relates to the Cajun civil litigation since the production of
documents sought by such Office is similar to that sought by Cajun in
its action against GSU. However, there can be no assurance given by
GSU as to the real purpose of such Office's investigation. Among
other areas of responsibility, such Office is authorized to
investigate possible violations of law. GSU believes the subpoena
proceeding has been administratively dismissed without prejudice to
the parties.
LP&L. For information regarding litigation in connection with an
abandoned waste oil recycling plant site in Livingston Parish,
Louisiana, in which LP&L and GSU are defendants, see "GSU," above.
LP&L does not believe that it was a generator of any material
delivered to this facility and is defending vigorously against the
claims in these suits.
Since the mid-1980's, LP&L and the tax authorities of St. Charles
Parish, Louisiana (Parish), the parish in which Waterford 3 is
located, have disputed use taxes paid on nuclear fuel ($4.9 million
through 1989) under protest by LP&L. LP&L continues to be successful
in lawsuits in the Parish with regard to recovering these taxes, plus
interest, and also with regard to Parish lease tax issues pertaining
to fuel financing arrangements. On the grounds of the previous
favorable court decisions, LP&L continues to challenge in the courts
additional use tax assessments that it has paid to the Parish and to
seek additional interest that LP&L claims it is due. On October 13,
1994, Parish tax authorities sued LP&L and Entergy Corporation in the
Civil District Court of Orleans Parish, Louisiana, claiming that $1.4
million of sales and use and lease taxes paid under protest by LP&L
with respect to newly acquired nuclear fuel were not, in fact, paid
under protest and should be disposed of by the Parish, and that
unspecified additional taxes, interest, and penalties are due. Entergy
Corporation was dismissed from the suit and the suit has been
transferred back to the Parish where it will form part of the suit by
LP&L to recover the $1.4 million of sales and use taxes it paid to the
Parish under protest. Also, in early procedural stages are (1) suits
by LP&L with regard to the state use tax on nuclear fuel, and (2)
LP&L's defense (and indemnification, if necessary) of nuclear fuel
lessors under LP&L's fuel financing arrangements in the suits filed by
the Parish use tax authorities claiming approximately $64.0 million in
lease and use taxes. These matters are pending.
Entergy Corporation, LP&L, and System Energy. In August 1994,
Entergy received an IRS report covering the federal income tax audit
of Entergy Corporation and subsidiaries for the years 1988 - 1990.
The report asserts an $80 million tax deficiency for the 1990
consolidated federal income tax returns related primarily to the
application of accelerated investment tax credits associated with
Waterford 3 and Grand Gulf nuclear plants. Entergy Corporation
believes there is no material tax deficiency and is vigorously
contesting the proposed assessment.
EARNINGS RATIOS OF SYSTEM OPERATING COMPANIES AND SYSTEM ENERGY
The System operating companies and System Energy have calculated
ratios of earnings to fixed charges and ratios of earnings to fixed
charges and preferred dividends pursuant to Item 503 of Regulation S-K
of the SEC as follows:
Years Ended December 31,
1990 1991 1992 1993 1994
Ratios of Earnings to
Fixed Charges(a)
AP&L 2.16 2.25 2.28 3.11(f) 2.32
GSU .80(g) 1.56 1.72 1.54 .36(g)
LP&L 2.32 2.40 2.79 3.06 2.91
MP&L 2.42 2.36 2.37 3.79(f) 2.12
NOPSI 2.73 5.66(e) 2.66 4.68(f) 1.91
System Energy 2.10 1.74 2.04 1.87 1.23
Years Ended December 31,
1990 1991 1992 1993 1994
Ratios of Earnings to
Fixed Charges and
Preferred Dividends(a)(b)(c)
AP&L 1.81 1.87 1.86 2.54(f) 1.97
GSU(d) .59(g) 1.19 1.37 1.21 .29(g)
LP&L 1.87 1.95 2.18 2.39 2.43
MP&L 1.93 1.94 1.97 3.08(f) 1.81
NOPSI 2.36 4.97(e) 2.36 4.12(f) 1.73
____________________
(a) "Earnings" as defined by SEC Regulation S-K represent the
aggregate of (1) net income, (2) taxes based on income, (3)
investment tax credit adjustments-net, and (4) fixed charges.
"Fixed Charges" include interest (whether expensed or
capitalized), related amortization, and interest applicable to
rentals charged to operating expenses.
(b) "Preferred Dividends" as defined by SEC Regulation S-K are
computed by dividing the preferred dividend requirement by one
hundred percent (100%) minus the income tax rate.
(c) System Energy's Amended and Restated Articles of Incorporation do
not currently provide for the issuance of preferred stock.
(d) "Preferred Dividends" in the case of GSU also include dividends
on preference stock.
(e) Earnings for the year ended December 31, 1991, include the $90
million effect of the 1991 NOPSI Settlement.
(f) Earnings for the year ended December 31, 1993, include
approximately $81 million, $52 million, and $18 million for AP&L,
MP&L, and NOPSI, respectively, related to the change in
accounting principle to provide for the accrual of estimated
unbilled revenues.
(g) Earnings for the year ended December 31, 1994 and 1990, for GSU
were not adequate to cover fixed charges by $144.8 million and
$60.6 million, respectively. Earnings for the year ended
December 31, 1994 and 1990, were not adequate to cover fixed
charges and preferred dividends by $197.1 million and $165.1
million, respectively.
INDUSTRY SEGMENTS
NOPSI
Narrative Description of NOPSI Industry Segments
Electric Service. NOPSI supplied electric service to 189,836
customers as of December 31, 1994. During 1994, 36% of electric
operating revenues was derived from residential sales, 41% from
commercial sales, 6% from industrial sales, 15% from sales to
governmental and municipal customers, and 2% from sales to public
utilities and other sources.
Natural Gas Service. NOPSI supplied natural gas service to
153,259 customers as of December 31, 1994. During 1994, 57% of gas
operating revenues was derived from residential sales, 18% from
commercial sales, 10% from industrial sales, and 15% from sales to
governmental and municipal customers. (See "Fuel Supply - Natural Gas
Purchased for Resale.")
Selected Financial Information Relating to Industry Segments
For selected financial information relating to NOPSI's industry
segments, see NOPSI's financial statements and Note 11 of NOPSI's
Notes to Financial Statements, "Business Segment Information."
Employees by Segment
NOPSI's full-time employees by industry segment as of
December 31, 1994, were as follows:
Electric 527
Natural Gas 133
---
Total 660
===
(For further information with respect to NOPSI's segments, see
"Property.")
GSU
For the year ended December 31, 1994, 96% of GSU's operating
revenues was derived from the electric utility business. The
remainder of operating revenues was derived 2% from the steam business
and 2% from the natural gas business. Segment information for GSU is
not provided.
PROPERTY
Generating Stations
The total capability of the System's owned and leased generating
stations as of December 31, 1994, by company and by fuel type, is
indicated below:
Owned and Leased Capability MW(1)
Gas
Turbine
and
Internal
Company Total Fossil Nuclear Combustion Hydro
AP&L 4,367 (2) 2,373 1,694 230 (8) 70
GSU 6,547 (2) 5,817 655 (5) 75 -
LP&L 5,405 (2) 4,311 1,075 (6) 19 -
MP&L 3,046 (2) 3,035 (4) - 11 -
NOPSI 927 (2) 912 - 15 -
System Energy 1,028 - 1,028 (7) - -
------ ------ ----- --- --
Total System 21,320 (3) 16,448 (3)(4) 4,452 350 70
====== ====== ===== === ==
_______________________
(1) "Owned and Leased Capability" is the dependable load carrying
capability, as demonstrated under actual operating conditions
based on the primary fuel (assuming no curtailments) that each
station was designed to utilize.
(2) Excludes the capacity of fossil-fueled generating stations placed
on extended reserve as follows: AP&L - 506 MW; GSU - 405 MW; LP&L
- 157 MW; MP&L - 73 MW; and NOPSI - 143 MW. Generating stations
that are not expected to be utilized in the near-term to meet
load requirements are placed in extended reserve shutdown in
order to minimize operating expenses.
(3) Excludes net capability of generating facilities owned by Entergy
Power, which owns 809 MW of fossil-fueled capacity (see "Rate
Matters and Regulation - Rate Matters - Wholesale Rate Matters -
Entergy Power," above).
(4) Includes Independence 2, a coal unit operated by AP&L and jointly
owned 25% by MP&L (210 MW), 31.5% by Entergy Power (265 MW), and
the balance by various municipalities and a cooperative. The
unit was out of service from August 11, 1993 to February 18,
1994, due to an explosion.
(5) GSU's nuclear capability represents its 70% undivided ownership
interest in River Bend; Cajun owns the remaining 30% undivided
interest.
(6) LP&L's nuclear capability represents its 90.7% undivided
ownership interest and 9.3% leasehold interest in Waterford 3.
(7) System Energy's capability represents its 90% interest in Grand
Gulf 1 (78.5% ownership interest and 11.5% leasehold interest).
South Mississippi Electric Power Association has the remaining
10% undivided ownership interest in Grand Gulf 1. Entitlement to
System Energy's capacity has been allocated to AP&L, LP&L, MP&L,
and NOPSI pursuant to the Unit Power Sales Agreement.
(8) Includes 188 MW of capacity leased by AP&L through 1999.
Representatives of the System regularly review load and capacity
projections in order to coordinate and recommend the location and time
of installation of additional generating capacity and of
interconnections in light of the availability of power, the location
of new loads, and maximum economy to the System. Based on load and
capability projections and bulk power availability, the System has no
current need to install additional generating capacity. To delay the
need for new capacity, the System is purchasing power in the wholesale
power market and engaging in conservation and DSM programs, as
discussed in "Business of Entergy - Competition - Least Cost
Planning," above. When new generation resources are needed, the
System plans to meet this need with a variety of sources other than
construction of new base load generating capacity. In the meantime,
the System will meet capacity needs by, among other things, purchasing
power in the wholesale power market and/or removing generating
stations from extended reserve shutdown.
Under the terms of the System Agreement, certain generating
capacity and other power resources are shared among the System
operating companies. Among other things, the System Agreement
provides that parties having generating capacity greater than their
load requirements shall sell such capacity to those parties having
deficiencies in generating capacity and that the purchasers shall pay
to the sellers a charge sufficient to cover certain of the sellers'
costs, including operating expenses, fixed charges on debt, dividend
requirements on preferred and preference stock, and a fair rate of
return on common equity investment. Under the System Agreement, these
charges are based on costs associated with the sellers' steam electric
generating units fueled by oil or gas. In addition, for all energy
exchanged among the System operating companies under the System
Agreement, the purchasers are required to pay the cost of fuel
consumed in generating such energy plus a charge to cover other
associated costs (see "Rate Matters and Regulation - Rate Matters -
Wholesale Rate Matters - System Agreement," above, for a discussion of
FERC proceedings relating to the System Agreement).
The System's business is subject to seasonal fluctuations, with
the peak period occurring in the summer months. The System's 1994 peak
demand of 18,028 MW occurred on June 28, 1994. The net System
capability at the time of peak was 20,884 MW, which reflects a
reduction of the System's total 21,196 MW of owned and leased
capability by net off-system firm sales of 312 MW. The capacity
margin at the time of the peak was approximately 13.7%, not including
units placed on extended reserve and capacity owned by Entergy Power.
Interconnections
The electric power supply facilities of Entergy consist
principally of steam-electric production facilities strategically
located with reference to availability of fuel, protection of local
loads, and other controlling economic factors. These are
interconnected by a transmission system operating at various voltages
up to 500 KV. Generally, with the exception of Grand Gulf 1, Entergy
Power's capacity and a small portion of MP&L's capacity, operating
facilities or interests therein are owned by the System operating
company serving the area in which the facilities are located.
However, all of the System's generating facilities are centrally
dispatched. The System seeks, among other things, the lowest cost
sources of energy from hour to hour. The minimum of investment and
the most efficient use of plant are sought to be achieved, in part,
through the coordinated scheduling of maintenance, inspection, and
overhaul.
Neighboring utilities with which one or more System operating
companies are directly interconnected include, Mississippi Power
Company, Southwestern Electric Power Company, Southwest Power
Administration, Central Louisiana Electric Company, Inc., Oklahoma Gas
and Electric Company, The Empire District Electric Company, Union
Electric Company, Arkansas Electric Cooperative Corporation, Tennessee
Valley Authority, Cajun, Sam Rayburn Dam Electric Cooperative, Inc.,
SRG&T, SRMPA, Associated Electric Cooperative, Inc., Municipal Energy
Agency of Mississippi, Louisiana Energy and Power Authority, Farmers
Electric Cooperative, South Mississippi Electric Power Authority, and
the cities of Lafayette, Plaquemine, and New Roads, Louisiana. GSU
also has an interconnection agreement with Houston Lighting and Power
Company providing a minor amount of emergency service only. The System
operating companies also have interchange agreements with Alabama
Electric Cooperative, Big Rivers Electric Cooperative, Northeast Texas
Electric Cooperative, Inc., Sam Rayburn G&T Electric Cooperative,
Inc., Florida Power Corporation, Florida Power & Light Company,
Jacksonville Electric Authority, Oglethorpe Power Cooperative, the
City of Lafayette, Louisiana, the City of Springfield, Missouri, and
East Kentucky Electric Cooperative.
The System operating companies are members of the Southwest Power
Pool, the primary purpose of which is to ensure the reliability and
adequacy of the electric bulk power supply in the southwest region of
the United States. The Southwest Power Pool is a member of the North
American Electric Reliability Council. AP&L, LP&L, MP&L, and NOPSI
are also members of the Western Systems Power Pool.
Gas Property
As of December 31, 1994, NOPSI distributed and transported
natural gas for distribution solely within the limits of the City of
New Orleans through a total of 1,419 miles of gas distribution mains
and 40 miles of gas transmission lines. NOPSI receives deliveries of
natural gas for distribution purposes at 14 separate locations,
including deliveries from Koch Gateway Pipeline Company (formerly
United Gas Pipe Line Company) at six of these locations. Of the
remaining delivery points, two are principally served by interstate
suppliers and the remainder are served by intrastate suppliers.
As of December 31, 1994, the gas properties of GSU were not
material to GSU.
Titles
The System's generating stations are generally located on lands
owned in fee simple. The greater portion of the transmission and
distribution lines of the System operating companies has been
constructed over lands of private owners pursuant to easements or on
public highways and streets pursuant to appropriate permits. The
rights of each company in the realty on which its properties are
located are considered by it to be adequate for its use in the conduct
of its business. Minor defects and irregularities customarily found
in properties of like size and character exist, but such defects and
irregularities do not materially impair the use of the properties
affected thereby. The System operating companies generally have the
right of eminent domain whereby they may, if necessary, perfect or
secure titles to, or easements or servitudes on, privately-held lands
used or to be used in their utility operations.
Substantially all the physical properties owned by each System
operating company and System Energy, respectively, are subject to the
lien of a mortgage and deed of trust securing the first mortgage bonds
of such company. The Lewis Creek generating station is owned by
GSG&T, Inc., and is not subject to the lien of the GSU mortgage
securing the first mortgage bonds of GSU, but is leased and operated
by GSU. In the case of LP&L, certain properties are also subject to
the liens of second mortgages securing other obligations of LP&L. In
the case of MP&L and NOPSI, substantially all of their properties and
assets are also subject to the second mortgage lien of their
respective general and refunding mortgage bond indentures.
FUEL SUPPLY
The following tabulation shows the percentages of natural gas,
fuel oil, nuclear fuel, and coal used in generation, excluding that of
Entergy Power, during the past three years and it also shows the
average fuel cost per KWH generated by each type of fuel during that
period. The balance of generation, which was immaterial, was provided
by hydroelectric power.
ENTERGY
Natural Gas Fuel Oil Nuclear Fuel Coal
% Cents % Cents % Cents % Cents
of per of per of Per of Per
Year Gen KWH Gen KWH Gen KWH Gen KWH
1994 44 2.24 1 3.99 39 .60 16 1.82
ENTERGY EXCLUDING GSU
Natural Gas Fuel Oil Nuclear Fuel Coal
% Cents % Cents % Cents % Cents
of per of per of Per of Per
Year Gen KWH Gen KWH Gen KWH Gen KWH
1993 27 2.70 7 2.10 51 .58 15 1.91
1992 32 1.99 - - 49 .67 18 1.90
GSU
Natural Gas Fuel Oil Nuclear Fuel Coal
% Cents % Cents % Cents % Cents
of Per of Per of Per of Per
Year Gen KWH Gen KWH Gen KWH Gen KWH
1993 69 2.44 - - 14 1.19 17 1.77
1992 76 2.01 - - 8 1.64 16 1.68
The following tabulation shows the percentages of generation by
fuel type used in generation, excluding that of Entergy Power, for
1994 (actual) and 1995 (projected). The balance of generation, which
is immaterial, is provided by hydroelectric power.
Natural Gas Fuel Oil Nuclear Fuel Coal
1994 1995 1994 1995 1994 1995 1994 1995
System 44% 47% 1% 0% 39% 35% 16% 18%
AP&L 7 2 - - 59 51 33 46
GSU 71 73 - - 13 15 16 12
LP&L 57 62 - - 43 38 - -
MP&L 60 67 13 - - - 27 33
NOPSI 100 100 - - - - - -
System - - - - 100(a) 100(a) - -
Energy
_______________________
(a) Capacity and energy from System Energy's interest in Grand Gulf 1
is allocated as follows: AP&L - 36%; LP&L - 14%; MP&L - 33%; and
NOPSI - 17%.
Natural Gas
The System operating companies retain a mix of long-term firm
and short-term interruptible gas contracts. Long-term firm supply
contracts currently comprise less than 40% of total System
requirements but can be called upon, if necessary, to satisfy a
significant percentage of the System's needs. Additional gas
requirements are satisfied by short-term contracts and spot-market
purchases. Furthermore, in November 1992, GSU entered into a
transportation service agreement with a gas supplier that obligates
such supplier to provide GSU with flexible natural gas service to
certain generating stations by using such supplier's pipeline and gas
storage facility.
Many factors influence the availability and price of natural gas
supplies for power plants including wellhead deliverability, storage
and pipeline capacity, and the demand requirements of the end users.
This demand is closely tied to the severity of the weather conditions
in the region. Furthermore, pricing relative to other energy sources
(i.e., fuel oil, coal, purchased power, etc.) will affect the demand
for natural gas for power plants. Supplies of natural gas are
expected to be adequate in 1995. However, pursuant to federal and
state regulations, gas supplies to power plants may be interrupted
during periods of shortage. To the extent natural gas supplies may be
disrupted, the System operating companies will use alternate fuels,
such as oil, or rely on coal and nuclear generation.
Coal
AP&L has long-term contracts for the supply of low-sulfur coal
for the White Bluff Steam Electric Generating Station and the
Independence Steam Electric Station (which is owned 25% by MP&L).
Coal for the White Bluff Station is supplied under a contract from a
mine in the State of Wyoming. The coal contract provides for the
delivery of sufficient coal to operate the White Bluff Station through
approximately 2002. Coal for the Independence Station is also
supplied under a contract from a mine in the State of Wyoming. Coal
supplied under this contract is expected to meet the requirements of
the Independence Station through at least 2014. GSU has a contract
for a supply of low-sulfur Wyoming coal for Nelson Unit 6, which
should be sufficient to satisfy the fuel requirements at Nelson Unit 6
through 2004. Cajun has advised GSU that it has contracts that should
provide an adequate supply of coal until 1997 for the operation of Big
Cajun 2, Unit 3 (which is operated by Cajun and of which GSU owns a
42% undivided interest).
Nuclear Fuel
Generally, the supply of fuel for nuclear generating units
involves the mining and milling of uranium ore to produce a
concentrate, the conversion of uranium concentrate to uranium
hexafluoride gas, enrichment of that gas, fabrication of nuclear fuel
assemblies for use in fueling nuclear reactors, and disposal of the
spent fuel.
System Fuels is responsible for contracts to acquire nuclear
material to be used in fueling AP&L's, LP&L's, and System Energy's
nuclear units and for maintaining inventories of such materials during
the various stages of processing. Each of these companies currently
contracts for the fabrication of its own nuclear fuel and for
purchasing the required enriched uranium hexafluoride from System
Fuels. The requirements for GSU's River Bend plant are covered by
contracts made by GSU. System Fuels sometimes acts as agent for GSU
in negotiating and/or administering such contracts.
On October 3, 1989, System Fuels entered into a revolving credit
agreement with banks permitting it to borrow up to $45 million to
finance its nuclear materials and services inventory. AP&L, LP&L, and
System Energy agreed to purchase from System Fuels the nuclear
materials and services financed under the agreement if System Fuels
should default in its obligations thereunder. Such purchases would be
allocated based on percentages agreed upon among the parties. In the
absence of such agreement, AP&L, LP&L, and System Energy would each be
obligated to purchase one-third of the nuclear materials and services.
Based upon the planned fuel cycles for the System's nuclear
units, the following tabulation shows the years through which existing
contracts and inventory will provide materials and services:
Acquisition
of or
Conversion Spent
Uranium to Uranium Enrich- Fabri- Fuel
Concentrate Hexafluoride ment cation Disposal
ANO 1 (1) (1) (3) 1997 (4)
ANO 2 (1) (1) (3) 1999 (4)
River Bend (2) (2) (3) 2000 (4)
Waterford 3 (1) (1) (3) 1999 (4)
Grand Gulf 1 (1) (1) (3) 2000 (4)
__________________________
(1) Current contracts will provide a significant percentage of these
materials and services through termination dates ranging from
1995-1998. Additional materials and services required beyond
these dates are estimated to be available for the foreseeable
future.
(2) Current GSU contracts will provide a significant percentage of
these materials and services for River Bend through 1996.
(3) Current contracts will provide a significant percentage of these
materials and services through approximately 2000. (See "Rate
Matters and Regulation - Regulation - Regulation of the Nuclear
Power Industry - Decommissioning," above for information on
annual contributions to a federal decontamination and
decommissioning fund required by the EPAct to be made by AP&L,
GSU, LP&L, and System Energy as a result of their enrichment
contracts with the DOE.)
(4) The Nuclear Waste Policy Act of 1982 provides for the disposal of
spent nuclear fuel or high level waste by the DOE. (See "Rate
Matters and Regulation - Regulation - Regulation of the Nuclear
Power Industry - Spent Fuel and Other High-Level Radioactive
Waste," above for further information).
The System will enter into additional arrangements to acquire
nuclear fuel beyond the dates shown above. Except as noted above,
Entergy cannot predict the ultimate availability or cost of such
arrangements at this time.
AP&L, GSU, LP&L, and System Energy have nuclear fuel leasing
arrangements that provide for AP&L, GSU, LP&L, and System Energy to
lease nuclear fuel and related equipment and services having an
aggregate value of up to $125 million, $105 million, $95 million, and
$105 million for each company, respectively. As of December 31, 1994,
the unrecovered cost base of AP&L's, GSU's, LP&L's, and System
Energy's nuclear fuel leases amounted to approximately $94.6 million,
$80.0 million, $44.2 million, and $46.7 million, respectively. Each
lessor finances its acquisition and ownership of nuclear fuel under a
credit agreement and through the issuance of intermediate-term notes.
The credit agreements, which were entered into by AP&L in 1988, by
LP&L and System Energy in 1989, and by GSU in 1993, had initial terms
of five years, with the exception of GSU, which has an initial term of
three years. These agreements are subject to annual renewal with, in
LP&L's and GSU's case, the consent of the lenders. The credit
agreements for AP&L, LP&L, and System Energy have been extended and
now have termination dates of December 1997, January 1998, and
February 1998, respectively. The credit agreement for GSU was entered
into in December 1993 and has a termination date of December 1997.
The intermediate-term notes issued pursuant to these fuel lease
arrangements have varying maturities through January 31, 1999. It is
expected that the credit agreements will be extended, or alternative
financing will be secured by each lessor, based on the particular
lessee's nuclear fuel requirements. If extensions or alternative
financing cannot be arranged, the lessee in each case must purchase
sufficient nuclear fuel to allow the lessor to retire such borrowings.
Natural Gas Purchased for Resale
NOPSI has several suppliers of natural gas for resale. Its
system is interconnected with three interstate and three intrastate
pipelines. Presently, NOPSI's primary suppliers of natural gas for
resale are Koch Gas Services, Company (KGS), an interstate gas
marketer, and Bridgeline and Pontchartrain, intrastate pipelines.
NOPSI has a firm gas purchase contract with KGS. The KGS gas supply
is transported to NOPSI pursuant to a "No-Notice" transportation
service agreement with Koch Gateway Pipeline Company (KGPC). This
service is subject to FERC-approved rates. NOPSI has firm contracts
with its two intrastate suppliers and also makes interruptible spot
market purchases when economically attractive. In recent years,
natural gas deliveries have been subject primarily to weather-related
curtailments. However, NOPSI has experienced no such curtailments.
After the implementation of FERC-mandated interstate pipeline
restructuring, which occurred on October 31, 1993, curtailments of
interstate gas supply could occur if NOPSI's suppliers failed to
perform their obligations to deliver gas under their supply
agreements. KGPC could curtail transportation capacity only in the
event of pipeline system constraints. Based on the current supply of
natural gas, and absent extreme weather related curtailments, NOPSI
does not anticipate any interruptions in natural gas deliveries to its
customers.
GSU purchases natural gas for resale from a single interstate
supplier. Abandonment of service by the present supplier would be
subject to abandonment proceedings by FERC.
Research
AP&L, GSU, LP&L, MP&L, and NOPSI are members of the Electric
Power Research Institute (EPRI). EPRI conducts a broad range of
research in major technical fields related to the electric utility
industry. Entergy participates in various EPRI projects, based on
Entergy's needs and available resources. During 1992, 1993 and 1994,
the System contributed approximately $16 million, $17 million and
$18 million, respectively, for the various research programs in which
Entergy was involved.
Item 2. Properties
Refer to Item 1. "Business - Property," for information regarding
the properties of the registrants.
Item 3. Legal Proceedings
Refer to Item 1. "Business - Rate Matters and Regulation," for
details of the registrants' material rate proceedings and other
regulatory proceedings and litigation that are pending or that
terminated in the fourth quarter of 1994.
Item 4. Submission of Matters to a Vote of Security Holders
During the fourth quarter of 1994, no matters that would be
described in response to this item were submitted to a vote of the
security holders of Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI,
or System Energy.
PART II
Item 5. Market for Registrants' Common Equity and Related
Stockholder Matters
Entergy Corporation. The shares of Entergy Corporation's common
stock are listed on the New York, Chicago, and Pacific Stock
Exchanges.
The high and low prices for each quarterly period in 1994 and
1993, were as follows:
1994 1993
High Low High Low
(In Dollars)
First 37 3/8 31 1/8 36 1/2 32 1/2
Second 32 1/8 24 5/8 38 1/4 33 1/4
Third 26 1/4 22 5/8 39 7/8 36 1/4
Fourth 24 3/4 21 1/4 39 1/4 35 1/8
Eight consecutive quarterly cash dividends on common stock were
paid to stockholders of Entergy Corporation in 1994 and 1993.
Dividends of 45 cents per share were paid in each of the four quarters
of 1994. In 1993, dividends of 40 cents per share were paid in each
of the first three quarters and dividends of 45 cents per share were
paid in the last quarter.
As of February 28, 1995, there were 103,100 stockholders of
record of Entergy Corporation.
For information with respect to Entergy Corporation's future
ability to pay dividends, refer to Note 7 of Entergy Corporation and
Subsidiaries' Notes to Consolidated Financial Statements, "Dividend
Restrictions." In addition to the restrictions described in Note 7,
the Holding Company Act provides that, without approval of the SEC,
the unrestricted, undistributed retained earnings of any Entergy
Corporation subsidiary are not available for distribution to Entergy
Corporation's common stockholders until such earnings are made
available to Entergy Corporation through the declaration of dividends
by such subsidiaries.
AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy. There is no
market for the common stock of System Energy and the System operating
companies, all of which is owned by Entergy Corporation. Prior to
December 31, 1993, GSU's common stock was publicly held. Effective
with the Merger, all shares of GSU common stock were acquired by
Entergy Corporation. No cash dividends on common stock were paid by
GSU to its stockholders in 1993. Cash dividends on common stock paid
by AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy to Entergy
Corporation during 1994 and 1993, were as follows:
1994 1993
(In Millions)
AP&L $80.0 $156.3
GSU 289.1 -
LP&L 167.1 167.6
MP&L 45.6 85.8
NOPSI 33.3 43.9
System Energy 148.3 233.1
For information with respect to restrictions that limit the
ability of System Energy and the System operating companies to pay
dividends, and for information with respect to dividends paid to
Entergy Corporation by its subsidiaries subsequent to December 31,
1994, refer respectively, to Note 6 of System Energy's and Note 7 of
AP&L's, GSU's, LP&L's, MP&L's, and NOPSI's Notes to Financial
Statements, "Dividend Restrictions."
Item 6. Selected Financial Data
Entergy Corporation. Refer to information under the heading
"Entergy Corporation and Subsidiaries Selected Financial Data - Five-
Year Comparison."
AP&L. Refer to information under the heading "Arkansas Power &
Light Company Selected Financial Data - Five-Year Comparison."
GSU. Refer to information under the heading "Gulf States
Utilities Company Selected Financial Data - Five-Year Comparison."
LP&L. Refer to information under the heading "Louisiana Power &
Light Company Selected Financial Data - Five-Year Comparison."
MP&L. Refer to information under the heading "Mississippi Power
& Light Company Selected Financial Data - Five-Year Comparison."
NOPSI. Refer to information under the heading "New Orleans
Public Service Inc. Selected Financial Data - Five-Year Comparison."
System Energy. Refer to information under the heading "System
Energy Resources, Inc. Selected Financial Data - Five-Year
Comparison."
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Entergy Corporation. Refer to information under the heading
"ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL
DISCUSSION AND ANALYSIS."
AP&L. Refer to information under the heading "ARKANSAS POWER &
LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS."
GSU. Refer to information under the heading "GULF STATES
UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS."
LP&L. Refer to information under the heading "LOUISIANA POWER &
LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS."
MP&L. Refer to information under the heading "MISSISSIPPI POWER
& LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS."
NOPSI. Refer to information under the heading "NEW ORLEANS
PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS."
System Energy. Refer to information under the heading "SYSTEM
ENERGY RESOURCES, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND
ANALYSIS."
Item 8. Financial Statements and Supplementary Data.
INDEX TO FINANCIAL STATEMENTS
Entergy Corporation and Subsidiaries:
Definitions 61
Report of Management 64
Audit Committee Chairman's Letter 65
Reports of Independent Accountants 66
Independent Auditors' Report 67
Consolidated Balance Sheets, December 31, 1994 and 1993 68
Statements of Consolidated Cash Flows For the Years Ended
December 31, 1994, 1993 and 1992 70
Management's Financial Discussion and Analysis 72
Statements of Consolidated Income For the Years Ended
December 31, 1994, 1993 and 1992 75
Statements of Consolidated Retained Earnings and Paid-In
Capital for the Years Ended December 31, 1994, 1993 and 1992 76
Management's Financial Discussion and Analysis (continued) 77
Notes to Consolidated Financial Statements 86
Selected Financial Data - Five-Year Comparison 120
AP&L:
Definitions 122
Report of Management 124
Audit Committee Chairman's Letter 125
Reports of Independent Accountants 126
Independent Auditors' Report 127
Balance Sheets, December 31, 1994 and 1993 128
Statements of Cash Flows For the Years Ended
December 31, 1994, 1993 and 1992 130
Management's Financial Discussion and Analysis 131
Statements of Income For the Years Ended
December 31, 1994, 1993 and 1992 132
Statements of Retained Earnings for the Years Ended
December 31, 1994, 1993 and 1992 133
Management's Financial Discussion and Analysis (continued) 134
Notes to Financial Statements 139
Selected Financial Data - Five-Year Comparison 156
GSU:
Definitions 158
Report of Management 160
Audit Committee Chairman's Letter 161
Report of Independent Accountants 163
Balance Sheets, December 31, 1994 and 1993 164
Statements of Cash Flows For the Years Ended
December 31, 1994, 1993 and 1992 166
Management's Financial Discussion and Analysis 167
Statements of Income (Loss) For the Years Ended
December 31, 1994, 1993 and 1992 168
Statements of Retained Earnings and Paid-In Capital
for the Years Ended December 31, 1994, 1993 and 1992 169
Management's Financial Discussion and Analysis (continued) 170
Notes to Financial Statements 176
Selected Financial Data - Five-Year Comparison 203
LP&L:
Definitions 206
Report of Management 208
Audit Committee Chairman's Letter 209
Reports of Independent Accountants 210
Independent Auditors' Report 211
Balance Sheets, December 31, 1994 and 1993 212
Statements of Cash Flows For the Years Ended
December 31, 1994, 1993 and 1992 214
Management's Financial Discussion and Analysis 215
Statements of Income For the Years Ended
December 31, 1994, 1993 and 1992 216
Statements of Retained Earnings for the Years
Ended December 31, 1994, 1993 and 1992 217
Management's Financial Discussion and Analysis (continued) 218
Notes to Financial Statements 222
Selected Financial Data - Five-Year Comparison 239
MP&L:
Definitions 242
Report of Management 244
Audit Committee Chairman's Letter 245
Reports of Independent Accountants 246
Independent Auditors' Report 247
Balance Sheets, December 31, 1994 and 1993 248
Statements of Cash Flows For the Years Ended
December 31, 1994, 1993 and 1992 250
Management's Financial Discussion and Analysis 251
Statements of Income For the Years Ended
December 31, 1994, 1993 and 1992 252
Statements of Retained Earnings for the Years Ended
December 31, 1994, 1993 and 1992 253
Management's Financial Discussion and Analysis (continued) 254
Notes to Financial Statements 259
Selected Financial Data - Five-Year Comparison 274
NOPSI:
Definitions 276
Report of Management 278
Audit Committee Chairman's Letter 279
Reports of Independent Accountants 280
Independent Auditors' Report 281
Balance Sheets, December 31, 1994 and 1993 282
Statements of Cash Flows For the Years Ended
December 31, 1994, 1993 and 1992 284
Management's Financial Discussion and Analysis 285
Statements of Income For the Years Ended December 31, 1994, 1993
and 1992 286
Statements of Retained Earnings for the Years Ended
December 31, 1994, 1993 and 1992 287
Management's Financial Discussion and Analysis (continued) 288
Notes to Financial Statements 293
Selected Financial Data - Five-Year Comparison 308
System Energy:
Definitions 310
Report of Management 312
Audit Committee Chairman's Letter 313
Reports of Independent Accountants 314
Independent Auditors' Report 315
Balance Sheets, December 31, 1994 and 1993 316
Statements of Cash Flows For the Years Ended
December 31, 1994, 1993 and 1992 318
Management's Financial Discussion and Analysis 319
Statements of Income For the Years Ended
December 31, 1994, 1993 and 1992 320
Statements of Retained Earnings for the Years Ended
December 31, 1994, 1993 and 1992 321
Management's Financial Discussion and Analysis (continued) 322
Notes to Financial Statements 325
Selected Financial Data - Five-Year Comparison 340
Entergy Corporation and Subsidiaries
1994 Financial Statements
ENTERGY CORPORATION AND SUBSIDIARIES
DEFINITIONS
Certain abbreviations or acronyms used in the Financial Statements, Notes
to Financial Statements, and Management's Financial Discussion and Analysis are
defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
ANO Arkansas Nuclear One Steam Electric Generating
Station
ANO 2 Unit No. 2 of ANO
AP&L Arkansas Power & Light Company
APSC Arkansas Public Service Commission
Cajun Cajun Electric Power Cooperative, Inc.
Council Council of the City of New Orleans, Louisiana
Entergy or System Entergy Corporation and its various direct and
indirect subsidiaries
Entergy Enterprises Entergy Enterprises, Inc.
Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy
Corporation that has operating responsibility for
Grand Gulf 1, Waterford 3, ANO, and River Bend
Entergy Services Entergy Services, Inc.
Entergy Power Entergy Power, Inc., a subsidiary of Entergy
Corporation that markets capacity and energy for
resale from certain generating facilities to other
parties, principally non-affiliates
EPAct The Energy Policy Act of 1992
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
G&R Bonds General and Refunding Mortgage Bonds issued and
issuable by MP&L and NOPSI
Grand Gulf 1 Unit No. 1 of the Grand Gulf Steam Electric
Generating Station (nuclear)
Grand Gulf 2 Unit No. 2 of the Grand Gulf Steam Electric
Generating Station (nuclear)
GSU Gulf States Utilities Company (including wholly
owned subsidiaries - Varibus Corporation, GSG&T,
Inc., Prudential Oil and Gas, Inc., and Southern
Gulf Railway Company)
KWH Kilowatt-Hour(s)
LP&L Louisiana Power & Light Company
LPSC Louisiana Public Service Commission
Merger The combination transaction, consummated on
December 31, 1993, by which GSU became a subsidiary
of Entergy Corporation and Entergy Corporation
became a Delaware corporation
Money Pool Entergy Money Pool, which allows certain System
companies to borrow from, or lend to, certain other
System companies
MP&L Mississippi Power & Light Company
MPSC Mississippi Public Service Commission
1991 NOPSI Settlement Agreement, retroactive to October 4, 1991, among
NOPSI, the Council, the Alliance for Affordable
Energy, Inc., and others that settled certain Grand
Gulf 1 prudence issues and pending litigation
related to the resolution (including the
Determinations and Order referred to therein)
adopted by the Council on February 4, 1988,
disallowing NOPSI's recovery of $135 million of
previously deferred Grand Gulf 1-related costs
NOPSI New Orleans Public Service Inc.
PUCT Public Utility Commission of Texas
Rate Cap The level of GSU's retail electric base rates in
effect at December 31, 1993, for the Louisiana
retail jurisdiction, and the level in effect prior
to the Texas Cities Rate Settlement for the Texas
retail jurisdiction, that may not be exceeded for
the five years following December 31, 1993
River Bend River Bend Steam Electric Generating Station
(nuclear), owned 70% by GSU
RUS Rural Utility Services (formerly the Rural
Electrification Administration or "REA")
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
promulgated by the FASB
SFAS 106 SFAS 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions"
SFAS 109 SFAS 109, "Accounting for Income Taxes"
System Agreement Agreement, effective January 1, 1983, as
subsequently modified by the FERC, among the System
operating companies relating to the sharing of
generating capacity and other power resources
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively
System or Entergy Entergy Corporation and its various direct and
indirect subsidiaries
Waterford 3 Unit No. 3 of the Waterford Steam Electric
Generating Station (nuclear)
ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENT
The management of Entergy Corporation has prepared and is responsible for
the financial statements and related financial information included herein. The
financial statements are based on generally accepted accounting principles.
Financial information included elsewhere in this report is consistent with the
financial statements.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting controls that
is designed to provide reasonable assurance, on a cost-effective basis, as to
the integrity, objectivity, and reliability of the financial records, and as to
the protection of assets. This system includes communication through written
policies and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and the
training of personnel. This system is also tested by a comprehensive internal
audit program.
The independent public accountants provide an objective assessment of the
degree to which management meets its responsibility for fairness of financial
reporting. They regularly evaluate the system of internal accounting controls
and perform such tests and other procedures as they deem necessary to reach and
express an opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide reasonable
assurance that its operations are carried out with a high standard of business
conduct.
/s/ Edwin Lupberger /s/ Gerald D. McInvale
EDWIN LUPBERGER GERALD D. MCINVALE
Chairman and Chief Executive Officer Senior Vice President and
Chief Financial Officer
ENTERGY CORPORATION AND SUBSIDIARIES
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Entergy Corporation Board of Directors' Audit Committee is comprised of
four directors, who are not officers of Entergy Corporation: H. Duke
Shackelford (Chairman), Lucie J. Fjeldstad, Dr. Norman C. Francis, and James R.
Nichols. The committee held four meetings during 1994.
The Audit Committee oversees Entergy Corporation's financial reporting
process on behalf of Entergy Corporation's Board of Directors. In fulfilling
its responsibility, the committee recommended to the board, subject to
stockholder approval, the selection of Entergy Corporation's independent public
accountants (Coopers & Lybrand L.L.P.).
The Audit Committee discussed with Entergy's internal auditors and the
independent public accountants the overall scope and specific plans for their
respective audits, as well as Entergy Corporation's consolidated financial
statements and the adequacy of Entergy Corporation's internal controls. The
committee met, together and separately, with Entergy's internal auditors and
independent public accountants, without management present, to discuss the
results of their audits, their evaluation of Entergy Corporation's internal
controls, and the overall quality of Entergy Corporation's financial reporting.
The meetings also were designed to facilitate and encourage any private
communication between the committee and the internal auditors or independent
public accountants.
/s/ H. Duke Shackelford
H. DUKE SHACKELFORD
Chairman, Audit Committee
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
Entergy Corporation
We have audited the accompanying consolidated balance sheet of Entergy
Corporation and Subsidiaries as of December 31, 1994, and the related statements
of consolidated income, retained earnings and paid-in capital and cash flows for
the year then ended. These financial statements are the responsibility of the
Corporation's management. Our responsibility is to express an opinion on these
financial statements based on our audit. The consolidated financial statements
of Entergy Corporation and Subsidiaries as of December 31, 1993 and for the
years ended December 31, 1993 and 1992, were audited by other auditors, whose
report, dated February 11, 1994, included explanatory paragraphs that (i)
described changes in 1993 in methods of accounting for revenues, income taxes
and postretirement benefits other than pensions (Notes 1, 3 and 10,
respectively); (ii) uncertainties regarding costs capitalized by Gulf States
Utilities Company for its River Bend Unit I Nuclear Generating Plant (River
Bend) and other rate-related contingencies which may result in a refund of
revenues previously collected (Note 2); and, (iii) an uncertainty regarding
civil actions against Gulf States Utilities Company (Note 8).
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Entergy
Corporation and Subsidiaries as of December 31, 1994, and the result of their
operations and their cash flows for the year then ended in conformity with
generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, the net
amount of capitalized costs for River Bend exceed those costs currently being
recovered through rates. At December 31, 1994, approximately $685 million is
not currently being recovered through rates. If current regulatory and court
orders are not modified, a write-off of all or a portion of such costs may be
required. Additionally, as discussed in Note 2 to the consolidated financial
statements, other rate-related contingencies exist which may result in refunds
of revenues previously collected. The extent of such write-off of capitalized
River Bend costs or refunds of revenues previously collected, if any, will not
be determined until appropriate rate proceedings and court appeals have been
concluded. Accordingly, the accompanying consolidated financial statements do
not include any adjustments or provision for write-off or refund that might
result from the outcome of these uncertainties.
As discussed in Note 8 to the consolidated financial statements, civil
actions have been initiated against Gulf States Utilities Company to, among
other things, recover the co-owner's investment in River Bend and to annul the
River Bend Joint Ownership Participation and Operating Agreement. The ultimate
outcome of these proceedings cannot presently be determined.
/s/ Coopers & Lybrand L.L.P.
COOPERS & LYBRAND L.L.P.
New Orleans, Louisiana
February 21, 1995, except for the last paragraph
of "Filings with the PUCT and Texas Cities" in
Note 2, as to which the date is March 20, 1995
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of
Entergy Corporation
We have audited the accompanying consolidated balance sheet of Entergy
Corporation and subsidiaries as of December 31, 1993, and the related statements
of consolidated income, retained earnings and paid-in capital, and cash flows
for each of the two years in the period ended December 31, 1993. These
financial statements are the responsibility of the Corporation's management.
Our responsibility is to express an opinion on these financial statements based
on our audits. We did not audit the financial statements of Gulf States
Utilities Company (a consolidated subsidiary acquired on December 31, 1993),
which statements reflect total assets constituting 31% of consolidated total
assets at December 31, 1993. Those statements were audited by other auditors
whose report (which included explanatory paragraphs regarding the uncertainties
discussed in the fourth and fifth paragraphs below) has been furnished to us,
and our opinion, insofar as it relates to the amounts included for Gulf States
Utilities Company, is based solely on the report of such other auditors.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits and the report of the other auditors provide a
reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors,
such consolidated financial statements present fairly, in all material respects,
the financial position of Entergy Corporation and subsidiaries at December 31,
1993, and the results of their operations and their cash flows for each of the
two years in the period ended December 31, 1993 in conformity with generally
accepted accounting principles.
The Corporation acquired a 70% interest in River Bend Unit I Nuclear
Generating Plant (River Bend) through its acquisition of Gulf States Utilities
Company on December 31, 1993. As discussed in Note 2 to the consolidated
financial statements, the net amount of capitalized costs for River Bend exceed
those costs currently being recovered through rates. At December 31, 1993,
approximately $747 million is not currently being recovered through rates. If
current regulatory and court orders are not modified, a write-off of all or a
portion of such costs may be required. Additionally, as discussed in Note 2 to
the consolidated financial statements, other rate-related contingencies exist
which may result in a refund of revenues previously collected. The extent of
such write-off of capitalized River Bend costs or refund of revenues previously
collected, if any, will not be determined until appropriate rate proceedings and
court appeals have been concluded. Accordingly, the accompanying 1993
consolidated financial statements do not include any adjustments that might
result from the outcome of these uncertainties.
As discussed in Note 8 to the consolidated financial statements, civil
actions have been initiated against Gulf States Utilities Company to, among
other things, recover the co-owner's investment in River Bend and to annul the
related joint ownership participation and operating agreement. The ultimate
outcome of these proceedings, including their impact on Gulf States Utilities
Company, cannot presently be determined. Accordingly, the accompanying 1993
consolidated financial statements do not include any adjustments that might
result from the outcome of this uncertainty.
As discussed in Note 1 to the consolidated financial statements, certain of
the Corporation's subsidiaries changed their method of accounting for revenues
in 1993 and, as discussed in Notes 3 and 10 to the consolidated financial
statements, in 1993 the Corporation changed its methods of accounting for income
taxes and postretirement benefits other than pensions, respectively.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 11, 1994
ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
1994 1993
(In Thousands)
Utility Plant:
Electric $21,184,013 $20,848,844
Plant acquisition adjustment - GSU 487,955 380,117
Electric plant under leases 668,846 663,024
Property under capital leases - electric 161,950 175,276
Natural gas 164,013 156,452
Steam products 77,307 75,689
Construction work in progress 476,816 533,112
Nuclear fuel under capital leases 265,520 329,433
Nuclear fuel 70,147 17,760
----------- -----------
Total 23,556,567 23,179,707
Less - accumulated depreciation and amortization 7,639,549 7,157,981
----------- -----------
Utility plant - net 15,917,018 16,021,726
----------- -----------
Other Property and Investments:
Decommissioning trust funds 207,395 172,960
Other 240,745 183,597
----------- -----------
Total 448,140 356,557
----------- -----------
Current Assets:
Cash and cash equivalents:
Cash 87,700 27,345
Temporary cash investments - at cost,
which approximates market 526,207 536,404
----------- -----------
Total cash and cash equivalents 613,907 563,749
Special deposits 8,074 36,612
Notes receivable 19,190 17,710
Accounts receivable:
Customer (less allowance for doubtful accounts of
$6.7 million in 1994 and $8.8 million in 1993) 325,410 315,796
Other 66,651 81,931
Accrued unbilled revenues 240,610 257,321
Fuel inventory 93,211 110,204
Materials and supplies - at average cost 365,956 360,353
Rate deferrals 380,612 333,311
Prepayments and other 98,811 98,144
----------- -----------
Total 2,212,432 2,175,131
----------- -----------
Deferred Debits and Other Assets:
Regulatory Assets:
Rate deferrals 1,451,926 1,876,051
SFAS 109 regulatory asset - net 1,417,646 1,385,824
Unamortized loss on reacquired debt 232,420 210,698
Other regulatory assets 316,878 283,846
Long-term receivables 277,830 228,030
Other 339,201 338,834
----------- -----------
Total 4,035,901 4,323,283
----------- -----------
TOTAL $22,613,491 $22,876,697
=========== ===========
See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
1994 1993
(In Thousands)
Capitalization:
Common stock, $0.01 par value, authorized 500,000,000
shares; issued 230,017,485 shares in 1994 and
231,219,737 shares in 1993 $2,300 $2,312
Paid-in capital 4,202,134 4,223,682
Retained earnings 2,223,739 2,310,082
Less - treasury stock (2,608,908 shares in 1994) 77,378 -
----------- -----------
Total common shareholders' equity 6,350,795 6,536,076
Subsidiaries' preference stock 150,000 150,000
Subsidiaries' preferred stock:
Without sinking fund 550,955 550,955
With sinking fund 299,946 349,053
Long-term debt 7,093,473 7,355,962
----------- -----------
Total 14,445,169 14,942,046
----------- -----------
Other Noncurrent Liabilities:
Obligations under capital leases 273,947 322,867
Other 310,977 296,572
----------- -----------
Total 584,924 619,439
----------- -----------
Current Liabilities:
Currently maturing long-term debt 349,085 322,010
Notes payable 171,867 43,667
Accounts payable 471,120 413,727
Customer deposits 134,478 127,524
Taxes accrued 92,578 118,267
Accumulated deferred income taxes 40,313 73,933
Interest accrued 195,639 210,894
Dividends declared 13,599 13,404
Deferred revenue - gas supplier judgment proceeds - 14,632
Deferred fuel cost 27,066 4,528
Obligations under capital leases 151,904 194,015
Reserve for rate fefund 56,972 -
Other 327,330 233,313
----------- -----------
Total 2,031,951 1,769,914
----------- -----------
Deferred Credits:
Accumulated deferred income taxes 3,915,138 3,829,041
Accumulated deferred investment tax credits 649,898 793,375
Other 986,411 922,882
----------- -----------
Total 5,551,447 5,545,298
----------- -----------
Commitments and Contingencies (Notes 2, 8, and 9)
TOTAL $22,613,491 $22,876,697
=========== ===========
See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Activities:
Net income $341,841 $551,930 $437,637
Noncash items included in net income:
Cumulative effect of a change in accounting principle - (93,841) -
Change in rate deferrals/excess capacity-net 394,344 200,532 109,153
Depreciation and decommissioning 656,896 443,550 424,958
Deferred income taxes and investment tax credits (123,503) 17,669 118,562
Allowance for equity funds used during construction (11,903) (8,049) (7,355)
Amortization of deferred revenues (14,632) (42,470) (38,646)
Gain on sale of property - net - - (19,612)
Changes in working capital:
Receivables 22,377 (40,682) (19,150)
Fuel inventory 16,993 (1,161) 20,008
Accounts payable 57,393 (9,167) (54,559)
Taxes accrued (25,689) (32,761) 28,561
Interest accrued (15,255) (758) (10,845)
Reserve for rate refund 56,972 -
Other working capital accounts 144,297 51,100 (12,428)
Refunds to customers - gas contract settlement - (56,027) (56,066)
Decommissioning trust contributions (24,755) (20,402) (20,896)
Provision for estimated losses and reserves 22,522 20,832 (24,911)
Other 39,869 94,092 (43,185)
---------- ---------- --------
Net cash flow provided by operating activities 1,537,767 1,074,387 831,226
---------- ---------- --------
Investing Activities:
Merger with GSU - cash paid - (250,000) -
Merger with GSU - cash acquired - 261,349 -
Construction / capital expenditures (676,180) (512,235) (438,845)
Allowance for equity funds used during construction 11,903 8,049 7,355
Nuclear fuel purchases (179,932) (118,216) (60,359)
Proceeds from sale/leaseback of nuclear fuel 128,675 121,526 62,332
Investment in nonregulated/nonutility properties (49,859) (76,870) (35,189)
Proceeds received from sale of property 26,000 - 67,985
Decrease in other temporary investments - 17,012 114,651
---------- ---------- --------
Net cash flow used in investing activities (739,393) (549,385) (282,070)
---------- ---------- --------
Financing Activities:
Proceeds from the issuance of:
First mortgage bonds 59,410 605,000 637,114
General and refunding mortgage bonds 24,534 350,000 65,000
Preferred stock - - 120,999
Other long-term debt 164,699 106,070 48,067
Premium and expense on refinancing sale/leaseback bonds (48,497) - -
Retirement of:
First mortgage bonds (303,800) (911,692) (1,009,320)
General and refunding mortgage bonds (45,000) (99,400) -
Other long-term debt (148,962) (69,982) (17,412)
Repurchase of common stock (119,486) (20,558) (105,673)
Redemption of preferred stock (49,091) (56,000) (109,369)
Common stock dividends paid (410,223) (287,483) (256,117)
Changes in short-term borrowings 128,200 43,000 -
---------- ---------- --------
Net cash flow used in financing activities (748,216) (341,045) (626,711)
---------- ---------- --------
Net increase (decrease) in cash and cash equivalents 50,158 183,957 (77,555)
Cash and cash equivalents at beginning of period 563,749 379,792 457,347
---------- ---------- --------
Cash and cash equivalents at end of period $613,907 $563,749 $379,792
========== ========== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $660,150 $485,876 $570,199
Income taxes $218,667 $159,659 $125,079
Noncash investing and financing activities:
Capital lease obligations incurred $88,574 $126,812 $75,040
Deficiency of fair value of decommissioning trust
assets over amount invested ($2,198) - -
Merger with GSU - common stock issued - $2,031,101 -
See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is important to Entergy due to the capital intensive nature of
its business, which requires large investments in long-lived assets. While
large capital expenditures for the construction of new generating capacity are
not currently planned, the System does require significant capital resources for
the periodic maturity of certain series of debt and preferred stock and ongoing
construction expenditures. Net cash flow from operations totaled $1,538
million, $1,074 million, and $831 million in 1994, 1993, and 1992, respectively.
In recent years, this cash flow, supplemented by cash on hand, has been
sufficient to meet substantially all investing and financing requirements,
including capital expenditures, dividends, and debt/preferred stock maturities.
Entergy's ability to fund these capital requirements with cash from operations
results, in part, from continued efforts to streamline operations and reduce
costs as well as collections under Grand Gulf 1 and River Bend rate phase-in
plans, which exceed the current cash requirements for Grand Gulf 1-related
costs. (In the income statement, these revenue collections are offset by the
amortization of previously deferred costs; therefore, there is no effect on net
income.) These phase-in plans will continue to contribute to Entergy's cash
position for the next several years. Further, Entergy Corporation's
subsidiaries have the ability to meet future capital requirements through future
debt or preferred stock issuances, as discussed below. See Note 8 for
additional information on the System's capital and refinancing requirements in
1995 - 1997. Also, to the extent current market interest and dividend rates
allow, the System operating companies and System Energy may continue to
refinance high-cost debt and preferred stock prior to maturity.
Productive investment by Entergy Corporation of excess funds is necessary
to enhance the long-term value of its common stock. In 1994, Entergy
Corporation invested in the Hub River Company which is constructing a generating
station near Karachi, Pakistan. In 1993, Entergy Corporation invested in an
electric distribution company and a high-voltage transmission system in
Argentina. In 1992, Entergy Corporation invested in a generating facility in
Argentina, an independent power plant in Virginia, a lighting efficiency
services company, and a company that develops energy management and other
technology applications. Entergy Corporation may invest up to $150 million per
year for the next several years in nonregulated business opportunities. See
"Significant Factors and Known Trends - Nonregulated Investments" for additional
information.
Certain agreements and restrictions limit the amount of mortgage bonds and
preferred stock that can be issued by the System operating companies and System
Energy. Based on the most restrictive applicable tests as of December 31, 1994,
and an assumed annual interest or dividend rate of 9.25%, the System operating
companies could have issued bonds or preferred stock in the following amounts,
respectively: AP&L - $253 million and $468 million; GSU - $0 million and $0
million; LP&L - $107 million and $784 million; MP&L - $246 million and
$95 million; and NOPSI - $89 million and $17 million. System Energy could also
have issued $241 million of bonds, but its charter does not presently provide
for the issuance of preferred stock. In addition, the System operating
companies and System Energy have the conditional ability to issue bonds against
the retirement of bonds, in some cases without meeting an earnings coverage
test. Although GSU was precluded from issuing first mortgage bonds under its
earnings coverage test as of December 31, 1994, GSU has the ability to issue
$578 million of first mortgage bonds against the retirement of first mortgage
bonds without meeting such test. AP&L may also issue preferred stock to refund
outstanding preferred stock without meeting an earnings coverage test. GSU has
no limitations on the issuance of preference stock. See Note 4 for information
on the System's short-term borrowings.
Entergy Corporation's current primary capital requirements are to
periodically invest in, or make loans to, its subsidiaries. Entergy Corporation
expects to meet these requirements in 1995 - 1997 with internally generated
funds and cash on hand. Further, Entergy Corporation paid $410.2 million of
dividends on its common stock in 1994. Declarations of dividends on common
stock are made at the discretion of Entergy Corporation's Board of Directors
(Board). It is anticipated that management will not recommend future dividend
increases to the Board unless such increases are justified by sustained earnings
growth of Entergy Corporation and its subsidiaries. Entergy Corporation
receives funds through dividend payments from its subsidiaries. During 1994,
these common stock dividend payments totaled $763.4 million. Certain
restrictions may limit the amount of these distributions. See Note 7 for
additional information.
See Notes 2 and 8 for information regarding litigation with Cajun and River
Bend rate appeals. Substantial write-offs or charges resulting from adverse
rulings in these matters could result in substantial additional net losses being
reported by Entergy and GSU in 1995 and subsequent periods, with resulting
substantial adverse adjustments to common shareholder's equity. Also, adverse
resolution of these matters could adversely affect GSU's ability to continue to
pay dividends and obtain financing, which could in turn affect GSU's liquidity.
Entergy Corporation has a program to repurchase shares of its outstanding
common stock. The timing and amount of such repurchases depend upon market
conditions and Board authorization. Entergy Corporation has requested, but not
yet received, SEC authorization for a $300 million bank line of credit, the
proceeds of which are expected to be used for common stock repurchases,
investments in nonregulated and nonutility businesses, and other optional
activities. Certain parties have intervened in this proceeding, and the
application is pending. See Notes 4 and 5 for additional information.
Increasing competition in the utility industry brings an increased need to
stabilize costs and reduce retail rates. See "Significant Factors and Known
Trends - Competition" for additional information on rate issues affecting the
System.
On March 20, 1995, the PUCT ordered GSU to implement a $72.9 million annual
base rate reduction for the period March 31, 1994, through September 1, 1994,
decreasing to an annual base rate reduction of $52.9 million after September 1,
1994. In accordance with the Merger agreement, the rate reduction is applied
retroactively to March 31, 1994. As a result, GSU recorded a $57 million
reserve for rate refund in 1994. See Note 2 for additional information.
In March 1994, the MPSC issued a final order adopting a formulary incentive
rate plan. The order also adopted previously agreed-upon stipulations of a
required return on equity of 11% and certain accounting adjustments that
resulted in a 4.3% ($28.1 million) reduction in MP&L's June 30, 1993, test-year
base revenues effective March 25, 1994. The plan allows for periodic small
adjustments in rates based on an annual comparison of earned to benchmark rates
of return and upon certain other performance factors. See Note 2 for additional
information.
As discussed in Note 2, NOPSI agreed to reduce electric and gas rates and
issue credits and refunds to customers pursuant to the 1994 NOPSI Settlement.
Under the terms of the settlement, NOPSI implemented rate reductions totaling
$44.9 million effective January 1, 1995. NOPSI will implement an additional
$4.4 million rate reduction on October 31, 1995. In addition, the 1994 NOPSI
Settlement requires NOPSI to credit its customers $25 million over a 21-month
period, beginning January 1, 1995, in order to resolve disputes with the Council
regarding the interpretation of the 1991 NOPSI Settlement. The 1994 NOPSI
Settlement also required NOPSI to refund $9.3 million of overcollections
associated with Grand Gulf 1 operating costs and $10.5 million of refunds
associated with the settlement by System Energy of a FERC tax audit. See Note 2
for additional information on the 1994 NOPSI Settlement.
As discussed in Note 2, in November 1994, FERC approved an agreement
settling a long-standing dispute involving income tax allocation procedures of
System Energy. In connection with this settlement, System Energy refunded
approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI, which in turn have
made or will make refunds or credits to their customers (except for those
portions attributable to AP&L's and LP&L's retained share of Grand Gulf 1
costs). Additionally, System Energy will refund a total of approximately $62
million, plus interest, to AP&L, LP&L, MP&L, and NOPSI over the period through
June 2004. AP&L, LP&L, MP&L, and NOPSI also wrote off certain related
unamortized balances of deferred investment tax credits. See Note 2 for further
information on the FERC Settlement.
Entergy Corporation has agreed to supply to System Energy sufficient
capital to (1) maintain System Energy's equity capital at an amount equal to a
minimum of 35% of its total capitalization (excluding short-term debt), and (2)
permit the continuation of commercial operation of Grand Gulf 1 and to pay in
full all indebtedness for borrowed money of System Energy when due under any
circumstances. In addition, under supplements to the Capital Funds Agreement
assigning System Energy's rights as security for specific debt of System Energy,
Entergy Corporation has agreed to make cash capital contributions to enable
System Energy to make payments on such debt when due. See Note 8 for additional
information.
ENTERGY CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
For the Years Ended December 31,
1994 1993 1992
(In Thousands, Except Share Data)
Operating Revenues:
Electric $5,797,769 $4,394,346 $4,043,555
Natural gas 118,962 90,991 72,944
Steam products 46,559 - -
---------- ---------- ----------
Total 5,963,290 4,485,337 4,116,499
---------- ---------- ----------
Operating Expenses:
Operation and maintenance:
Fuel, fuel-related expenses, and
gas purchased for resale 1,446,397 912,233 802,682
Purchased power 350,903 278,070 228,679
Nuclear refueling outage expenses 63,979 76,383 87,885
Other operation and maintenance 1,568,810 1,043,838 1,020,894
Depreciation and decommissioning 656,896 443,550 424,958
Taxes other than income taxes 284,234 199,151 197,895
Income taxes 131,965 251,163 210,081
Rate deferrals:
Rate deferrals - (1,651) (24,176)
Amortization of rate deferrals 391,365 289,259 209,015
---------- ---------- ----------
Total 4,894,549 3,491,996 3,157,913
---------- ---------- ----------
Operating Income 1,068,741 993,341 958,586
---------- ---------- ----------
Other Income (Deductions):
Allowance for equity funds used
during construction 11,903 8,049 7,355
Miscellaneous - net 20,631 50,957 135,475
Income taxes 241 (33,640) (46,382)
---------- ---------- ----------
Total 32,775 25,366 96,448
---------- ---------- ----------
Interest Charges:
Interest on long-term debt 665,541 503,797 546,805
Other interest - net 22,354 5,740 12,549
Allowance for borrowed funds used
during construction (9,938) (5,478) (5,094)
Preferred dividend requirements of
subsidiaries and other 81,718 56,559 63,137
---------- ---------- ----------
Total 759,675 560,618 617,397
---------- ---------- ----------
Income before Cumulative Effect of
a Change in Accounting Principle 341,841 458,089 437,637
Cumulative effect to January 1, 1993,
of Accruing Unbilled Revenues (net
of income taxes of $57,188) - 93,841 -
---------- ---------- ----------
Net Income $341,841 $551,930 $437,637
========== ========== ==========
Earnings per average common share
before cumulative effect of a
change in accounting principle $1.49 $2.62 $2.48
Earnings per average common share $1.49 $3.16 $2.48
Dividends declared per common share $1.80 $1.65 $1.45
Average number of common shares
outstanding 228,734,843 174,887,556 176,573,778
See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED RETAINED EARNINGS AND PAID-IN CAPITAL
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Retained Earnings, January 1 $2,310,082 $2,062,188 $1,943,298
Add:
Net income 341,841 551,930 437,637
---------- ---------- ----------
Total 2,651,923 2,614,118 2,380,935
---------- ---------- ----------
Deduct:
Dividends declared on common stock 411,806 288,342 255,479
Common stock retirements 13,940 13,906 59,187
Capital stock and other expenses 2,438 1,788 4,081
---------- ---------- ----------
Total 428,184 304,036 318,747
---------- ---------- ----------
Retained Earnings, December 31 $2,223,739 $2,310,082 $2,062,188
========== ========== ==========
Paid-in Capital, January 1 $4,223,682 $1,327,589 $1,357,883
Add:
Loss on reacquisition of
subsidiaries' preferred stock (23) (20) (1,323)
Issuance of 56,695,724 shares of common
stock in the merger with GSU - 2,027,325 -
Issuance of 174,552,011 shares of common
stock at $.01 par value net of the
retirement of 174,552,011 shares of
common stock at $5.00 par value - 871,015 -
---------- ---------- ----------
Total 4,223,659 4,225,909 1,356,560
---------- ---------- ----------
Deduct:
Common stock retirements 22,468 4,389 28,127
Capital stock discounts and other expenses (943) (2,162) 844
---------- ---------- ----------
Total 21,525 2,227 28,971
---------- ---------- ----------
Paid-in Capital, December 31 $4,202,134 $4,223,682 $1,327,589
========== ========== ==========
See Notes to Consolidated Financial Statements
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
On December 31, 1993, GSU became a subsidiary of Entergy Corporation. In
accordance with the purchase method of accounting, the results of operations for
the 12 months ended December 31, 1993, of Entergy Corporation and subsidiaries
reported in its Statements of Consolidated Income and Cash Flows do not include
GSU's results of operations. However, the following discussion between the
years 1994 and 1993 is presented with GSU's 1993 results of operations included
for comparative purposes. The discussion between the years 1993 and 1992
reflects reported results which do not include GSU.
In the second half of 1994, Entergy recorded certain charges that
significantly affected results of operations as discussed below. These charges
included, among other things, the FERC Settlement refund, NOPSI rate reductions
and credits, Merger-related costs, and restructuring costs (see Notes 2, 11, and
12).
Net Income
Consolidated net income decreased $253.4 million in 1994 due primarily to
the one-time recording in 1993 of the cumulative effect of the change in
accounting principle for unbilled revenues for AP&L, GSU, MP&L, and NOPSI and a
base rate reduction ordered by the PUCT applied retroactively to March 31, 1994
(see Note 2). In addition, net income was impacted by a decrease in revenues,
increased Merger-related costs, certain restructuring costs, and decreased
miscellaneous income - net, partially offset by a decrease in interest on long-
term debt and preferred dividend requirements.
Consolidated net income increased in 1993 due primarily to the one-time
recording of the cumulative effect of the change in accounting principle for
unbilled revenues for AP&L, MP&L, and NOPSI. This increase was partially offset
by the effects of implementing SFAS 109 and SFAS 106, and the impact in March
1992 of an after-tax gain from the sale of AP&L's Missouri properties.
Significant factors affecting the results of operations and causing
variances between the years 1994 and 1993, and 1993 and 1992, are discussed
under "Revenues and Sales," "Expenses," and "Other" below.
Revenues and Sales
See "Selected Financial Data - Five-Year Comparison," following the notes,
for information on operating revenues by source and KWH sales.
Electric operating revenues decreased in 1994 due primarily to rate
reductions/credits at GSU, MP&L, and NOPSI, the effects of the 1994 NOPSI
Settlement and the FERC Settlement, and decreased fuel adjustment revenues,
partially offset by increased retail energy sales and increased collections of
previously deferred Grand Gulf 1-related costs.
Electric operating revenues were higher in 1993 due primarily to increased
residential and commercial energy sales resulting from favorable weather
conditions, increased industrial sales due to improving market conditions in the
petrochemical, lumber, and plywood industries, and increased fuel adjustment
revenues and collections of previously deferred Grand Gulf 1-related costs,
neither of which affects net income, partially offset by the impact of a System
Energy rate reduction settlement.
Expenses
Purchased power decreased in 1994 due primarily to decreased power
purchases from nonassociated utilities due to changes in generation requirements
for the System operating companies. Purchased power increased in 1993 due to
increased power purchases from non-associated utilities, resulting from changes
in fuel-related costs and increased energy sales.
Nuclear refueling outage expenses decreased in 1994 due primarily to Grand
Gulf 1 outage expenses incurred in 1993. Nuclear refueling outage expenses
decreased in 1993 due primarily to a decrease in the number of scheduled and
unscheduled refueling outages.
Total income taxes decreased in 1994 due primarily to lower pre-tax book
income and the effects of the FERC Settlement. Total income taxes increased in
1993 due primarily to higher pretax income, an increase in the federal income
tax rate as a result of the Omnibus Budget Reconciliation Act of 1993, and the
implementation of SFAS 109, partially offset by the impact of the March 1992
sale of AP&L's Missouri properties.
The amortization of rate deferrals increased in 1994 and 1993 due primarily
to collection of more Grand Gulf 1-related costs from customers.
Interest expense decreased in 1994 due primarily to the refinancing of
high-cost debt partially offset by interest recorded on the FERC Settlement.
Interest expense decreased in 1993 due primarily to the refinancing of high-cost
debt and debt reduction activities.
Preferred dividend requirements decreased in 1994 and 1993 due primarily to
stock redemption activities.
Other
Miscellaneous income - net decreased in 1994 due primarily to amortization
of plant acquisition adjustment related to the Merger, the adoption of SFAS 116,
"Accounting for Contributions Made and Contributions Received" and reduced Grand
Gulf 1 carrying charges at AP&L. Miscellaneous income - net decreased in 1993
due primarily to the 1992 pretax gain of approximately $33.7 million from the
sale of AP&L's Missouri properties.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Competition
The electric utility industry, including Entergy, is experiencing increased
competitive pressures. Entergy is seeking to become a leading competitor in the
changing electric energy business. Competition presents Entergy with many
challenges. The following have been identified by Entergy as its major
competitive challenges.
Retail and Wholesale Rate Issues
Increasing competition in the utility industry brings an increased need to
stabilize or reduce retail rates. The retail regulatory philosophy is shifting
in some jurisdictions from traditional cost-of-service regulation to incentive-
rate regulation. Incentive and performance-based rate plans encourage
efficiencies and productivity while permitting utilities and their customers to
share in the results. MP&L implemented an incentive-rate plan in 1994 and LP&L
filed a performance-based formula rate plan with the LPSC in August 1994. GSU
agreed to shared-savings plans as part of the Merger. Recognizing that many
industrial customers have energy alternatives, Entergy continues to work with
these customers to address their needs. In certain cases, competitive prices
are negotiated, using variable-rate designs.
In a settlement with the Council that was approved on December 29, 1994,
NOPSI agreed to reduce electric and gas rates and issue credits and refunds to
customers. Effective January 1, 1995, NOPSI implemented a $31.8 million
permanent reduction in electric base rates and a $3.1 million permanent
reduction in gas base rates. These adjustments resolved issues associated with
NOPSI's return on equity exceeding 13.76% for the test year ended September 30,
1994. Under the 1991 NOPSI Settlement, NOPSI is recovering from its retail
customers its allocable share of certain costs related to Grand Gulf 1. NOPSI's
base rates to recover those costs were derived from estimates of those costs
made at that time. Any overrecovery of costs is required to be returned to
customers. Grand Gulf 1 has experienced lower operating costs than previously
estimated, and NOPSI accordingly is reducing its base rates in two steps to more
accurately match the current costs related to Grand Gulf 1. On January 1,
1995, NOPSI implemented a $10 million permanent reduction in base electric rates
to reflect the reduced costs related to Grand Gulf 1, to be followed by an
additional $4.4 million rate reduction on October 31, 1995. These Grand Gulf 1
rate reductions, which are expected to be largely offset by lower operating
costs, may reduce NOPSI's after-tax net income by approximately $1.4 million per
year beginning November 1, 1995. The next scheduled Grand Gulf 1 phase-in rate
increase in the amount of $4.4 million on October 31, 1995, will not be affected
by the 1994 NOPSI Settlement.
The 1994 NOPSI Settlement also requires NOPSI to credit its customers $25
million over a 21-month period, beginning January 1, 1995, in order to resolve
disputes with the Council regarding the interpretation of the 1991 NOPSI
Settlement. NOPSI recorded a $15.4 million net-of-tax reserve associated with
the credit in the fourth quarter of 1994. The 1994 NOPSI Settlement further
required NOPSI to refund, in December 1994, $13.3 million of credits previously
scheduled to be made to customers during the period January 1995 through July
1995. These credits were associated with a July 7, 1994, Council resolution
that ordered a $24.95 million rate reduction based on NOPSI's overearnings
during the test year ended September 30, 1993. Accordingly, NOPSI recorded an
$8 million net-of-tax charge in the fourth quarter of 1994.
MP&L's formulary incentive rate plan allows for periodic small adjustments
in rates based on a comparison of earned to benchmark returns and upon certain
performance factors. In addition, certain previously agreed-upon stipulations
of a required return on equity of 11% and certain accounting adjustments
resulted in a 4.3% ($28.1 million) reduction in MP&L's revenues effective
March 25, 1994. See Note 2 for further information.
LP&L's five-year rate freeze expired in March 1994. In August 1994, LP&L
filed a performance-based formula rate plan with the LPSC. The proposed formula
rate plan would continue existing LP&L rates at current levels, while providing
financial incentive to reduce costs and maintain high levels of customer
satisfaction and system reliability. Hearings were held in March 1995. See
Note 2 for additional information.
In connection with the Merger, AP&L and MP&L agreed with their respective
retail regulators not to request any general retail rate increases that would
take effect before November 1998, with certain exceptions. MP&L also agreed
that during this period retail base rates under its formula rate plan would not
be increased above the level of rates in effect on November 1, 1993. In
connection with the Merger, NOPSI agreed with the Council to reduce its annual
electric base rates by $4.8 million effective for bills rendered on or after
November 1, 1993. GSU agreed with the LPSC and PUCT to a five-year Rate Cap on
retail electric rates, and to pass through to retail customers the fuel savings
and a certain percentage of the nonfuel savings created by the Merger. Under
the terms of their respective Merger agreements, the LPSC and PUCT have reviewed
GSU's base rates during the first post-Merger earnings analysis. The LPSC
ordered a $12.7 million annual rate reduction effective January 1, 1995. GSU
received an injunction delaying implementation of $8.3 million of the reduction
and on January 1, 1995, reduced rates by $4.4 million. The entire $12.7 million
is being appealed. On March 20, 1995, the PUCT ordered a $72.9 million annual
base rate reduction for the period March 31, 1994, through September 1, 1994,
decreasing to an annual base rate reduction of $52.9 million after September 1,
1994. In accordance with the Merger agreement, the rate reduction is applied
retroactively to March 31, 1994. The rate reduction is being appealed and no
assurance can be given as to the timing or outcome of the appeal. See Note 2
for further information.
Retail wheeling, the transmission by an electric utility of energy produced
by another entity over the utility's transmission and distribution system to a
retail customer in the electric utility's area of service, is also evolving.
Over a dozen states have been or are studying the concept of retail competition.
In April 1994, the state of Michigan initiated a five-year experiment that
allows limited competition among public utilities. During the same month, the
California Public Utilities Commission proposed to deregulate that state's
electric power industry, starting on January 1, 1996, to allow the largest
industrial customers to select the lowest cost supplier for electricity service.
Under the proposal, by the year 2002, smaller companies and residential
customers in California would also be able to buy power from any suppliers. The
California Public Utilities Commission is currently reviewing its proposal and
is expected to make a ruling in the first half of 1995. The retail market for
electricity is expected to become more competitive with such moves toward
deregulation.
In some areas of the country, municipalities (or comparable entities) whose
residents are served at retail by an investor-owned utility pursuant to a
franchise are exploring the possibility of establishing new or extending
existing distribution systems or seeking new delivery points in order to serve
retail customers, especially large industrial customers, that currently receive
service from an investor-owned utility. These options depend on the terms of a
utility's franchise as well as on state law and regulation. In addition, FERC's
authority to order utilities to transmit for a new or expanding municipal system
is limited in certain respects. Where successful, however, the establishment of
a municipal system or the acquisition by a municipal system of a utility's
customers could result in the inability to recover costs that the utility has
incurred in serving those customers.
In mid-1994, FERC issued a notice of proposed rulemaking concerning a
regulatory framework for dealing with recovery of stranded costs, such as high-
cost nuclear generating units, which may be incurred by electric utilities as a
result of increased competition. In addition to addressing recovery of stranded
costs related to wholesale service, the proposal requested comment as to
recovery of retail stranded costs in transmission rates where state regulatory
authorities failed to address the issue or were in conflict. Comments and reply
comments have been filed, and the matter is pending. The risk of exposure to
stranded costs which may result from competition in the industry will depend on
the extent and timing of retail competition, the resolution of jurisdictional
issues concerning stranded cost recovery, and the extent to which such costs are
recovered from departing or remaining customers, among other matters.
Cogeneration projects developed or considered by certain of GSU's
industrial customers over the last several years have resulted in GSU developing
and securing approval of rates lower than the rates previously approved by the
PUCT and LPSC for such industrial customers. Such rates are designed to retain
such customers, and to compete for and develop new loads, and do not presently
recover GSU's full cost of service. The pricing agreements at non-full cost of
service based rates fully recover all related costs but provide only a minimal
return. Substantially all of such pricing agreements expire no later than 1997.
In 1994, KWH sales to GSU's industrial customers at non-full cost of service
rates, which make up approximately 28% of GSU's total industrial class,
increased 13%. Sales to the remaining GSU industrial customers increased 2%.
See Note 2 for information with respect to a settlement between System
Energy and FERC in which System Energy refunded approximately $61.7 million to
AP&L, LP&L, MP&L, and NOPSI, which in turn have made or will make refunds or
credits to their customers (except for those portions attributable to AP&L's and
LP&L's retained share of Grand Gulf 1 costs). Additionally, System Energy will
refund a total of approximately $62 million, plus interest, to AP&L, LP&L, MP&L,
and NOPSI over the period through June 2004. AP&L, LP&L, MP&L, and NOPSI also
wrote off certain related unamortized balances of deferred investment tax
credits.
In the wholesale rate area, FERC approved in 1992, with certain
modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power to
sell wholesale power at market-based rates and to provide to electric utilities
"open access" to the System's transmission system (subject to certain
requirements). GSU was later added to this filing. On October 31, 1994, as
amended on January 25, 1995, Entergy Services filed with FERC revised
transmission tariffs intended to provide access to transmission service on the
same or comparable basis, terms, and conditions as the System operating
companies, and the matter is pending. Open access and market pricing, once it
takes effect, will increase marketing opportunities for the System, but will
also expose the System to the risk of loss of load or reduced revenues due to
competition with alternative suppliers.
In March 1994, North Little Rock, Arkansas, awarded AP&L a wholesale power
contract that will provide estimated revenues of $347 million over 11 years.
Under the contract, the price per KWH was reduced 18%, with increases in price
through the year 2004. AP&L, which has been serving North Little Rock for over
40 years, was awarded the contract after intense bidding with several
competitors. On May 22, 1994, FERC accepted the contract. Rehearings were
requested by one of AP&L's competitors and were held in February 1995. The
matter is pending.
In light of the rate issues discussed above, Entergy is aggressively
reducing costs to avoid potential earnings erosions that might result as well as
to successfully compete by becoming a low-cost producer. In 1994, Entergy
announced a restructuring program related to certain of its operating units.
This program is designed to reduce costs and improve operating efficiencies.
See Note 12 for further information. Also, in response to an increasingly
competitive environment, AP&L, LP&L, MP&L, and NOPSI have announced intentions
to revise their initial least-cost planning activities and GSU is continuing to
work with the PUCT regarding integrated resource planning.
The Energy Policy Act of 1992
The EPAct addresses a wide range of energy issues and is altering the way
Entergy and the rest of the electric utility industry operate. The EPAct
encourages competition and affords utilities the opportunities and the risks,
associated with an open and more competitive market environment. The EPAct
creates exemptions from regulation under the Public Utility Holding Company Act
of 1935 (Holding Company Act) and creates a class of exempt wholesale generators
consisting of utility affiliates and nonutilities that are owners and operators
of facilities for the generation and transmission of power for sales at
wholesale. The EPAct also gives FERC the authority to order investor-owned
utilities, including the System operating companies, to transmit power and
energy to or for wholesale purchasers and sellers. The law creates the
potential for electric utilities and other power producers to gain increased
access to the transmission systems of other entities to facilitate wholesale
sales. Both the System operating companies and Entergy Power expect to compete
in this market. In addition, the EPAct allows utilities to own and operate
foreign generation, transmission, and distribution facilities. See
"Nonregulated Investments" below for further information.
Public Utility Holding Company Act of 1935
Entergy Corporation, along with 10 other electric utility holding
companies, recently asked Congress to repeal the Holding Company Act. The
Holding Company Act requires oversight by the SEC of many business practices and
activities of utility holding companies and their subsidiaries including, among
other things, nonutility activities. Entergy Corporation believes that the
Holding Company Act inhibits its ability to compete in the evolving electric
energy marketplace, and largely duplicates the oversight activities already
performed by FERC and state and local public service commissions.
Litigation and Regulatory Proceedings
See Note 2 for information on the possible material adverse effects on
GSU's financial condition and results of operations as a result of substantial
write-offs and/or refunds in connection with outstanding appeals and remands
regarding approximately $1.4 billion of abeyed company-wide River Bend plant
costs and approximately $187 million ($170 million net of tax) of Texas retail
jurisdiction deferred River Bend operating and carrying costs.
See Note 8 for information on the bankruptcy proceedings of Cajun and
litigation with Cajun concerning Cajun's ownership interest in River Bend and
the related possible material adverse effects on GSU's financial condition.
Entergy Corporation-GSU Merger
The acquisition of GSU by Entergy Corporation was the largest electric
utility merger in United States history. Entergy expects to achieve $850 million
in fuel cost savings and $670 million in operation and maintenance expense
savings over 10 years as a result of the Merger. In 1994, GSU recorded charges
associated with certain preacquisition contingencies, severance and augmented
retirement costs, and restructuring costs. See Notes 12 and 11 for further
information. Although common shareholders experienced some dilution in earnings
as a result of the Merger, Entergy believes that the Merger will ultimately be
beneficial to common shareholders in terms of strategic benefits as well as
economies and efficiencies produced. For further information, see Note 2.
Nonregulated Investments
Entergy Corporation continues to consider opportunities to expand its
utility and utility-related businesses that are not regulated by state and local
regulatory authorities (nonregulated businesses). Entergy Corporation's
investment strategy is to invest in nonregulated business opportunities that
have the potential to earn a greater rate of return than its regulated utility
operations, and Entergy Corporation may invest up to approximately $150 million
per year for the next several years in nonregulated businesses. Entergy
Corporation's nonregulated businesses currently fall into two broad categories:
power development and new technology related to the utility business. Entergy
Corporation made investments in Argentina's and Pakistan's electric energy
infrastructures and is also pursuing additional projects in Central America,
South America, Europe, and Asia. Entergy Corporation opened an office in Hong
Kong during 1994 and expects to open offices in South America and Europe in
1995. Entergy Corporation is negotiating in China to participate in two power
generation projects, Datong and Taishan, which are expected to receive final
approval in 1995 or 1996. To date, Entergy Corporation has made no investment
in the China projects; however, Entergy Corporation's share of these projects
may total approximately $115 million. In addition, Entergy Corporation is
exploring the possibility to provide telecommunications services that allow
customers to control energy usage.
In 1994, Entergy Corporation's nonregulated investments reduced
consolidated net income by approximately $31.7 million. In the near term, these
investments are unlikely to have a positive effect on earnings; but management
believes that these investments will contribute to future earnings growth.
ANO Matters
ANO 2 experienced a forced outage for repair of certain steam generator
tubes in March 1992. Further inspections and repairs were conducted at
subsequent refueling and mid-cycle outages in September 1992, May 1993, April
1994, and January 1995. AP&L's budgeted maintenance expenditures were adequate
to cover the cost of such repairs. ANO 2's output has been reduced 15 megawatts
or 1.6% due to secondary side fouling, tube plugging, and reduction of primary
temperature. Entergy Operations continues to take steps at ANO 2 to reduce the
number and severity of future tube cracks. In addition, Entergy Operations
continues to meet with the NRC to discuss such steps and results of inspections
of the generator tubes, as well as the timing of future inspections. Additional
inspections are planned for the normal refueling outage scheduled for October
1995.
Deregulated Portion of River Bend
As of December 31, 1994, GSU had not recovered a significant amount of its
investment in, or received any return associated with, the portion of River Bend
included in the deregulated asset plan in Louisiana and the portion of River
Bend placed in abeyance as part of the Texas rate order which went into effect
in July 1988. See Note 2 for further information. Future earnings will continue
to be limited as long as the limited recovery of the investment and lack of
return continues.
For the year ended December 31, 1994, GSU recorded revenues resulting from
the sale of electricity from the deregulated asset plan of approximately $34.1
million. Operation and maintenance expenses, including fuel, were approximately
$30 million, and depreciation expense associated with the deregulated asset plan
investment was approximately $16.7 million for the year ended December 31, 1994.
For the year ended December 31, 1994, GSU recorded nonfuel revenue of $32.5
million (included in the $34.1 million of total deregulated asset plan revenue
discussed above) which, absent the deregulated asset plan, would not have been
realized. The operation and maintenance expenses and depreciation expense
allocated to the deregulated asset plan as detailed above would have been
incurred at River Bend with or without the deregulated asset plan. The future
impact of the deregulated asset plan on GSU's results of operations and
financial position will depend on River Bend's future operating costs, the
unit's efficiency and availability, and the future market for energy over the
remaining life of the unit. Based on current estimates of the factors discussed
above, GSU anticipates that future revenues from the deregulated asset plan will
fully recover all related costs.
Property Tax Exemptions
Exemptions from the payment of Louisiana local property taxes on Waterford
3 and River Bend, which have been in effect for 10 years for each of the plants,
will expire in December 1995 and December 1996, respectively. LP&L and GSU are
working with taxing authorities to determine the method for calculating the
amount of the property taxes to be paid when the exemptions expire. LP&L
believes that assessed property taxes will be recovered from its customers
through rates. GSU believes that assessed property taxes allocated to its
retail jurisdictions will be recovered from those customers through rates.
Environmental Issues
GSU has been notified by the United States Environmental Protection Agency
(EPA) that it has been designated as a potentially responsible party for the
cleanup of sites on which GSU and others have or have been alleged to have
disposed of material designated as hazardous waste. GSU is currently
negotiating with the EPA and state authorities regarding the cleanup of some of
these sites. Several class action and other suits have been filed in state and
federal courts seeking relief from GSU and others for damages caused by the
disposal of hazardous waste and for asbestos-related disease allegedly resulting
from exposure on GSU premises. While the amounts at issue in the cleanup
efforts and suits may be substantial, GSU believes that its results of
operations and financial condition will not be materially affected by the
outcome of the suits.
During 1993, the Louisiana Department of Environmental Quality issued new
rules for solid waste regulation, including waste water impoundments. LP&L has
determined that certain of its power plant waste water impoundments are affected
by these regulations and has chosen to either upgrade or close them. The
aggregate cost of the upgrades and closures, to be completed by 1996, is
estimated to be $16 million.
Accounting Issues
Proposed Accounting Standards - The FASB has proposed a SFAS on "Accounting
for the Impairment of Long-Lived Assets," effective January 1, 1996. The
proposed standard describes circumstances which may result in assets (including
goodwill such as the Merger acquisition adjustment, see Note 1) being impaired
and provides criteria for recognition and measurement of asset impairment. Note
2 describes regulatory assets of $170 million (net of tax) related to Texas
retail deferred River Bend operating and carrying costs. Management believes
these deferred costs will be required to be written off under the provisions of
the new standard unless there are favorable regulatory or court actions related
to these costs prior to the adoption of the new standard by Entergy. Certain
other operations of Entergy are potentially affected by this standard, and any
resulting write-offs will depend on future operating costs, generating units'
efficiency and availability, and the future market for energy over the remaining
life of the units. Based on current estimates, Entergy anticipates that future
revenues will fully recover the costs of such operations.
Continued Application of SFAS 71 - Entergy's financial statements currently
reflect, for the most part, assets and costs based on current cost-based
ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects
of Certain Types of Regulation." As discussed above, the electric utility
industry is changing and these changes could possibly result in the
discontinuance of the application of SFAS 71, which would result in the
elimination of regulatory assets and liabilities. See Note 1 for further
information.
Accounting for Decommissioning Costs - The FASB is currently reviewing the
accounting for decommissioning of nuclear plants. This project could possibly
change the System's, as well as the entire utility industry's, accounting for
such costs. For further information, see Note 8.
ENTERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying consolidated financial statements include the accounts of
Entergy Corporation and its direct and indirect subsidiaries: AP&L, GSU, LP&L,
MP&L, NOPSI, System Energy, Entergy Operations, Entergy Pakistan, Ltd., Entergy
Power, Entergy Power Development Corporation, Entergy Richmond Power
Corporation, Entergy Services, System Fuels, Entergy Enterprises, Entergy SASI,
Entergy S.A., Entergy Argentina S.A, Entergy Transener S.A., Entergy Power Asia,
Ltd., Entergy Yacyreta I, Inc., and Entergy Edegel, Inc. Because the
acquisition of GSU was consummated on December 31, 1993, under the purchase
method of accounting, GSU is included only in the December 31, 1993,
consolidated balance sheet amounts. GSU is included in all of the consolidated
financial statements for 1994. All references made to Entergy or the System as
of, and subsequent to, the Merger closing date include amounts and information
pertaining to GSU as an Entergy company. All significant intercompany
transactions have been eliminated. Entergy Corporation's utility subsidiaries
maintain accounts in accordance with FERC and other regulatory guidelines.
Certain previously reported amounts have been reclassified to conform to current
classifications.
Revenues and Fuel Costs
The System operating companies accrue estimated revenues for energy
delivered since the latest billings. However, prior to January 1, 1993, AP&L,
GSU, MP&L, and NOPSI recognized electric and gas revenues when billed. To
provide a better matching of revenues and expenses, effective January 1, 1993,
AP&L, GSU, MP&L, and NOPSI adopted a change in accounting principle to provide
for accrual of estimated unbilled revenues. The cumulative effect of this
accounting change as of January 1, 1993, (excluding GSU) increased net income by
$93.8 million or $0.54 per share. Had this new accounting method been in effect
during prior years, net income before the cumulative effect would not have been
materially different from that shown in the accompanying financial statements.
In accordance with a LPSC rate order, GSU recorded a deferred credit of $16.6
million for the January 1, 1993, amount of unbilled revenues. See Note 2
regarding recent LPSC rate actions regarding the deferred unbilled revenues.
The System operating companies' rate schedules (except GSU's Texas retail
rate schedules) include fuel adjustment clauses that allow either current
recovery or deferrals of fuel costs until such costs are reflected in the
related revenues. GSU's Texas retail rate schedules include a fixed fuel factor
approved by the PUCT, which remains in effect until changed as part of a general
rate case, fuel reconciliation, or a fixed fuel factor filing.
Utility Plant
Utility plant is stated at original cost. The original cost of utility
plant retired or removed, plus the applicable removal costs, less salvage, is
charged to accumulated depreciation. Maintenance, repairs, and minor
replacement costs are charged to operating expenses. Substantially all of the
utility plant is subject to liens of the subsidiaries' mortgage bond indentures.
Utility plant includes the portions of Grand Gulf 1 and Waterford 3 that
were sold and are currently under lease. For financial reporting purposes,
these sale and leaseback transactions are reflected as financing transactions.
Total System net electric utility plant in service of $14.5 billion as of
December 31, 1994, (excluding approximately $0.5 billion of plant acquisition
adjustment related to the Merger) includes $9.8 billion of production plant,
$1.4 billion of transmission plant, $2.8 billion of distribution plant, and $0.5
billion of other plant.
Depreciation is computed on the straight-line basis at rates based on the
estimated service lives and costs of removal of the various classes of property.
Depreciation provisions on average depreciable property approximated 3.0% in
1994 and 1993, and 3.1% in 1992.
AFUDC represents the approximate net composite interest cost of borrowed
funds and a reasonable return on the equity funds used for construction.
Although AFUDC increases utility plant and increases earnings, it is only
realized in cash through depreciation provisions included in rates. The System
operating companies' effective composite rates for AFUDC were 9.5% for 1994,
10.6% for 1993, and 10.8% for 1992.
Jointly-Owned Generating Stations
Certain Entergy Corporation subsidiaries own undivided interests in several
jointly-owned electric generating facilities and record the investments and
expenses associated with these generating stations to the extent of their
respective ownership interests. As of December 31, 1994, the System's
investment and accumulated depreciation in each of these generating stations
were as follows:
Total
Megawatt Accumulated
Generating Stations Fuel Type Capability Ownership Investment Depreciation
(In Thousands)
Grand Gulf Nuclear 1,143 90.00% (1) $3,366,471 $751,717
River Bend Unit 1 Nuclear 936 70.00% (2) $3,080,019 $617,002
Independence Units 1 and 2 Coal 1,678 56.50% $ 541,893 $170,837
White Bluff Units 1 and 2 Coal 1,660 57.00% $ 400,918 $151,830
Roy S. Nelson Unit 6 Coal 550 70.00% $ 390,033 $145,897
Big Cajun 2 Unit 3 Coal 540 42.00% $ 219,788 $ 74,442
(1) Includes System Energy's ownership and leasehold interests in Grand
Gulf 1.
(2) See Note 8 regarding the current status of Cajun's 30% undivided
ownership interest in River Bend.
Income Taxes
Entergy Corporation and its subsidiaries file a consolidated federal income
tax return. Income taxes are allocated to the System companies in proportion to
their contribution to consolidated taxable income. SEC regulations require that
no Entergy Corporation subsidiary pay more taxes than it would have had a
separate income tax return been filed. Deferred taxes are recorded for all
temporary differences between book and taxable income. Investment tax credits
are deferred and amortized based upon the average useful life of the related
property in accordance with rate treatment. As discussed in Note 3, in 1993
Entergy changed its accounting for income taxes to conform with SFAS 109.
Acquisition Adjustment
Entergy Corporation, upon completion of the Merger in December 1993 (see
Note 12 for additional details), recorded an acquisition adjustment in utility
plant in the amount of $380 million representing the excess of the purchase
price over the net assets acquired of GSU. During 1994, the System recorded an
additional $115 million of acquisition adjustment related to the resolution of
certain preacquisition contingencies and appropriate allocation of purchase
price, which combined with the amortization of the acquisition adjustment of $16
million in 1994, resulted in an unamortized balance of $479 million of
acquisition adjustment as of December 31, 1994. The acquisition adjustment is
being amortized on a straight-line basis over a 31-year period beginning January
1, 1994, which approximates the remaining average book life of the plant
acquired as a result of the Merger. The System anticipates that its future net
cash flows will be sufficient to recover such amortization.
Reacquired Debt
The premiums and costs associated with reacquired debt are being amortized
over the life of the related new issuances, in accordance with ratemaking
treatment.
Cash and Cash Equivalents
Entergy considers all unrestricted highly liquid debt instruments purchased
with an original maturity of three months or less to be cash equivalents.
Continued Application of SFAS 71
As a result of the EPAct and actions of regulatory commissions, the
electric utility industry is moving toward a combination of competition and a
modified regulatory environment. The System's financial statements currently
reflect, for the most part, assets and costs based on current cost-based
ratemaking regulations, in accordance with SFAS 71, "Accounting for the Effects
of Certain Types of Regulation." Continued applicability of SFAS 71 to the
System's financial statements requires that rates set by an independent
regulator on a cost-of-service basis (including a reasonable rate of return on
invested capital) can actually be charged to and collected from customers.
In the event that either all or a portion of a utility's operations cease
to meet those criteria for various reasons, including deregulation, a change in
the method of regulation or a change in the competitive environment for the
utility's regulated services, the utility should discontinue application of SFAS
71 for the relevant portion. That discontinuation should be reported by
elimination from the balance sheet of the effects of any actions of regulators
recorded as regulatory assets and liabilities.
As of December 31, 1994, and for the foreseeable future, the System's
financial statements continue to follow SFAS 71, with the exceptions noted
below.
SFAS 101
SFAS 101, "Accounting for the Discontinuation of Application of FASB 71,"
specifies how an enterprise that ceases to meet the criteria for application of
SFAS 71 to all or part of its operations should report that event in its
financial statements. GSU discontinued regulatory accounting principles for its
wholesale jurisdiction and steam department and the Louisiana deregulated
portion of River Bend during 1989 and 1991, respectively.
Fair Value Disclosures
The estimated fair value of financial instruments has been determined by
Entergy, using available market information and appropriate valuation
methodologies. However, considerable judgment is required in developing the
estimates of fair value. Therefore, estimates are not necessarily indicative of
the amounts that Entergy could realize in a current market exchange. In
addition, gains or losses realized on financial instruments may be reflected in
future rates and not accrue to the benefit of stockholders.
Entergy considers the carrying amounts of financial instruments classified
as current assets and liabilities to be a reasonable estimate of their fair
value because of the short maturity of these instruments. In addition, Entergy
does not presently expect that performance of its obligations will be required
in connection with certain off-balance sheet commitments and guarantees
considered financial instruments. Due to this factor, and because of the
related party nature of these commitments and guarantees, determination of fair
value is not considered practicable. See Notes 5, 6, and 8 for additional fair
value disclosure.
Entergy adopted the provisions of SFAS 115, "Accounting for Certain
Investments in Debt and Equity Securities," effective January 1, 1994. As a
result, at December 31, 1994, Entergy recorded on the balance sheet a reduction
of $2.2 million in decommissioning trust funds, representing the amount by which
the fair value of the securities held in such funds is less than amounts for
decommissioning recovered in rates and deposited in the funds and the related
earnings on the amounts deposited. Due to the regulatory treatment for
decommissioning trust funds, the System recorded an offsetting amount in
unrealized losses on investment securities as a regulatory asset.
NOTE 2. RATE AND REGULATORY MATTERS
River Bend
In May 1988, the PUCT granted GSU a permanent increase in annual revenues
of $59.9 million resulting from the inclusion in rate base of approximately $1.6
billion of company-wide River Bend plant investment and approximately $182
million of related Texas retail jurisdiction deferred River Bend costs (Allowed
Deferrals). In addition, the PUCT disallowed as imprudent $63.5 million of
company-wide River Bend plant costs and placed in abeyance, with no finding of
prudence, approximately $1.4 billion of company-wide River Bend plant investment
and approximately $157 million of Texas retail jurisdiction deferred River Bend
operating and carrying costs. The PUCT affirmed that the ultimate rate
treatment of such amounts would be subject to future demonstration of the
prudence of such costs. GSU and intervening parties appealed this order (Rate
Appeal) and GSU filed a separate rate case asking that the abeyed River Bend
plant costs be found prudent (Separate Rate Case). Intervening parties filed
suit in a Texas district court to prohibit the Separate Rate Case. The district
court's decision was ultimately appealed to the Texas Supreme Court, which ruled
in 1990 that the prudence of the purported abeyed costs could not be relitigated
in a separate rate proceeding. The Texas Supreme Court's decision stated that
all issues relating to the merits of the original PUCT order, including the
prudence of all River Bend-related costs, should be addressed in the Rate
Appeal.
In October 1991, the Texas district court in the Rate Appeal issued an
order holding that, while it was clear the PUCT made an error in assuming it
could set aside $1.4 billion of the total costs of River Bend and consider them
in a later proceeding, the PUCT, nevertheless, found that GSU had not met its
burden of proof related to the amounts placed in abeyance. The court also ruled
that the Allowed Deferrals should not be included in rate base. The court
further stated that the PUCT had erred in reducing GSU's deferred costs by $1.50
for each $1.00 of revenue collected under the interim rate increases authorized
in 1987 and 1988. The court remanded the case to the PUCT with instructions as
to the proper handling of the Allowed Deferrals. GSU's motion for rehearing was
denied and, in December 1991, GSU filed an appeal of the October 1991 district
court order. The PUCT also appealed the October 1991 district court order,
which served to supersede the district court's judgment, rendering it
unenforceable under Texas law.
In August 1994, the Texas Third District Court of Appeals (the Appellate
Court) affirmed the district court's decision that there was substantial
evidence to support the PUCT's 1988 decision not to include the abeyed
construction costs in GSU's rate base. While acknowledging that the PUCT had
exceeded its authority when it attempted to defer a decision on the inclusion of
those costs in rate base in order to allow GSU a further opportunity to
demonstrate the prudence of those costs in a subsequent proceeding, the
Appellate Court found that GSU had suffered no harm or lack of due process as a
result of the PUCT's error. Accordingly, the Appellate Court held that the
PUCT's action had the effect of disallowing the company-wide $1.4 billion of
River Bend construction costs for ratemaking purposes. In its August 1994
opinion, the Appellate Court also held that GSU's deferred operating and
maintenance costs associated with the allowed portion of River Bend should be
included in rate base and that GSU's deferred River Bend carrying costs included
in the Allowed Deferrals should also be included in rate base. The Appellate
Court's August 1994 opinion affirmed the PUCT's original order in this case.
The Appellate Court's August 1994 opinion was entered by two judges, with a
third judge dissenting. The dissenting opinion states that the result of the
majority opinion is, among other things, to deprive GSU of due process at the
PUCT because the PUCT never reached a finding on the $1.4 billion of
construction costs.
In October 1994, the Appellate Court denied GSU's motion for rehearing on
the August 1994 opinion as to the $1.4 billion in River Bend construction costs
and other matters. GSU appealed the Appellate Court's decision to the Texas
Supreme Court, where it is pending.
As of December 31, 1994, the River Bend plant costs disallowed for retail
ratemaking purposes in Texas, the River Bend plant costs held in abeyance, and
the related operating and carrying cost deferrals totaled (net of taxes)
approximately $13 million, $280 million (both net of depreciation), and $170
million, respectively. Allowed Deferrals were approximately $107 million, net
of taxes and amortization, as of December 31, 1994. GSU estimates it has
collected approximately $158 million of revenues as of December 31, 1994, as a
result of the originally ordered rate treatment by the PUCT of these deferred
costs. If recovery of the Allowed Deferrals is not upheld, future revenues
based upon those allowed deferrals could also be lost, and no assurance can be
given as to whether or not refunds of revenue received based upon such deferred
costs previously recorded will be required.
No assurance can be given as to the timing or outcome of the remands or
appeals described above. Pending further developments in these cases, GSU has
made no write-offs or reserves for the River Bend-related costs. Management
believes, based on advice from Clark, Thomas & Winters, a Professional
Corporation, legal counsel of record in the Rate Appeal, that it is reasonably
possible that the case will be remanded to the PUCT, and the PUCT will be
allowed to rule on the prudence of the abeyed River Bend plant costs. Rate Caps
imposed by the PUCT's regulatory approval of the Merger could result in GSU
being unable to use the full amount of a favorable decision to immediately
increase rates; however, a favorable decision could permit some increases and/or
limit or prevent decreases during the period the Rate Caps are in effect. At
this time, management and legal counsel are unable to predict the amount, if
any, of the abeyed and previously disallowed River Bend plant costs that
ultimately may be disallowed by the PUCT. A net of tax write-off as of December
31, 1994, of up to $293 million could be required based on an ultimate adverse
ruling by the PUCT on the abeyed and disallowed costs.
In prior proceedings, the PUCT has held that the original cost of nuclear
power plants will be included in rates to the extent those costs were prudently
incurred. Based upon the PUCT's prior decisions, management believes that its
River Bend construction costs were prudently incurred and that it is reasonably
possible that it will recover in rate base, or otherwise through means such as a
deregulated asset plan, all or substantially all of the abeyed River Bend plant
costs. However, management also recognizes that it is reasonably possible that
not all of the abeyed River Bend plant costs may ultimately be recovered.
As part of its direct case in the Separate Rate Case, GSU filed a cost
reconciliation study prepared by Sandlin Associates, management consultants with
expertise in the cost analysis of nuclear power plants, which supports the
reasonableness of the River Bend costs held in abeyance by the PUCT. This
reconciliation study determined that approximately 82% of the River Bend cost
increase above the amount included by the PUCT in rate base was a result of
changes in federal nuclear safety requirements and provided other support for
the remainder of the abeyed amounts.
There have been four other rate proceedings in Texas involving nuclear
power plants. Investment in the plants ultimately disallowed ranged from 0% to
15%. Each case was unique, and the disallowances in each were made on a
case-by-case basis for different reasons. Appeals of two of these PUCT
decisions are currently pending.
The following factors support management's position that a loss contingency
requiring accrual has not occurred, and its belief that all, or substantially
all, of the abeyed plant costs will ultimately be recovered:
1. The $1.4 billion of abeyed River Bend plant costs have never been ruled
imprudent and disallowed by the PUCT.
2. Sandlin Associates' analysis which supports the prudence of
substantially all of the abeyed construction costs.
3. Historical inclusion by the PUCT of prudent construction costs in rate
base.
4. The analysis of GSU's internal legal staff, which has considerable
experience in Texas rate case litigation.
Additionally, management believes, based on advice from Clark, Thomas &
Winters, a Professional Corporation, legal counsel of record in the Rate Appeal,
that it is reasonably possible that the Allowed Deferrals will continue to be
recovered in rates. Management also believes, based on advice from Clark,
Thomas & Winters, a Professional Corporation, legal counsel of record in the
Rate Appeal, that it is reasonably possible that the deferred costs related to
the $1.4 billion of abeyed River Bend plant costs will be recovered in rates to
the extent that the $1.4 billion of abeyed River Bend plant is recovered.
However, a net of tax write-off of the $170 million of deferred costs related to
the $1.4 billion of abeyed River Bend plant costs would be required if they are
not allowed to be recovered in rates.
A proposed accounting standard, "Accounting for the Impairment of Long-
Lived Assets," which is expected to become effective January 1, 1996, may
require the write-off of the $170 million of rate deferrals discussed above,
upon adoption of the standard, unless there are favorable regulatory or court
actions related to these costs prior to adoption.
Merger-Related Rate Agreements
In November 1993, Entergy Corporation, AP&L, MP&L, and NOPSI entered into
separate settlement agreements whereby the APSC, MPSC, and Council agreed to
withdraw from the SEC proceeding related to the Merger. In return AP&L, MP&L,
and NOPSI agreed, among other things, that their retail ratepayers would be
protected from (1) increases in the cost of capital resulting from risks
associated with the Merger, (2) recovery of any portion of the acquisition
premium or transactional costs associated with the Merger, (3) certain direct
allocations of costs associated with GSU's River Bend nuclear unit, and (4) any
losses of GSU resulting from resolution of litigation in connection with its
ownership of River Bend. AP&L and MP&L agreed not to request any general retail
rate increase that would take effect before November 1998, except for, among
other things, increases associated with the recovery of certain Grand Gulf 1-
related costs, recovery of certain taxes, and force majeure (defined to include,
among other things, war, natural catastrophes, and high inflation), and in the
case of AP&L, excess capacity costs and costs related to the adoption of SFAS
106 that were previously deferred. MP&L also agreed that retail base rates
under the formula rate plan would not be increased above November 1, 1993,
levels for a period of five years beginning November 9, 1993 (described below).
In 1993, the LPSC and the PUCT approved separate regulatory proposals that
include the following elements: (1) a five-year Rate Cap on GSU's retail
electric base rates in the respective states, except for force majeure (defined
to include, among other things, war, natural catastrophes, and high inflation);
(2) a provision for passing through to retail customers in the respective states
the jurisdictional portion of the fuel savings created by the Merger; and (3) a
mechanism for tracking nonfuel operation and maintenance savings created by the
Merger. The LPSC regulatory plan provides that such nonfuel savings will be
shared 60% by the shareholder and 40% by ratepayers during the eight years
following the Merger. The LPSC plan requires regulatory filings each year by
the end of May through 2001. The PUCT regulatory plan provides that such
savings will be shared equally by the shareholder and ratepayers, except that
the shareholder's portion will be reduced by $2.6 million per year on a total
company basis in years four through eight. The PUCT plan also requires a series
of future regulatory filings in November 1996, 1998, and 2001 to ensure that
ratepayers' share of such savings be reflected in rates on a timely basis and
requires Entergy Corporation to hold GSU's Texas retail customers harmless from
the effects of the removal by FERC of a 40% cap on the amount of fuel savings
GSU may be required to transfer to other System operating companies under the
FERC tracking mechanism (see below). On January 14, 1994, Entergy Corporation
filed a request for rehearing of FERC's December 15, 1993, order approving the
Merger requesting that FERC restore the 40% cap provision in the fuel cost
protection mechanism. The matter is pending.
FERC approved certain rate schedule changes to integrate GSU into the
System Agreement. Certain commitments were adopted to provide reasonable
assurance that the ratepayers of AP&L, LP&L, MP&L, and NOPSI will not be
allocated higher costs, including, among other things, (1) a tracking mechanism
to protect AP&L, LP&L, MP&L, and NOPSI from certain unexpected increases in fuel
costs, (2) the distribution of profits from power sales contracts entered into
prior to the Merger, (3) a methodology to estimate the cost of capital in future
FERC proceedings, and (4) a stipulation that AP&L, LP&L, MP&L, and NOPSI will be
insulated from certain direct effects on capacity equalization payments should
GSU acquire Cajun's 30% share in River Bend (see Note 8).
Formula Rate Plan
Under a formulary incentive rate plan (Formula Rate Plan) effective March
25, 1994, MP&L's earned rate of return is calculated automatically every 12
months and compared to and adjusted against a benchmark rate of return
(calculated under a separate formula within the Formula Rate Plan). The Formula
Rate Plan allows for periodic small adjustments in rates based on a comparison
of earned to benchmark returns and upon certain performance factors. In the
same proceeding, the MPSC conducted a general review of MP&L's current rates and
on March 1, 1994, issued a final order adopting the Formula Rate Plan and
previously agreed-upon stipulations of (1) a required return on equity of 11%
and (2) certain accounting adjustments that resulted in a 4.3% ($28.1 million)
reduction in MP&L's June 30, 1993, test-year base revenues. The MPSC's order
required MP&L to file rates designed to provide for this reduction in operating
revenues for the test year on or before March 18, 1994, which became effective
March 25, 1994. The final order was appealed to the Mississippi Supreme Court
on May 17, 1994, by Mississippi Valley Gas Company (MVG) on the grounds that the
MPSC issued the final order without having reviewed the cost of MP&L's
promotional practices, some of which MVG alleged to be improper. MVG filed a
motion to dismiss the appeal, and on October 28, 1994, the Mississippi Supreme
Court granted MVG's motion.
FERC Settlement
In November 1994, FERC approved an agreement settling a long-standing
dispute involving income tax allocation procedures of System Energy. In
accordance with the agreement, System Energy refunded approximately $61.7
million to AP&L, LP&L, MP&L, and NOPSI, which in turn have made or will make
refunds or credits to their customers (except for those portions attributable to
AP&L's and LP&L's retained share of Grand Gulf 1 costs). Additionally, System
Energy will refund a total of approximately $62 million, plus interest, to AP&L,
LP&L, MP&L, and NOPSI over the period through June 2004. The settlement also
required the write-off of certain related unamortized balances of deferred
investment tax credits by AP&L, LP&L, MP&L, and NOPSI. The settlement reduced
Entergy Corporation's consolidated net income for the year ended December 31,
1994, by approximately $68.2 million, offset by the write-off of the unamortized
balances of related deferred investment tax credits of approximately $69.4
million ($2.9 million for Entergy Corporation; $27.3 million for AP&L; $31.5
million for LP&L; $6 million for MP&L; and $1.7 million for NOPSI). System
Energy also reclassified from utility plant to other deferred debits
approximately $81 million of other Grand Gulf 1 costs. Although excluded from
rate base, System Energy will be permitted to recover such costs over a 10-year
period. Interest on the $62 million refund and the loss of the return on the
$81 million of other Grand Gulf 1 costs will reduce Entergy's and System
Energy's net income by approximately $10 million annually over the next 10
years.
As a result of the charges associated with the settlement, System Energy
obtained the consent of certain banks (parties to the Reimbursement Agreement)
to waive temporarily the fixed charge coverage covenant in the letters of credit
and Reimbursement Agreement related to the Grand Gulf 1 sale and leaseback
transaction until November 30, 1995. System Energy expects that upon expiration
of the waiver period, it will be in compliance with the fixed charge coverage
covenant. Absent a waiver, System Energy's failure to perform this covenant
could cause a draw under the letters of credit and/or early termination of the
letters of credit. If the letters of credit were not replaced in a timely
manner, a default or early termination of System Energy's leases could result.
Rate Deferrals
The System operating companies have various rate moderation or phase-in
plans that reduced the immediate effect of Grand Gulf 1, River Bend, and
Waterford 3 costs on ratepayers. Under these plans, certain costs are either
retained permanently (and not recovered from ratepayers), deferred in early
years and collected in later years, or recovered currently from customers.
These plans vary in the proportions of costs each company retains, defers, or
recovers and in the length of the deferral/recovery periods. Only those costs
retained permanently and not recovered through rates or through sales to third
parties result in a reduction of net income. The carrying charges associated
with unamortized deferrals were either deferred or recovered currently from
customers.
GSU deferred approximately $369 million of River Bend operating costs,
purchased power costs, and accrued carrying charges pursuant to a 1986 PUCT
accounting order. Approximately $182 million of these costs are being amortized
over a 20-year period, and the remaining $187 million are not being amortized
pending the ultimate outcome of the Rate Appeal. As of December 31, 1994, the
unamortized balance of these costs was $321 million. Further, GSU deferred
approximately $400.4 million of similar costs pursuant to a 1986 LPSC accounting
order. These costs, of which approximately $122 million were unamortized as of
December 31, 1994, are being amortized over a 10-year period ending in 1997.
In accordance with a phase-in plan approved by the LPSC, GSU deferred $294
million of its River Bend costs related to the period February 1988 through
February 1991. GSU has amortized $129 million through December 31, 1994, and
the remainder of $165 million will be recovered over approximately 3.2 years.
AP&L's permanently retained share of Grand Gulf 1 costs is 7.92% in 1994
and all succeeding years of the unit's commercial operation. In the event AP&L
is not able to sell its retained share to third parties, it may sell such energy
to its retail customers at a price equal to its avoided energy cost, which is
currently less than AP&L's cost of such energy. LP&L permanently absorbs 18% of
its 14% (approximately 2.52%) FERC-allocated share of Grand Gulf 1-related
costs. LP&L is able to recover through the fuel adjustment clause 4.6 cents per
KWH (as of May 1994) for the energy related to its retained portion of these
costs. Alternatively, LP&L may sell such energy to nonaffiliated parties at
prices above the fuel adjustment clause recovery amount, subject to LPSC
approval. For the year ended December 31, 1994, System Energy's billings for
Grand Gulf 1-related costs totaled approximately $475 million. A deregulated
asset plan representing an unregulated portion (approximately 22%) of River Bend
(plant costs, generation, revenues, and expenses) was established pursuant to a
January 1992 LPSC order. The plan allows GSU to sell such generation to
Louisiana retail customers at 4.6 cents per KWH or off-System at higher prices
with certain sharing provisions for such incremental revenue. Based on current
estimates, Entergy anticipates that future revenues will fully recover all
related costs.
Filings with the PUCT and Texas Cities
In March 1994, the Texas Office of Public Utility Counsel and certain
cities served by GSU instituted an investigation of the reasonableness of GSU's
rates. In June 1994, GSU provided the cities with information that GSU believed
supported the current rate level. GSU filed the same information with the PUCT
in June 1994, pursuant to provisions of the Merger. In September 1994, various
cities adopted ordinances directing GSU to reduce its Texas retail rates by
$45.9 million. GSU appealed the cities' ordinances to the PUCT for a
determination of reasonableness of GSU's rates.
In November 1994, those cities that intervened in the PUCT appeal filed
testimony with the PUCT supporting a $118 million base rate reduction in lieu of
the previously proposed $45.9 million reduction. In November 1994, the PUCT
staff filed testimony that supported a $38.2 million base rate reduction. GSU
filed information with the PUCT that it believed supported the current level of
rates. Hearings were held in December 1994 and on March 20, 1995, the PUCT
ordered a $72.9 million annual base rate reduction for the period March 31,
1994, through September 1, 1994, decreasing to an annual base rate reduction of
$52.9 million after September 1, 1994. In accordance with the Merger agreement,
the rate reduction is applied retroactively to March 31, 1994. As a result, GSU
recorded a $57 million reserve for rate refund in 1994. The rate reduction is
being appealed and no assurance can be given as to the timing or outcome of the
appeal.
Texas Cities Rate Settlement - 1993
In June 1993, 13 cities within GSU's Texas service area instituted an
investigation to determine whether GSU's current rates were justified. In
October 1993, the general counsel of the PUCT instituted an inquiry into the
reasonableness of GSU's rates. In November 1993, a settlement agreement was
filed with the PUCT which provided for an initial reduction in GSU's annual
retail base revenues in Texas of approximately $22.5 million effective for
electric usage on or after November 1, 1993, and a second reduction of $20
million effective September 1994. Pursuant to the settlement, GSU reduced rates
with a $20 million one-time bill credit in December 1993, and refunded
approximately $3 million to Texas retail customers on bills rendered in
December 1993. The PUCT approved the settlement agreement on July 21, 1994.
The cities' rate inquiries were settled earlier on the same terms.
LPSC Rate Reviews
In May 1994, GSU made the required first post-Merger earnings analysis
filing with the LPSC. On December 14, 1994, the LPSC ordered a $12.7 million
annual rate reduction for GSU effective January 1995. The rate order included,
among other things, a reduction in GSU's Louisiana jurisdictional authorized
return on equity from 12.75% to 10.95% and the amortization for the benefit of
the customer of $8.3 million of previously deferred unbilled revenue,
representing one-half of the total resulting from a change in accounting as
discussed in Note 1. On December 28, 1994, GSU received a preliminary
injunction from the 19th Judicial District Court regarding $8.3 million of the
reduction. On January 1, 1995, GSU reduced rates by $4.4 million. The entire
$12.7 million reduction is being appealed and no assurance can be given as to
the timing or outcome of the appeal.
In August 1994, LP&L filed a performance-based formula rate plan with the
LPSC. The proposed formula rate plan would continue existing LP&L rates at
current levels, while providing financial incentive to reduce costs and maintain
high levels of customer satisfaction and system reliability. A performance
rating adjustment feature of the plan would allow LP&L the opportunity to earn a
higher rate of return if it improves performance over time. Conversely, if
performance declines, the rate of return LP&L could earn would be lowered. This
provides financial incentive for LP&L to maintain continuous improvement in all
three performance categories (customer price, customer satisfaction, and
customer reliability). Under the proposed plan, if LP&L's earnings fall within
a bandwidth around a benchmark rate of return, there would be no adjustment in
rates. If LP&L's earnings are above the bandwidth, the proposed plan would
automatically reduce LP&L's base rates. Alternatively, if LP&L's earnings are
below the bandwidth, the proposed plan would automatically increase LP&L's base
rates. The reduction or increase in base rates would be an amount representing
50% of the difference between the earned rate of return and the nearest limit of
the bandwidth. In no event would the annual adjustment in rates exceed 2% of
LP&L's retail revenues. Hearings were held in March 1995. No assurance
can be given that the LPSC will accept the performance-based formula rate plan,
or that the current rate review will not result in a rate decrease.
February 1994 Ice Storm/Rate Rider
In early February 1994, an ice storm left more than 221,000 Entergy
customers without electric power across the System's four-state service area.
The storm was the most severe natural disaster ever to affect the System,
causing damage to transmission and distribution lines, equipment, poles, and
facilities in certain areas, primarily in Mississippi. Repair costs totaled
approximately $116.2 million, $30.8 million, and $77.2 million for the System,
AP&L, and MP&L, respectively, with $85 million, $18.7 million, and $64.6 million
of these amounts capitalized as plant-related costs. The remaining balances
have been charged against the respective companies' regulatory storm damage
reserves, except for MP&L which recorded a deferred debit. On April 15, 1994,
MP&L filed for rate recovery of costs related to the ice storm. MP&L's filing,
as subsequently amended, requested recovery of the revenue requirement
associated with MP&L's ice storm costs recorded through April 30, 1994,
representing approximately 86% of the total estimated ice storm costs. MP&L may
make another ice storm rate filing with the MPSC during 1995 to recover ice
storm costs recorded by MP&L after April 30, 1994. In August 1994, MP&L and the
MPSC's Public Utilities Staff entered into a stipulation with respect to the
recovery of ice storm costs recorded through April 30, 1994, and in September
1994, the MPSC approved the stipulation. Under the stipulation, MP&L
implemented an ice storm rider schedule, which went into effect on September 29,
1994, that will increase rates approximately $8 million annually for five years.
At the end of the five-year period, the revenue requirement associated with the
undepreciated ice storm capitalized costs will be included in MP&L's base rates
to the extent that this revenue requirement does not result in MP&L's rate of
return on rate base being above the benchmark rate of return under MP&L's
formula rate plan.
PUCT Fuel Cost Review (December 1, 1986 - September 30, 1991)
In January 1992, GSU applied to the PUCT for a new fixed fuel factor and
requested a final reconciliation of fuel and purchased power costs incurred
between December 1, 1986, and September 30, 1991. GSU proposed to recover net
underrecoveries and interest (including underrecoveries related to Nelson
Industrial Steam Company (NISCO), discussed below) over a 12-month period.
In April 1993, the presiding PUCT administrative law judge (ALJ) issued a
report concluding that GSU incurred approximately $117 million of
nonreimbursable fuel costs on a company-wide basis (approximately $50 million on
a Texas retail jurisdictional basis) during the reconciliation period. Included
in the nonreimbursable fuel costs were payments above GSU's avoided cost rate
for power purchased from NISCO. The PUCT ordered in 1986 that the purchased
power costs from NISCO in excess of GSU's avoided costs be disallowed. The PUCT
disallowance resulted in approximately $12 million to $15 million of unrecovered
purchased power costs on an annual basis, which GSU continued to expense as the
costs were incurred. In April 1991, the Texas Supreme Court, in the appeal of
such order, ordered the PUCT to allow GSU to recover purchased power payments in
excess of its avoided cost in future proceedings, if GSU established to the
PUCT's satisfaction that the payments were reasonable and necessary expenses.
In June 1993, the PUCT concluded that the purchased power payments made to
NISCO in excess of GSU's avoided cost were not reasonably incurred. As a result
of the order, GSU recorded additional fuel expenses (including interest) of $2.8
million for non-NISCO related items. The PUCT's order resulted in no additional
expenses related to the NISCO issue, or for overcollections related to the fixed
fuel factor, as those charges were expensed by GSU as they were incurred. The
PUCT concluded that GSU had over-collected its fuel costs in Texas and ordered
GSU to refund approximately $33.8 million to its Texas retail customers,
including approximately $7.5 million of interest. In that proceeding, the PUCT
also set GSU's fixed fuel factor in Texas at 1.84 cents per KWH in response to
GSU's request that the factor be set at 2.02 cents per KWH. In October 1993,
GSU appealed the PUCT's order to the Travis County District Court where the
matter is still pending. No assurance can be given as to the timing or outcome
of that appeal. In a subsequent proceeding to review GSU's fuel factor, the
PUCT approved GSU's request to further reduce its fixed fuel factor in Texas to
1.78 cents per KWH from 1.84 cents per KWH.
PUCT Fuel Cost Review (October 1, 1991 - December 31, 1993)
On January 9, 1995, GSU and various parties reached an agreement for the
reconciliation of over- and under-recovery of fuel and purchased power expenses
for the period October 1, 1991, through December 31, 1993. While the settlement
still requires PUCT approval, GSU believes it will ultimately be approved and
has accordingly recorded a reserve of $7.6 million.
LPSC Fuel Cost Review
In November 1993, the LPSC ordered a review of GSU's fuel costs for the
period October 1988 through September 1991 (Phase 1) based on the number of
outages at River Bend and the findings in the June 1993 PUCT fuel reconciliation
case. In July 1994, the LPSC ruled in the Phase 1 fuel review case and ordered
GSU to refund approximately $27 million to its customers. Under the order, a
refund of $13.1 million, which was not contested under a Louisiana Supreme Court
decision as discussed below, was made through a billing credit on August 1994
bills. In August 1994, GSU appealed the remaining portion of the LPSC-ordered
refund to the district court. GSU has made no reserve for the remaining
portion, pending outcome of the district court appeal, and no assurance can be
given as to the timing or outcome of the appeal.
On January 18, 1995, GSU met with the special counsel of the LPSC to
discuss the procedural schedule for the upcoming fuel review (Phase II). The
period under investigation was determined to be from October 1991 to December
1994. Hearings are scheduled to begin in July 1995.
In February 1990, the LPSC disallowed the pass-through to ratepayers for
the portion of GSU's cost to purchase power from NISCO representing the excess
of NISCO's purchase price of the units over GSU's depreciated cost of the units.
GSU appealed the 1990 order. In March 1994, the Louisiana Supreme Court ruled
in favor of the LPSC. In 1994, GSU recorded an estimated refund provision of
$13.1 million, before related income taxes of $5.3 million.
1994 NOPSI Settlement
In a settlement with the Council that was approved on December 29, 1994,
NOPSI agreed to reduce electric and gas rates and issue credits and refunds to
customers. Effective January 1, 1995, NOPSI implemented a $31.8 million
permanent reduction in electric base rates and a $3.1 million permanent
reduction in gas base rates. These adjustments resolved issues associated with
NOPSI's return on equity exceeding 13.76% for the test year ended September 30,
1994. Under the 1991 NOPSI Settlement, NOPSI is recovering from its retail
customers its allocable share of certain costs related to Grand Gulf 1. NOPSI's
base rates to recover those costs were derived from estimates of those costs
made at that time. Any overrecovery of costs is required to be returned to
customers. Grand Gulf 1 has experienced lower operating costs than previously
estimated, and NOPSI accordingly is reducing its base rates in two steps to more
accurately match the current costs related to Grand Gulf 1. On January 1, 1995,
NOPSI implemented a $10 million permanent reduction in base electric rates to
reflect the reduced costs related to Grand Gulf 1, to be followed by an
additional $4.4 million rate reduction on October 31, 1995. These Grand Gulf 1
rate reductions, which are expected to be largely offset by lower operating
costs, may reduce NOPSI's after-tax net income by approximately $1.4 million per
year beginning November 1, 1995. The next scheduled Grand Gulf 1 phase-in rate
increase in the amount of $4.4 million on October 31, 1995, will not be affected
by the 1994 NOPSI Settlement.
The 1994 NOPSI Settlement also requires NOPSI to credit its customers
$25 million over a 21-month period, beginning January 1, 1995, in order to
resolve disputes with the Council regarding the interpretation of the 1991 NOPSI
Settlement. NOPSI reduced its revenues by $25 million and recorded a
$15.4 million net-of-tax reserve associated with the credit in the fourth
quarter of 1994. The 1994 NOPSI Settlement further required NOPSI to refund, in
December 1994, $13.3 million of credits previously scheduled to be made to
customers during the period January 1995 through July 1995. These credits were
associated with a July 7, 1994, Council resolution that ordered a $24.95 million
rate reduction based on NOPSI's overearnings during the test year ended
September 30, 1993. Accordingly, NOPSI recorded an $8 million net-of-tax charge
in the fourth quarter of 1994.
The 1994 NOPSI Settlement also required NOPSI to refund $9.3 million of
overcollections associated with Grand Gulf 1 operating costs, and $10.5 million
of refunds associated with the settlement by System Energy of a FERC tax audit.
The settlement of the FERC tax audit by System Energy required refunds to be
passed on to NOPSI and to other Entergy subsidiaries and then on to customers.
These refunds have no effect on current period net income.
NOTE 3. INCOME TAXES
Income tax expense consisted of the following:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Current:
Federal $227,046 $236,513 $ 99,898
State 50,300 30,618 23,596
-------- -------- --------
Total 277,346 267,131 123,494
-------- -------- --------
Deferred - net:
Reclassification due to net operating loss carryforward 48,482 (17,131) 35,969
Rate deferrals - net (137,376) (88,651) (54,079)
Gas contract settlement 5,483 9,513 15,180
Liberalized depreciation 127,881 116,513 107,976
Unbilled revenue 7,246 56,315 (18,902)
Alternative minimum tax (614) (10,270) 6,577
Bond reacquisition cost (4,481) 17,958 11,496
Nuclear refueling and maintenance 552 (7,929) 9,740
Decontamination and decommissioning fund 2,366 27,303 -
Provision for rate refunds (31,739) - -
FERC Settlement (23,098) - -
Adjustment to Grand Gulf 2 tax basis (14,037) - -
Other (35,094) 15,035 (1,595)
-------- -------- --------
Total (54,429) 118,656 112,362
-------- -------- --------
Investment tax credit adjustments - net (24,739) (43,796) 20,607
Investment tax credit amortization - FERC settlement (66,454) - -
-------- -------- --------
Recorded income tax expense $131,724 $341,991 $256,463
======== ======== ========
Charged to operations $131,965 $251,163 $210,081
Charged to other income (241) 33,640 46,382
Charged to cumulative effect - 57,188 -
-------- -------- --------
Recorded income tax expense 131,724 341,991 256,463
Income taxes applied against the debt component of AFUDC - - 696
-------- -------- --------
Total income taxes $131,724 $341,991 $257,159
======== ======== ========
Total income taxes differ from the amounts computed by applying the
statutory federal income tax rate to income before taxes. The reasons for the
differences were:
For the Years Ended December 31
1994 1993 1992
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
(Dollars in Thousands)
Computed at statutory rate $194,448 35.0 $332,555 35.0 $257,461 34.0
Increases (reductions) in tax resulting from:
Amortization of excess deferred income taxes (5,845) (1.1) (7,063) (0.7) (6,537) (0.9)
State income taxes net of federal income
tax effect 13,766 2.5 30,160 3.2 26,057 3.5
Amortization of investment tax credits (27,337) (4.9) (25,911) (2.7) (26,885) (3.6)
Investment tax credit amortization -
FERC Settlement (66,454) (12.0) - - - -
Depreciation 9,995 1.8 5,925 0.6 4,527 0.6
SFAS 109 adjustment - - 9,547 1.0 - -
Other - net 13,151 2.4 (3,222) (0.4) 1,840 0.3
-------- ---- -------- ---- -------- ----
Recorded income tax expense 131,724 23.7 341,991 36.0 256,463 33.9
Income taxes applied against debt component
of AFUDC - - - - 696 0.1
-------- ---- -------- ---- -------- ----
Total income taxes $131,724 23.7 $341,991 36.0 $257,159 34.0
======== ==== ======== ==== ======== ====
Significant components of net deferred tax liabilities as of December 31,
1994 and 1993, were:
1994 1993
Deferred tax liabilities: (In Thousands)
Net regulatory assets $(1,645,119) $(1,676,161)
Plant-related basis differences (3,092,889) (2,945,933)
Rate deferrals (617,699) (767,124)
Other (181,743) (167,478)
----------- -----------
Total $(5,537,450) $(5,556,696)
=========== ===========
Deferred tax assets:
Sale and leaseback $ 247,842 $ 241,391
Accumulated deferred investment tax credit 227,473 330,852
Alternative minimum tax credit 137,387 138,063
Removal cost 88,052 92,618
Standard coal plant 29,275 30,165
NOL carryforwards 251,000 307,737
Pension-related items 30,040 24,879
Unbilled revenues 25,328 23,587
Provision for rate refunds 37,838 -
Investment tax credit carryforwards 190,987 314,862
Other 316,777 149,568
----------- -----------
Total $ 1,581,999 $ 1,653,722
=========== ===========
Net deferred tax liabilities $(3,955,451) $(3,902,974)
=========== ===========
As of December 31, 1994, Entergy had federal net operating loss (NOL)
carryforwards of $666.7 million and state NOL carryforwards of $498.2 million
related to GSU operations. Investment tax credit (ITC) and other credit
carryforwards, as of December 31, 1994, amounted to $282.6 million. The ITC
carryforwards include the 35% reduction required by the Tax Reform Act of 1986
and may be applied against federal income tax liabilities and, if not utilized,
will expire between 1995 and 2005. It is currently anticipated that
approximately $64.4 million will expire unutilized. A valuation allowance has
been provided for deferred tax assets relating to that amount. The alternative
minimum tax (AMT) credit carryforwards as of December 31, 1994, were
$137.4 million. This AMT credit can be carried forward indefinitely and will
reduce the System's federal income tax liability in the future.
In accordance with the System Energy FERC Settlement, the System wrote off
$66.5 million of unamortized deferred investment tax credits in 1994.
In 1993, the System adopted SFAS 109. SFAS 109 required that deferred
income taxes be recorded for all temporary differences and carryforwards, and
that deferred tax balances be based on enacted tax laws at tax rates that are
expected to be in effect when the temporary differences reverse. SFAS 109
required that regulated enterprises recognize adjustments resulting from
implementation as regulatory assets or liabilities if it is probable that such
amounts will be recovered from or returned to customers in future rates. A
substantial majority of the adjustments required by SFAS 109 was recorded to
deferred tax balance sheet accounts with offsetting adjustments to regulatory
assets and liabilities. As a result of the adoption of SFAS 109, 1993 net
income and earnings per share were decreased by $13.2 million and $0.08 per
share, respectively, and assets and liabilities were increased by $822.7 million
and $835.9 million, respectively. The cumulative effect of the adoption of SFAS
109 is included in income tax expense charged to operations.
In August 1994, Entergy received an Internal Revenue Service report
covering the federal income tax audit of Entergy Corporation and subsidiaries
for the years 1988 - 1990. The report asserts an $80 million tax deficiency for
the 1990 consolidated federal income tax returns related primarily to the
application of accelerated investment tax credits associated with Waterford 3
and Grand Gulf nuclear plants. Entergy believes there is no material tax
deficiency and is vigorously contesting the proposed assessment.
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy to
effect short-term borrowings up to an aggregate of $664 million, which may be
increased to as much as $1.216 billion (subject to individual authorizations for
each company) after further SEC approval. These authorizations are effective
through November 30, 1996. As of December 31, 1994, AP&L, GSU, LP&L, MP&L,
NOPSI, and System Energy had total outstanding borrowings of $91.8 million
(including $8 million under the Money Pool arrangement). Short-term borrowings
by MP&L and NOPSI are also limited by the terms of their respective G&R Bond
indentures to amounts not exceeding the greater of 10% of capitalization or 50%
of Grand Gulf 1 rate deferrals available to support the issuance of G&R Bonds.
As of December 31, 1994, GSU had unused lines of credit for short-term
borrowings of $5 million from banks within its service territories. Entergy
Services has bank lines of credit permitting it to borrow up to $70 million, of
which $65 million in borrowings was outstanding as of December 31, 1994.
Interest rates associated with AP&L, Entergy Services, GSU, LP&L, and MP&L's
lines of credit generally are based on the prime rate, the EURO dollar rate, a
certificate of deposit rate, the London interbank offered rate, or a bid rate.
Commitment fees on these lines of credit are 0.125% of the amount of available
credit. In addition, AP&L, GSU, LP&L, MP&L, NOPSI, System Energy, Entergy
Operations, Entergy Services, and System Fuels can borrow from each other and
from Entergy Corporation through the Money Pool, an intra-System borrowing
arrangement designed to reduce the System's dependence on external short-term
borrowings.
Entergy Corporation has requested, but not yet received, SEC approval for a
$300 million three-year bank line of credit. System Fuels has financing
agreements with banks permitting it to borrow up to $65 million, of which $23
million in borrowings was outstanding as of December 31, 1994. Borrowings under
System Fuels' financing agreements are restricted as to use, and are secured by
fuel inventories and certain accounts receivable from the sales of these
inventories.
NOTE 5. PREFERRED, PREFERENCE, AND COMMON STOCK
The number of shares and dollar value of the System operating companies'
preferred and preference stock were:
As of December 31,
Shares Call Price Per
Authorized and Total Share as of
Outstanding Dollar Value December 31,
1994 1993 1994 1993 1994
(Dollars in Thousands)
Preference Stock
Cumulative, without par value
7% Series (1)(2) 6,000,000 6,000,000 $150,000 $150,000 -
========= ========= ======== ========
Preferred Stock
Without sinking fund:
Cumulative, $100 par value
4.16% - 5.56% Series 1,201,715 1,201,715 $120,172 $120,172 $102.50 to $108.00
6.08% - 8.56% Series 2,262,829 2,262,829 226,283 226,283 $101.80 to $103.78
9.16% - 11.48% Series 425,000 425,000 42,500 42,500 $104.06 to $104.64
Cumulative, $25 par value
8.00% - 9.68% Series 3,880,000 3,880,000 97,000 97,000 $26.56
Cumulative, $0.01 par value
$2.40 Series (1)(2) 2,000,000 2,000,000 50,000 50,000 -
$1.96 Series (1)(2) 600,000 600,000 15,000 15,000 -
---------- ---------- -------- --------
Total without sinking fund 10,369,544 10,369,544 $550,955 $550,955
========== ========== ======== ========
With sinking fund:
Cumulative, $100 par value
7.00% - 9.76% Series 1,935,372 2,126,539 $193,537 $212,654 $100.00 to $106.75
12.00% - 15.44% Series 72,195 117,195 7,219 11,720 $106.00 to $107.72
Adjustable, 7.10% - 7.15%
as of December 31, 1993 519,000 553,500 51,900 55,350 $100.00 to $103.00
Cumulative, $25 par value
9.92% - 12.64% Series 1,691,666 2,311,666 42,290 57,791 $25.67 to $27.37
13.28% Series 200,000 461,537 5,000 11,538 $28.22
---------- ---------- -------- --------
Total with sinking fund 4,418,233 5,570,437 $299,946 $349,053
========== ========== ======== ========
(1) The total dollar value represents the involuntary liquidation value of $25
per share.
(2) These series are not redeemable as of December 31, 1994.
The fair value of the System operating companies' preferred and preference
stock with sinking fund was estimated to be approximately $437.4 million and
$526.2 million as of December 31, 1994 and 1993, respectively. The fair values
were determined using quoted market prices or estimates from nationally
recognized investment banking firms. See Note 1 for additional information on
disclosure of fair value of financial instruments.
Changes in the preferred stock of AP&L, GSU, LP&L, MP&L, and NOPSI with and
without sinking fund during the last three years were (excluding GSU in 1992):
Number of Shares
1994 1993 1992
Preferred Stock Issuances:
$100 par value - - 700,000
$25 par value - - 1,480,000
$0.01 par value - - 600,000
Preferred Stock Retirements:
$100 par value (270,667) (265,000) (589,940)
$25 par value (881,537) (1,180,000) (1,895,160)
Cash sinking fund requirements for the next five years for preferred stock
outstanding as of December 31, 1994, are (in millions): 1995 - $38.8, 1996 -
$23.3, 1997 - $22.6, 1998 - $15.3, and 1999 - $64.8.
On December 31, 1993, Entergy Corporation issued 56,695,724 shares of
common stock in connection with the Merger. In addition, Entergy Corporation
redeemed 174,552,011 shares of $5 par value common stock and reissued
174,552,011 shares of $0.01 par value common stock resulting in an increase in
paid-in capital of $871 million.
Entergy Corporation has a program to repurchase shares of its outstanding
common stock. The timing and amount of such repurchases depend upon market
conditions and authorization from the Board of Directors of Entergy Corporation
(Board). Under this program, Entergy Corporation repurchased and retired
(returned to authorized but unissued status) 1,230,000 shares at a cost of $30.7
million in 1994, and 3,671,900 shares at a cost of $161.6 million in 1992. No
shares were repurchased under the program in 1993. In addition, 2,805,000
shares, 627,000 shares, and 1,943 shares of treasury stock were purchased for
cash during 1994, 1993, and 1992, respectively, at a cost of $88.8 million,
$20.6 million, and $0.1 million, respectively. A portion of the treasury shares
purchased in 1993 were subsequently reissued and in connection with the Merger
on December 31, 1993, all of the existing balance of 579,274 shares of treasury
shares was canceled. On December 9, 1994, the Board approved the repurchase of
common shares for an aggregate consideration of not in excess of $300 million
during the period through January 1996.
Entergy Corporation has SEC authorization to acquire up to 3,000,000
shares of its common stock to be held as treasury shares and to be reissued to
meet the requirements of the Stock Plan for Outside Directors (Directors' Plan),
the Equity Ownership Plan of Entergy Corporation and Subsidiaries (Equity Plan),
and certain other stock benefit plans. The Directors' Plan awards nonemployee
directors a portion of their compensation in the form of a fixed number of
shares of Entergy Corporation common stock. Shares awarded under the Directors'
Plan were 18,757, 12,550 and 14,904 during 1994, 1993, and 1992, respectively.
The Equity Plan grants stock options, restricted shares, and equity awards to
key employees of the System companies. The costs of awards are charged to
income over the period of the grant or restricted period, as appropriate.
Amounts charged to compensation expense in 1994 were immaterial. Stock options,
which comprise 50% of the shares targeted for distribution under the Equity
Plan, are granted at exercise prices not less than market value on the date of
grant. The options are generally exercisable no less than six months nor more
than 10 years after the date of grant.
Nonstatutory stock options transactions are summarized as follows:
Option Number
Price of Options
Options granted during 1992 29.625 50,000
Options exercised during 1992 29.625 (5,000)
Options granted during 1993: 34.75 70,000
39.75* 6,107
Options exercised during 1993: 29.625 (13,198)
34.75 (5,000)
Options granted during 1994 37.00 67,500
Options exercised during 1994 - -
-------
Options remaining as of December 31, 1994 170,409
=======
* Options are not currently exercisable at December 31, 1994.
Entergy Corporation received SEC authorization in 1994 to issue new shares
for the Employee Stock Investment Plan (ESIP) or to acquire, through March 31,
1997, up to 2,000,000 shares of its common stock to be held as treasury shares
and reissued to meet the requirements of the ESIP. Under the ESIP, employees
may be granted the opportunity to purchase, (for up to 10% of their regular
annual salary, (but not more than $25,000)), common stock at 85% of the market
value on the first or last business day of the plan year, whichever is lower.
The 1994 plan year runs from April 1, 1994, to March 31, 1995.
NOTE 6. LONG -TERM DEBT
The long-term debt of Entergy Corporation's subsidiaries as of
December 31, 1994 and 1993, was:
Maturities Interest Rates
From To From To 1994 1993
(In Thousands)
First Mortgage Bonds
1995 1999 4-5/8% 14% $1,290,210 $1,354,810
2000 2004 6% 11% 1,282,320 1,143,520
2005 2009 6.65% 10% 335,000 635,000
2015 2019 9-5/8% 11-3/8% 90,319 90,319
2020 2024 7% 10-3/8% 1,083,818 1,083,818
G&R Bonds
1995 1999 5.95% 14.95%* 221,200 284,200
2000 2023 6-5/8% 8.65% 375,000 350,000
Governmental Obligations **
1992 2008 6.125% 10% 142,622 139,009
2009 2023 5.95% 12.5% 1,499,768 1,481,678
Debentures - Due 1998, 9.72% 200,000 200,000
Long-Term DOE Obligation (Note 8) 105,163 101,029
Waterford 3 Lease Obligation, 8.76% (Note 9) 353,600 353,600
Grand Gulf Lease Obligation, 7.02% (Note 9) 500,000 500,000
Other Long-Term Debt 6,879 6,879
Unamortized Premium and Discount - Net (43,341) (45,890)
---------- ----------
Total Long-Term Debt 7,442,558 7,677,972
Less Amount Due Within One Year 349,085 322,010
---------- ----------
Long-Term Debt Excluding Amount Due Within One Year $7,093,473 $7,355,962
========== ==========
* $20 million of the 14.95% Series G&R Bonds and $9.2 million of the 13.9%
Series G&R Bonds were due 2/1/95. All other series are at interest rates
within the range of 5.95% - 11.2%.
** Consists of pollution control bonds, certain series of which are secured by
non-interest bearing first mortgage bonds.
The fair value of Entergy Corporation's long-term debt, excluding lease
obligations and long-term DOE obligations, as of December 31, 1994 and 1993, was
estimated to be $6.293 billion and $7.207 billion, respectively. The fair
values were determined using bid prices reported by dealer markets and by
nationally recognized investment banking firms.
For the years 1995, 1996, 1997, 1998, and 1999, Entergy Corporation's
subsidiaries have long-term debt maturities (excluding lease obligations) and
cash sinking fund requirements aggregating (in millions) $349.1, $558.0, $361.3,
$314.9, and $172.4, respectively. In addition, other sinking fund requirements
will be satisfied by cash or by certification of property additions at the rate
of 167% of such requirements. The amounts associated with this provision total
approximately $20.9 million for each of the years 1995 through 1999.
NOTE 7. DIVIDEND RESTRICTIONS
Various agreements relating to the long-term debt and preferred stock of
Entergy Corporation's subsidiaries restrict the payment of cash dividends or
other distributions on their common stock. In addition to these restrictions,
the Holding Company Act prohibits Entergy Corporation's subsidiaries from making
loans or advances to Entergy Corporation. As of December 31, 1994, Entergy
Corporation's subsidiaries had restricted common equity of approximately $4.495
billion, including $497 million of restricted retained earnings, which were
unavailable for distribution to Entergy Corporation. In February 1995, Entergy
Corporation received common stock dividend payments from its subsidiaries
totaling $96.8 million.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Cajun - River Bend
GSU has significant business relationships with Cajun, including co-
ownership of River Bend and Big Cajun 2, Unit 3. GSU and Cajun own 70% and 30%
undivided interests in River Bend, respectively, and 42% and 58% undivided
interests in Big Cajun 2, Unit 3, respectively.
In June 1989, Cajun filed a civil action against GSU in the United States
District Court for the Middle District of Louisiana (District Court). Cajun's
complaint seeks to annul, rescind, terminate, and/or dissolve the Joint
Ownership Participation and Operating Agreement entered into on August 28, 1979
(Operating Agreement) relating to River Bend. Cajun alleges fraud and error by
GSU, breach of its fiduciary duties owed to Cajun, and/or GSU's repudiation,
renunciation, abandonment, or dissolution of its core obligations under the
Operating Agreement, as well as the lack or failure of cause and/or
consideration for Cajun's performance under the Operating Agreement. The suit
also seeks to recover Cajun's alleged $1.6 billion investment in the unit as
damages, plus attorneys' fees, interest, and costs. Two member cooperatives of
Cajun have brought an independent action to declare the Operating Agreement
void, based upon failure to get prior LPSC approval alleged to be necessary.
GSU believes the suits are without merit and is contesting them vigorously.
A trial without jury on the portion of the suit by Cajun to rescind the
Operating Agreement which began in April 1994 has been completed, and an order
from the District Court is pending. No assurance can be given as to the outcome
of this litigation. If GSU were ultimately unsuccessful in this litigation and
were required to make substantial payments, GSU would probably be unable to make
such payments and would probably have to seek relief from its creditors under
the United States Bankruptcy Code. If GSU prevails in this litigation, there
can be no assurance that the Bankruptcy Court will allow funding of all required
costs of Cajun's ownership in River Bend.
Since 1992 Cajun has not paid its full share of operating and maintenance
expenses and other costs for repairs and improvements to River Bend. In
addition, certain costs and expenses paid by Cajun were paid under protest.
These actions were taken by Cajun based on its contention, which GSU disagrees,
that River Bend's operating and maintenance expenses were excessive.
In a letter dated October 21, 1994, and at a subsequent meeting, Cajun
representatives advised Entergy Corporation and GSU that, on October 25, 1994,
Cajun would exhaust its 1994 budget for operating and maintenance expenses for
River Bend, and did not make any further payments to GSU in 1994 for River Bend
operating, maintenance, or capital costs. Cajun also advised that the RUS
(which provided funding to Cajun for its investment in River Bend) would not
permit Cajun to budget funds in 1995 to pay its share of operating and
maintenance expenses or capital costs for River Bend. However, Cajun stated
that it would continue to fund its share of the nuclear decommissioning trust
payments for River Bend, as well as insurance and safety-related expenses. The
unpaid portion of Cajun's River Bend operating, maintenance, and capital costs
for 1994 (which has been fully reserved) was approximately $22.4 million.
Cajun's total share of River Bend annual operating (including nuclear fuel) and
maintenance expenses and capital costs was approximately $76.1 million in 1994.
In view of Cajun's stated expectation that it will fund only a limited
portion of its share of River Bend related operating, maintenance, and capital
costs, GSU notified Cajun that it would (i) credit GSU's share of expenses for
Big Cajun 2, Unit 3 against amounts due from Cajun to GSU and (ii) seek to
market Cajun's share of the power from River Bend and apply the proceeds to the
amounts due from Cajun to GSU. On November 2, 1994, Cajun discontinued GSU's
entitlement of energy from Big Cajun 2, Unit 3. In response, on November 3,
1994, GSU filed pleadings in District Court seeking an order requiring Cajun to
provide GSU with the energy from Big Cajun 2, Unit 3 to which GSU is entitled,
and holding that GSU is entitled to credit amounts due from GSU to Cajun for Big
Cajun 2, Unit 3 against amounts due from Cajun to GSU with respect to River
Bend. On December 19, 1994, the District Court issued an injunction prohibiting
Cajun from denying its share of energy from Big Cajun 2, Unit 3 and stipulating
that GSU must make payments for its portion of expenses for Big Cajun 2, Unit 3
to the registry of the District Court.
On December 14, 1994, the LPSC ordered Cajun to decrease the rates charged
to its member distribution cooperatives by approximately $30 million per year.
The rate decrease is associated with the LPSC's prior finding of imprudence in
Cajun's participation in River Bend.
On December 21, 1994, Cajun filed a petition in the United States
Bankruptcy Court for the Middle District of Louisiana seeking bankruptcy relief
under Chapter 11 of the United States Bankruptcy Code. Cajun's bankruptcy could
have a material adverse effect on GSU, including the possibility of an NRC
action with respect to the operation of River Bend. However, GSU is taking
appropriate steps to protect its interests and its claims against Cajun arising
from the co-ownership in River Bend and Big Cajun 2, Unit 3. On December 31,
1994, the District Court issued an order lifting an automatic stay as to certain
proceedings, with the result that the preliminary injunction granted by the
Court on December 19, 1994, remains in effect. Cajun filed a Notice of Appeal
on January 18, 1995, to the United States Court of Appeals for the Fifth Circuit
seeking a reversal of the District Court's grant of the preliminary injunction.
No hearing date has been set on Cajun's appeal.
In the bankruptcy proceedings, Cajun filed on January 10, 1995, a motion to
reject the River Bend Operating Agreement as a burdensome executory contract.
GSU responded on January 10, 1995, with a memorandum opposing Cajun's motion
filed with the District Court. This memorandum argues that the motion should be
denied because (1) the Operating Agreement is not an executory contract that can
be rejected under the United States Bankruptcy Code, but an agreement
establishing property rights and obligations; (2) Cajun legally cannot have its
payment obligations under the Operating Agreement suspended while retaining the
benefits from co-ownership in River Bend, as the benefits and obligations are
indivisible; (3) Cajun cannot seek to dispose of its property interest in River
Bend or reject the Operating Agreement with respect thereto without disposing of
all of its property interests and rejecting all of the arrangements under the
River Bend package of agreements consisting of the Operating Agreement, Big
Cajun 2, Unit 3 facility, certain transmission lines and the buy-back agreement
pursuant to when GSU paid Cajun approximately $600 million for River Bend
capacity and energy during the early years of operation of River Bend; and (4) a
legal determination of Cajun's obligations and interests in River Bend should
only be made as part of a plan of reorganization in bankruptcy and such
determination should be subject to regulatory approvals by certain agencies with
jurisdiction over Cajun, including the NRC. If the court were to grant Cajun's
motion to reject the Operating Agreement, Cajun would be relieved of its
financial obligations under the contract, while GSU would likely have a
substantial damage claim arising from any such rejection. Although GSU believes
that Cajun's motion to reject the Operating Agreement is non-meritorious, it is
not possible to predict the outcome or ultimate impact of these proceedings.
During the period in which Cajun is not paying its share of River Bend
costs, GSU intends to fund all costs necessary for the safe, continuing
operation of the unit. The responsibilities of Entergy Operations as the
licensed operator of River Bend, for safely operating and maintaining the unit
are not affected by Cajun's actions.
The total resulting from Cajun's failure to fund repair projects, Cajun's
funding limitation on refueling outages, and the weekly funding limitation by
Cajun was $55.6 million as of December 31, 1994, compared with $33.3 million as
of December 31, 1993. These amounts are reflected in long-term receivables with
an offsetting reserve in other deferred credits. Cajun's bankruptcy may affect
the ultimate collectibility of the amounts owed to GSU, including any amounts
that may be awarded in litigation.
In September 1994, in connection with Entergy Corporation's analysis of
certain preacquisition contingencies, Entergy Corporation increased its
acquisition adjustment and GSU recorded a loss provision associated with the
River Bend litigation between GSU and Cajun and certain underpayments by Cajun
of River Bend costs, in accordance with SFAS 5, "Accounting for Contingencies."
See Note 12 for additional information on provisions for preacquisition
contingencies recorded during 1994.
Cajun - Transmission Service
GSU and Cajun are parties to FERC proceedings relating to transmission
service charge disputes. In April 1992, FERC issued a final order. In May
1992, GSU and Cajun filed motions for rehearings which are pending at FERC. In
June 1992, GSU filed a petition for review in the United States Court of Appeals
regarding certain of the issues decided by FERC. In August 1993, the United
States Court of Appeals rendered an opinion reversing the FERC order regarding
the portion of such disputes relating to the calculations of certain credits and
equalization charges under GSU's service schedules with Cajun. The opinion
remanded the issues to FERC for further proceedings consistent with its opinion.
In December 1994, FERC held a hearing to address the issues remanded by the
Court of Appeals. In February 1995, FERC clarified its order, eliminating an
issue that GSU believes the Court of Appeals directed FERC to reconsider.
GSU interprets the 1992 FERC order and the United States Court of Appeals'
decision to mean that Cajun would owe GSU approximately $93.3 million as of
December 31, 1994. However, FERC's February 1995, order indicates that FERC
believes an issue, estimated by GSU to constitute approximately $26.2 million of
this amount, may not be pursued by GSU in the remand proceedings. GSU further
estimates that if it prevails in its May 1992 motion for rehearing, Cajun would
owe GSU approximately $129.6 million as of December 31, 1994. If Cajun were to
prevail in its May 1992 motion for rehearing to FERC, and if GSU were not to
prevail in its May 1992 motion for rehearing to FERC, and if FERC does not
implement the court's remand as GSU contends is required, GSU estimates it would
owe Cajun approximately $85.6 million as of December 31, 1994. The above
amounts are exclusive of a $7.3 million payment by Cajun on December 31, 1990,
which the parties agreed to apply to the disputed transmission service charges.
GSU and Cajun further agreed that their positions at FERC would remain
unaffected by the $7.3 million payment. Pending FERC's ruling on the May 1992
motions for rehearing, GSU has continued to bill Cajun utilizing the historical
billing methodology and has booked underpaid transmission charges, including
interest, in the amount of $160.2 million as of December 31, 1994. This amount
is reflected in long-term receivables with an offsetting reserve in other
deferred credits.
Capital Requirements and Financing
Construction expenditures (excluding nuclear fuel) for the years 1995,
1996, and 1997 are estimated to total $568 million, $568 million, and
$565 million, respectively. The System will also require $1.4 billion during
the period 1995-1997 to meet long-term debt and preferred stock maturities and
cash sinking fund requirements. The System plans to meet the above requirements
primarily with internally generated funds and cash on hand, supplemented by the
issuance of debt and preferred stock. Certain System companies may also
continue with the acquisition or refinancing of all or a portion of certain
outstanding series of preferred stock and long-term debt.
Capital Funds and Availability Agreements
Entergy Corporation has agreed to supply to System Energy sufficient
capital to (1) maintain System Energy's equity capital at an amount equal to a
minimum of 35% of its total capitalization (excluding short-term debt), and (2)
permit the continuation of commercial operation of Grand Gulf 1 and to pay in
full all indebtedness for borrowed money of System Energy when due under any
circumstances. In addition, under supplements to the Capital Funds Agreement
assigning System Energy's rights as security for specific debt of System Energy,
Entergy Corporation has agreed to make cash capital contributions to enable
System Energy to make payments on such debt when due.
System Energy has entered into various agreements with AP&L, LP&L, MP&L,
and NOPSI, whereby AP&L, LP&L, MP&L, and NOPSI are obligated to purchase their
respective entitlements of capacity and energy from System Energy's 90%
ownership and leasehold interest in Grand Gulf 1, and to make payments that,
together with other available funds, are adequate to cover System Energy's
operating expenses. System Energy would have to secure funds from other
sources, including Entergy Corporation's obligations under the Capital Funds
Agreement, to cover any shortfalls from payments received from AP&L, LP&L, MP&L,
and NOPSI under these agreements.
Long-Term Contracts
The System has several long-term contracts to purchase natural gas and
low-sulfur coal for use at its generating units. LP&L has a long-term agreement
through the year 2031 to purchase energy generated by a hydroelectric facility.
If the maximum percentage (94%) of the energy is made available to LP&L, current
production projections would require estimated payments of approximately
$47 million per year through 1996, $54 million in 1997, and a total of $3.5
billion for the years 1998 through 2031. LP&L recovers the cost of purchased
energy through its fuel adjustment clause.
In 1988, GSU entered into a joint venture with a primary term of 20 years
with Conoco, Inc., Citgo Petroleum Corporation, and Vista Chemical Company
(Industrial Participants) whereby GSU's Nelson Units 1 and 2 were sold to a
partnership (NISCO) consisting of the Industrial Participants and GSU. The
Industrial Participants are supplying the fuel for the units, while GSU operates
the units at the discretion of the Industrial Participants and purchases the
electricity produced by the units. GSU is continuing to sell electricity to the
Industrial Participants. For the years ended December 31, 1994, 1993, and 1992,
the purchases of electricity from the joint venture totaled $58.3 million,
$62.6 million, and $37.8 million, respectively.
Nuclear Insurance
The Price-Anderson Act limits public liability for a single nuclear
incident to approximately $8.92 billion as of December 31, 1994. The System has
protection for this liability through a combination of private insurance
(currently $200 million each) and an industry assessment program. Under the
assessment program, the maximum amount the System would be required to pay for
each nuclear incident would be $79.3 million per reactor, payable at a rate of
$10 million per licensed reactor per incident per year. As a co-licensee of
Grand Gulf 1 with System Energy, South Mississippi Electric Power Association
(SMEPA) would share 10% of this obligation. With respect to River Bend, any
assessments pertaining to this program are allocated in accordance with the
respective ownership interests of GSU and Cajun. The System has five licensed
reactors. In addition, the System participates in a private insurance program
which provides coverage for worker tort claims filed for bodily injury caused by
radiation exposure. The program provides for a maximum assessment of
approximately $16 million for the System's five nuclear units in the event
losses exceed accumulated reserve funds.
AP&L, GSU, LP&L, and System Energy are also members of certain insurance
programs that provide coverage for property damage, including decontamination
and premature decommissioning expense, to members' nuclear generating plants.
As of December 31, 1994, AP&L, GSU, LP&L, and System Energy each were insured
against such losses up to $2.75 billion, with $250 million of this amount
designated to cover any shortfall in the NRC required decommissioning trust
funding. In addition, AP&L, GSU, LP&L, MP&L, and NOPSI are members of an
insurance program that covers certain replacement power and business
interruption costs incurred due to prolonged nuclear unit outages. Under the
property damage and replacement power/business interruption insurance programs,
these System companies could be subject to assessments if losses exceed the
accumulated funds available to the insurers. As of December 31, 1994, the
maximum amounts of such possible assessments were: AP&L - $37.2 million; GSU -
$22.6 million; LP&L - $34.7 million; MP&L - $0.9 million; NOPSI - $0.5 million;
and System Energy - $29.7 million. Under its agreement with System Energy,
SMEPA would share in System Energy's obligation. Cajun shares approximately
$4.4 million of GSU's obligation.
The amount of property insurance presently carried by the System exceeds
the NRC's minimum requirement for nuclear power plant licensees of $1.06 billion
per site. NRC regulations provide that the proceeds of this insurance must be
used, first, to place and maintain the reactor in a safe and stable condition
and, second, to complete decontamination operations. Only after proceeds are
dedicated for such use and regulatory approval is secured, would any remaining
proceeds be made available for the benefit of plant owners or their creditors.
Spent Nuclear Fuel and Decommissioning Costs
AP&L, GSU, LP&L, and System Energy provide for estimated future disposal
costs for spent nuclear fuel in accordance with the Nuclear Waste Policy Act of
1982. The affected System companies entered into contracts with the Department
of Energy (DOE), whereby the DOE will furnish disposal service at a cost of one
mill per net KWH generated and sold after April 7, 1983, plus a one-time fee for
generation prior to that date. AP&L, the only System company that generated
electricity with nuclear fuel prior to that date, elected to pay the one-time
fee, plus accrued interest, no earlier than 1998, and has recorded a liability
as of December 31, 1994, of approximately $105 million. The fees payable to the
DOE may be adjusted in the future to assure full recovery. The System considers
all costs incurred or to be incurred, except accrued interest, for the disposal
of spent nuclear fuel to be proper components of nuclear fuel expense, and
provisions to recover such costs have been or will be made in applications to
regulatory authorities.
Delays have occurred in the DOE's program for the acceptance and disposal
of spent nuclear fuel at a permanent repository. In a statement released
February 17, 1993, the DOE asserted that it does not have a legal obligation to
accept spent nuclear fuel without an operational repository for which it has not
yet arranged. Currently the DOE projects it will begin to accept spent fuel no
earlier than 2010. In the meantime, all System companies are responsible for
spent fuel storage. Current on-site spent fuel storage capacity at River Bend,
Waterford 3, and Grand Gulf 1 is estimated to be sufficient until 2003, 2000,
and 2004, respectively. Thereafter, the affected companies will provide
additional storage. Current on-site spent fuel storage capacity at ANO is
estimated to be sufficient until mid-1995, at which time an ANO storage facility
using dry casks will begin operation. This facility is estimated to provide
sufficient storage until 2000, with the capability of being expanded further as
required. The initial cost of providing the additional on-site spent fuel
storage capability required at ANO, River Bend, Waterford 3, and Grand Gulf 1 is
expected to be approximately $5 million to $10 million per unit. In addition,
approximately $3 million to $5 million per unit will be required every two to
three years subsequent to 1995 for ANO and every four to five years subsequent
to 2003, 2000, and 2004 for River Bend, Waterford 3, and Grand Gulf 1,
respectively, until the DOE's repository begins accepting such units' spent
fuel.
Entergy Operations and System Fuels joined in lawsuits against the DOE,
seeking clarification of the DOE's responsibility to receive spent nuclear fuel
beginning in 1998. The original suits, filed June 20, 1994, asked for a ruling
stating that the Nuclear Waste Policy Act require the DOE to begin taking title
to the spent fuel and to start removing it from nuclear power plants in 1998, a
mandate for the DOE's nuclear waste management program to begin accepting fuel
in 1998 and court monitoring of the program, and the potential for escrow of
payments to a nuclear waste fund instead of directly to the DOE.
Decommissioning costs for ANO, River Bend (excluding Cajun's 30% share),
Waterford 3, and Grand Gulf 1 (excluding Southern Mississippi Electric Power
Association's 10% share) were estimated to be approximately $806.3 million
(based on a 1994 interim update to the 1992 cost study), $267.8 million (based
on a 1991 cost study reflecting 1990 dollars), $320.1 million (based on a 1994
updated study in 1993 dollars), and $365.9 million (based on a 1994 cost study
using 1993 dollars), respectively. AP&L is authorized to recover through rates
amounts that, when added to estimated investment income, should be sufficient to
meet the above estimated decommissioning costs for ANO. GSU is currently
recovering in rates decommissioning costs based on the 1985 original cost study
of $141 million. GSU filed a 1991 study with the PUCT requesting a rate
adjustment for decommissioning expense. As discussed in Note 2, on March 20,
1995, the PUCT ruled in the current rate case. The PUCT order included recovery
of River Bend decommissioning costs totaling $204.9 million. GSU plans to
include the 1991 study in its next LPSC rate review scheduled for mid-1995.
LP&L currently is recovering in rates decommissioning costs based on a 1988
study update reflecting a cost of $203 million. LP&L filed with the LPSC a
request for a rate adjustment for decommissioning expense based on a 1994 cost
study update and the matter is under review. System Energy is currently
recovering in rates amounts sufficient to fund $198 million (in 1989 dollars) of
its decommissioning costs. A filing with FERC to request the updated
decommissioning costs in rates is under consideration by System Energy. AP&L,
GSU, LP&L, and System Energy regularly review and update estimated
decommissioning costs, and applications will be made to the appropriate
regulatory authorities to reflect in rates any future change in projected
decommissioning costs. The amounts recovered in rates are deposited in external
trust funds and reported at market value. The accumulated decommissioning
liability has been recorded in accumulated depreciation for AP&L, GSU, and LP&L,
and in other deferred credits for System Energy, in the amounts of $137.4
million, $22.2 million, $28.2 million, and $31.9 million, respectively, as of
December 31, 1994. Decommissioning expense amounting to $25.1 million was
recorded in 1994. The actual decommissioning costs may vary from the estimates
because of regulatory requirements, changes in technology, and increased costs
of labor, materials, and equipment. Management believes that actual
decommissioning costs are likely to be higher than the amounts presented above.
The staff of the SEC has questioned certain of the current accounting
practices of the electric utility industry, regarding the recognition,
measurement, and classification of decommissioning costs for nuclear generating
stations in the financial statements of electric utilities. In response to
these questions, the FASB is currently reviewing the accounting for
decommissioning. If current electric utility industry accounting practices for
such decommissioning are changed, annual provisions for decommissioning could
increase, the estimated cost for decommissioning could be recorded as a
liability rather than as accumulated depreciation, and trust fund income from
the external decommissioning trusts could be reported as investment income
rather than as a reduction to decommissioning expense.
The EPAct has a provision that assesses domestic nuclear utilities with
fees for the decontamination and decommissioning of the DOE's past uranium
enrichment operations. The decontamination and decommissioning assessments will
be used to set up a fund into which contributions from utilities and the federal
government will be placed. AP&L's, GSU's, LP&L's, and System Energy's annual
assessments, which will be adjusted annually for inflation, are approximately
$3.4 million, $0.9 million, $1.3 million, and $1.4 million (in 1995 dollars),
respectively, for approximately 15 years. FERC requires that utilities treat
these assessments as costs of fuel as they are amortized. The cumulative
liability of $75.9 million as of December 31, 1994, is recorded in other current
liabilities and other noncurrent liabilities and is offset in the consolidated
financial statements by a regulatory asset.
ANO Matters
ANO 2 experienced a forced outage for repair of certain steam generator
tubes in March 1992. Further inspections and repairs were conducted at
subsequent refueling and mid-cycle outages in September 1992, May 1993, April
1994, and January 1995. AP&L's budgeted maintenance expenditures were adequate
to cover the cost of such repairs. ANO 2's output has been reduced 15 megawatts
or 1.6% due to secondary side fouling, tube plugging, and reduction of primary
temperature. Entergy Operations continues to take steps at ANO 2 to reduce the
number and severity of future tube cracks. In addition, Entergy Operations
continues to meet with the NRC to discuss such steps and results of inspections
of the steam generator tubes, as well as the timing of future inspections.
Additional inspections are planned for the normal refueling outage scheduled for
October 1995.
Sales/Use Tax Issues
In September 1994, the Louisiana Supreme Court (Court) issued an opinion
(in a case in which none of the System companies was a party) holding, in part,
that the Louisiana state legislature's suspension of state sales and use tax
exemptions also had the effect of suspending exemptions from local sales and use
taxes. On January 27, 1995 the Court, after rehearing, reversed its opinion.
Because of the Court's most recent ruling, sales of electricity and gas, fuels
and other items used by GSU, LP&L, and NOPSI to generate electricity in
Louisiana, as well as other items exempt from sales and use taxes, continue to
be exempt from local sales and use taxes, even though the state exemptions for
sales and use tax have been suspended.
NOTE 9. LEASES
General
As of December 31, 1994, the System had capital leases and noncancelable
operating leases (excluding nuclear fuel leases and the sale and leaseback
transactions discussed below) with minimum lease payments as follows:
Capital Operating
Year Leases Leases
(In Thousands)
1995 $ 33,008 $65,429
1996 29,054 57,133
1997 24,653 48,861
1998 24,634 47,446
1999 24,610 43,128
Years thereafter 136,294 246,303
--------- --------
Minimum lease payments 272,253 $508,300
========
Less: Amount representing interest 103,596
--------
Present value of net minimum lease payments $168,657
========
Rental expense for capital and operating leases (excluding nuclear fuel
leases and the sale and leaseback transactions) amounted to approximately $64.8
million, $62.7 million, and $75.5 million in 1994, 1993, and 1992, respectively.
Nuclear Fuel Leases
AP&L, GSU, LP&L, and System Energy have arrangements to lease nuclear fuel
in an aggregate amount up to $430 million as of December 31, 1994. The lessors
finance their acquisitions of nuclear fuel through credit agreements and the
issuance of notes. If a lessor cannot arrange financing upon maturity of its
borrowings, the lessee must purchase nuclear fuel in an amount sufficient to
enable the lessor to retire such borrowings.
Lease payments are based on nuclear fuel use. Nuclear fuel lease expense
for AP&L, GSU, LP&L, and System Energy of $163.4 million (including interest of
$27.3 million) was charged to operations in 1994. Excluding GSU, nuclear fuel
expense of $145.8 million and $158.4 million (including interest of $20.5
million and $25.6 million) was charged to operations in 1993 and 1992,
respectively.
Sale and Leaseback Transactions
In 1988 and 1989, System Energy and LP&L, respectively, sold and leased
back portions of their ownership interests in Grand Gulf 1 and Waterford 3, for
26 1/2-year and 28-year lease terms, respectively. Both companies have options
to terminate the leases, to repurchase the sold interests, or to renew the
leases at the end of their terms.
Under System Energy's sale and leaseback arrangements, letters of credit
are required to be maintained to secure certain amounts payable, for the benefit
of equity investors, by System Energy under the leases. The letters of credit
currently maintained are effective until January 1997. It is expected that the
letters of credit will either be renewed, extended, or replaced prior to
expiration. On January 18, 1994, System Energy refinanced the debt portion of
the sale and leaseback arrangements. The new secured lease obligation bonds of
$356 million, 7.43% series due 2011, and $79 million, 8.2% series due 2014, will
be indirectly secured by liens on, and a security interest in, certain ownership
interests and the respective leases relating to Grand Gulf 1.
LP&L did not exercise its option to repurchase the undivided interests in
Waterford 3 on the fifth anniversary (September 1994) of the closing date of the
sale and leaseback transactions. As a result, LP&L was required to provide
collateral to the Owner Participants for the equity portion of certain amounts
payable by LP&L under the lease. Such collateral was in the form of a new
series of non-interest bearing first mortgage bonds in the aggregate principal
amount of $208.2 million issued by LP&L in September 1994 under its first
mortgage bond indenture.
As of December 31, 1994, System Energy and LP&L had future minimum lease
payments (reflecting implicit rates of 7.02% after the above refinancing and
8.76%, respectively) as follows:
System
Energy LP&L
(In Thousands)
1995 $ 42,464 $ 32,569
1996 42,753 35,165
1997 42,753 39,805
1998 42,753 41,447
1999 42,753 50,530
Years thereafter 802,820 676,214
---------- --------
Total $1,016,296 $875,730
========== ========
NOTE 10. POSTRETIREMENT BENEFITS
Pension Plans
The System companies have various postretirement benefit plans covering
substantially all of their employees. The pension plans are noncontributory and
provide pension benefits that are based on employees' credited service and
compensation during the final years before retirement. Entergy Corporation and
its subsidiaries fund pension costs in accordance with contribution guidelines
established by the Employee Retirement Income Security Act of 1974, as amended,
and the Internal Revenue Code of 1986, as amended. The assets of the plans
include common and preferred stocks, fixed income securities, interest in a
money market fund, and insurance contracts.
Total 1994, 1993, and 1992 pension cost of Entergy Corporation and its
subsidiaries (excluding GSU for 1993 and 1992), including amounts capitalized,
included the following components:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Service cost - benefits earned during the period $35,712 $21,760 $18,784
Interest cost on projected benefit obligation 77,943 53,371 50,225
Actual return on plan assets 10,381 (81,708) (43,772)
Net amortization and deferral (96,893) 27,261 (8,243)
Other 17,963 - -
------- ------- -------
Net pension cost $45,106 $20,684 $16,994
======= ======= =======
The funded status of Entergy's various pension plans as of December 31,
1994 and 1993 was:
1994 1993
(In Thousands)
Actuarial present value of accumulated pension plan obligation:
Vested $ 851,194 $ 851,726
Nonvested 6,479 17,867
---------- ----------
Accumulated benefit obligation $ 857,673 $ 869,593
========== ==========
Plan assets at fair value $1,014,430 $1,059,715
Projected benefit obligation 999,153 1,064,364
---------- ----------
Plan assets in excess of (less than) projected benefit obligation 15,277 (4,649)
Unrecognized prior service cost 25,501 20,288
Unrecognized transition asset (54,209) (61,561)
Unrecognized net loss (gain) (9,332) 32,634
---------- ----------
Accrued pension liability $ (22,763) $ (13,288)
========== ==========
The pension liability for 1993 has been restated in order to make GSU's
presentation of certain Early Retirement Plan liabilities consistent with the
other System companies. The significant actuarial assumptions used in computing
the information above for 1994, 1993, and 1992 (only 1994 and 1993 with respect
to GSU's plan), were as follows: weighted average discount rate, 8.5% for 1994,
7.5% for 1993, and 8.25% for 1992; weighted average rate of increase in future
compensation levels, 5.1% for 1994 and 5.6% (5% for GSU) for 1993 and 1992; and
expected long-term rate of return on plan assets, 8.5% . Transition assets of
the System are being amortized over the greater of the remaining service period
of active participants or 15 years.
Other Postretirement Benefits
The System companies also provide certain health care and life insurance
benefits for retired employees. Substantially all employees may become eligible
for these benefits if they reach retirement age while still working for the
System companies. The cost of providing these benefits, recorded on a cash
basis, to retirees in 1992 (excluding GSU) was approximately $13 million.
Effective January 1, 1993, Entergy adopted SFAS 106. The new standard
requires a change from a cash method to an accrual method of accounting for
postretirement benefits other than pensions. The System operating companies,
other than MP&L and NOPSI, continue to fund these benefits on a pay-as-you-go
basis. During 1994, pursuant to regulatory directives, MP&L and NOSPI began to
fund their postretirement benefit obligation. At January 1, 1993, the
actuarially determined accumulated postretirement benefit obligation (APBO)
earned by retirees and active employees was estimated to be approximately
$241.4 million and $128 million for Entergy (other than GSU) and for GSU,
respectively. Such obligations are being amortized over a 20-year period
beginning in 1993.
The System operating companies have sought approval, in their respective
regulatory jurisdictions, to implement the appropriate accounting requirements
related to SFAS 106 for ratemaking purposes. AP&L has received an order
permitting deferral, as a regulatory asset, of these costs. MP&L is expensing
its SFAS 106 costs, which are reflected in rates pursuant to an order from the
MPSC in connection with MP&L's formulary incentive rate plan (see Note 2). The
LPSC ordered GSU and LP&L to use the pay-as-you-go method for ratemaking
purposes for postretirement benefits other than pensions, but the LPSC retains
the flexibility to examine individual companies' accounting for postretirement
benefits to determine if special exceptions to this order are warranted. NOPSI
is expensing its SFAS 106 costs. Pursuant to resolutions adopted in November
1993 by the Council related to the Merger, NOPSI's SFAS 106 expenses through
October 31, 1996, will be allowed by the Council for purposes of evaluating the
appropriateness of NOPSI's rates. Pursuant to a ruling by the PUCT applicable
to all Texas utilities, including GSU, amounts recorded in compliance with SFAS
106 and included in a rate filing test period, will be recoverable in rates (at
the time of the next general rate case), and postretirement benefits amounts
allowed in rates must then be funded by the utility.
Total 1994 and 1993 postretirement benefit cost of Entergy Corporation and
its subsidiaries (excluding GSU for 1993), including amounts capitalized and
deferred, included the following components:
1994 1993
(In Thousands)
Service cost - benefits earned during the period $11,863 $7,751
Interest cost on APBO 23,312 19,394
Return on plan assets - (71)
Net amortization and deferral 9,891 12,071
------- -------
Net periodic postretirement benefit cost $45,066 $39,145
======= =======
The funded status of Entergy's postretirement plans as of December 31, 1994
and 1993, was:
1994 1993
(In Thousands)
Accumulated postretirement benefit obligation:
Retirees $ 186,570 $ 221,562
Other fully eligible participants 58,330 68,283
Other active participants 52,324 95,854
--------- ---------
297,224 385,699
Plan assets at fair value 9,733 354
--------- ---------
Plan assets less than APBO (287,491) (385,345)
Unrecognized transition obligation 217,275 229,346
Unrecognized net loss (gain) (58,178) 28,529
--------- ---------
Accrued postretirement benefit liability $(128,394) $(127,470)
========= =========
The assumed health care cost trend rate used in measuring the APBO of the
System companies was 9.4% for 1995, gradually decreasing each successive year
until it reaches 5.0% in 2011. A one percentage-point increase in the assumed
health care cost trend rate for each year would have increased the APBO of the
System companies, as of December 31, 1994, by 8.9%, and the sum of the service
cost and interest cost by approximately 11.3% . The assumed discount rate and
rate of increase in future compensation used in determining the APBO were 8.5%
for 1994 and 7.5% for 1993 and 5.1% for 1994 and 5.5% (5% for GSU) for 1993,
respectively.
NOTE 11. RESTRUCTURING COSTS
During the third quarter of 1994, Entergy announced a restructuring program
related to certain of its operating units. The program is designed to reduce
costs, improve operating efficiencies, and increase shareholder value in order
to enable Entergy to become a low-cost producer. The program includes
reductions in the number of employees and the consolidation of offices and
facilities. In 1994, AP&L, GSU, LP&L, MP&L, and NOPSI recorded restructuring
charges of $12.5 million, $6.5 million, $6.8 million, $6.2 million, and $3.4
million, respectively. These charges primarily include employee severance costs
related to the expected termination of approximately 1,850 employees. As of
December 31, 1994, 35 AP&L employees were terminated under the program at a
severance cost of approximately $0.3 million.
NOTE 12. ENTERGY CORPORATION-GSU MERGER
On December 31, 1993, Entergy Corporation and GSU consummated their Merger.
GSU became a wholly-owned subsidiary of Entergy Corporation and continues to
operate as a corporation under the regulation of FERC, the PUCT, and the LPSC.
As consideration to GSU's shareholders, Entergy Corporation paid $250 million
and issued 56,695,724 shares of its common stock in exchange for the 114,055,065
outstanding shares of GSU common stock. In addition, $33.5 million of
transaction costs were capitalized in connection with the Merger.
As a result of the December 31, 1993, Merger closing, GSU recorded expenses
totaling $49 million, net of related tax effects, for early retirement and other
severance related plans and the payment to financial consultants involved in
Merger negotiations on behalf of GSU. Additionally, GSU recorded $23.8 million
in 1994 for remaining severance and augmented retirement benefits related to the
Merger. See Note 2 for information regarding Merger-related rate agreements.
In 1993, Entergy Corporation recorded an acquisition adjustment in utility
plant in the amount of $380 million representing the excess of the purchase
price over the net assets acquired of GSU. The acquisition adjustment will be
amortized on a straight-line basis over a 31-year period, which approximates the
remaining average book life of GSU's plant. During the allocation period (which
expired on December 31, 1994), Entergy Corporation completed its analyses with
respect to preacquisition contingencies and revised the allocation of the
purchase price for a number of preacquisition contingencies. In 1994, GSU wrote
off assets or recorded liabilities totaling approximately $137 million net of
tax for the Cajun-River Bend litigation, unfunded Cajun-River Bend costs,
environmental cleanup costs, obsolete spare parts, Louisiana River Bend rate
deferrals previously disallowed by the LPSC, plant held for future use, and a
PUCT fuel reconciliation settlement. Any items recorded in 1995 or later will
result in write-offs and/or losses charged to operations on GSU's financial
statements and Entergy Corporation's consolidated financial statements.
In accordance with the purchase method of accounting, the 12-month results
of operations for Entergy Corporation reported in its Statements of Consolidated
Income, Cash Flows, and Retained Earnings do not reflect GSU's results of
operations for any period prior to January 1, 1994, as a result of the Merger.
The pro forma combined revenues, net income, earnings per common share before
extraordinary items, cumulative effect of accounting changes, and earnings per
common share of Entergy Corporation presented below give effect to the Merger as
if it had occurred at January 1, 1992. This unaudited pro forma information is
not necessarily indicative of the results of operations that would have occurred
had the Merger been consummated for the period for which it is being given
effect, nor is it necessarily indicative of future operating results.
Year Ended December 31,
1993 1992
(In Thousands, Except Per Share Amounts)
Revenues $6,286,999 $5,850,973
Net income $ 595,211 $ 521,783
Earnings per average common share
before extraordinary items and
cumulative effect of accounting changes $ 2.10 $ 2.26
Earnings per average common share $ 2.57 $ 2.24
NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED)
The business of the System is subject to seasonal fluctuations with the
peak period occurring during the third quarter. Consolidated operating results
for the four quarters of 1994 and 1993 were:
Net Earnings
Operating Operating Income (Loss)
Revenue Income (Loss) per Share
(In Thousands, Except Per Share Amounts)
1994:
First Quarter $1,406,039 $253,870 $ 70,735 $ 0.31
Second Quarter $1,586,298 $325,935 $144,337 $ 0.63
Third Quarter $1,805,524 $336,611 $143,198 $ 0.63
Fourth Quarter $1,165,429 $152,325 $(16,429) $(0.07)
1993:
First Quarter $ 926,412 $192,743 $151,154 $ 0.86
Second Quarter $1,070,102 $260,574 $130,860 $ 0.75
Third Quarter $1,410,951 $359,938 $233,430 $ 1.34
Fourth Quarter $1,077,872 $180,086 $ 36,486 $ 0.21
See Note 1 for information regarding the recording of the cumulative effect
of the change in accounting principle for unbilled revenues in January
1993.
ENTERGY CORPORATION AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1994 1993 1992 1991 1990
(In Thousands, Except Per Share Amounts)
Operating revenues $ 5,963,290 $ 4,485,337 $ 4,116,499 $ 4,051,429 $ 3,982,062
Income before cumulative
effect of a change in
accounting principle $ 341,841 $ 458,089 $ 437,637 $ 482,032 $ 478,318
Earnings per share before
cumulative effect of a change
in accounting principle $ 1.49 $ 2.62 $ 2.48 $ 2.64 $ 2.44
Dividends declared per share $ 1.80 $ 1.65 $ 1.45 $ 1.25 $ 1.05
Return on average common equity 5.31% 12.58% 10.31% 11.57% 11.47%
Book value per share, year-end (2) $ 27.93 $ 28.27 $ 24.35 $ 23.46 $ 22.18
Total assets (2) $22,613,491 $22,876,697 $14,239,537 $14,383,102 $14,831,394
Long-term obligations (1)(2) $ 7,817,366 $ 8,177,882 $ 5,630,505 $ 5,801,364 $ 6,395,951
(1) Includes long-term debt (excluding currently maturing debt), preferred and
preference stock with sinking fund, and noncurrent capital lease
obligations.
(2) 1993 amounts include the effects of the Merger in accordance with the
purchase method of accounting for combinations (see Note 11).
1994 1993 1992 1991 1990
(Dollars in Thousands)
Electric Operating Revenues:
Residential $2,126,260 $1,596,480 $1,440,360 $1,463,281 $1,449,768
Commercial 1,499,206 1,072,583 1,007,420 996,619 988,409
Industrial 1,832,916 1,199,172 1,097,023 1,068,802 1,051,796
Governmental 159,694 136,649 127,753 128,762 124,597
---------- ---------- ---------- ----------- ----------
Total retail 5,618,076 4,004,884 3,672,556 3,657,464 3,614,570
Sales for resale 311,018 293,894 252,288 220,347 212,504
Other (1) (131,325) 95,568 118,711 96,667 67,045
---------- ---------- ---------- ----------- ----------
Total $5,797,769 $4,394,346 $4,043,555 $3,974,478 $3,894,119
========== ========== ========== ========== ==========
Billed Electric Energy
Sales (Millions of KWH):
Residential 26,231 18,946 17,549 18,329 18,174
Commercial 20,050 13,420 12,928 13,164 12,977
Industrial 41,030 24,889 23,610 23,466 22,795
Governmental 2,233 1,887 1,839 1,903 1,831
---------- ---------- ---------- ----------- ----------
Total retail 89,544 59,142 55,926 56,862 55,777
Sales for resale 7,908 8,291 7,979 7,346 6,292
---------- ---------- ---------- ----------- ----------
Total 97,452 67,433 63,905 64,208 62,069
========== ========== ========== =========== ==========
(1) 1994 includes the effects of the FERC Settlement, the 1994 NOPSI
Settlement, and a GSU reserve for rate refund.
Arkansas Power & Light Company
1994 Financial Statements
ARKANSAS POWER & LIGHT COMPANY
DEFINITIONS
Certain abbreviations or acronyms used in AP&L's Financial
Statements, Notes to Financial Statements, and Management's Financial
Discussion and Analysis are defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
ANO Arkansas Nuclear One Steam Electric
Generating Station
ANO 2 Unit No. 2 of ANO
AP&L Arkansas Power & Light Company
APSC Arkansas Public Service Commission
DOE United States Department of Energy
Entergy or System Entergy Corporation and its various direct
and indirect subsidiaries
Entergy Operations Entergy Operations, Inc., a subsidiary of
Entergy Corporation that has operating
responsibility for Grand Gulf 1, Waterford 3,
ANO, and River Bend
Entergy Services Entergy Services, Inc.
Entergy Power Entergy Power, Inc., a subsidiary of Entergy
Corporation that markets capacity and energy
for resale from certain generating facilities
to other parties, principally non-affiliates
EPAct The Energy Policy Act of 1992
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Grand Gulf Station Grand Gulf Steam Electric Generating Station
(nuclear)
Grand Gulf 1 Unit No. 1 of the Grand Gulf Station
(nuclear)
Grand Gulf 2 Unit No. 2 of the Grand Gulf Station
(nuclear)
GSU Gulf States Utilities Company (including
wholly-owned subsidiaries - Varibus
Corporation, GSG&T, Inc., Prudential Oil and
Gas, Inc., and Southern Gulf Railway Company)
Independence Station Independence Steam Electric Generating
Station
KWH Kilowatt-Hour(s)
LP&L Louisiana Power & Light Company
Merger The combination transaction, consummated on
December 31, 1993, by which GSU became a
subsidiary of Entergy Corporation and Entergy
Corporation became a Delaware Corporation
Money Pool Entergy Money Pool, which allows certain
System companies to borrow from, or lend to,
certain other System companies
MP&L Mississippi Power & Light Company
NOPSI New Orleans Public Service Inc.
NRC Nuclear Regulatory Commission
OBRA Omnibus Budget Reconciliation Act of 1993
Revised Settlement
Agreement Arkansas Settlement Agreement, as
modified by the APSC order issued October 6,
1988, to bring the Grand Gulf 1-related
phase-in plan into compliance with the
requirements of SFAS 92, "Regulated
Enterprises - Accounting for Phase-in Plans"
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
promulgated by the FASB
SFAS 106 SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions"
SFAS 109 SFAS 109, "Accounting for Income Taxes"
System or Entergy Entergy Corporation and its various direct
and indirect subsidiaries
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI,
collectively
Union Electric Union Electric Company of St. Louis, Missouri
White Bluff Station White Bluff Steam Electric Generating Station
ARKANSAS POWER & LIGHT COMPANY
REPORT OF MANAGEMENT
The management of Arkansas Power & Light Company has prepared and
is responsible for the financial statements and related financial
information included herein. The financial statements are based on
generally accepted accounting principles. Financial information
included elsewhere in this report is consistent with the financial
statements.
To meet its responsibilities with respect to financial
information, management maintains and enforces a system of internal
accounting controls that is designed to provide reasonable assurance,
on a cost-effective basis, as to the integrity, objectivity, and
reliability of the financial records, and as to the protection of
assets. This system includes communication through written policies
and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and
the training of personnel. This system is also tested by a
comprehensive internal audit program.
The independent public accountants provide an objective
assessment of the degree to which management meets its responsibility
for fairness of financial reporting. They regularly evaluate the
system of internal accounting controls and perform such tests and
other procedures as they deem necessary to reach and express an
opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide
reasonable assurance that its operations are carried out with a high
standard of business conduct.
/s/ Edwin Lupberger /s/ Gerald D. McInvale
EDWIN LUPBERGER GERALD D. MCINVALE
Chairman and Chief Executive Officer Senior Vice President and
Chief Financial Officer
ARKANSAS POWER & LIGHT COMPANY
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Entergy Corporation Board of Directors' Audit Committee
functions as the Audit Committee for Arkansas Power & Light Company.
The Audit Committee is comprised of four directors, who are not
officers of AP&L: H. Duke Shackelford (Chairman), Lucie J. Fjeldstad,
Dr. Norman C. Francis, and James R. Nichols. The committee held four
meetings during 1994.
The Audit Committee oversees AP&L's financial reporting process
on behalf of the Board of Directors and provides reasonable assurance
to the Board that sufficient operating, accounting, and financial
controls are in existence and are adequately reviewed by programs of
internal and external audits.
The Audit Committee discussed with Entergy's internal auditors
and the independent public accountants (Coopers & Lybrand L.L.P.) the
overall scope and specific plans for their respective audits, as well
as AP&L's financial statements and the adequacy of AP&L's internal
controls. The committee met, together and separately, with Entergy's
internal auditors and independent public accountants, without
management present, to discuss the results of their audits, their
evaluation of AP&L's internal controls, and the overall quality of
AP&L's financial reporting. The meetings also were designed to
facilitate and encourage any private communication between the
committee and the internal auditors or independent public accountants.
/s/ H. Duke Shackelford
H. DUKE SHACKELFORD
Chairman, Audit Committee
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
Arkansas Power & Light Company
We have audited the accompanying balance sheet of Arkansas Power
& Light Company as of December 31, 1994, and the related statements of
income, retained earnings and cash flows for the year then ended.
These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements based on our audit. The financial statements of
the Company as of December 31, 1993 and for the years ended December
31, 1993 and 1992, were audited by other auditors, whose report, dated
February 11, 1994, included an explanatory paragraph that described
changes in methods of accounting for revenues, income taxes and
postretirement benefits other than pensions which are discussed in
Notes 1, 3 and 10 respectively, to these financial statements.
We conducted our audit in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position of
the Company as of December 31, 1994, and the result of its operations
and its cash flows for the year then ended in conformity with
generally accepted accounting principles.
/s/ Coopers & Lybrand L.L.P.
COOPERS & LYBRAND L.L.P.
New Orleans, Louisiana
February 21, 1995
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of
Arkansas Power & Light Company
We have audited the accompanying balance sheet of Arkansas Power
& Light Company (AP&L) as of December 31, 1993, and the related
statements of income, retained earnings, and cash flows for each of
the two years in the period ended December 31, 1993. These financial
statements are the responsibility of AP&L's management. Our
responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all
material respects, the financial position of AP&L at December 31,
1993, and the results of its operations and its cash flows for each of
the two years in the period ended December 31, 1993 in conformity with
generally accepted accounting principles.
As discussed in Note 1 to the financial statements, AP&L changed
its method of accounting for revenues in 1993 and, as discussed in
Notes 3 and 10 to the financial statements, in 1993 AP&L changed its
methods of accounting for income taxes and postretirement benefits
other than pensions, respectively.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 11, 1994
ARKANSAS POWER & LIGHT COMPANY
BALANCE SHEETS
ASSETS
December 31,
1994 1993
(In Thousands)
Utility Plant:
Electric $4,293,097 $4,098,355
Property under capital leases 56,135 62,139
Construction work in progress 136,701 197,005
Nuclear fuel under capital lease 94,628 93,606
---------- ----------
Total 4,580,561 4,451,105
Less - accumulated depreciation and amortization 1,710,216 1,604,318
---------- ----------
Utility plant - net 2,870,345 2,846,787
---------- ----------
Other Property and Investments:
Investment in subsidiary companies - at equity 11,215 11,232
Decommissioning trust fund 127,136 108,192
Other - at cost (less accumulated depreciation) 4,628 4,257
---------- ----------
Total 142,979 123,681
---------- ----------
Current Assets:
Cash and cash equivalents:
Cash 3,737 1,825
Temporary cash investments - at cost,
which approximates market:
Associated companies 4,713 -
Other 72,306 -
---------- ----------
Total cash and cash equivalents 80,756 1,825
Accounts receivable:
Customer (less allowance for doubtful accounts
of $2.0 million in 1994 and $2.1 million in 1993) 53,781 65,641
Associated companies 28,506 18,312
Other 11,181 20,817
Accrued unbilled revenues 83,863 83,378
Fuel inventory - at average cost 34,561 51,920
Materials and supplies - at average cost 79,886 81,398
Rate deferrals 113,630 92,592
Deferred excess capacity 8,414 9,115
Prepayments and other 23,867 28,303
---------- ----------
Total 518,445 453,301
---------- ----------
Deferred Debits and Other Assets:
Regulatory Assets:
Rate deferrals 360,496 475,387
Deferred excess capacity 20,060 28,465
SFAS 109 regulatory asset - net 227,068 234,015
Unamortized loss on reacquired debt 57,344 60,169
Other regulatory assets 68,813 72,360
Other 26,665 39,940
---------- ----------
Total 760,446 910,336
---------- ----------
TOTAL $4,292,215 $4,334,105
========== ==========
See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
1994 1993
(In Thousands)
Capitalization:
Common stock, $0.01 par value, authorized
325,000,000 shares; issued and outstanding
46,980,196 shares in 1994 and 1993 $470 $470
Paid-in capital 590,844 590,844
Retained earnings 491,799 448,811
---------- ----------
Total common shareholder's equity 1,083,113 1,040,125
Preferred stock:
Without sinking fund 176,350 176,350
With sinking fund 58,527 70,027
Long-term debt 1,293,879 1,313,315
---------- ----------
Total 2,611,869 2,599,817
---------- ----------
Other Noncurrent Liabilities:
Obligations under capital leases 94,534 94,861
Other 68,235 66,575
---------- ----------
Total 162,769 161,436
---------- ----------
Current Liabilities:
Currently maturing long-term debt 28,175 3,020
Notes payable:
Associated companies - 21,395
Other 34,667 667
Accounts payable:
Associated companies 17,345 45,177
Other 89,329 93,611
Customer deposits 17,113 15,241
Taxes accrued 45,239 43,013
Accumulated deferred income taxes 25,043 32,367
Interest accrued 31,064 31,410
Dividends declared 4,727 5,049
Co-owner advances 20,639 39,435
Deferred fuel cost 20,254 16,130
Nuclear refueling reserve 37,954 30,677
Obligations under capital leases 56,154 60,883
Other 45,632 26,034
---------- ----------
Total 473,335 464,109
---------- ----------
Deferred Credits:
Accumulated deferred income taxes 859,558 876,618
Accumulated deferred investment tax credits 118,548 154,723
Other 66,136 77,402
---------- ----------
Total 1,044,242 1,108,743
---------- ----------
Commitments and Contingencies (Notes 2, 8, and 9)
TOTAL $4,292,215 $4,334,105
========== ==========
See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Activities:
Net income $142,263 $205,297 $130,529
Noncash items included in net income:
Cumulative effect of a change in accounting principle - (50,187) -
Change in rate deferrals/excess capacity-net 102,959 84,712 60,344
Depreciation and decommissioning 149,878 135,530 132,459
Deferred income taxes and investment tax credits (54,080) (6,965) (820)
Allowance for equity funds used during construction (4,001) (3,627) (4,173)
Gain on sale of property - net - - (19,612)
Changes in working capital:
Receivables 10,817 7,385 (22,281)
Fuel inventory 17,359 173 17,039
Accounts payable (32,114) 20,608 (5,393)
Taxes accrued 2,226 (21,983) (23,492)
Interest accrued (346) 201 (8,041)
Other working capital accounts 20,324 26,486 5,249
Decommissioning trust contributions (11,581) (11,491) (13,255)
Provision for estimated losses and reserves 16,617 1,963 (21,670)
Other (4,744) (41,826) (2,736)
-------- -------- --------
Net cash flow provided by operating activities 355,577 346,276 224,147
-------- -------- --------
Investing Activities:
Construction expenditures (179,116) (176,540) (179,320)
Proceeds from sale of property - - 67,985
Allowance for equity funds used during construction 4,001 3,627 4,173
Nuclear fuel purchases (40,074) (29,156) (34,238)
Proceeds from sale/leaseback of nuclear fuel 40,074 29,156 34,238
-------- -------- --------
Net cash flow used in investing activities (175,115) (172,913) (107,162)
-------- -------- --------
Financing Activities:
Proceeds from issuance of:
First mortgage bonds - 445,000 148,114
Preferred Stock - - 14,222
Other long-term debt 27,992 48,070 3,973
Retirement of:
First mortgage bonds (800) (441,141) (329,019)
Other long-term debt (30,231) (47,700) (1,225)
Redemption of preferred stock (11,500) (15,500) (34,388)
Changes in short-term borrowings 12,605 17,395 4,000
Dividends paid:
Common stock (80,000) (156,300) (75,000)
Preferred stock (19,597) (21,362) (23,730)
-------- -------- --------
Net cash flow used in financing activities (101,531) (171,538) (293,053)
-------- -------- --------
Net increase (decrease) cash and cash equivalents 78,931 1,825 (176,068)
Cash and cash equivalents at beginning of period 1,825 - 176,068
-------- -------- --------
Cash and cash equivalents at end of period $80,756 $1,825 -
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $98,787 $103,826 $114,791
Income taxes $79,553 $66,366 $60,987
Noncash investing and financing activities:
Capital lease obligations incurred $47,719 $48,513 $37,351
Excess of fair value of decommissioning trust
assets over amount invested $1,361 - -
See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is important to AP&L due to the capital intensive
nature of its business, which requires large investments in long-lived
assets. While large capital expenditures for the construction of new
generating capacity are not currently planned, AP&L does require
significant capital resources for the periodic maturity of certain
series of debt and preferred stock and ongoing construction. Net cash
flow from operations totaled $356 million, $346 million, and $224
million in 1994, 1993, and 1992, respectively. Net cash flow from
operations increased in 1993 due primarily to increased electric sales
and increased collections under the phase-in plan, as discussed below.
In recent years, this cash flow, supplemented by issuances of debt,
has been sufficient to meet substantially all investing and financing
requirements, including capital expenditures, dividends, and
debt/preferred stock maturities. AP&L's ability to fund these capital
requirements results, in part, from its continued efforts to
streamline operations and reduce costs, as well as collections under
its Grand Gulf 1 rate phase-in plan which exceed the current cash
requirements for Grand Gulf 1-related costs. (In the income
statement, these revenue collections are offset by the amortization of
previously deferred costs; therefore, there is no effect on net
income.) AP&L's Grand Gulf 1 phase-in plan will continue to contribute
to AP&L's cash position through 1998. See Note 2 for additional
information on AP&L's rate phase-in plan. See Note 8 for additional
information on AP&L's capital and refinancing requirements in 1995 -
1997. Also, to the extent current market interest and dividend rates
allow, AP&L may continue to refinance high-cost debt and preferred
stock prior to maturity.
Earnings coverage tests and bondable property additions limit the
amount of first mortgage bonds and preferred stock that AP&L can
issue. Based on the most restrictive applicable tests as of
December 31, 1994, and an assumed annual interest or dividend rate of
9.25%, AP&L could have issued $253 million of additional first
mortgage bonds or $468 million of additional preferred stock. AP&L
has the conditional ability to issue first mortgage bonds and
preferred stock against the retirement of first mortgage bonds and
preferred stock, respectively, in some cases, without satisfying an
earnings coverage test.
See Notes 5 and 6 for information on AP&L's financing activities
and Note 4, for information on AP&L's short-term borrowings and lines
of credit.
ARKANSAS POWER & LIGHT COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Revenues $1,590,742 $1,591,568 $1,521,129
---------- ---------- ----------
Operating Expenses:
Operation and maintenance:
Fuel and fuel-related expenses 261,932 257,983 242,040
Purchased power 328,379 349,718 417,099
Nuclear refueling outage expenses 33,107 30,069 40,512
Other operation and maintenance 390,472 373,758 363,768
Depreciation and decommissioning 149,878 135,530 132,459
Taxes other than income taxes 33,610 28,626 26,709
Income taxes 9,938 18,746 4,058
Amortization of rate deferrals 166,793 160,916 114,711
---------- ---------- ----------
Total 1,374,109 1,355,346 1,341,356
---------- ---------- ----------
Operating Income 216,633 236,222 179,773
---------- ---------- ----------
Other Income (Deductions):
Allowance for equity funds used
during construction 4,001 3,627 4,173
Miscellaneous - net 48,049 64,884 113,842
Income taxes (19,282) (32,451) (46,531)
---------- ---------- ----------
Total 32,768 36,060 71,484
---------- ---------- ----------
Interest Charges:
Interest on long-term debt 106,001 110,472 121,676
Other interest - net 4,811 9,118 2,308
Allowance for borrowed funds used
during construction (3,674) (2,418) (3,256)
---------- ---------- ----------
Total 107,138 117,172 120,728
---------- ---------- ----------
Income before Cumulative Effect of a
Change in Accounting Principle 142,263 155,110 130,529
Cumulative Effect to January 1, 1993
of Accruing Unbilled Revenues (net
of income taxes of $31,140) - 50,187 -
---------- ---------- ----------
Net Income 142,263 205,297 130,529
Preferred Stock Dividend Requirements
and Other 19,275 20,877 23,202
---------- ---------- ----------
Earnings Applicable to Common Stock $122,988 $184,420 $107,327
========== ========== ==========
See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Retained Earnings, January 1 $448,811 $420,691 $388,364
Add:
Net income 142,263 205,297 130,529
-------- -------- --------
Total 591,074 625,988 518,893
-------- -------- --------
Deduct:
Dividends declared:
Preferred stock 19,275 20,877 23,202
Common stock 80,000 156,300 75,000
-------- -------- --------
Total 99,275 177,177 98,202
-------- -------- --------
Retained Earnings, December 31 (Note 7) $491,799 $448,811 $420,691
======== ======== ========
See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income decreased in 1994 due primarily to the one-time
recording in the first quarter of 1993 of the cumulative effect of the
change in accounting principle for unbilled revenues and its ongoing
effects, and to increased operation and maintenance expenses as a
result of restructuring costs and storm damage activity during 1994.
Net income increased in 1993 due primarily to the one-time
recording of the cumulative effect of the change in accounting
principle for unbilled revenues (see Note 1), and its ongoing effects,
partially offset by the effect of the implementation of SFAS 109 (see
Note 3) and by the impact in March 1992 of an after-tax gain from the
sale of AP&L's retail properties in Missouri. Effective January 1,
1993, AP&L began accruing as revenues the charges for energy delivered
to customers but not yet billed. Electric revenues were previously
recorded on a cycle-billing basis. Excluding the above mentioned
items, net income for 1993 would have been $157.7 million and net
income for 1992 would have been $110.9 million. This increase of
$46.8 million is due primarily to increased retail energy sales.
Significant factors affecting the results of operations and
causing variances between the years 1994 and 1993, and 1993 and 1992,
are discussed under "Revenues and Sales," "Expenses," and "Other"
below.
Revenues and Sales
See "Selected Financial Data - Five-Year Comparison," following
the notes, for information on operating revenues by source and KWH
sales.
Total revenues remained relatively unchanged in 1994. Retail
revenue decreased primarily due to lower fuel recovery revenue during
the year offset by increased sales for resale to associated companies
in 1994, caused by changes in generation availability and requirements
among the System operating companies.
Electric operating revenues were higher in 1993 due to an
increase in residential and commercial energy sales resulting from a
return to more normal weather as compared to milder weather in 1992.
Industrial sales increased primarily in the lumber/plywood and
petroleum/natural gas pipeline industries. Additionally, electric
revenues increased as a result of increased collections of previously
deferred Grand Gulf 1-related costs, which do not impact net income.
Expenses
Operating expenses increased in 1994 due primarily to increased
other operation and maintenance expenses and increased amortization of
rate deferrals partially offset by lower purchased power expenses.
Operating expenses increased in 1993 due primarily to higher fuel
expense, income tax expense and increased amortization of rate
deferrals.
Other operation and maintenance expenses increased in 1994
primarily due to the storm damage costs and restructuring costs as
discussed in Note 12. The decrease in 1994 purchased power expenses
is primarily due to the decrease in the price of purchased power.
Fuel for electric generation and fuel-related expenses increased
in 1993 due primarily to an increase in generation requirements
resulting primarily from increased retail energy sales and increased
fuel costs as discussed in "Revenues and Sales" above. Purchased
power decreased in 1993 due primarily to energy demands being met by
increased nuclear generation.
Total income taxes decreased during 1994 primarily due to the
write-off of unamortized deferred investment tax credit of $27.3
million due to a FERC settlement and due to lower pretax income in
1994. This decrease was partially offset by an increase in tax
expense due to the true-up of actual income tax expense for 1993
determined during 1994.
Total income taxes increased in 1993 due primarily to higher
pretax income, an increase in the federal income tax rate as a result
of OBRA, and the effect of implementing SFAS 109.
The amortization of rate deferrals increased in 1993 due to
increased amortization of previously deferred Grand Gulf 1-related
costs pursuant to the step-up provisions of AP&L's phase-in plan.
Other
Miscellaneous other income - net decreased in 1994 due primarily
to reduced Grand Gulf 1 carrying charges. Miscellaneous other income -
net decreased in 1993 due primarily to the impact of the pretax gain
on the 1992 sale of AP&L's retail properties in Missouri.
Other income taxes decreased in 1994 primarily due to a lower
pretax income as discussed above.
Interest on long-term debt decreased in 1994 and 1993 due
primarily to the continued refinancing of high-cost debt.
ARKANSAS POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Competition
The electric utility industry is becoming increasingly
competitive and AP&L is seeking to become a leading competitor in the
changing electric energy business. Competition presents AP&L with
many challenges. The following have been identified by AP&L as its
major competitive challenges.
Retail and Wholesale Rate Issues
Increasing competition in the utility industry brings an
increased need to stabilize or reduce retail rates. In connection
with the Merger, AP&L agreed with its retail regulator not to request
any general retail rate increases that would take effect before
November 1998, with certain exceptions. See Note 2 for further
information. Recognizing that many industrial customers have energy
alternatives, AP&L continues to work with these customers to address
their needs. In certain cases, competitive prices are negotiated,
using variable rate designs.
Retail wheeling, the transmission by an electric utility of
energy produced by another entity over the utility's transmission and
distribution system to a retail customer in the electric utility's
service territory, is evolving. Over a dozen states have been
studying the concept of retail competition. In April 1994, the state
of Michigan agreed to a five-year experiment that allows limited
competition among public utilities. During the same month, the
California Public Utilities Commission proposed to deregulate that
state's electric power industry, starting on January 1, 1996, to allow
the largest industrial customers to select the lowest cost supplier
for electricity service. Under the proposal, by the year 2002,
smaller companies and residential customers in California would also
be able to buy power from any suppliers. The California Public
Utilities Commission is currently reviewing its decision and is
expected to make a ruling in the first half of 1995. The retail market
for electricity is expected to become more competitive with such moves
toward deregulation.
In some areas of the country, municipalities (or comparable
entities) whose residents are served at retail by an investor-owned
utility pursuant to a franchise are exploring the possibility of
establishing new or extending existing distribution systems or seeking
new delivery points in order to serve retail customers, especially
large industrial customers, that currently receive service from an
investor-owned utility. These options depend on the terms of a
utility's franchise as well as on state law and regulation. In
addition, FERC's authority to order utilities to transmit for a new or
expanding municipal system is limited in certain respects. Where
successful, however, the establishment of a municipal system or the
acquisition by a municipal system of a utility's customers could
result in the inability to recover costs that the utility has incurred
in serving those customers.
In mid-1994, the FERC issued a notice of proposed rulemaking
concerning a regulatory framework for dealing with recovery of
stranded costs, such as high cost nuclear generating units, which may
be incurred by electric utilities as a result of increased
competition. In addition to addressing recovery of stranded costs
related to wholesale service, the proposal requested comment as to
recovery of retail stranded costs in transmission rates where state
regulatory authorities failed to address the issue or were in
conflict. Comments and reply comments have been filed, and the matter
is pending. The risk of exposure to stranded costs which may result
from competition in the industry will depend on the extent and timing
of retail competition, the resolution of jurisdictional issues
concerning stranded cost recovery, and the extent to which such costs
are recovered from departing or remaining customers, among other
matters.
In the wholesale rate area, FERC approved in 1992, with certain
modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy
Power to sell wholesale power at market-based rates and to provide to
electric utilities "open access" to the System's transmission system
(subject to certain requirements). GSU was later added to this
filing. On October 31, 1994, as amended on January 25, 1995, Entergy
Services filed with FERC revised transmission tariffs intended to
provide access to transmission service on the same or comparable
basis, terms, and conditions as the System operating companies, and
the matter is pending. Open access and market pricing, once in effect,
will increase marketing opportunities for AP&L, but will also expose
AP&L to the risk of loss of load or reduced revenues due to
competition with alternative suppliers.
In March 1994, North Little Rock, Arkansas, awarded AP&L a
wholesale power contract that will provide estimated revenues of $347
million over 11 years. Under the contract, the price per KWH was
reduced 18%, with increases in price through the year 2004. AP&L,
which has been serving North Little Rock for over 40 years, was
awarded the contract after intense bidding with several competitors.
On May 22, 1994, FERC accepted the contract. Rehearings were
requested by one of AP&L's competitors and were held in February 1995.
The matter is pending.
In light of the rate issues discussed above, AP&L is aggressively
reducing costs to avoid potential earnings erosions that might result
as well as to become more competitive. In 1994, AP&L announced a
restructuring program related to certain of its operating units. This
program is designed to reduce costs and improve operating
efficiencies. See Note 12 for further information. Also, in response
to an increasingly competitive environment, AP&L announced intentions
to revise its initial least cost planning activities.
The Energy Policy Act of 1992
The EPAct addresses a wide range of energy issues and is altering
the way Entergy and the rest of the electric utility industry
operate. The EPAct encourages competition and affords utilities the
opportunities, and the risks, associated with an open and more
competitive market environment. The EPAct creates exemptions from
regulation under the Holding Company Act and creates a class of exempt
wholesale generators consisting of utility affiliates and nonutilities
that are owners and operators of facilities for the generation and
transmission of power for sales at wholesale. The EPAct also gives
FERC the authority to order investor-owned utilities, including AP&L,
to transmit power and energy to or for wholesale purchasers and
sellers. The law creates the potential for electric utilities and
other power producers to gain increased access to the transmission
systems of other entities to facilitate wholesale sales. Both AP&L
and Entergy Power expect to compete in this market.
Litigation and Regulatory Proceedings
In November 1994, FERC approved an agreement settling a long-
standing dispute involving income tax allocation procedures of System
Energy. In accordance with the agreement, System Energy refunded
approximately $22.2 million to AP&L, which will in turn make refunds
or credits to its customers (except for those portions attributable to
its retained share of Grand Gulf 1 costs). Additionally, System
Energy will refund a total of approximately $22.3 million, plus
interest, to AP&L over the period through June 2004. The settlement
also required the write-off of approximately $27.3 million of certain
related unamortized balances of deferred investment tax credits by
AP&L.
ANO Matters
ANO 2 experienced a forced outage for repair of certain steam
generator tubes in March 1992. Further inspections and repairs were
conducted at subsequent refueling and mid-cycle outages in September
1992, May 1993, April 1994, and January 1995. AP&L's budgeted
maintenance expenditures were adequate to cover the cost of such
repairs. ANO 2's output has been reduced 15 megawatts or 1.6% due to
secondary side fouling, tube plugging, and reduction of primary
temperature. Entergy Operations continues to take steps at ANO 2 to
reduce the number and severity of future tube cracks. In addition,
Entergy Operations continues to meet with the NRC to discuss such
steps and results of inspections of the generator tubes, as well as
the timing of future inspections. Additional inspections are planned
for the normal refueling outage scheduled for October 1995.
Accounting Issues
Proposed Accounting Standards - The FASB has proposed a SFAS on
"Accounting for the Impairment of Long-Lived Assets," effective
January 1, 1996. The proposed standard describes circumstances which
may result in assets being impaired and provides criteria for
recognition and measurement of asset impairment. Certain operations of
AP&L are potentially affected by this standard, and any resulting
write-offs will depend on future operating costs, generating units'
efficiency and availability, and the future market for energy over the
remaining life of the units. Based on current estimates, AP&L
anticipates that future revenues will fully recover the costs of such
operations.
Continued Application of SFAS 71 - AP&L's financial statements
currently reflect assets and costs based on current cost-based
ratemaking regulations, in accordance with SFAS 71, "Accounting for
the Effects of Certain Types of Regulation." As discussed above, the
electric utility industry is changing and these changes could possibly
result in the discontinuance of the application of SFAS 71, which
would result in the elimination of regulatory assets and liabilities.
See Note 1 for further information.
Accounting for Decommissioning Costs - The FASB is currently
reviewing the accounting for decommissioning of nuclear plants. This
project could possibly change AP&L's, as well as the entire utility
industry's, accounting for such costs. For further information, see
Note 8.
ARKANSAS POWER & LIGHT COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
AP&L maintains accounts in accordance with FERC and other
regulatory guidelines. Certain previously reported amounts have been
reclassified to conform to current classifications.
Revenues and Fuel Costs
Prior to January 1, 1993, AP&L recorded revenues when billed to
its customers with no accrual for energy delivered but not yet billed.
To provide a better matching of revenues and expenses, effective
January 1, 1993, AP&L adopted a change in accounting principle to
provide for accrual of estimated unbilled revenues. The cumulative
effect of this accounting change as of January 1, 1993 increased net
income by $50.2 million. Had this new accounting method been in
effect during prior years, net income before the cumulative effect
would not have been materially different from that shown in the
accompanying financial statements.
Substantially all of AP&L's rate schedules include fuel
adjustment clauses that allow either current recovery or deferrals of
fuel costs until such costs are reflected in the related revenues. The
fuel adjustment clause provides, as an incentive with respect to ANO,
for over- or under-recovery of the cost of replacement energy in
excess of the cost of equal amounts of nuclear energy when the units
are not down for refueling.
Utility Plant
Utility plant is stated at original cost. The original cost of
utility plant retired or removed, plus the applicable removal costs,
less salvage, is charged to accumulated depreciation. Maintenance,
repairs, and minor replacement costs are charged to operating
expenses. Substantially all of AP&L's utility plant is subject to the
lien of its mortgage and deed of trust.
Total AP&L net utility plant in service of $2.64 billion as of
December 31, 1994 includes $1.23 billion of production plant, $.43
billion of transmission plant, $.82 billion of distribution plant, and
$.16 billion of other plant.
Depreciation is computed on the straight-line basis at rates
based on the estimated service lives and costs of removal of the
various classes of property. Depreciation provisions on average
depreciable property approximated 3.4% in 1994, 1993 and 1992.
AFUDC represents the approximate net composite interest cost of
borrowed funds and a reasonable return on the equity funds used for
construction. Although AFUDC increases utility plant and increases
earnings, it is only realized in cash through depreciation provisions
included in rates. AP&L's effective composite rates for AFUDC were
9.2%, 10.3%, and 10.5% for 1994, 1993, and 1992, respectively.
Jointly-Owned Generating Stations
AP&L is a co-owner of two coal-fueled, two-unit generating
stations, the White Bluff Station and the Independence Station. AP&L
is the agent for the respective co-owners and operates the stations.
AP&L records the investment and expenses associated with these
generating stations to the extent of its ownership interests. As of
December 31, 1994, AP&L's investment and accumulated depreciation in
these generating stations were as follows:
Total
Megawatt Accumulated
Generating Stations Capability Ownership Investment Depreciation
(In Thousands)
White Bluff: Units 1 and 2 1,660 57.00% $400,918 $151,830
Independence: Unit 1 836 31.50% $116,555 $ 38,594
Common Facilities 15.75% $ 29,331 $ 8,758
Income Taxes
AP&L, its parent, and affiliates file a consolidated federal
income tax return. Income taxes are allocated to AP&L in proportion
to its contribution to consolidated taxable income. SEC regulations
require that no Entergy Corporation subsidiary pay more taxes than it
would have had a separate income tax return been filed. Deferred
taxes are recorded for all temporary differences between book and
taxable income. Investment tax credits are deferred and amortized
based upon the average useful life of the related property in
accordance with rate treatment. As discussed in Note 3, in 1993 AP&L
changed its accounting for income taxes to conform with SFAS 109.
Reacquired Debt
The premiums and costs associated with reacquired debt are being
amortized over the life of the related new issuances, in accordance
with ratemaking treatment.
Cash and Cash Equivalents
AP&L considers all unrestricted highly liquid debt instruments
purchased with an original maturity of three months or less to be cash
equivalents.
Continued Application of SFAS 71
As a result of the EPAct and actions of regulatory commissions,
the electric utility industry is moving toward a combination of
competition and a modified regulatory environment. AP&L's financial
statements currently reflect assets and costs based on current cost-
based ratemaking regulations, in accordance with SFAS 71, "Accounting
for the Effects of Certain Types of Regulation." Continued
applicability of SFAS 71 to AP&L's financial statements requires that
rates set by an independent regulator on a cost of service basis
(including a reasonable rate of return on invested capital) can
actually be charged to and collected from customers.
In the event that either all or a portion of a utility's
operations cease to meet those criteria for various reasons, including
deregulation, a change in the method of regulation or a change in the
competitive environment for the utility's regulated services, the
utility should discontinue application of SFAS 71 for the relevant
portion. That discontinuation should be reported by elimination from
the balance sheet of the effects of any actions of regulators
recorded as regulatory assets and liabilities.
As of December 31, 1994, and for the foreseeable future, AP&L's
financial statements continue to follow SFAS 71.
Fair Value Disclosure
The estimated fair value of financial instruments has been
determined by AP&L, using available market information and appropriate
valuation methodologies. However, considerable judgment is required
in developing the estimates of fair value. Therefore, estimates are
not necessarily indicative of the amounts that AP&L could realize in a
current market exchange. In addition, gains or losses realized on
financial instruments may be reflected in future rates and not accrue
to the benefit of stockholders.
AP&L considers the carrying amounts of financial instruments
classified as current assets and liabilities to be a reasonable
estimate of their fair value because of the short maturity of these
instruments. In addition, AP&L does not presently expect that
performance of its obligations will be required in connection with
certain off-balance sheet commitments and guarantees considered
financial instruments. Due to this factor, and because of the related
party nature of these commitments and guarantees, determination of
fair value is not considered practicable. See Notes 5, 6, and 8 for
additional fair value disclosure.
AP&L adopted the provisions of SFAS 115, "Accounting for Certain
Investments in Debt and Equity Securities," effective January 1, 1994.
As a result, at December 31, 1994, AP&L recorded on the balance sheet
an additional $1.4 million in decommissioning trust funds,
representing the amount by which the fair value of the securities held
in such funds exceeds the amounts for decommissioning recovered in
rates and deposited in the funds and the related earnings on the
amounts deposited. Due to the regulatory treatment for
decommissioning trust funds, AP&L recorded an offsetting amount in
unrealized gains on investment securities as a regulatory liability.
NOTE 2. RATE AND REGULATORY MATTERS
Merger - Related Rate Agreement
In November 1993, AP&L and the APSC entered into a settlement
agreement whereby the APSC agreed to withdraw its request for hearing
and its objections in the SEC proceeding related to the Merger. In
return AP&L agreed, among other things, (a) that it will not request
any general retail rate increase that would take effect before
November 3, 1998, except for, among other things, increases associated
with the recovery of certain Grand Gulf 1-related costs, excess
capacity costs, and costs related to the adoption of SFAS 106 that
were previously deferred, recovery of certain taxes, and force majeure
(defined to include, among other things, war, natural catastrophes,
and high inflation); and (b) that its retail ratepayers would be
protected from (1) increases in its cost of capital resulting from
risks associated with the Merger, (2) recovery of any portion of the
acquisition premium or transactional costs associated with the Merger,
(3) certain direct allocations of costs associated with GSU's River
Bend nuclear unit, and (4) any losses of GSU resulting from resolution
of litigation in connection with its ownership of River Bend.
Arkansas - Revised Settlement Agreement
Pursuant to the terms of the Revised Settlement Agreement, AP&L
(1) permanently retains 7.92% (stated as a percentage of System
Energy's share of Grand Gulf 1) of its Grand Gulf 1-related costs
(Retained Share) for 1994 and all succeeding years of commercial
operation of the unit; (2) recovers currently 28.08% of such costs in
1994 and thereafter; and (3) deferred a portion of such costs for
future recovery (Deferred Balance). AP&L is permitted to currently
recover carrying charges on the unrecovered portion of the Deferred
Balance. For the year ended December 31, 1994, $170 million was
billed to AP&L by System Energy.
AP&L has the right under the Revised Settlement Agreement to sell
capacity and energy available from its Retained Share to third
parties, which shall not include AP&L's wholesale customers. In the
event AP&L is not able to sell such capacity and energy to such third
parties, it has the right to sell the energy available from such
capacity, and to date a significant portion has been sold, to its
retail customers at a price equal to AP&L's avoided energy cost, which
is currently less than AP&L's cost of such energy. The Revised
Settlement Agreement requires that a portion of the proceeds from
sales of Retained Share capacity and energy to third parties prior to
January 1, 1996 be applied to reduce the Deferred Balance.
Arkansas - Rate Riders
In conjunction with the Revised Settlement Agreement, AP&L was
permitted to implement annual updates to the Grand Gulf 1 rate rider,
increasing Arkansas retail rates by approximately 3.1% and 2.6% for
the years 1992 and 1991, respectively. These increases reflect
scheduled phase-in plan increases adjusted for any prior year over-or
under-collection. Beginning in 1993 and continuing for a five-year
period, rates will remain at the 1992 level, unless adjustments are
made for an over-or under-collection of Grand Gulf 1-related costs in
excess of $10 million. Although it was not required under the terms
of the Grand Gulf 1 rate rider, in 1993 AP&L opted to implement a 0.7%
rate refund in 1994 for a cumulative over-recovery amount of $7.3
million.
Various other rate riders, which modify non-Grand Gulf 1 rates
under the Revised Settlement Agreement, have been implemented with
respect to tax adjustments, depreciation, decommissioning costs, and
deferred return on excess capacity (which is being recovered over a
10-year period ending in 1998).
Missouri Retail Operations
In March 1992, AP&L sold its retail properties in Missouri to
Union Electric for approximately $68 million. The gain on the sale,
classified as "Other Income-Miscellaneous" in the 1992 Statement of
Income, was approximately $33.7 million, which resulted in a $19.6
million increase in net income after taxes. In addition, AP&L agreed
to sell to Union Electric 120 megawatts of capacity and associated
energy for an initial period of 10 years, and beginning on January 1,
1995, Union Electric shall also purchase 40 megawatts of peaking
capacity from AP&L.
February 1994 Ice Storm
In early February 1994, an ice storm left more than 97,000 AP&L
customers without electric power across the service area. The storm
was the most severe natural disaster ever to affect the System,
causing damage to transmission and distribution lines, equipment,
poles, and facilities in certain areas. Repair costs totaled
approximately $30.8 million with $18.7 million of these amounts
capitalized as plant-related costs. The remaining balance has been
charged against regulatory storm damage reserves.
NOTE 3. INCOME TAXES
Income tax expense consisted of the following:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Current:
Federal $64,238 $47,326 $45,932
State 19,062 10,836 11,156
------- ------- -------
Total 83,300 58,162 57,088
------- ------- -------
Deferred - net:
Liberalized depreciation 9,314 7,074 4,929
Alternative minimum tax 30,601 (2,227) 6,577
Nuclear refueling and maintenance (2,855) (2,161) 7,751
Deferred purchased power costs (42,529) (35,896) (14,375)
Deferred excess capacity costs (3,487) (4,044) (3,190)
Unbilled revenue 1,330 26,847 (2,474)
Bond reacquisition costs (1,108) 14,706 5,184
TCBY Tower (CADC) 44 8,743 -
Decontamination and decommissioning fund 676 16,429 -
Nuclear reserve (1,537) (37) 1,747
Other (8,388) 5,314 (2,659)
------- ------- -------
Total (17,939) 34,748 3,490
------- ------- -------
Investment tax credit adjustments - net (8,814) (10,573) (9,989)
Investment tax credit amortization - FERC settlement (27,327) - -
------- ------- -------
Recorded income tax expense $29,220 $82,337 $50,589
======= ======= =======
Charged to operations $9,938 $18,746 $4,058
Charged to other income 19,282 32,451 46,531
Charged to cumulative effect - 31,140 -
------- ------- -------
Recorded income tax expense 29,220 82,337 50,589
Income taxes applied against the debt component of AFUDC - - 1
------- ------- -------
Total income taxes $29,220 $82,337 $50,590
======= ======= =======
Total income taxes differ from the amounts computed by applying
the statutory federal income tax rate to income before taxes. The
reasons for the differences were:
For the Years Ended December 31,
1994 1993 1992
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
(Dollars in Thousands)
Computed at statutory rate $60,017 35.0 $100,673 35.0 $61,580 34.0
Increases (reductions) in tax resulting from:
State income taxes net of federal income
tax effect 7,821 4.6 12,119 4.2 7,963 4.4
Amortization of investment tax credits (10,220) (6.0) (11,702) (4.1) (13,285) (7.4)
Investment tax credit amortization -
FERC settlement (27,327) (15.9) - - - -
Depreciation (921) (0.5) (3,156) (1.1) (6,755) (3.7)
Reversal of tax contingency - - (3,771) (1.3) - -
Flow-through/permanent differences (208) (0.1) (7,669) (2.7) (1,407) (0.8)
Other - net 58 - (4,157) (1.4) 2,493 1.4
------- ---- ------- ---- ------- ----
Recorded income tax expense 29,220 17.1 82,337 28.6 50,589 27.9
Income taxes applied against debt component
of AFUDC - - - - 1 -
------- ---- ------- ---- ------- ----
Total income taxes $29,220 17.1 $82,337 28.6 $50,590 27.9
======= ==== ======= ==== ======= ====
Significant components of AP&L's net deferred tax liabilities as
of December 31, 1994 and 1993, were (in thousands):
1994 1993
Deferred tax liabilities:
Net regulatory assets $(273,574) $ (294,713)
Plant related basis differences (465,787) (458,023)
Rate deferrals (183,700) (229,714)
Bond reacquisition (22,496) (23,604)
Decontamination and decommissioning fund (17,104) (16,429)
Other (20,317) (21,414)
--------- -----------
Total $(982,978) $(1,043,897)
========= ===========
Deferred tax assets:
Accumulated deferred investment tax credit $ 46,506 $ 60,698
Nuclear refueling and maintenance 14,889 12,035
Alternative minimum tax credit 3,536 34,137
Standard coal plant 9,214 9,552
Other 24,232 18,490
--------- -----------
Total $ 98,377 $ 134,912
========= ===========
Net deferred tax liabilities $(884,601) $ (908,985)
========= ===========
The alternative minimum tax (AMT) credit as of December 31, 1994,
was $3.5 million. This AMT credit can be carried forward indefinitely
and will reduce AP&L's federal income tax liability in future years.
In accordance with a System Energy FERC settlement, AP&L wrote
off $27.3 million of unamortized deferred investment tax credits in
1994.
In 1993, AP&L adopted SFAS 109. SFAS 109 required that deferred
income taxes be recorded for all temporary differences and
carryforwards, and that deferred tax balances be based on enacted tax
laws at tax rates that are expected to be in effect when the temporary
differences reverse. SFAS 109 required that regulated enterprises
recognize adjustments resulting from implementation as regulatory
assets or liabilities if it is probable that such amounts will be
recovered from or returned to customers in future rates. A
substantial majority of the adjustments required by SFAS 109 was
recorded to deferred tax balance sheet accounts with offsetting
adjustments to regulatory assets and liabilities. As a result of the
adoption of SFAS 109, 1993 net income was reduced by $2.6 million,
assets were increased by $168.2 million, and liabilities were
increased by $170.8 million. The cumulative effect of the adoption of
SFAS 109 is included in income tax expense charged to operations.
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized AP&L to effect short-term borrowings up to
$125 million, which may be increased to as much as $243 million after
further SEC approval. This authorization is effective through
November 30, 1996. As of December 31, 1994, AP&L had outstanding
short-term lines of credit of $34 million from banks within its
service territory. Interest rates associated with these lines of
credit generally are based on the prime rate, the London interbank
offered rate, or a bid rate. Commitment fees on these lines of credit
are .125% of the amount of available credit. In addition, AP&L can
borrow from the Money Pool, subject to its maximum authorized level of
short-term borrowings and the availability of funds. AP&L had no
outstanding borrowings under the Money Pool arrangement as of December
31, 1994.
NOTE 5. PREFERRED STOCK
The number of shares and dollar value of AP&L's preferred stock
were:
As of December 31,
Shares Call Price Per
Authorized and Total Share as of
Outstanding Dollar Value December 31,
1994 1993 1994 1993 1994
(Dollars in Thousands)
Without sinking fund:
Cumulative, $100 par value:
4.32% Series 70,000 70,000 $7,000 $ 7,000 $103.647
4.72% Series 93,500 93,500 9,350 9,350 $107.000
4.56% Series 75,000 75,000 7,500 7,500 $102.830
4.56% 1965 Series 75,000 75,000 7,500 7,500 $102.500
6.08% Series 100,000 100,000 10,000 10,000 $102.830
7.32% Series 100,000 100,000 10,000 10,000 $103.170
7.80% Series 150,000 150,000 15,000 15,000 $103.250
7.40% Series 200,000 200,000 20,000 20,000 $102.800
7.88% Series 150,000 150,000 15,000 15,000 $103.000
Cumulative, $25 par value:
8.84% Series 400,000 400,000 10,000 10,000 $26.560
Cumulative, $0.01 par value:
$2.40 Series(1)(2) 2,000,000 2,000,000 50,000 50,000 -
$1.96 Series(1)(2) 600,000 600,000 15,000 15,000 -
--------- --------- -------- --------
Total without sinking fund 4,013,500 4,013,500 $176,350 $176,350
========= ========= ======== ========
With sinking fund:
Cumulative, $100 par value:
10.60% Series - 20,000 - $ 2,000 -
8.52% Series 375,000 40,000 $37,500 40,000 $106.390
Cumulative, $25 par value:
9.92% Series 641,085 721,085 16,027 18,027 $26.320
13.28% Series 200,000 400,000 5,000 10,000 $28.220
--------- --------- ------- -------
Total with sinking fund 1,216,085 1,541,085 $58,527 $70,027
========= ========= ======= =======
(1) The total dollar value represents the involuntary liquidation
value of $25 per share.
(2) These series are not redeemable as of December 31, 1994.
The fair value of AP&L's preferred stock with sinking fund was
estimated to be approximately $60.6 million and $74.7 million as of
December 31, 1994 and 1993, respectively. The fair values were
determined using quoted market prices or estimates from nationally
recognized investment banking firms. See Note 1 for additional
information on disclosure of fair value of financial instruments.
Changes in the preferred stock, with and without sinking fund,
during the last three years were:
Number of Shares
1994 1993 1992
Preferred stock issuances:
$0.01 par value - - 600,000
Preferred stock retirements:
$100 par value (45,000) (85,000) (109,940)
$25 par value (280,000) (280,000) (880,000)
Cash sinking fund requirements for the next five years for
preferred stock outstanding as of December 31, 1994 are (in millions):
1995 - $9.5; 1996 - $4.5; 1997 - $4.5; 1998 - $4.5; and 1999 - $4.5.
AP&L has the annual non-cumulative option to redeem, at par,
additional amounts of certain series of its outstanding preferred
stock.
NOTE 6. LONG-TERM DEBT
The long-term debt of AP&L as of December 31, 1994 and 1993, was:
Maturities Interest Rates
From To From To 1994 1993
(In Thousands)
First Mortgage Bonds
1995 1999 4-5/8% 9-3/4% $100,960 $100,560
2000 2004 6% 9-3/4% 180,800 182,000
2005 2009 6.25% 7-1/2% 215,000 215,000
2019 2023 7% 10-3/8% 448,818 448,818
Governmental Obligations*
1995 2008 6.125% 10% 53,120 83,290
2009 2021 6.25% 11% 234,004 202,193
Long-Term DOE Obligation (Note 8) 105,163 101,029
Unamortized Premium and Discount - Net (15,811) (16,555)
---------- ----------
Total Long-Term Debt 1,322,054 1,316,335
Less Amount Due Within One Year 28,175 3,020
---------- ----------
Long-Term Debt Excluding Amount Due $1,293,879 $1,313,315
Within One Year ========== ==========
* Consists of pollution control bonds, certain series of which are
secured by non-interest bearing first mortgage bonds.
The fair value of AP&L's long-term debt, excluding long-term DOE
obligation, as of December 31, 1994 and 1993 was estimated to be
$1,133.6 million and $1,250.8 million, respectively. The fair values
were determined using quoted market prices or estimates from
nationally recognized investment banking firms. See Note 1 for
additional information on disclosure of fair value of financial
instruments.
For the years 1995, 1996, 1997, 1998 and 1999, AP&L has long-term
debt maturities and cash sinking fund requirements (in millions) of
$28.2, $28.0, $33.1, $18.7, and $1.2, respectively. In addition,
other sinking fund requirements of approximately $.9 million annually
may be satisfied by cash or by certification of property additions at
the rate of 167% of such requirements.
NOTE 7. DIVIDEND RESTRICTIONS
The indenture relating to AP&L's long-term debt and provisions of
its Amended and Restated Articles of Incorporation, as amended,
relating to AP&L's preferred stock provide for restrictions on the
payment of cash dividends or other distributions on common stock. As
of December 31, 1994, $291.3 million of AP&L's retained earnings were
restricted against the payment of cash dividends or other
distributions on common stock. On February 1, 1995, AP&L paid Entergy
Corporation a $32.8 million cash dividend on common stock.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Capital Requirements and Financing
Construction expenditures (excluding nuclear fuel) for the years
1995, 1996, and 1997 are estimated to total $154.9 million each year.
AP&L will also require $107 million during the period 1995-1997 to
meet long-term debt and preferred stock maturities and sinking fund
requirements. AP&L plans to meet the above requirements with
internally generated funds and cash on hand. See Notes 5 and 6
regarding the possible refunding, redemption, purchase or other
acquisition of certain outstanding series of preferred stock and long-
term debt.
Unit Power Sales Agreement
System Energy has agreed to sell all of its 90% owned and leased
share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L,
and NOPSI in accordance with specified percentages (AP&L 36%, LP&L
14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this
agreement are paid in consideration for AP&L's respective entitlement
to receive capacity and energy, and are payable irrespective of the
quantity of energy delivered so long as the unit remains in commercial
operation. The agreement will remain in effect until terminated by
the parties and approved by FERC, most likely upon Grand Gulf 1's
retirement from service. AP&L's monthly obligation for payments under
the agreement is approximately $18 million.
Availability Agreement
AP&L, LP&L, MP&L, and NOPSI are individually obligated to make
payments or subordinated advances to System Energy in accordance with
stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI
24.7%) in amounts that when added to amounts received under the Unit
Power Sales Agreement or otherwise, are adequate to cover all of
System Energy's operating expenses. System Energy has assigned its
rights to payments and advances to certain creditors as security for
certain obligations. Since commercial operation of Grand Gulf 1,
payments under the Unit Power Sales Agreement have exceeded the
amounts payable under the Availability Agreement. Accordingly, no
payments have ever been required.
Reallocation Agreement
System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the
Reallocation Agreement relating to the sale of capacity and energy
from the Grand Gulf Station and the related costs, in which LP&L,
MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and
obligations with respect to the Grand Gulf Station under the
Availability Agreement. FERC's decision allocating a portion of Grand
Gulf 1 capacity and energy to AP&L supersedes the Reallocation
Agreement as it relates to Grand Gulf 1. Responsibility for any Grand
Gulf 2 amortization amounts has been individually allocated (LP&L
26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the
Reallocation Agreement. However, the Reallocation Agreement does not
affect AP&L's obligation to System Energy's lenders under the
assignments referred to in the preceding paragraph. AP&L would be
liable for its share of such amounts if LP&L, MP&L, and NOPSI were
unable to meet their contractual obligations. No payments of any
amortization amounts will be required as long as amounts paid to
System Energy under the Unit Power Sales Agreement, including other
funds available to System Energy, exceed amounts required under the
Availability Agreement, which is expected to be the case for the
foreseeable future.
System Fuels
AP&L has a 35% interest in System Fuels, a jointly owned
subsidiary of AP&L, LP&L, MP&L, and NOPSI. The parent companies of
System Fuels, including AP&L, agreed to make loans to System Fuels to
finance its fuel procurement, delivery, and storage activities. As of
December 31, 1994, AP&L had approximately $11 million of loans
outstanding to System Fuels which mature in 2008.
In addition, System Fuels entered into a revolving credit
agreement with a bank that provides $45 million in borrowings to
finance System Fuels' nuclear materials and services inventory.
Should System Fuels default on its obligations under its credit
agreement, AP&L, LP&L, and System Energy have agreed to purchase
nuclear materials and services financed under the agreement.
On April 30, 1993, AP&L assumed System Fuels' rights and
obligations in connection with System Fuels' coal car leases. The
other parent companies of System Fuels have been released from their
obligations with respect to the coal car leases.
Coal
AP&L is a party to a contract for supply of coal from a mine in
Wyoming and owns certain coal mining equipment and facilities at the
mine. Based on estimated reserves, the mine is expected to provide the
projected requirements of the Independence Station through at least
2011. AP&L has also agreed to purchase, over an approximate 20-year
period beginning in 1980, 100 million tons of coal for use at the
White Bluff Station, of which approximately 64 million have been
purchased as of December 31, 1994.
Nuclear Insurance
The Price-Anderson Act limits public liability for a single
nuclear incident to approximately $8.92 billion as of December 31,
1994. AP&L has protection for this liability through a combination of
private insurance (currently $200 million) and an industry assessment
program. Under the assessment program, the maximum amount that would
be required for each nuclear incident would be $79.3 million per
reactor, payable at a rate of $10 million per licensed reactor per
incident per year. AP&L has two licensed reactors. In addition, AP&L
participates in a private insurance program which provides coverage
for worker tort claims filed for bodily injury caused by radiation
exposure. AP&L's maximum assessment under the program is an aggregate
of approximately $6.4 million in the event losses exceed accumulated
reserve funds.
AP&L is a member of certain insurance programs that provide
coverage for property damage, including decontamination and premature
decommissioning expense, to members' nuclear generating plants. As of
December 31, 1994, AP&L was insured against such losses up to $2.75
billion, with $250 million of this amount designated to cover any
shortfall in the NRC required decommissioning trust funding. In
addition, AP&L is a member of an insurance program that covers certain
replacement power and business interruption costs incurred due to
prolonged nuclear unit outages. Under the property damage and
replacement power/business interruption insurance programs, AP&L could
be subject to assessments if losses exceed the accumulated funds
available to the insurers. As of December 31, 1994, the maximum
amount of such possible assessments to AP&L was $37.2 million.
The amount of property insurance presently carried by AP&L
exceeds the NRC's minimum requirement for nuclear power plant
licensees of $1.06 billion per site. NRC regulations provide that the
proceeds of this insurance must be used, first, to place and maintain
the reactor in a safe and stable condition and, second, to complete
decontamination operations. Only after proceeds are dedicated for
such use and regulatory approval is secured, would any remaining
proceeds be made available for the benefit of plant owners or their
creditors.
Spent Nuclear Fuel and Decommissioning Costs
AP&L provides for estimated future disposal costs for spent
nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982.
AP&L entered into a contract with the DOE, whereby the DOE will
furnish disposal service at a cost of one mill per net KWH generated
and sold after April 7, 1983, plus a one-time fee for generation prior
to that date. AP&L elected to pay the one-time fee, plus accrued
interest, and has recorded a liability as of December 31, 1994, of
approximately $105 million. The fees payable to the DOE may be
adjusted in the future to assure full recovery. AP&L considers all
costs incurred or to be incurred, except accrued interest, for the
disposal of spent nuclear fuel to be proper components of nuclear fuel
expense and provisions to recover such costs have been or will be made
in applications to regulatory authorities.
Delays have occurred in the DOE's program for the acceptance and
disposal of spent nuclear fuel at a permanent repository. In a
statement released February 17, 1993, the DOE asserted that it does
not have a legal obligation to accept spent nuclear fuel without an
operational repository for which it has not yet arranged. Currently
the DOE projects it will begin to accept spent fuel no earlier than
2010. In the meantime, AP&L is responsible for spent fuel storage.
Current on-site spent fuel storage capacity at ANO is estimated to be
sufficient until mid-1995, at which time an ANO storage facility using
dry casks will begin operation. This facility is estimated to provide
sufficient storage until 2000, with the capability of being expanded
further as required. The initial cost of providing the additional on-
site spent fuel storage capability required at ANO is $5 million to
$10 million per unit. In addition, approximately $3 million to $5
million per unit will be required every two to three years subsequent
to 1995 until the DOE's repository begins accepting ANO's spent fuel.
Entergy Operations and System Fuels joined in lawsuits against
the DOE, seeking clarification of the DOE's responsibility to receive
spent nuclear fuel beginning in 1998. The original suits, filed June
20, 1994, asked for a ruling stating that the Nuclear Waste Policy Act
require the DOE to begin taking title to the spent fuel and to start
removing it from nuclear power plants in 1998, a mandate for the DOE's
nuclear waste management program to begin accepting fuel in 1998 and
court monitoring of the program, and the potential for escrow of
payments to the Nuclear Waste Fund instead of directly to the DOE.
AP&L is recovering in rates amounts sufficient to fund
decommissioning costs for ANO, based on a 1994 interim update to the
1992 decommissioning cost study (in 1992 dollars), of approximately
$806.3 million. The 1994 interim update adjusted the 1992 study only
for increased cost of low level radioactive waste disposal. The
amounts recovered in rates are deposited in external trust funds and
reported at market value. The accumulated decommissioning liability
of $137.4 million as of December 31, 1994, has been recorded in
accumulated depreciation. Decommissioning expense in the amount of
$12.2 million was recorded in 1994. AP&L regularly reviews and updates
its estimates for decommissioning costs and applications will be made
to the APSC to reflect in rates future changes in projected
decommissioning costs. The actual decommissioning costs may vary from
the estimates because of regulatory requirements, changes in
technology, and increased costs of labor, materials, and equipment.
Management believes that actual decommissioning costs are likely to be
higher than the amounts presented above.
The staff of the SEC has questioned certain of the current
accounting practices of the electric utility industry regarding the
recognition, measurement, and classification of decommissioning costs
for nuclear generating stations in the financial statements of
electric utilities. In response to these questions, the FASB is
currently reviewing the accounting for decommissioning. If current
electric utility industry accounting practices for such
decommissioning are changed, annual provisions for decommissioning
could increase, the estimated cost for decommissioning could be
recorded as a liability rather than as accumulated depreciation, and
trust fund income from the external decommissioning trusts could be
reported as investment income.
The EPAct has a provision that assesses domestic nuclear
utilities with fees for the decontamination and decommissioning of the
DOE's past uranium enrichment operations. The decontamination and
decommissioning assessments will be used to set up a fund into which
contributions from utilities and the federal government will be
placed. AP&L's annual assessment, which will be adjusted annually for
inflation, is $3.4 million (in 1995 dollars) annually for
approximately 15 years. FERC requires that utilities treat these
assessments as costs of fuel as they are amortized. The cumulative
liability of $38.9 million as of December 31, 1994, is recorded in
other current liabilities and other noncurrent liabilities, and is
offset in the financial statements by a regulatory asset.
ANO Matters
ANO 2 experienced a forced outage for repair of certain steam
generator tubes in March 1992. Further inspections and repairs were
conducted at subsequent refueling and mid-cycle outages in September
1992, May 1993, April 1994, and January 1995. AP&L's budgeted
maintenance expenditures were adequate to cover the cost of such
repairs. ANO 2's output has been reduced 15 megawatts or 1.6% due to
secondary side fouling, tube plugging, and reduction of primary
temperature. Entergy Operations continues to take steps at ANO 2 to
reduce the number and severity of future tube cracks. In addition,
Entergy Operations continues to meet with the NRC to discuss such
steps and results of inspections of the steam generator tubes, as well
as the timing of future inspections. Additional inspections are
planned for the normal refueling outage scheduled for October 1995.
NOTE 9. LEASES
As of December 31, 1994, AP&L had capital leases and
noncancelable operating leases (excluding the nuclear fuel lease) with
minimum lease payments as follows:
Capital Operating
Leases Leases
(In Thousands)
1995 $13,539 $28,303
1996 11,126 24,217
1997 8,293 15,566
1998 8,293 15,144
1999 8,294 11,552
Years thereafter 48,695 50,685
------- --------
Minimum lease payments 98,240 $145,467
Less: Amount representing interest 40,587 ========
-------
Present value of net minimum lease payments $57,653
=======
Rental expense for capital and operating leases (excluding the
nuclear fuel lease) amounted to approximately $26.4 million, $23.2
million, and $27.4 million in 1994, 1993, and 1992, respectively.
Nuclear Fuel Lease
AP&L has an arrangement to lease nuclear fuel in an amount up to
$125 million. The lessor finances its acquisition of nuclear fuel
through a credit agreement and the issuance of notes. The credit
agreement, which was entered into in 1988, has been extended to
December 1997 and the notes have varying remaining maturities of up to
3 years. It is expected that these arrangements will be extended or
alternative financing will be secured by the lessor upon the maturity
of the current arrangements, based on AP&L's nuclear fuel
requirements. If the lessor cannot arrange financing upon maturity of
its borrowings, AP&L must purchase nuclear fuel in an amount
sufficient to enable the lessor to retire such borrowings.
Lease payments are based on nuclear fuel use. Nuclear fuel lease
expense of $56.2 million, $69.7 million, and $65.5 million (including
interest of $7.5 million, $10.6 million, and $11.6 million) was
charged to operations in 1994, 1993, and 1992, respectively.
NOTE 10. POSTRETIREMENT BENEFITS
Pension Plan
AP&L has a defined benefit pension plan covering substantially
all of its employees. The pension plan is noncontributory and
provides pension benefits that are based on employees' credited
service and average compensation, generally during the last five years
before retirement. AP&L funds pension costs in accordance with
contribution guidelines established by the Employee Retirement Income
Security Act of 1974, as amended, and the Internal Revenue Code of
1986, as amended. The assets of the plan consist primarily of common
and preferred stocks, fixed income securities, interest in a money
market fund, and insurance contracts.
Effective June 6, 1990, AP&L's nuclear operations employees
became employees of Entergy Operations. However, the employees still
remain under AP&L's plan and no transfers of related pension
liabilities and assets have been made.
AP&L's 1994, 1993, and 1992 pension cost, including amounts
capitalized, included the following components:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Service cost - benefits earned during the period $8,854 $7,940 $6,906
Interest cost on projected benefit obligation 22,651 21,744 20,512
Actual return on plan assets 365 (31,984) (16,765)
Net amortization and deferral (24,474) 10,531 (3,531)
Other - - -
------ ------ ------
Net pension cost $7,396 $8,231 $7,122
====== ====== ======
The funded status of AP&L's pension plan as of December 31, 1994
and 1993, was:
1994 1993
(In Thousands)
Actuarial present value of accumulated pension plan benefits:
Vested $238,769 $255,955
Nonvested 1,797 1,724
-------- --------
Accumulated benefit obligation $240,566 $257,679
======== ========
Plan assets at fair value $283,437 $288,418
Projected benefit obligation 283,256 316,255
-------- --------
Plan assets greater (less than) projected benefit obligation 181 (27,837)
Unrecognized prior service cost 6,568 5,841
Unrecognized transition asset (16,350) (18,686)
Unrecognized net loss (gain) (12,453) 13,242
-------- --------
Accrued pension liability $(22,054) $(27,440)
======== ========
The significant actuarial assumptions used in computing the
information above for 1994, 1993, and 1992 were as follows: weighted
average discount rate, 8.5% for 1994, 7.5% for 1993 and 8.25% for
1992; weighted average rate of increase in future compensation levels,
5.1% for 1994 and 5.6% for 1993 and 1992 and expected long-term rate
of return on plan assets, 8.5%. Transition assets are being amortized
over 15 years.
Other Postretirement Benefits
AP&L also provides certain health care and life insurance
benefits for retired employees. Substantially all employees may
become eligible for these benefits if they reach retirement age while
still working for AP&L. The cost of providing these benefits, recorded
on a cash basis, to retirees in 1992 was approximately $3.5 million.
Effective January 1, 1993, AP&L adopted SFAS 106. This standard
required a change from a cash method to an accrual method of
accounting for postretirement benefits other than pensions. AP&L
continues to fund these benefits on a pay-as-you-go basis. As of
January 1, 1993, the actuarially determined accumulated postretirement
benefit obligation (APBO) earned by retirees and active employees was
estimated to be approximately $80.5 million. This obligation is being
amortized over a 20-year period beginning in 1993. AP&L has received
an order from the APSC permitting deferral, as a regulatory asset, of
the increased annual expense associated with these benefits.
AP&L's 1994 and 1993 postretirement benefit cost, including
amounts capitalized and deferred, included the following components:
1994 1993
(In Thousands)
Service cost - benefits earned during the period $3,080 $2,366
Interest cost on APBO 5,510 6,427
Actual return on plan assets - (71)
Net amortization and deferral 3,833 3,954
------- --------
Net postretirement benefit cost $12,423 $ 12,676
======= ========
The funded status of AP&L's pension plan as of December 31, 1994
and 1993, was:
1994 1993
(In Thousands)
Accumulated postretirement benefit obligation:
Retirees $49,291 $59,906
Other fully eligible participants 9,876 8,366
Other active participants 12,204 25,038
-------- -------
71,371 93,310
Plan assets at fair value - 354
-------- -------
Plan assets less than APBO (71,371) (92,956)
Unrecognized transition obligation 71,160 75,114
Unrecognized net loss (gain) (16,272) 8,360
-------- -------
Accrued postretirement benefit liability $(16,483) $(9,482)
======== =======
The assumed health care cost trend rate used in measuring the
APBO was 9.4% for 1995, gradually decreasing each successive year
until it reaches 5.0% in 2011. A one percentage-point increase in the
assumed health care cost trend rate for each year would have increased
the APBO as of December 31, 1994, by 8.2% and the sum of the service
cost and interest cost by approximately 10.8%. The assumed discount
rate and rate of increase in future compensation used in determining
the APBO were 8.5% for 1994 and 7.5% for 1993 and 5.1% for 1994 and
5.5% for 1993, respectively.
NOTE 11. TRANSACTIONS WITH AFFILIATES
AP&L buys electricity from and/or sells electricity to the other
System operating companies, System Energy, and Entergy Power under
rate schedules filed with FERC. In addition, AP&L purchases fuel from
System Fuels, receives technical and advisory services from Entergy
Services, and receives management and operating services from Entergy
Operations.
Operating revenues include revenues from sales to affiliates
amounting to $238.7 million in 1994, $181.8 million in 1993, and
$211.4 million in 1992. Operating expenses include charges from
affiliates for fuel costs, purchased power and related charges,
management services, and technical and advisory services totaling
$310.7 million in 1994, $323.2 million in 1993, and $573.4 million in
1992. Operating expenses also include $25.7 million in 1994,
$16.8 million in 1993, and $47.4 million in 1992, for power purchased
from Entergy Power. AP&L pays directly or reimburses Entergy
Operations for the costs associated with operating ANO (excluding
nuclear fuel), which were approximately $221.2 million in 1994, $226.3
million in 1993, and $292.3 million in 1992.
NOTE 12. RESTRUCTURING COSTS
During the third quarter of 1994, AP&L announced a restructuring
program related to certain of its operating units. The program is
designed to reduce costs, improve operating efficiencies, and increase
shareholder value in order to enable AP&L to become a low-cost
producer. The program includes reductions in the number of employees
and the consolidation of offices and facilities. In 1994, AP&L
recorded restructuring charges of $12.5 million. These charges
primarily include employee severance costs related to the expected
termination of approximately 696 employees. As of December 31, 1994,
35 AP&L employees were terminated under the program at a severance
cost of $0.3 million.
NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED)
AP&L's business is subject to seasonal fluctuations with the peak
period occurring during the third quarter. Operating results for the
four quarters of 1994 and 1993 were:
Operating Operating Net
Revenues Income Income
(In Thousands)
1994:
First Quarter $371,091 $ 44,674 $26,388
Second Quarter $414,901 $ 59,581 $41,763
Third Quarter $470,770 $ 56,163 $36,630
Fourth Quarter $333,980 $ 56,215 $37,482
1993:
First Quarter $346,740 $ 36,961 $66,081
Second Quarter $383,651 $ 53,332 $34,572
Third Quarter $519,822 $101,484 $81,677
Fourth Quarter $341,355 $ 44,445 $22,967
See Note 1 for information regarding the recording of the
cumulative effect of the change in accounting principle for
unbilled revenues in January 1993.
ARKANSAS POWER & LIGHT COMPANY
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1994 1993 1992 1991 1990
(In Thousands)
Operating revenues $1,590,742 $1,591,568 $1,521,129 $1,528,270 $1,481,408
Income before cumulative
effect of a change in
accounting principle $ 142,263 $ 155,110 $ 130,529 $ 143,451 $ 129,765
Total assets $4,292,215 $4,334,105 $4,038,811 $4,192,020 $4,137,938
Long-term obligations (1) $1,446,940 $1,478,203 $1,453,588 $1,670,678 $1,731,212
(1) Includes long-term debt (excluding currently maturing debt),
preferred stock with sinking fund, and noncurrent capital lease
obligations.
See Notes 1, 3, and 10 for the effect of accounting changes in
1993.
1994 1993 1992 1991 1990
(Dollars in Thousands)
Operating Revenues:
Residential $506,160 $528,734 $476,090 $494,375 $484,359
Commercial 307,296 306,742 291,367 289,291 283,971
Industrial 338,988 336,856 325,569 324,632 331,929
Governmental 16,698 16,670 17,700 19,731 19,599
---------- ---------- ---------- ---------- ----------
Total retail 1,169,142 1,189,002 1,110,726 1,128,029 1,119,858
Sales for resale 395,234 379,480 385,028 373,735 339,366
Other 26,366 23,086 25,375 26,506 22,184
---------- ---------- ---------- ---------- ----------
Total $1,590,742 $1,591,568 $1,521,129 $1,528,270 $1,481,408
========== ========== ========== ========== ==========
Billed Electric Energy
Sales (Millions of KWH):
Residential 5,522 5,680 5,102 5,564 5,401
Commercial 4,147 4,067 3,841 3,967 3,821
Industrial 5,941 5,690 5,509 5,565 5,532
Governmental 231 230 248 290 285
------ ------ ------ ------ ------
Total retail 15,841 15,667 14,700 15,386 15,039
Sales for resale 15,497 13,950 15,413 16,087 13,618
------ ------ ------ ------ ------
Total 31,338 29,617 30,113 31,473 28,657
====== ====== ====== ====== ======
Gulf States Utilities Company
1994 Financial Statements
GULF STATES UTILITIES COMPANY
DEFINITIONS
Certain abbreviations or acronyms used in GSU's Financial
Statements, Notes to Financial Statements, and Management's Financial
Discussion and Analysis are defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During
Construction
AP&L Arkansas Power & Light Company
Cajun Cajun Electric Power Cooperative, Inc.
DOE United States Department of Energy
Entergy or System Entergy Corporation and its various
direct and indirect subsidiaries
Entergy Operations Entergy Operations, Inc., a subsidiary of
Entergy that has operating responsibility
for Grand Gulf 1, River Bend,
Waterford 3, and Arkansas Nuclear One
Steam Electric Generating Station
Entergy Power Entergy Power, Inc., a subsidiary of
Entergy Corporation that markets capacity
and energy for resale from certain
generating facilities to other parties,
principally non-affiliates
Entergy Services Entergy Services, Inc.
EPAct The Energy Policy Act of 1992
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
GSU Gulf States Utilities Company (including
wholly owned subsidiaries - Varibus
Corporation, GSG&T, Inc., Prudential Oil
and Gas, Inc., and Southern Gulf Railway
Company)
KWH Kilowatt-Hour(s)
LP&L Louisiana Power & Light Company
LPSC Louisiana Public Service Commission
Money Pool Entergy Money Pool, which allows certain
System companies to borrow from, or lend
to, certain other System companies
MP&L Mississippi Power & Light Company
Merger The combination transaction consummated
on December 31, 1993, by which GSU became
a subsidiary of Entergy Corporation and
Entergy Corporation became a Delaware
corporation
NOPSI New Orleans Public Service Inc.
PUCT Public Utility Commission of Texas
Rate Cap The level of retail electric base rates
in effect at December 31, 1993, for the
Louisiana retail jurisdiction, and the
level in effect prior to the Texas Cities
Rate Settlement for the Texas retail
jurisdiction, that may not be exceeded
for the five years following December
31, 1993
River Bend River Bend Steam Electric Generating
Station (nuclear), owned 70% by GSU
RUS Rural Utility Services (formerly the
Rural Electrification Administration or
"REA")
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting
Standards promulgated by the FASB
SFAS 106 SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than
Pensions"
SFAS 109 SFAS 109, "Accounting for Income Taxes"
System or Entergy Entergy Corporation and its various
direct and indirect subsidiaries
System Agreement Agreement, effective January 1, 1983, as
amended among the System operating
companies relating to the sharing of
generating capacity and other power
resources
System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI,
collectively
GULF STATES UTILITIES COMPANY
REPORT OF MANAGEMENT
The management of Gulf States Utilities Company has prepared and
is responsible for the financial statements and related financial
information included herein. The financial statements are based on
generally accepted accounting principles. Financial information
included elsewhere in this report is consistent with the financial
statements.
To meet its responsibilities with respect to financial
information, management maintains and enforces a system of internal
accounting controls that is designed to provide reasonable assurance,
on a cost-effective basis, as to the integrity, objectivity, and
reliability of the financial records, and as to the protection of
assets. This system includes communication through written policies
and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and
the training of personnel. This system is also tested by a
comprehensive internal audit program.
The independent public accountants provide an objective
assessment of the degree to which management meets its responsibility
for fairness of financial reporting. They regularly evaluate the
system of internal accounting controls and perform such tests and
other procedures as they deem necessary to reach and express an
opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide
reasonable assurance that its operations are carried out with a high
standard of business conduct.
/s/ Edwin Lupberger /s/ Gerald D. McInvale
EDWIN LUPBERGER GERALD D. MCINVALE
Chairman and Chief Executive Officer Senior Vice President and
Chief Financial Officer
GULF STATES UTILITIES COMPANY
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Entergy Corporation Board of Directors' Audit Committee
functions as the Audit Committee for Gulf States Utilities Company.
The Audit Committee is comprised of four directors, who are not
officers of GSU: H. Duke Shackelford (Chairman), Lucie J. Fjeldstad,
Dr. Norman C. Francis, and James R. Nichols. The committee held four
meetings during 1994.
The Audit Committee oversees GSU's financial reporting process on
behalf of the Board of Directors and provides reasonable assurance to
the Board that sufficient operating, accounting, and financial
controls are in existence and are adequately reviewed by programs of
internal and external audits.
The Audit Committee discussed with Entergy's internal auditors
and the independent public accountants (Coopers & Lybrand L.L.P.) the
overall scope and specific plans for their respective audits, as well
as GSU's financial statements and the adequacy of GSU's internal
controls. The committee met, together and separately, with Entergy's
internal auditors and independent public accountants, without
management present, to discuss the results of their audits, their
evaluation of GSU's internal controls, and the overall quality of
GSU's financial reporting. The meetings also were designed to
facilitate and encourage any private communication between the
committee and the internal auditors or independent public accountants.
/s/ H. Duke Shackelford
H. DUKE SHACKELFORD
Chairman, Audit Committee
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
Gulf States Utilities Company
We have audited the accompanying balance sheets of Gulf States
Utilities Company as of December 31, 1994 and 1993 and the related
statements of income (loss), retained earnings and paid-in-capital and
cash flows for each of the three years in the period ended December
31, 1994. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As discussed in Note 13 to the financial statements, the common
stock of the Company was acquired on December 31, 1993.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position of
the Company as of December 31, 1994 and 1993, and the results of its
operations and its cash flows for each of the three years in the
period ended December 31, 1994 in conformity with generally accepted
accounting principles.
As discussed in Note 2 to the financial statements, the net
amount of capitalized costs for River Bend Unit I Nuclear Generating
Plant (River Bend) exceed those costs currently being recovered
through rates. At December 31, 1994, approximately $685 million is
not currently being recovered through rates. If current regulatory
and court orders are not modified, a write-off of all or a portion of
such costs may be required. Additionally, as discussed in Note 2 to
the financial statements, other rate-related contingencies exist which
may result in refunds of revenues previously collected. The extent
of such write-off of capitalized River Bend costs or refunds of
revenues previously collected, if any, will not be determined until
appropriate rate proceedings and court appeals have been concluded.
Accordingly, the accompanying financial statements do not include any
adjustments or provision for write-off or refund that might result
from the outcome of these uncertainties.
As discussed in Note 8 to the financial statements, civil actions
have been initiated against the Company to, among other things,
recover the co-owner's investment in River Bend and to annul the River
Bend Joint Ownership Participation and Operating Agreement. The
ultimate outcome of these proceedings cannot presently be determined.
As discussed in Note 3 to the financial statements, in 1993, the
Company adopted Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes". As discussed in Note 10 to the
financial statements, the Company adopted Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions", as of January 1, 1993.
As discussed in Note 1 to the financial statements, as of
January 1, 1993, the Company began accruing revenues for energy
delivered to customers but not yet billed. As discussed in Note 1 to
the financial statements, the Company changed its accounting for power
plant materials and supplies as of January 1, 1992.
/s/ Coopers & Lybrand L.L.P.
COOPERS & LYBRAND L.L.P.
New Orleans, Louisiana
February 21, 1995, except for the last paragraph of
"Filings with the PUCT and Texas Cities" in
Note 2, as to which the date is March 20, 1995
GULF STATES UTILITIES COMPANY
BALANCE SHEETS
ASSETS
December 31,
1994 1993
(In Thousands)
Utility Plant:
Electric $6,842,726 $6,825,989
Natural gas 44,505 42,786
Steam products 77,307 75,689
Property under capital leases 82,914 86,039
Construction work in progress 96,176 50,080
Nuclear fuel under capital leases 80,042 94,828
---------- ---------
Total 7,223,670 7,175,411
Less - accumulated depreciation and amortization 2,504,826 2,323,804
---------- ---------
Utility plant - net 4,718,844 4,851,607
---------- ---------
Other Property and Investments:
Decommissioning trust fund 21,309 17,873
Other - at cost (less accumulated depreciation) 29,315 29,360
---------- ---------
Total 50,624 47,233
---------- ---------
Current Assets:
Cash and cash equivalents:
Cash 8,063 3,012
Temporary cash investments - at cost,
which approximates market
Associated companies 5,085 -
Other 91,496 258,337
---------- ---------
Total cash and cash equivalents 104,644 261,349
Accounts receivable:
Customer (less allowance for doubtful accounts
of $0.7 million in 1994 and $2.4 million in 1993) 167,745 117,369
Associated companies 12,732 -
Other 20,706 18,371
Accrued unbilled revenues 39,470 32,572
Deferred fuel costs 6,314 5,883
Accumulated deferred income taxes 49,457 -
Fuel inventory 25,784 23,448
Materials and supplies - at average cost 90,054 86,831
Rate deferrals 100,478 90,775
Prepayments and other 13,754 48,948
---------- ----------
Total 631,138 685,546
---------- ----------
Deferred Debits and Other Assets:
Regulatory Assets:
Rate deferrals 506,974 638,015
SFAS 109 regulatory asset - net 426,358 432,411
Unamortized loss on reacquired debt 63,994 70,970
Other regulatory assets 35,168 40,690
Long-term receivables 264,752 218,079
Other 145,609 152,800
---------- ----------
Total 1,442,855 1,552,965
---------- ----------
TOTAL $6,843,461 $7,137,351
========== ==========
See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
1994 1993
(In Thousands)
Capitalization:
Common stock, no par value, authorized
200,000,000 shares; issued and outstanding
100 shares in 1994 and 1993 $114,055 $114,055
Paid-in capital 1,152,336 1,152,304
Retained earnings 264,626 666,401
---------- ---------
Total common shareholder's equity 1,531,017 1,932,760
Preference stock 150,000 150,000
Preferred stock:
Without sinking fund 136,444 136,444
With sinking fund 94,934 101,004
Long-term debt 2,318,417 2,368,639
---------- ---------
Total 4,230,812 4,688,847
---------- ---------
Other Noncurrent Liabilities:
Obligations under capital leases 125,691 152,359
Other 68,753 65,259
---------- ---------
Total 194,444 217,618
---------- ---------
Current Liabilities:
Currently maturing long-term debt 50,425 425
Accounts payable:
Associated companies 31,722 2,745
Other 140,975 109,840
Customer deposits 22,216 21,958
Taxes accrued 12,478 22,856
Interest accrued 55,327 59,516
Nuclear refueling reserve 10,117 22,356
Obligations under capital leases 37,265 41,713
Reserve for rate refund 56,972 -
Other 111,963 97,741
---------- ---------
Total 529,460 379,150
---------- ---------
Deferred Credits:
Accumulated deferred income taxes 1,100,396 1,062,180
Accumulated deferred investment tax credits 199,428 255,274
Deferred River Bend finance charges 82,406 106,765
Other 506,515 427,517
---------- ---------
Total 1,888,745 1,851,736
---------- ---------
Commitments and Contingencies (Notes 2, 8, and 9)
TOTAL $6,843,461 $7,137,351
========== ==========
See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Activities:
Net income (loss) ($82,755) $78,862 $133,848
Noncash items included in net income (loss):
Extraordinary items - 1,259 9,597
Cumulative effect of a change in accounting principle - (10,660) (4,032)
Change in rate deferrals 96,979 61,115 52,946
Depreciation and decommissioning 197,151 190,405 188,393
Deferred income taxes and investment tax credits (62,171) 41,302 50,238
Allowance for equity funds used during construction (1,334) (726) (1,226)
Write-off of plant held for future use 85,476 - -
Changes in working capital:
Receivables (72,341) 6,879 4,373
Fuel inventory (2,336) (2,289) (4,152)
Accounts payable 60,112 11,072 (1,171)
Taxes accrued (10,378) 3,764 (2,634)
Interest accrued (4,189) (2,497) (15,276)
Reserve for rate refund 56,972 - -
Other working capital accounts 33,781 (9,915) (13,675)
Decommissioning trust contributions (3,202) (2,710) (5,912)
Purchased power settlement - (169,300) (20,797)
Other 34,594 58,874 (22,992)
-------- -------- ----------
Net cash flow provided by operating activities 326,359 255,435 347,528
-------- -------- ----------
Investing Activities:
Construction expenditures (155,989) (115,481) (97,377)
Proceeds received from sale of property - - 12,460
Allowance for equity funds used during construction 1,334 726 1,226
Nuclear fuel purchases (31,178) (2,118) -
Proceeds from sale/leaseback of nuclear fuel 29,386 2,118 -
Refund of escrow account and other property - 5,921 13,091
-------- -------- ----------
Net cash flow used in investing activities (156,447) (108,834) (70,600)
-------- -------- ----------
Financing Activities:
Proceeds from the issuance of:
First mortgage bonds - 338,379 1,185,260
Other long-term debt 101,109 21,440 48,965
Preference stock - 146,625 -
Retirement of:
First mortgage bonds - (360,199) (1,067,717)
Other long-term debt (102,425) (18,398) (127,161)
Redemption of preferred and preference stock (6,070) (174,841) (174,226)
Dividends paid:
Common stock (289,100) - -
Preferred and preference stock (30,131) (35,999) (237,369)
-------- -------- ----------
Net cash flow used in financing activities (326,617) (82,993) (372,248)
-------- -------- ----------
Net increase (decrease) in cash and cash equivalents (156,705) 63,608 (95,320)
Cash and cash equivalents at beginning of period 261,349 197,741 293,061
-------- -------- ----------
Cash and cash equivalents at end of period $104,644 $261,349 $197,741
======== ======== ==========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $191,850 $197,058 $239,607
Income taxes $251 $15,600 $8,000
Noncash investing and financing activities:
Capital lease obligations incurred $31,178 $17,143 $87,022
Deficiency of fair value of decommissioning
trust assets over amount invested ($915) - -
See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is important to GSU due to the capital intensive nature
of its business, which requires large investments in long-lived
assets. While large capital expenditures for the construction of new
generating capacity are not currently planned, GSU does require
significant capital resources for the periodic maturity of certain
series of debt and preferred stock and ongoing construction
expenditures. Net cash flow from operations totaled $326 million,
$255 million, and $348 million in 1994, 1993, and 1992, respectively.
Cash flow from operations in 1993 includes nonrecurring items related
to the payment of $169.3 million as a result of the settlement of a
purchased power dispute. In recent years, this cash flow,
supplemented by cash on hand, has been sufficient to meet
substantially all investing and financing requirements, including
capital expenditures, dividends, and debt/preferred stock maturities.
GSU's ability to fund these capital requirements with cash from
operations, results in part from continued efforts to reduce costs as
well as collections under River Bend rate phase-in plan of previously
deferred amounts. (In the income statement, these revenue collections
are offset by the amortization of previously deferred costs;
therefore, there is no effect on net income.) The River Bend rate
phase-in plan will continue to contribute to GSU's cash position
through 1998. See Note 2 for additional information on GSU's rate
phase-in plan. Further, GSU has the ability to meet future capital
requirements through future debt and preference stock issuances, as
discussed below. See Note 8 for additional information on GSU's
capital and refinancing requirements in 1995 - 1997. Also, to the
extent current market interest and dividend rates allow, GSU may
continue to refinance high-cost debt and preferred stock prior to
maturity.
In 1994, GSU paid to Entergy Corporation approximately $289.1
million of cash dividends on its common stock. Prior to 1994, GSU had
not paid any cash dividends on its common stock since June 1986.
On March 20, 1995, the PUCT ordered GSU to implement a $72.9
million annual base rate reduction for the period March 31, 1994,
through September 1, 1994, decreasing to an annual base rate reduction
of $52.9 million after September 1, 1994. In accordance with the
Merger agreement, the rate reduction is applied retroactively to March
31, 1994. As a result, GSU recorded a $57 million reserve for reserve
for rate refund in 1994. See Note 2 for additional information.
Earnings coverage tests and bondable property additions limit the
amount of first mortgage bonds and preferred stock that GSU can issue.
As a result of the charges recorded in 1994 as discussed in Notes 12
and 13, GSU was precluded from issuing first mortgage bonds under its
earnings coverage test as of December 31, 1994. As of December 31,
1994, GSU was unable to issue any additional preferred stock. There
are no limitations on the issuance of preference stock. However, GSU
has the ability to issue approximately $578 million of first mortgage
bonds against the retirement of first mortgage bonds without
satisfying an earnings coverage test.
See Notes 5 and 6 for information on GSU's financing activities
and Note 4 for information on GSU's short-term borrowings and lines of
credit.
See Notes 2 and 8 for information regarding litigation with
Cajun, and River Bend rate appeals. Substantial write-offs or charges
resulting from adverse rulings in these matters could result in
substantial additional net losses being reported by GSU in 1995 and
subsequent periods, with resulting substantial adverse adjustments to
common shareholder's equity. Also, adverse resolution of these
matters could adversely affect GSU's ability to continue to pay
dividends and obtain financing, which could in turn affect GSU's
liquidity.
GULF STATES UTILITIES COMPANY
STATEMENTS OF INCOME (LOSS)
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Revenues:
Electric $1,719,201 $1,747,961 $1,694,536
Natural gas 31,605 32,466 28,523
Steam products 46,559 47,193 50,315
---------- ---------- ----------
Total 1,797,365 1,827,620 1,773,374
---------- ---------- ----------
Operating Expenses:
Operation and maintenance:
Fuel, fuel-related expenses and
gas purchased for resale 517,177 559,416 488,436
Purchased power 203,773 134,936 136,716
Nuclear refueling outage expenses 12,684 10,706 29,087
Other operation and maintenance 494,865 458,677 409,378
Depreciation and amortization 197,151 190,405 188,393
Taxes other than income taxes 98,096 95,742 91,740
Income taxes (6,448) 46,007 38,058
Amortization of rate deferrals 66,416 61,115 52,946
---------- ---------- ----------
Total 1,583,714 1,557,004 1,434,754
---------- ---------- ----------
Operating Income 213,651 270,616 338,620
---------- ---------- ----------
Other Income (Deductions):
Allowance for equity funds used
during construction 1,334 726 1,226
Write-off of plant held for future use (85,476) - -
Miscellaneous - net (64,843) 19,996 64,837
Income taxes 55,638 (12,009) (17,801)
---------- ---------- ----------
Total (93,347) 8,713 48,262
---------- ---------- ----------
Interest Charges:
Interest on long-term debt 195,414 202,235 239,341
Other interest - net 8,720 8,364 9,075
Allowance for borrowed funds used
during construction (1,075) (731) (947)
---------- ---------- ----------
Total 203,059 209,868 247,469
---------- ---------- ----------
Income (Loss) before Extraordinary Items and
the Cumulative Effect of Accounting Changes (82,755) 69,461 139,413
Extraordinary Items (net of income taxes) - (1,259) (9,597)
Cumulative Effect of Accounting
Changes (net of income taxes) (Note 1) - 10,660 4,032
---------- ---------- ----------
Net Income (Loss) (82,755) 78,862 133,848
Preferred and Preference Stock
Dividend Requirements and Other 29,919 35,581 49,702
---------- ---------- ----------
Earnings (Loss) Applicable to Common Stock ($112,674) $43,281 $84,146
========== ========== ==========
See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY
STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Retained Earnings, January 1 $ 666,401 $ 631,462 $ 667,893
Add:
Net income (loss) (82,755) 78,862 133,848
---------- ---------- ----------
Total 583,646 710,324 801,741
---------- ---------- ----------
Deduct:
Dividends declared:
Preferred and preference stock 29,831 35,581 158,547
Common stock 289,100 - -
Preferred and preference stock redemption 89 8,342 11,732
---------- ---------- ----------
Total 319,020 43,923 170,279
---------- ---------- ----------
Retained Earnings, December 31 (Note 7) $264,626 $ 666,401 $631,462
========== ========== ==========
Paid-in Capital, January 1 $1,152,304 $67,316 $73,993
Add:
Issuance of 100 shares of no par common
stock with a stated value of $114,055
net of the retirement of 114,055,065 shares
of no par common stock - 1,086,868 -
Gain (loss) on reacquisition of
preferred and preference stock 32 (1,880) (6,677)
---------- ---------- ----------
Paid-in Capital, December 31 $1,152,336 $1,152,304 $67,316
========== ========== ==========
See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
GSU incurred a net loss for the year 1994 due primarily to write-
offs and charges associated with the resolution of certain
contingencies and additional Merger-related costs aggregating $137
million (see Note 13), a base rate reduction ordered by the PUCT
applied retroactively to March 1994 (see Note 2), and restructuring
costs (see Note 12). Net income decreased in 1993 due primarily to
Merger-related charges recorded at year-end. Also contributing to the
decrease was a rate refund and one-time credit resulting from a
November 1993 rate settlement, the effect of implementing SFAS 106,
and the impact in 1992 of reducing a purchased power settlement
liability. The decrease in net income was partially offset by the one-
time recording of the cumulative effect of the change in accounting
principle for unbilled revenues and its ongoing effects. Effective
January 1, 1993, GSU began accruing as revenues the charges for energy
delivered to customers but not yet billed. Electric and gas revenues
were previously recorded on a cycle-billing basis. Excluding the above
mentioned items, net income for 1993 would have been $139.2 million,
an increase of $29.6 million which is due primarily to increased
retail energy sales and decreased interest expense.
Significant factors affecting the results of operations and
causing variances between the years 1994 and 1993, and 1993 and 1992
are discussed under "Revenues and Sales," "Expenses," and "Other"
below.
Revenues and Sales
Operating revenues decreased in 1994 due primarily to a base rate
reduction ordered by the PUCT applied retroactively to March 1994 (see
Note 2) and lower retail fuel revenues partially offset by increased
wholesale revenues associated with higher sales for resale and
increased retail base revenue. The decrease in retail revenues is
primarily due to a decrease in fuel recovery revenue and a November
1993 rate reduction in Texas. Energy sales increased due primarily to
higher sales for resale as a result of GSU's participation in the
System power pool.
Operating revenues were higher in 1993 due primarily to increased
residential and commercial energy sales resulting primarily from a
return to more normal weather as compared to milder weather in 1992,
and increased fuel adjustment revenues and collections of previously
deferred River Bend costs, neither of which affects net income. These
increases were partially offset by a refund and one-time credit to
Texas retail customers resulting from a rate settlement.
See "Selected Financial Data - Five-Year Comparison," following
the notes, for information on operating revenues by source and KWH
sales.
Expenses
Operating expenses increased in 1994 due primarily to higher
purchased power and other operation and maintenance expenses,
partially offset by lower fuel for electric generation and fuel-
related expense and lower income tax expense. Purchased power
increased in 1994 due to GSU's participation in joint dispatching
through the System power pool resulting from increased energy sales as
discussed above. In addition, the increase in purchased power expense
in 1994 was also due to the recording of a provision for refund of
disallowed purchased power costs resulting from a Louisiana Supreme
Court ruling (see Note 2). Fuel, fuel-related expenses and gas
purchased for resale decreased in 1994 primarily due to lower gas
prices.
Fuel for electric generation and fuel-related expenses increased
in 1993 due primarily to a higher average per unit cost for gas
resulting from increased gas prices in 1993 and increased generation,
primarily at River Bend.
Other operation and maintenance expenses increased in 1994 due
primarily to charges associated with certain contingencies as
discussed in Note 13, additional Merger-related costs and
restructuring costs as discussed in Note 12.
Other operation and maintenance expenses increased in 1993 due
primarily to $52.3 million of Merger-related charges for financial
investment advisor fees and early retirement and other severance plan
provisions. Charges for other postemployment benefits increased
resulting from the adoption of SFAS 106. Amortization of amounts in
accordance with the River Bend phase-in plan also increased.
Income taxes decreased in 1994 due primarily to lower pretax
income resulting from the charges discussed above.
Other
Other miscellaneous income decreased due to the write-off of
plant held for future use in 1994 (see Note 13), establishment of a
reserve related to the Cajun River Bend litigation (see Note 8), the
write-off of previously disallowed rate deferrals, and obsolete spare
parts, partially offset by lower interest expense as a result of the
continued refinancing of high-cost debt.
Income taxes decreased in 1994 due primarily to the charges
discussed above.
Other miscellaneous income decreased in 1993 due primarily to the
1992 effect of reducing a liability relating to a purchased power
settlement. In accordance with the settlement, the liability was
based upon the price of GSU common stock as of the November 1991
settlement and was subsequently reduced as the price of GSU common
stock increased. Interest expense declined in 1993 as a result of the
continued refinancing of high-cost debt.
GULF STATES UTILITIES COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Competition
The electric utility industry is becoming increasingly
competitive and GSU is seeking to become a leading competitor in the
changing electric energy business. Competition presents GSU with many
challenges. The following have been identified by GSU as its major
competitive challenges.
Retail and Wholesale Rate Issues
Increasing competition in the utility industry brings an
increased need to stabilize or reduce retail rates. GSU implemented
shared-savings plans as part of the Merger. Recognizing that many
industrial customers have energy alternatives, GSU continues to work
with these customers to address their needs. In certain cases,
competitive prices are negotiated, using variable rate designs.
In connection with the Merger, GSU agreed with the LPSC and PUCT
to a five-year Rate Cap on retail electric rates, and to pass through
to retail customers the fuel savings and a certain percentage of the
nonfuel savings created by the Merger. Under the terms of their
respective Merger agreements, the LPSC and PUCT have reviewed GSU's
base rates during the first post-Merger earnings analysis for
reasonableness of its return on equity. The LPSC ordered a $12.7
million annual rate reduction effective January 1, 1995. GSU received
an injunction delaying implementation of $8.3 million of the reduction
and on January 1, 1995, reduced rates by $4.4 million. The entire
$12.7 million is being appealed. On March 20, 1995, the PUCT ordered
a $72.9 million annual base rate reduction for the period March 31,
1994, through September 1, 1994, decreasing to an annual base rate
reduction of $52.9 million after September 1, 1994. In accordance
with the Merger agreement, the rate reduction is applied retroactively
to March 31, 1994. The rate reduction is being appealed and no
assurance can be given as to the timing or outcome of the appeal. See
Note 2 for further information.
See Note 2 for information on the settlement of several PUCT fuel
cost reviews and the continuing likelihood of future reviews.
Retail wheeling, the transmission by an electric utility of
energy produced by another entity over the utility's transmission and
distribution system to a retail customer in the electric utility's
service territory, is evolving. Over a dozen states have been
studying the concept of retail competition. In April 1994, the state
of Michigan agreed to a five-year experiment that allows limited
competition among public utilities. During the same month, the
California Public Utilities Commission proposed to deregulate that
state's electric power industry, starting on January 1, 1996, to allow
the largest industrial customers to select the lowest cost supplier
for electricity service. Under the proposal, by the year 2002,
smaller companies and residential customers in California would also
be able to buy power from any suppliers. The California Public
Utilities Commission is currently reviewing its decision and is
expected to make a ruling in the first half of 1995. The retail market
for electricity is expected to become more competitive with such moves
toward deregulation.
In some areas of the country, municipalities (or comparable
entities) whose residents are served at retail by an investor-owned
utility pursuant to a franchise are exploring the possibility of
establishing new or extending existing distribution systems or seeking
new delivery points in order to serve retail customers, especially
large industrial customers, that currently receive service from an
investor-owned utility. These options depend on the terms of a
utility's franchise as well as on state law and regulation. In
addition, FERC's authority to order utilities to transmit for a new or
expanding municipal system is limited in certain respects. Where
successful, however, the establishment of a municipal system or the
acquisition by a municipal system of a utility's customers could
result in the inability to recover costs that the utility has incurred
in serving those customers.
In mid-1994, the FERC issued a notice of proposed rulemaking
concerning a regulatory framework for dealing with recovery of
stranded costs, such as high cost nuclear generating units, which may
be incurred by electric utilities as a result of increased
competition. In addition to addressing recovery of stranded costs
related to wholesale service, the proposal requested comment as to
recovery of retail stranded costs in transmission rates where state
regulatory authorities failed to address the issue or were in
conflict. Comments and reply comments have been filed, and the matter
is pending. The risk of exposure to stranded costs which may result
from competition in the industry will depend on the extent and timing
of retail competition, the resolution of jurisdictional issues
concerning stranded cost recovery, and the extent to which such costs
are recovered from departing or remaining customers, among other
matters.
Cogeneration projects developed or considered by certain of GSU's
industrial customers over the last several years have resulted in GSU
developing and securing approval of rates lower than the rates
previously approved by the PUCT and LPSC for such industrial
customers. Such rates are designed to retain such customers, and to
compete for and develop new loads, and do not presently recover GSU's
full cost of service. The pricing agreements at non-full cost of
service based rates fully recover all related costs but provide only a
minimal return. Substantially all of such pricing agreements expire
no later than 1997. In 1994, KWH sales to GSU's industrial customers
at non-full cost of service rates, which make up approximately 28% of
the total industrial class, increased 13%. Sales to the remaining
industrial customers increased 2%.
In the wholesale rate area, FERC approved in 1992, with certain
modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy
Power to sell wholesale power at market-based rates and to provide to
electric utilities "open access" to the System's transmission system
(subject to certain requirements). GSU was later added to this
filing. On October 31, 1994, as amended on January 25, 1995, Entergy
Services filed with FERC revised transmission tariffs intended to
provide access to transmission service on the same or comparable
basis, terms, and conditions as the Entergy operating companies, and
the matter is pending. Open access and market pricing, once in
effect, will increase marketing opportunities for GSU, but will also
expose GSU to the risk of loss of load or reduced revenues due to
competition with alternative suppliers.
In light of the rate issues discussed above, GSU is aggressively
reducing costs to avoid potential earnings erosions that might result
as well as to become more competitive. In 1994, GSU announced a
restructuring program related to certain of its operating units. This
program is designed to reduce costs and improve operating
efficiencies. See Note 12 for further information. Also, in response
to an increasingly competitive environment, GSU is continuing to work
with the PUCT regarding integrated resource planning.
The Energy Policy Act of 1992
The EPAct addresses a wide range of energy issues and is altering
the way Entergy and the rest of the electric utility industry
operate. The EPAct encourages competition and affords utilities the
opportunities, and the risks, associated with an open and more
competitive market environment. The EPAct creates exemptions from
regulation under the Holding Company Act and creates a class of exempt
wholesale generators consisting of utility affiliates and nonutilities
that are owners and operators of facilities for the generation and
transmission of power for sales at wholesale. The EPAct also gives
FERC the authority to order investor-owned utilities, including GSU,
to transmit power and energy to or for wholesale purchasers and
sellers. The law creates the potential for electric utilities and
other power producers to gain increased access to the transmission
systems of other entities to facilitate wholesale sales. Both GSU and
Entergy Power expect to compete in this market.
Litigation and Regulatory Proceedings
See Note 2 for information on the possible material adverse
effects on GSU's financial condition and results of operations as a
result of substantial write-offs and/or refunds in connection with
outstanding appeals and remands regarding approximately $1.4 billion
of abeyed company-wide River Bend plant costs and approximately $187
million ($170 million net of tax) of Texas retail jurisdiction
deferred River Bend operating and carrying costs.
Entergy Corporation-GSU Merger
The acquisition of GSU by Entergy Corporation was the largest
electric utility merger in United States history. Entergy expects to
achieve $850 million in fuel cost savings and $670 million in
operation and maintenance expense savings over ten years as a result
of the Merger. For further information, see Note 2.
See Note 8 for information on the bankruptcy proceedings of Cajun
and litigation with Cajun concerning Cajun's ownership interest in
River Bend and the related possible material adverse effects on GSU's
financial condition.
Deregulated Portion of River Bend
As of December 31, 1994, GSU had not recovered a significant
amount of its investment in, or received any return associated with,
the portion of River Bend included in the deregulated asset plan in
Louisiana and the portion of River Bend placed in abeyance as part of
the Texas rate order which went into effect in July 1988. See Note 2
for further information. Future earnings will continue to be limited
as long as the limited recovery of the investment and lack of return
continue.
For the year ended December 31, 1994, GSU recorded revenues
resulting from the sale of electricity from the deregulated asset plan
of approximately $34.1 million. Operation and maintenance expenses,
including fuel, were approximately $30 million, and depreciation
expense associated with the deregulated asset plan investment was
approximately $16.7 million for the year ended December 31, 1994. For
the year ended December 31, 1994, GSU recorded nonfuel revenue of
$32.5 million (included in the $34.1 million of total deregulated
asset plan revenue discussed above) which, absent the deregulated
asset plan, would not have been realized. The operation and
maintenance expenses and depreciation expense allocated to the
deregulated asset plan as detailed above would have been incurred at
River Bend with or without the deregulated asset plan. The future
impact of the deregulated asset plan on GSU's results of operations
and financial position will depend on River Bend's future operating
costs, the unit's efficiency and availability, and the future market
for energy over the remaining life of the unit. Based on current
estimates of the factors discussed above, GSU anticipates that future
revenues from the deregulated asset plan will fully recover all
related costs.
Property Tax Exemptions
Exemption from the payment of property taxes on River Bend, which
has been in effect for 10 years, will expire in December 1996. GSU is
working with Louisiana local taxing authorities to determine the
method for calculating the amount of the property taxes to be paid
when the exemption expires. GSU believes that any property taxes
allocated to its retail jurisdictions will be recovered from those
customers in rates.
Environmental Issues
GSU has been notified by the U. S. Environmental Protection
Agency (EPA) that it has been designated as a potentially responsible
party for the cleanup of sites on which GSU and others have or have
been alleged to have disposed of material designated as hazardous
waste. GSU is currently negotiating with the EPA and state
authorities regarding the cleanup of some of these sites. Several
class action and other suits have been filed in state and federal
courts seeking relief from GSU and others for damages caused by the
disposal of hazardous waste and for asbestos-related disease allegedly
resulting from exposure on GSU premises. While the amounts at issue
in the cleanup efforts and suits may be substantial, GSU believes that
its results of operations and financial condition will not be
materially affected by the outcome of the suits. See Note 8 for
further information.
Accounting Issues
Proposed Accounting Standards - The FASB has proposed a SFAS on
"Accounting for the Impairment of Long-Lived Assets," effective
January 1, 1996. The proposed standard describes circumstances which
may result in assets being impaired and provides criteria for
recognition and measurement of asset impairment. Note 2 describes
regulatory assets of $170 million (net of tax) related to Texas retail
deferred River Bend operating and carrying costs. Management believes
these deferred costs will be required to be written off under the
provisions of the new standard unless there are favorable regulatory
or court actions related to these costs prior to the adoption of the
new standard by GSU. Certain other operations of GSU are potentially
affected by this standard, and any resulting write-offs will depend on
future operating costs, generating units' efficiency and availability,
and the future market for energy over the remaining life of the units.
Based on current estimates, GSU anticipates that future revenues will
fully recover the costs of such operations.
Continued Application of SFAS 71 - GSU's financial statements
currently reflect, for the most part, assets and costs based on
current cost-based ratemaking regulations, in accordance with SFAS 71,
"Accounting for the Effects of Certain Types of Regulation." As
discussed above, the electric utility industry is changing and these
changes could possibly result in the discontinuance of the application
of SFAS 71, which would result in the elimination of regulatory assets
and liabilities. See Note 1 for further information.
Accounting for Decommissioning Costs - The FASB is currently
reviewing the accounting for decommissioning of nuclear plants. This
project could possibly change GSU's, as well as the entire utility
industry's, accounting for such costs. For further information, see
Note 8.
GULF STATES UTILITIES COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GSU maintains accounts in accordance with FERC and other
regulatory guidelines. Certain previously reported amounts have been
reclassified to conform to current classifications.
Revenues and Fuel Costs
Prior to January 1, 1993, GSU recognized electric and gas
revenues when billed. To provide a better matching of revenues and
expenses, effective January 1, 1993, GSU adopted a change in
accounting principle to provide for accrual of the nonfuel portion of
estimated unbilled revenues. The cumulative effect of this accounting
change as of January 1, 1993 for the Texas retail jurisdiction,
wholesale jurisdiction, and gas department increased 1993 net income
by $10.7 million, net of related income taxes of $6.9 million. Had
this new accounting method been in effect during prior years, net
income before the cumulative effect would not have been materially
different from that shown in the accompanying financial statements.
In the Louisiana retail jurisdiction, the LPSC issued a rate
order, effective March 1, 1991, which required GSU to defer the
initial effect when and if GSU changed its accounting for unbilled
revenue. The amount of unbilled revenues in the Louisiana retail
jurisdiction was $16.6 million at January 1, 1993. Because of the
LPSC rate order, GSU recorded a deferred credit of $16.6 million.
There was no cumulative effect of the change recorded in operations.
If the LPSC order were to be revised, the net income effect would be
$10.1 million, net of related income taxes of $6.5 million. Changes
in unbilled revenues in the Louisiana retail jurisdiction subsequent
to January 1, 1993 have been recorded in operations. See Note 2
regarding recent LPSC rate actions regarding the deferred unbilled
revenues.
GSU's wholesale and Louisiana retail rate schedules include fuel
adjustment clauses that allow deferral of fuel costs until such costs
are reflected in the related revenues. Although deferred fuel
accounting is also practiced in Texas, the Texas retail rate schedules
include a fixed fuel factor approved by the PUCT, which remains in
effect until changed as part of a general rate case, fuel
reconciliation, or a fixed fuel factor filing. Reconcilable fuel and
purchased power costs in excess of those included in base rates or
recovered through fuel adjustment clauses are deferred (or accrued)
until such costs are billed (or credited) to customers.
Utility Plant
Utility plant is stated at original cost. The original cost of
utility plant retired or removed, plus the applicable removal costs,
less salvage, is charged to accumulated depreciation. Maintenance,
repairs, and minor replacement costs are charged to operating
expenses. Substantially all of GSU's utility plant is subject to the
lien of its mortgage indenture.
Total GSU net electric utility plant in service of $4.50 billion
as of December 31, 1994 includes $3.22 billion of production plant,
$.44 billion of transmission plant, $.69 billion of distribution plant
and $.15 billion of other plant.
Depreciation is computed on the straight-line basis at rates
based on the estimated service lives and cost of removal of the
various classes of property. Depreciation provisions on average
depreciable property approximated 2.7% in 1994, 1993, and 1992.
AFUDC represents the approximate net composite interest cost of
borrowed funds and a reasonable return on the equity funds used for
construction. Although AFUDC increases utility plant and increases
earnings, it is only realized in cash through depreciation provisions
included in rates. GSU's AFUDC rates were as follows:
January 1, 1992 - March 31, 1992 11.75%
April 1, 1992 - March 31, 1993 10.75%
April 1, 1993 - December 31, 1993 10.50%
1994 effective composite rate 10.20%
Jointly-Owned Facilities
GSU owns undivided interests in three jointly-owned electric
generating stations and records the investment and expenses associated
with these generating stations to the extent of its ownership
interest. As of December 31, 1994, GSU's investment and accumulated
depreciation in these generating stations were as follows:
Total
Fuel Megawatt Accumulated
Generating Stations Type Capability Ownership Investment Depreciation
(In Thousands)
River Bend Unit 1 Nuclear 936 70% $3,080,019 $617,002
Roy S. Nelson Unit 6 Coal 550 70% $ 390,033 $145,897
Big Cajun 2, Unit 3 Coal 540 42% $ 219,788 $ 74,442
See Note 8 for information regarding the current status of
Cajun's 30% undivided ownership interest in River Bend.
Income Taxes
GSU, its parent, and affiliates file a consolidated federal
income tax return. Income taxes are allocated to GSU in proportion to
its contribution to the consolidated taxable income. SEC regulations
require that no Entergy Corporation subsidiary pay more taxes than it
would have had a separate income tax return been filed. Deferred
taxes are recorded for all temporary differences between book and
taxable income. Investment tax credits are deferred and amortized
based upon the average useful life of the related property in
accordance with rate treatment. As discussed in Note 3, in 1993 GSU
changed its accounting for income taxes to conform with SFAS 109.
Inventories
GSU's fuel inventories (fuel oil and natural gas) are valued at
weighted average cost.
Accounting for Power Plant Materials and Supplies
During the first quarter of 1992, accounting procedures were
changed to include in inventory, power plant materials and supplies
previously expensed or capitalized as plant in service. GSU believed
this change provided a better matching of costs with related revenues.
The change resulted from recommendations during audits by FERC and the
LPSC, in addition to a general change in industry practice. The pro
forma effect of retroactive application on any period prior to 1992
was not determinable as, prior to this change, GSU did not perform the
physical inventory counts necessary to determine inventory balances in
prior periods. The effect of the change was to increase materials and
supplies by $76.6 million, of which $41.1 million associated with
GSU's Texas and Louisiana retail jurisdictions was deferred, and to
decrease amounts previously capitalized, primarily plant in service,
by $29 million. Amounts deferred for the Louisiana retail
jurisdiction are currently being amortized to income over
approximately seven years, through February 1998, while amounts
deferred for the Texas retail jurisdiction are expected to be
amortized to income in future years. The cumulative effect of this
accounting change as of January 1, 1992, which relates to the
operations on which GSU has discontinued regulatory accounting
principles, amounted to $6.5 million before the related income tax
effect of $2.5 million.
Reacquired Debt
The premiums and costs associated with reacquired debt are
amortized over the life of the related new issuances for the portions
of the business accounted for in accordance with generally accepted
accounting principles for regulated enterprises.
During 1992, GSU extinguished over $1 billion of long-term debt
through refinancings. A loss of $81.8 million was recorded associated
with the extinguished debt of which $67.2 million of the loss was
deferred, representing the portion of GSU's operations allocable to
the Texas and Louisiana retail jurisdictions, and began to amortize
that amount over the life of the new debt sold to retire the existing
debt. A loss of $9.6 million, net of related income taxes of $5
million, was charged to income in 1992 as an extraordinary item.
Further, refinancings of long-term debt during 1993 resulted in an
extraordinary loss of $1.3 million, net of $.7 million of related
taxes.
Cash and Cash Equivalents
GSU considers all unrestricted highly liquid debt instruments
purchased with an original maturity of three months or less to be cash
equivalents.
Continued Application of SFAS 71
As a result of the EPAct and actions of regulatory commissions,
the electric utility industry is moving toward a combination of
competition and a modified regulatory environment. GSU's financial
statements, for the most part, currently reflect assets and costs
based on current cost-based ratemaking regulations, in accordance with
SFAS. 71, "Accounting for the Effects of Certain Types of Regulation."
Continued applicability of SFAS 71 to GSU's financial statements
requires that rates set by an independent regulator on a cost of
service basis (including a reasonable rate of return on invested
capital) can actually be charged to and collected from customers.
In the event that either all or a portion of a utility's
operations cease to meet those criteria for various reasons, including
deregulation, a change in the method of regulation, or a change in the
competitive environment for the utility's regulated services, the
utility should discontinue application of SFAS 71 for the relevant
portion. That discontinuation should be reported by elimination from
the balance sheet of the effects of any actions of regulators
recorded as regulatory assets and liabilities.
As of December 31, 1994, and for the foreseeable future, GSU's
financial statements continue to follow SFAS 71, with the exceptions
noted below.
SFAS 101
SFAS 101, "Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement No. 71," specifies
how an enterprise that ceases to meet the criteria for application of
SFAS 71, to all or part of its operations should report that event in
its financial statements. GSU discontinued regulatory accounting
principles for its wholesale jurisdiction and steam department, and
the Louisiana deregulated portion of River Bend, during 1989 and 1991,
respectively.
Fair Value Disclosure
The estimated fair value of financial instruments has been
determined by GSU using available market information and appropriate
valuation methodologies. However, considerable judgment is required
in developing the estimates of fair value. Therefore, estimates are
not necessarily indicative of the amounts that GSU could realize in a
current market exchange. In addition, gains or losses realized on
financial instruments may be reflected in future rates and not accrue
to the benefit of stockholders.
GSU considers the carrying amounts of financial instruments
classified as current assets and liabilities to be a reasonable
estimate of their fair value because of the short maturity of these
instruments. See Notes 5, 6, and 8 for additional fair value
disclosure.
The System adopted the provisions of SFAS 115, "Accounting for
Certain Investments in Debt and Equity Securities," effective January
1, 1994. As a result, as of December 31, 1994, GSU recorded on the
balance sheet an additional reduction of $0.9 million in
decommissioning trust funds, representing the amount by which the fair
value of the securities held in such funds exceeds the amounts
recovered in rates for decommissioning and deposited in the funds and
the related earnings on the amounts deposited. Due to the regulatory
treatment for decommissioning trust funds, the System recorded an
offsetting amount in unrealized losses on investment securities as a
regulatory asset.
NOTE 2. RATE AND REGULATORY MATTERS
River Bend
In May 1988, the PUCT granted GSU a permanent increase in annual
revenues of $59.9 million resulting from the inclusion in rate base of
approximately $1.6 billion of company-wide River Bend plant investment
and approximately $182 million of related Texas retail jurisdiction
deferred River Bend costs (Allowed Deferrals). In addition, the PUCT
disallowed as imprudent $63.5 million of company-wide River Bend plant
costs and placed in abeyance, with no finding of prudence,
approximately $1.4 billion of company-wide River Bend plant investment
and approximately $157 million of Texas retail jurisdiction deferred
River Bend operating and carrying costs. The PUCT affirmed that the
ultimate rate treatment of such amounts would be subject to future
demonstration of the prudence of such costs. GSU and intervening
parties appealed this order (Rate Appeal) and GSU filed a separate
rate case asking that the abeyed River Bend plant costs be found
prudent (Separate Rate Case). Intervening parties filed suit in a
Texas district court to prohibit the Separate Rate Case. The district
court's decision was ultimately appealed to the Texas Supreme Court,
which ruled in 1990 that the prudence of the purported abeyed costs
could not be relitigated in a separate rate proceeding. The Texas
Supreme Court's decision stated that all issues relating to the merits
of the original PUCT order, including the prudence of all River Bend-
related costs, should be addressed in the Rate Appeal.
In October 1991, the Texas district court in the Rate Appeal
issued an order holding that, while it was clear the PUCT made an
error in assuming it could set aside $1.4 billion of the total costs
of River Bend and consider them in a later proceeding, the PUCT,
nevertheless, found that GSU had not met its burden of proof related
to the amounts placed in abeyance. The court also ruled that the
Allowed Deferrals should not be included in rate base. The court
further stated that the PUCT had erred in reducing GSU's deferred
costs by $1.50 for each $1.00 of revenue collected under the interim
rate increases authorized in 1987 and 1988. The court remanded the
case to the PUCT with instructions as to the proper handling of the
Allowed Deferrals. GSU's motion for rehearing was denied and, in
December 1991, GSU filed an appeal of the October 1991 district court
order. The PUCT also appealed the October 1991 district court order,
which served to supersede the district court's judgment, rendering it
unenforceable under Texas law.
In August 1994, the Texas Third District Court of Appeals (the
Appellate Court) affirmed the district court's decision that there was
substantial evidence to support the PUCT's 1988 decision not to
include the abeyed construction costs in GSU's rate base. While
acknowledging that the PUCT had exceeded its authority when it
attempted to defer a decision on the inclusion of those costs in rate
base in order to allow GSU a further opportunity to demonstrate the
prudence of those costs in a subsequent proceeding, the Appellate
Court found that GSU had suffered no harm or lack of due process as a
result of the PUCT's error. Accordingly, the Appellate Court held
that the PUCT's action had the effect of disallowing the company-wide
$1.4 billion of River Bend construction costs for ratemaking purposes.
In its August 1994 opinion, the Appellate Court also held that GSU's
deferred operating and maintenance costs associated with the allowed
portion of River Bend should be included in rate base and that GSU's
deferred River Bend carrying costs included in the Allowed Deferrals
should also be included in rate base. The Appellate Court's August
1994 opinion affirmed the PUCT's original order in this case.
The Appellate Court's August 1994 opinion was entered by two
judges, with a third judge dissenting. The dissenting opinion states
that the result of the majority opinion is, among other things, to
deprive GSU of due process at the PUCT because the PUCT never reached
a finding on the $1.4 billion of construction costs.
In October 1994, the Appellate Court denied GSU's motion for
rehearing on the August 1994 opinion as to the $1.4 billion in River
Bend construction costs and other matters. GSU appealed the Appellate
Court's decision to the Texas Supreme Court, where it is pending.
As of December 31, 1994, the River Bend plant costs disallowed
for retail ratemaking purposes in Texas, the River Bend plant costs
held in abeyance, and the related operating and carrying cost
deferrals totaled (net of taxes) approximately $13 million, $280
million (both net of depreciation), and $170 million, respectively.
Allowed Deferrals were approximately $107 million, net of taxes and
amortization, as of December 31, 1994. GSU estimates it has collected
approximately $158 million of revenues as of December 31, 1994, as a
result of the originally ordered rate treatment by the PUCT of these
deferred costs. If recovery of the Allowed Deferrals is not upheld,
future revenues based upon those allowed deferrals could also be lost,
and no assurance can be given as to whether or not refunds of revenue
received based upon such deferred costs previously recorded will be
required.
No assurance can be given as to the timing or outcome of the
remands or appeals described above. Pending further developments in
these cases, GSU has made no write-offs or reserves for the River Bend-
related costs. Management believes, based on advice from Clark,
Thomas & Winters, a Professional Corporation, legal counsel of record
in the Rate Appeal, that it is reasonably possible that the case will
be remanded to the PUCT, and the PUCT will be allowed to rule on the
prudence of the abeyed River Bend plant costs. Rate Caps imposed by
the PUCT's regulatory approval of the Merger could result in GSU being
unable to use the full amount of a favorable decision to immediately
increase rates; however, a favorable decision could permit some
increases and/or limit or prevent decreases during the period the Rate
Caps are in effect. At this time, management and legal counsel are
unable to predict the amount, if any, of the abeyed and previously
disallowed River Bend plant costs that ultimately may be disallowed by
the PUCT. A net of tax write-off as of December 31, 1994, of up to
$293 million could be required based on an ultimate adverse ruling by
the PUCT on the abeyed and disallowed costs.
In prior proceedings, the PUCT has held that the original cost of
nuclear power plants will be included in rates to the extent those
costs were prudently incurred. Based upon the PUCT's prior decisions,
management believes that its River Bend construction costs were
prudently incurred and that it is reasonably possible that it will
recover in rate base, or otherwise through means such as a deregulated
asset plan, all or substantially all of the abeyed River Bend plant
costs. However, management also recognizes that it is reasonably
possible that not all of the abeyed River Bend plant costs may
ultimately be recovered.
As part of its direct case in the Separate Rate Case, GSU filed a
cost reconciliation study prepared by Sandlin Associates, management
consultants with expertise in the cost analysis of nuclear power
plants, which supports the reasonableness of the River Bend costs held
in abeyance by the PUCT. This reconciliation study determined that
approximately 82% of the River Bend cost increase above the amount
included by the PUCT in rate base was a result of changes in federal
nuclear safety requirements and provided other support for the
remainder of the abeyed amounts.
There have been four other rate proceedings in Texas involving
nuclear power plants. Investment in the plants ultimately disallowed
ranged from 0% to 15%. Each case was unique, and the disallowances in
each were made on a case-by-case basis for different reasons. Appeals
of two of these PUCT decisions are currently pending.
The following factors support management's position that a loss
contingency requiring accrual has not occurred, and its belief that
all, or substantially all, of the abeyed plant costs will ultimately
be recovered:
1. The $1.4 billion of abeyed River Bend plant costs have never
been ruled imprudent and disallowed by the PUCT.
2. Sandlin Associates' analysis which supports the prudence of
substantially all of the abeyed construction costs.
3. Historical inclusion by the PUCT of prudent construction
costs in rate base.
4. The analysis of GSU's internal legal staff, which has
considerable experience in Texas rate case litigation.
Additionally, management believes, based on advice from Clark,
Thomas & Winters, a Professional Corporation, legal counsel of record
in the Rate Appeal, that it is reasonably possible that the Allowed
Deferrals will continue to be recovered in rates. Management also
believes, based on advice from Clark, Thomas & Winters, a Professional
Corporation, legal counsel of record in the Rate Appeal, that it is
reasonably possible that the deferred costs related to the $1.4
billion of abeyed River Bend plant costs will be recovered in rates to
the extent that the $1.4 billion of abeyed River Bend plant is
recovered. However, a net of tax write-off of the $170 million of
deferred costs related to the $1.4 billion of abeyed River Bend plant
costs would be required if they are not allowed to be recovered in
rates.
A proposed accounting standard, "Accounting for the Impairment of
Long-Lived Assets," which is expected to become effective January 1,
1996, may require the write-off of the $170 million of rate deferrals
discussed above, upon adoption of the standard unless there are
favorable regulatory or court actions related to these costs prior to
adoption.
Merger-Related Rate Agreements
In November 1993, Entergy Corporation, AP&L, MP&L, and NOPSI
entered into separate settlement agreements whereby the APSC, MPSC,
and Council agreed to withdraw from the SEC proceeding related to the
Merger. In return AP&L, MP&L, and NOPSI agreed, among other things,
that their retail ratepayers would be protected from (1) increases in
the cost of capital resulting from risks associated with the Merger,
(2) recovery of any portion of the acquisition premium or
transactional costs associated with the Merger, (3) certain direct
allocations of costs associated with GSU's River Bend nuclear unit,
and (4) any losses of GSU resulting from resolution of litigation in
connection with its ownership of River Bend.
The LPSC and the PUCT approved separate regulatory proposals that
include the following elements: (1) a five-year Rate Cap on GSU's
retail electric base rates in the respective states, except for force
majeure (defined to include, among other things, war, natural
catastrophes, and high inflation); (2) a provision for passing through
to retail customers in the respective states the jurisdictional
portion of the fuel savings created by the Merger; and (3) a mechanism
for tracking nonfuel operation and maintenance savings created by the
Merger. The LPSC regulatory plan provides that such nonfuel savings
will be shared 60% by the shareholder and 40% by ratepayers during the
eight years following the Merger. The LPSC plan requires regulatory
filings each year by the end of May through 2001. The PUCT regulatory
plan provides that such savings will be shared equally by the
shareholder and ratepayers, except that the shareholder's portion will
be reduced by $2.6 million per year on a total company basis in years
four through eight. The PUCT plan also requires a series of future
regulatory filings in November 1996, 1998, and 2001, to ensure that
ratepayers' share of such savings be reflected in rates on a timely
basis and requires Entergy Corporation to hold GSU's Texas retail
customers harmless from the effects of the removal by FERC of a 40%
cap on the amount of fuel savings GSU may be required to transfer to
other System operating companies under the FERC tracking mechanism
(see below). On January 14, 1994, Entergy Corporation filed a request
for rehearing of FERC's December 15, 1993, order approving the Merger
requesting that FERC restore the 40% cap provision in the fuel cost
protection mechanism. The matter is pending.
FERC approved certain rate schedule changes to integrate GSU into
the System Agreement. Certain commitments were adopted to provide
reasonable assurance that the ratepayers of AP&L, LP&L, MP&L, and
NOPSI will not be allocated higher costs, including, among other
things, (1) a tracking mechanism to protect AP&L, LP&L, MP&L, and
NOPSI from certain unexpected increases in fuel costs, (2) the
distribution of profits from power sales contracts entered into prior
to the Merger, (3) a methodology to estimate the cost of capital in
future FERC proceedings, and (4) a stipulation that AP&L, LP&L, MP&L,
and NOPSI will be insulated from certain direct effects on capacity
equalization payments should GSU acquire Cajun's 30% share in River
Bend (see Note 8).
Filings with the PUCT and Texas Cities
In March 1994, the Texas Office of Public Utility Counsel and
certain cities served by GSU instituted an investigation of the
reasonableness of GSU's rates. In June 1994, GSU provided the cities
with information that GSU believed supported the current rate level.
GSU filed the same information with the PUCT in June 1994, pursuant to
provisions of the Merger. In September 1994, the various cities
adopted ordinances directing GSU to reduce its Texas retail rates by
$45.9 million. GSU appealed the cities' ordinances to the PUCT for a
determination of reasonableness of GSU's rates.
In November 1994, those cities that intervened in the PUCT appeal
filed testimony with the PUCT supporting a $118 million base rate
reduction in lieu of the previously proposed $45.9 million reduction.
In November 1994, the PUCT staff filed testimony that supported a
$38.2 million base rate reduction. GSU filed information with the
PUCT that it believed supported the current level of rates. Hearings
were held in December 1994 and on March 20, 1995, the PUCT ordered a
$72.9 million annual base rate reduction for the period March 31,
1994, through September 1, 1994, decreasing to an annual base rate
reduction of $52.9 million after September 1, 1994. In accordance
with the Merger agreement, the rate reduction is applied retroactively
to March 31, 1994. As a result, GSU recorded in 1994 a $57 million
reserve for rate refund and a $12.8 million reserve for franchise
taxes to be refunded. These charges reduced net income after tax by
$41.6 million. The rate reduction is being appealed and no assurance
can be given as to the timing or outcome of the appeal.
Texas Cities Rate Settlement - 1993
In June 1993, 13 cities within GSU's Texas service area
instituted an investigation to determine whether GSU's current rates
were justified. In October 1993, the general counsel of the PUCT
instituted an inquiry into the reasonableness of GSU's rates. In
November 1993, a settlement agreement was filed with the PUCT which
provided for an initial reduction in GSU's annual retail base revenues
in Texas of approximately $22.5 million effective for electric usage
on or after November 1, 1993, and a second reduction of $20 million
effective September 1994. Pursuant to the settlement, GSU reduced
rates with a $20 million one-time bill credit in December 1993, and
refunded approximately $3 million to Texas retail customers on bills
rendered in December 1993. The PUCT approved the settlement agreement
on July 21, 1994. The cities' rate inquiries were settled earlier on
the same terms.
LPSC Rate Order - 1994
In May 1994, GSU made the required first post-Merger earnings
analysis filing with the LPSC. On December 14, 1994, the LPSC ordered
a $12.7 million annual rate reduction for GSU effective January 1995.
The rate order included, among other things, a reduction in GSU's
Louisiana jurisdictional authorized return on equity from 12.75% to
10.95% and the amortization for the benefit of the customers of $8.3
million of previously deferred unbilled revenue, representing one-half
of the total resulting from a change in accounting discussed in Note
1. On December 28, 1994, GSU received a preliminary injunction from
the 19th Judicial District Court regarding $8.3 million of the
reduction. On January 1, 1995, GSU reduced rates by $4.4 million.
The entire $12.7 million reduction is being appealed and no assurance
can be given as to the timing or outcome of the appeal.
PUCT Fuel Cost Review (December 1, 1986 - September 30, 1991)
In January 1992, GSU applied to the PUCT for a new fixed fuel
factor and requested a final reconciliation of fuel and purchased
power costs incurred between December 1, 1986 and September 30, 1991.
GSU proposed to recover net underrecoveries and interest (including
underrecoveries related to Nelson Industrial Steam Company (NISCO),
discussed below) over a twelve-month period.
In April 1993, the presiding PUCT administrative law judge (ALJ)
issued a report concluding that GSU incurred approximately
$117 million of nonreimbursable fuel costs on a company-wide basis
(approximately $50 million on a Texas retail jurisdictional basis)
during the reconciliation period. Included in the nonreimbursable
fuel costs were payments above GSU's avoided cost rate for power
purchased from NISCO. The PUCT ordered in 1986 that the purchased
power costs from NISCO in excess of GSU's avoided costs be disallowed.
The PUCT disallowance resulted in approximately $12 million to
$15 million of unrecovered purchased power costs on an annual basis,
which GSU continued to expense as the costs were incurred. In April
1991, the Texas Supreme Court, in the appeal of such order, ordered
the PUCT to allow GSU to recover purchased power payments in excess of
its avoided cost in future proceedings, if GSU established to the
PUCT's satisfaction that the payments were reasonable and necessary
expenses.
In June 1993, the PUCT concluded that the purchased power
payments made to NISCO in excess of GSU's avoided cost were not
reasonably incurred. As a result of the order, GSU recorded
additional fuel expenses (including interest) of $2.8 million for non-
NISCO related items. The PUCT's order resulted in no additional
expenses related to the NISCO issue, or for overcollections related to
the fixed fuel factor, as those charges were expensed by GSU as they
were incurred. The PUCT concluded that GSU had over-collected its
fuel costs in Texas and ordered GSU to refund approximately $33.8
million to its Texas retail customers, including approximately $7.5
million of interest. In that proceeding, the PUCT also set GSU's
fixed fuel factor in Texas at 1.84 cents per KWH in response to GSU's
request that the factor be set at 2.02 cents per KWH. In October
1993, GSU appealed the PUCT's order to the Travis County District
Court where the matter is still pending. No assurance can be given as
to the timing or outcome of that appeal. In a subsequent proceeding
to review GSU's fuel factor, the PUCT approved GSU's request to
further reduce its fixed fuel factor in Texas to 1.78 cents per KWH
from 1.84 cents per KWH.
PUCT Fuel Cost Review (October 1, 1991 - December 31, 1993)
On January 9, 1995, GSU and various parties reached an agreement
for the reconciliation of over- and under-recovery of fuel and
purchased power expenses for the period October 1, 1991, through
December 31, 1993. While the settlement still requires PUCT approval,
GSU believes it will ultimately be approved and has accordingly
recorded a reserve of $7.6 million.
LPSC Fuel Cost Review
In November 1993, the LPSC ordered a review of GSU's fuel costs
for the period October 1988 through September 1991 (Phase 1) based on
the number of outages at River Bend and the findings in the June 1993
PUCT fuel reconciliation case. In July 1994, the LPSC ruled in the
Phase 1 fuel review case and ordered GSU to refund approximately $27
million to its customers. Under the order, a refund of $13.1 million,
which was not contested under a Louisiana Supreme Court decision as
discussed below, was made through a billing credit on August 1994
bills. In August 1994, GSU appealed the remaining portion of the LPSC
ordered refund to the district court. GSU has made no reserve for the
remaining portion, pending outcome of the district court appeal, and
no assurance can be given as to the timing or outcome of the appeal.
On January 18, 1995, GSU met with the Special Counsel of the LPSC
to discuss the procedural schedule for the upcoming fuel review (Phase
II). The period under investigation was determined to be from October
1991 to December 1994. Hearings are scheduled to begin in July 1995.
In February 1990, the LPSC disallowed the pass-through to
ratepayers for the portion of GSU's cost to purchase power from NISCO
representing the excess of NISCO's purchase price of the units over
GSU's depreciated cost of the units. GSU appealed the 1990 order. In
March 1994, the Louisiana Supreme Court ruled in favor of the LPSC.
GSU recorded an estimated refund provision of $13.1 million, before
related income taxes of $5.3 million.
Deregulated Asset Plan
A deregulated asset plan representing an unregulated portion
(approximately 22%) of River Bend (plant costs, generation, revenues,
and expenses) was established pursuant to a January 1992 LPSC order.
The plan allows GSU to sell such generation to Louisiana retail
customers at 4.6 cents per KWH or off-system at higher prices with
certain sharing provisions for such incremental revenue.
River Bend Cost Deferrals
GSU deferred approximately $369 million of River Bend operating
costs, purchased power costs, and accrued carrying charges pursuant to
a 1986 PUCT accounting order. Approximately $182 million of these
costs are being amortized over a 20-year period, and the remaining
$187 million are not being amortized pending the ultimate outcome of
the Rate Appeal. As of December 31, 1994, the unamortized balance of
these costs was $321 million. Further, GSU deferred approximately
$400.4 million of similar costs pursuant to a 1986 LPSC accounting
order. These costs, of which approximately $122 million are
unamortized as of December 31, 1994, are being amortized over a 10-
year period ending in 1997.
In accordance with a phase-in plan approved by the LPSC, GSU
deferred $294 million of its River Bend costs related to the period
February 1988 through February 1991. GSU has amortized $129 million
through December 31, 1994, and the remainder of $165 million will be
recovered over approximately 3.2 years.
NOTE 3. INCOME TAXES
(1) Income tax expense (benefit) consisted of the following:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Current
Federal $ 71 $16,714 $ 5,621
State 14 - -
-------- ------- -------
Total 85 16,714 5,621
-------- ------- -------
Deferred - net
Liberalized depreciation 21,560 37,951 24,287
Nuclear unit cancellation costs, net of amortization (2,111) (2,930) (3,107)
Fuel and purchased power costs (accrued) 8,266 7,689 (669)
Expenses deferred for tax purposes (33,358) 3,449
(12,387)
Tax net operating loss carryforward 56,736 (8,357) 12,349
Rate deferrals - net (37,477) (24,458) (21,238)
Unbilled revenues (2,093) 4,999 2,889
Income deferred for book purposes (1,845) (2,102) 2,328
Louisiana provision for rate refund - 3,793 4,416
Texas provision for rate refund (23,034) - -
Alternative minimum tax 118 (22,183) (8,197)
Loss on debt extinguishment, net of amortization (2,215) 1,398 22,314
Purchased power settlement - 66,753 6,562
Write-off of plant held for future use (29,572) - -
Other (12,886) (3,689) 4,590
-------- ------- -------
Total (57,911) 46,477 49,973
-------- ------- -------
Investment tax credit adjustments - net (4,260) 1,093 (2,200)
-------- ------- -------
Recorded income tax expense $(62,086) $64,284 $53,394
======== ======= =======
Charged to operations $(6,448) $46,007 $38,058
Charged to other income (55,638) 12,009 17,801
Charged to extraordinary items - (671) (4,943)
Charged to cumulative effect of accounting changes - 6,939 2,478
-------- ------- -------
Total income taxes $(62,086) $64,284 $53,394
======== ======= =======
Income taxes differ from the amounts computed by applying the statutory
federal income tax rate to income before taxes. The reasons for these
differences were:
For the Years Ended December 31,
1994 1993 1992 (1)
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
(Dollars in Thousands)
Computed at statutory rate $(50,694) (35.0) $50,101 35.0 $63,662 34.0
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect (6,571) (4.5) 1,332 0.9 3,573 1.9
Rate deferrals - net 6,551 4.5 6,193 4.3 5,439 2.9
Depreciation (8,188) (5.7) (11,343) (7.9) (15,479) (8.3)
Impact of change in tax rate - - 5,179 3.6 - -
Book expenses not deducted for tax 151 0.1 15,134 10.6 142 0.1
Amortization of investment tax credits (4,472) (3.1) (4,435) (3.1) (4,356) (2.3)
Other - net 1,137 0.8 2,123 1.5 413 0.2
-------- ----- ------- ---- ------- ----
Total income taxes $(62,086) (42.9) $64,284 44.9 $53,394 28.5
======== ===== ======= ==== ======= ====
Significant components of net deferred tax liabilities, as of
December 31, 1994 and 1993, were (in thousands):
1994 1993
Deferred tax liabilities:
Net regulatory assets $ (494,443) $ (529,706)
Plant related basis differences (1,065,053) (1,023,446)
Rate deferrals - net (132,213) (169,689)
Debt reacquisition loss (21,922) (24,140)
Other (1,241) (25,871)
----------- -----------
Total $(1,714,872) $(1,772,852)
=========== ===========
Deferred tax assets:
Net operating loss carryforwards $ 251,000 $ 307,737
Investment tax credit carryforward 173,852 176,032
Valuation allowance-investment tax credit carryforward (64,407) (15,213)
Unbilled revenue 14,336 12,243
Plant related basis differences 23,796 25,007
Alternative minimum tax credit 39,743 39,860
Texas provision for rate refund 23,034 -
Other 202,579 164,135
----------- ----------
Total $ 663,933 $ 709,801
----------- -----------
Net deferred tax liability $(1,050,939) $(1,063,051)
=========== ===========
As of December 31, 1994, for tax purposes, GSU had federal tax
loss carryforwards of approximately $666.7 million, state tax loss
carryforward of approximately $498.2 million, and investment tax (ITC)
and other credit carryforwards of approximately $176.4 million which
will be used to reduce income tax payments in future years and, if not
used, will expire through the year 2008. It is currently anticipated
that approximately $64.4 million of ITC carryforwards will expire
unutilized as a result of limitations arising from the Merger. A
valuation allowance has been provided for deferred tax assets relating
to that amount. The alternative minimum tax credit, which can be
carried forward indefinitely to reduce GSU's future federal income tax
liability, was $40.6 million as of December 31, 1994.
In 1993, GSU adopted SFAS 109. SFAS 109 required that deferred
income taxes be recorded for all temporary differences and
carryforwards, and that deferred tax balances be based on enacted tax
laws at tax rates that are expected to be in effect when the temporary
differences reverse. SFAS 109 required that regulated enterprises
recognize adjustments resulting from its implementation as regulatory
assets or liabilities if it is probable that such amounts will be
recovered from or returned to customers in future rates. A
substantial majority of the adjustments required by SFAS 109 were
recorded to deferred tax balance sheet accounts with offsetting
adjustments to regulatory assets and liabilities. GSU recorded the
adoption of SFAS 109 by restating 1990, 1991, and 1992 financial
statements and including a charge of $96.5 million for the cumulative
effect of the adoption of SFAS 109 in 1990 primarily for that portion
of the operations on which GSU has discontinued regulatory accounting
principles.
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized GSU to effect short-term borrowings up to
$125 million, which may be increased to as much as $395 million after
further SEC approval. This authorization is effective through
November 30, 1996. As of December 31, 1994, GSU had unused lines of
credit for short-term borrowings of $5 million. Interest rates
associated with these lines of credit generally are based on the prime
rate, the EURO dollar rate, or a certificate of deposit rate.
Commitment fees on these lines of credit are .125% of the amount of
available credit. In addition, GSU can borrow from the Money Pool,
subject to its maximum authorized level of short-term borrowings and
the availability of funds. GSU had no outstanding borrowings under
the Money Pool arrangement as of December 31, 1994.
NOTE 5. PREFERRED, PREFERENCE, AND COMMON STOCK
The number of shares and dollar value of GSU's preferred and preference
stock were:
Call Price
As of December 31 Per Share as
Shares Outstanding Total Dollar Value of December
1994 1993 1994 1993 31, 1994
(Dollars in Thousands)
Preference Stock
Authorized 20,000,000 shares, without
par value, cumulative
7% Series (2) 6,000,000 6,000,000 $150,000 $150,000 (1)
========= ========= ======== ========
Preferred Stock
Authorized 6,000,000 shares, $100 par
value, cumulative
Without sinking fund:
4.40% Series 51,173 51,173 $ 5,117 $ 5,117 $108.00
4.50% Series 5,830 5,830 583 583 $105.00
4.40% - 1949 Series 1,655 1,655 166 166 $103.00
4.20% Series 9,745 9,745 975 975 $102.82
4.44% Series 14,804 14,804 1,480 1,480 $103.75
5.00% Series 10,993 10,993 1,099 1,099 $104.25
5.08% Series 26,845 26,845 2,685 2,685 $104.63
4.52% Series 10,564 10,564 1,056 1,056 $103.57
6.08% Series 32,829 32,829 3,283 3,283 $103.34
7.56% Series 350,000 350,000 35,000 35,000 $101.80
8.52% Series 500,000 500,000 50,000 50,000 $102.43
9.96% Series 350,000 350,000 35,000 35,000 $102.64
--------- --------- --------- --------
Total without sinking fund 1,364,438 1,364,438 $ 136,444 $136,444
========= ========= ========= ========
With sinking fund:
8.80% Series 226,807 237,963 $ 22,680 $ 23,796 $100.00
9.75% Series 21,565 22,576 2,154 2,258 $100.00
8.64% Series 182,000 196,000 18,200 19,600 $101.00
Adjustable Rate Series A, 7.10% (3) 204,000 216,000 20,400 21,600 $100.00
Adjustable Rate Series B, 7.15% (3) 315,000 337,500 31,500 33,750 $100.00
--------- --------- --------- --------
Total with sinking fund 949,372 1,010,039 $ 94,934 $101,004
========= ========= ========= ========
(1)This series is not redeemable as of December 31, 1994.
(2)The total dollar value represents the involuntary liquidation
value of $25 per share.
(3)Rates are as of December 31, 1994.
The fair value of GSU's preferred and preference stock with
sinking fund was estimated to be approximately $227.8 million and $255
million as of December 31, 1994 and 1993, respectively. The fair
values were determined using quoted market prices or estimates from
nationally recognized investment banking firms. See Note 1 for
additional information on disclosure of fair value of financial
instruments.
Changes in the common stock, preference stock, and preferred
stock during the last three years were:
Number of Shares
1994 1993 1992
Common stock issuances - 100 -
Common stock retirements with Merger closing - (114,055,065) -
Preference stock issuances - 6,000,000 -
Preference stock retirements - - (4,000,000)
Preferred stock with sinking fund retirements (60,667) (1,683,834) (559,257)
Minimum cash sinking fund requirements for preferred stock with
sinking funds are $6.1 million for each of the years 1995-1999.
Limitations based on the ratio of after-tax earnings to fixed charges
and preferred dividends are imposed by GSU's Restated Articles of
Incorporation (Articles) upon the issuance of additional preferred
stock. Based upon the results of operations for the year ended
December 31, 1994, GSU is unable to issue any additional preferred
stock.
NOTE 6. LONG-TERM DEBT
GSU's long-term debt as of December 31, 1994 and 1993, was as
follows:
Maturities Interest Rates December 31
From To From To 1994 1993
(In Thousands)
First Mortgage Bonds
1996 1999 5% 7.35% $ 445,000 $ 345,000
2000 2004 6.41% 8-1/2% 670,000 470,000
2005 2009 6.77% 8-7/8% 120,000 420,000
2023 2024 8.70% 8.94% 450,000 450,000
Governmental and Industrial Development Bonds
2006 2024 5.9% 12% 482,460 482,885
Debentures - Due 1998, 9.72% 200,000 200,000
Other long-term debt 6,879 6,879
Unamortized premium and discount - net (5,497) (5,700)
---------- ----------
Total long-term debt 2,368,842 2,369,064
Less amount due within one year 50,425 425
---------- ----------
Long-term debt excluding amount due within one year $2,318,417 $2,368,639
========== ==========
The fair value of GSU's long-term debt as of December 31, 1994
and 1993 was estimated to be $2,277.3 million and $2,548.1 million,
respectively. Fair values were determined using bid prices reported
by dealer markets and by nationally recognized investment banking
firms. See Note 1 for additional information on disclosure of fair
value of financial instruments.
For the years 1995, 1996, 1997, 1998, and 1999, GSU has long-term
debt maturities and cash sinking fund requirements of (in millions)
$50.4, $145.4, $160.9, $190.9 and $100.9, respectively. In addition,
other sinking fund requirements for the years 1995, 1996, 1997, 1998,
and 1999 of (in millions) $16.7, $16.5, $15.2, $13.5, and $12.3,
respectively, may be satisfied by cash or by certification of
property additions at a rate of 167% of such requirements.
GSU has two outstanding series of pollution control bonds which
are collateralized by irrevocable letters of credit which are
scheduled to expire before the scheduled maturity of the bonds. The
letter of credit collateralizing the $28.4 million variable rate
series due December 1, 2015, expires in September 1996 and the letter
of credit collateralizing the $20 million variable rate series due
April 1, 2016, expires in April 1996. GSU plans to refinance these
series or renew the letters of credit.
NOTE 7. DIVIDEND RESTRICTIONS
Certain limitations on the payment of cash dividends on common
stock are contained in the Articles, Mortgage Indenture, and
applicable state and federal law. As of December 31, 1994, none of
GSU's retained earnings were restricted against the payment of cash
dividends or other distributions on common stock.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Financial Condition
Although GSU received partial rate relief relating to River Bend,
GSU's financial position was strained from 1986 to 1990 by its
inability to earn a return on and fully recover its investment and
other costs associated with River Bend. Issues to be finally resolved
in PUCT rate proceedings and appeals thereof, as discussed in Note 2,
combined with certain significant business relationships (discussed
below) and the application of accounting standards, may result in
substantial write-offs and charges that could result in substantial
net losses being reported in 1995, and subsequent periods, with
resulting substantial adverse adjustments to common shareholder's
equity. Future earnings will continue to be adversely affected by the
lack of full recovery and return on the investment and other costs
associated with River Bend.
Cajun - River Bend
GSU has significant business relationships with Cajun, including
co-ownership of River Bend and Big Cajun 2, Unit 3. GSU and Cajun own
70% and 30% undivided interests in River Bend, respectively, and 42%
and 58% undivided interests in Big Cajun 2, Unit 3, respectively.
In June 1989, Cajun filed a civil action against GSU in the
United States District Court for the Middle District of Louisiana
(District Court). Cajun's complaint seeks to annul, rescind,
terminate, and/or dissolve the Joint Ownership Participation and
Operating Agreement entered into on August 28, 1979 (Operating
Agreement) relating to River Bend. Cajun alleges fraud and error by
GSU, breach of its fiduciary duties owed to Cajun, and/or GSU's
repudiation, renunciation, abandonment, or dissolution of its core
obligations under the Operating Agreement, as well as the lack or
failure of cause and/or consideration for Cajun's performance under
the Operating Agreement. The suit seeks also to recover Cajun's
alleged $1.6 billion investment in the unit as damages, plus
attorneys' fees, interest, and costs. Two member cooperatives of
Cajun have brought an independent action to declare the Operating
Agreement void, based upon failure to get prior LPSC approval alleged
to be necessary. GSU believes the suits are without merit and is
contesting them vigorously.
A trial without jury on the portion of the suit by Cajun to
rescind the Operating Agreement which began in April 1994 has been
completed, and an order from the District Court is pending. No
assurance can be given as to the outcome of this litigation. If GSU
were ultimately unsuccessful in this litigation and were required to
make substantial payments, GSU would probably be unable to make such
payments and would probably have to seek relief from its creditors
under the United States Bankruptcy Code. If GSU prevails in this
litigation, there can be no assurance that the Bankruptcy Court will
allow funding of all required costs of Cajun's ownership in River
Bend.
Since 1992 Cajun has not paid its full share of operating and
maintenance expenses and other costs for repairs and improvements to
River Bend. In addition, certain costs and expenses paid by Cajun
were paid under protest. These actions were taken by Cajun based on
its contention, which GSU disagrees, that River Bend's operating and
maintenance expenses were excessive.
In a letter dated October 21, 1994, and at a subsequent meeting,
Cajun representatives advised Entergy Corporation and GSU that, on
October 25, 1994, Cajun would exhaust its 1994 budget for operating
and maintenance expenses for River Bend, and did not make any further
payments to GSU in 1994 for River Bend operating, maintenance or
capital costs. Cajun also advised that the RUS (which provided
funding to Cajun for its investment in River Bend) would not permit
Cajun to budget funds in 1995 to pay its share of operating and
maintenance expenses or capital costs for River Bend. However, Cajun
stated that it would continue to fund its share of the nuclear
decommissioning trust payments for River Bend, as well as insurance
and safety-related expenses. The unpaid portion of Cajun's River Bend
operating, maintenance, and capital costs for 1994 (which has been
fully reserved) was approximately $22.4 million. Cajun's total share
of River Bend annual operating (including nuclear fuel) and
maintenance expenses and capital costs was approximately $76.1 million
in 1994.
In view of Cajun's stated expectation that it will fund only a
limited portion of its share of River Bend related operating,
maintenance, and capital costs, GSU notified Cajun that it would (i)
credit GSU's share of expenses for Big Cajun 2, Unit 3 against amounts
due from Cajun to GSU and (ii) seek to market Cajun's share of the
power from River Bend and apply the proceeds to the amounts due from
Cajun to GSU. On November 2, 1994, Cajun discontinued GSU's
entitlement of energy from Big Cajun 2, Unit 3. In response, on
November 3, 1994, GSU filed pleadings in District Court seeking an
order requiring Cajun to provide GSU with the energy from Big Cajun 2,
Unit 3 to which GSU is entitled, and holding that GSU is entitled to
credit amounts due from GSU to Cajun for Big Cajun 2, Unit 3 against
amounts due from Cajun to GSU with respect to River Bend. On December
19, 1994, the District Court issued an injunction prohibiting Cajun
from denying its share of energy from Big Cajun 2, Unit 3 and
stipulating that GSU must make payments for its portion of expenses
for Big Cajun 2, Unit 3 to the registry of the District Court.
On December 14, 1994, the LPSC ordered Cajun to decrease the
rates charged to its member distribution cooperatives by approximately
$30 million per year. The rate decrease is associated with the LPSC's
prior finding of imprudence in Cajun's participation in River Bend.
On December 21, 1994, Cajun filed a petition in the United
States Bankruptcy Court for the Middle District of Louisiana seeking
bankruptcy relief under Chapter 11 of the United States Bankruptcy
Code. Cajun's bankruptcy could have a material adverse effect on GSU,
including the possibility of an NRC action with respect to the
operation of River Bend. However, GSU is taking appropriate steps to
protect its interests and its claims against Cajun arising from the co-
ownership in River Bend and Big Cajun 2, Unit 3. On December 31,
1994, the District Court issued an order lifting an automatic stay as
to certain proceedings, with the result that the preliminary
injunction granted by the Court on December 19, 1994, remains in
effect. Cajun filed a Notice of Appeal on January 18, 1995, to the
United States Court of Appeals for the Fifth Circuit seeking a
reversal of the District Court's grant of the preliminary injunction.
No hearing date has been set on Cajun's appeal.
In the bankruptcy proceedings, Cajun filed on January 10, 1995, a
motion to reject the River Bend Operating Agreement as a burdensome
executory contract. GSU responded on January 10, 1995, with a
memorandum opposing Cajun's motion filed with the District Court.
This memorandum argues that the motion should be denied because (1)
the Operating Agreement is not an executory contract that can be
rejected under the United States Bankruptcy Code, but an agreement
establishing property rights and obligations; (2) Cajun legally cannot
have its payment obligations under the Operating Agreement suspended
while retaining the benefits from co-ownership in River Bend, as the
benefits and obligations are indivisible; (3) Cajun cannot seek to
dispose of its property interest in River Bend or reject the Operating
Agreement with respect thereto without disposing of all of its
property interests and rejecting all of the arrangements under the
River Bend package of agreements consisting of the Operating
Agreement, Big Cajun 2, Unit 3 facility, certain transmission lines
and the buy-back agreement pursuant to when GSU paid Cajun
approximately $600 million for River Bend capacity and energy during
the early years of operation of River Bend; and (4) a legal
determination of Cajun's obligations and interests in River Bend
should only be made as part of a plan of reorganization in bankruptcy
and such determination should be subject to regulatory approvals by
certain agencies with jurisdiction over Cajun, including the NRC. If
the court were to grant Cajun's motion to reject the Operating
Agreement, Cajun would be relieved of its financial obligations under
the contract, while GSU would likely have a substantial damage claim
arising from any such rejection. Although GSU believes that Cajun's
motion to reject the Operating Agreement is non-meritorious, it is not
possible to predict the outcome or ultimate impact of these
proceedings.
During the period in which Cajun is not paying its share of River
Bend costs, GSU intends to fund all costs necessary for the safe,
continuing operation of the unit. The responsibilities of Entergy
Operations as the licensed operator of River Bend, for safely
operating and maintaining the unit are not affected by Cajun's
actions.
The total resulting from Cajun's failure to fund repair projects,
Cajun's funding limitation on refueling outages, and the weekly
funding limitation by Cajun was $55.6 million as of December 31, 1994,
compared with $33.3 million as of December 31, 1993. These amounts
are reflected in long-term receivables with an offsetting reserve in
other deferred credits. Cajun's bankruptcy may affect the ultimate
collectibility of the amounts owed to GSU, including any amounts that
may be awarded in litigation.
In September 1994, in connection with Entergy Corporation's
analysis of certain preacquisition contingencies, Entergy Corporation
increased its acquisition adjustment and GSU recorded a loss provision
associated with the River Bend litigation between GSU and Cajun and
certain underpayments by Cajun of River Bend costs, in accordance with
SFAS 5, "Accounting for Contingencies." See Note 13 for additional
information on provisions for preacquisition contingencies recorded
during 1994.
Cajun - Transmission Service
GSU and Cajun are parties to FERC proceedings relating to
transmission service charge disputes. In April 1992, FERC issued a
final order. In May 1992, GSU and Cajun filed motions for rehearings
which are pending at FERC. In June 1992, GSU filed a petition for
review in the United States Court of Appeals regarding certain of the
issues decided by FERC. In August 1993, the United States Court of
Appeals rendered an opinion reversing the FERC order regarding the
portion of such disputes relating to the calculations of certain
credits and equalization charges under GSU's service schedules with
Cajun. The opinion remanded the issues to FERC for further pro
ceedings consistent with its opinion. In December 1994, FERC held a
hearing to address the issues remanded by the Court of Appeals. In
February 1995, FERC clarified its order, eliminating an issue that GSU
believes the Court of Appeals directed FERC to reconsider.
GSU interprets the 1992 FERC order and the United States Court of
Appeals' decision to mean that Cajun would owe GSU approximately $93.3
million as of December 31, 1994. However, FERC's February 1995 order
indicates that FERC believes an issue, estimated by GSU to constitute
approximately $26.2 million of this amount, may not be pursued by GSU
in the remand proceedings. GSU further estimates that if it prevails
in its May 1992 motion for rehearing, Cajun would owe GSU
approximately $129.6 million as of December 31, 1994. If Cajun were
to prevail in its May 1992 motion for rehearing to FERC, and if GSU
were not to prevail in its May 1992 motion for rehearing to FERC, and
if FERC does not implement the court's remand as GSU contends is
required, GSU estimates it would owe Cajun approximately $85.6 million
as of December 31, 1994. The above amounts are exclusive of a $7.3
million payment by Cajun on December 31, 1990, which the parties
agreed to apply to the disputed transmission service charges. GSU and
Cajun further agreed that their positions at FERC would remain
unaffected by the $7.3 million payment. Pending FERC's ruling on the
May 1992 motions for rehearing, GSU has continued to bill Cajun
utilizing the historical billing methodology and has booked underpaid
transmission charges, including interest, in the amount of $160.2
million as of December 31, 1994. This amount is reflected in long-
term receivables with an offsetting reserve in other deferred credits.
Capital Requirements and Financing
Construction expenditures (excluding nuclear fuel) for the years
1995, 1996, and 1997 are estimated to total $177 million each year.
GSU will also require $375 million during the period 1995-1997 to meet
long-term debt and preferred stock maturities and sinking fund
requirements. GSU plans to meet the above requirements with
internally generated funds and cash on hand. See Notes 5 and 6
regarding the possible issuance, refunding, redemption, purchase or
other acquisition of certain outstanding series of preferred stock and
long-term debt.
Nuclear Insurance
The Price-Anderson Act limits public liability for a single
nuclear incident to approximately $8.92 billion as of December 31,
1994. GSU has protection for this liability through a combination of
private insurance (currently $200 million) and an industry assessment
program. Under the assessment program, the maximum amount that would
be required for each nuclear incident would be $79.3 million per
reactor, payable at a rate of $10 million per licensed reactor per
incident per year. GSU has one licensed reactor. Any assessments
pertaining to this program are subject to the allocation in accordance
with the respective ownership interests of GSU and Cajun. In
addition, GSU participates in a private insurance program which
provides coverage for worker tort claims filed for bodily injury
caused by radiation exposure. GSU's maximum assessment under the
program is an aggregate of approximately $3.2 million in the event
losses exceed accumulated reserve funds.
GSU and Cajun are members of certain insurance programs that
provide coverage for property damage, including decontamination and
premature decommissioning expense, to members' nuclear generating
plants. As of December 31, 1994, GSU was insured against such losses
up to $2.75 billion with $250 million of this amount designated to
cover any shortfall in the NRC required decommissioning trust funding.
In addition, GSU is a member of an insurance program that covers
certain replacement power and business interruption costs incurred due
to prolonged nuclear unit outages. Under the property damage and
replacement power/business interruption insurance programs, GSU could
be subject to assessments if losses exceed the accumulated funds
available to the insurers. As of December 31, 1994, the maximum
amount of such possible assessments to GSU was $22.6 million. Cajun
shares approximately $4.4 million of GSU's obligation.
The amount of property insurance presently carried by GSU exceeds
the NRC's minimum requirement for nuclear power plant licensees of
$1.06 billion per site. NRC regulations provide that the proceeds of
this insurance must be used, first, to place and maintain the reactor
in a safe and stable condition and, second, to complete
decontamination operations. Only after proceeds are dedicated for
such use and regulatory approval is secured, would any remaining
proceeds be made available for the benefit of plant owners or their
creditors.
Spent Nuclear Fuel and Decommissioning Costs
GSU provides for estimated future disposal costs for spent
nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982.
GSU entered into a contract with the DOE, whereby the DOE will furnish
disposal service at a cost of one mill per net KWH generated and sold.
The fees payable to the DOE may be adjusted in the future to assure
full recovery. GSU considers all costs incurred or to be incurred for
the disposal of spent nuclear fuel to be proper components of nuclear
fuel expense, and provisions to recover such costs have been or will
be made in applications to regulatory authorities.
Delays have occurred in the DOE's program for the acceptance and
disposal of spent nuclear fuel at a permanent repository. In a
statement released February 17, 1993, the DOE asserted that it does
not have a legal obligation to accept spent nuclear fuel without an
operational repository for which it has not yet arranged. Currently
the DOE projects it will begin to accept spent fuel no earlier than
2010. In the meantime, GSU is responsible for spent fuel storage.
Current on-site spent fuel storage capacity at River Bend is estimated
to be sufficient until 2003. Thereafter, GSU will provide additional
storage capacity at an initial cost of $5 million to $10 million. In
addition, approximately $3 million to $5 million will be required
every four to five years subsequent to 2003 until the DOE's repository
program begins accepting River Bend's spent fuel.
Entergy Operations and System Fuels joined in lawsuits against
the DOE, seeking clarification of the DOE's responsibility to receive
spent nuclear fuel beginning in 1998. The original suits, filed June
20, 1994, asked for a ruling stating that the Nuclear Waste Policy Act
require the DOE to begin taking title to the spent fuel and to start
removing it from nuclear power plants in 1998, a mandate for the DOE's
nuclear waste management program to begin accepting fuel in 1998 and
court monitoring of the program, and the potential for escrow of
payments to the Nuclear Waste Fund instead of directly to the DOE.
GSU is recovering in rates amounts sufficient to fund
decommissioning costs for River Bend, based on the original 1985
decommissioning cost study of approximately $141 million, which
relates to GSU's 70% interest in River Bend. The amounts recovered in
rates are deposited in external trust funds and reported at market
value. The accumulated decommissioning liability of $22.2 million as
of December 31, 1994, has been recorded in accumulated depreciation.
Decommissioning expense amounting to $3.0 million was recorded in
1994. A more recent 1991 engineering study indicates decommissioning
costs for GSU's 70% interest may be $267.8 million (in 1990 dollars).
GSU filed the more recent cost study with the PUCT requesting a rate
adjustment for decommissioning expense. As discussed in Note 2, on
March 20, 1995, the PUCT ruled in the current rate case. The PUCT
order included recovery of River Bend decommissioning costs totaling
$204.9 million. GSU plans to ask the LPSC for a rate adjustment for
decommissioning expense in conjunction with its next rate review in
mid 1995. The actual decommissioning costs may vary from the
estimates because of regulatory requirements, changes in technology,
and increased costs of labor, materials, and equipment. Management
believes that actual decommissioning costs are likely to be higher
than the amounts presented above.
The staff of the SEC has questioned certain of the current
accounting practices of the electric utility industry, regarding the
recognition, measurement, and classification of decommissioning costs
for nuclear generating stations in the financial statements of
electric utilities. In response to these questions, the FASB is
currently reviewing the accounting for decommissioning. If current
electric utility industry accounting practices for such
decommissioning are changed, annual provisions for decommissioning
could increase, the estimated cost for decommissioning could be
recorded as a liability rather than as accumulated depreciation, and
trust fund income from the external decommissioning trusts could be
reported as investment income rather than as a reduction to
decommissioning expense.
The EPAct has a provision that assesses domestic nuclear
utilities with fees for the decontamination and decommissioning of the
DOE's past uranium enrichment operations. The decontamination and
decommissioning assessments will be used to set up a fund into which
contributions from utilities and the federal government will be
placed. GSU's annual assessment, which will be adjusted annually for
inflation, is $0.9 million (in 1995 dollars) for approximately 15
years. FERC requires that utilities treat these assessments as costs
of fuel as they are amortized. The liability of $6.6 million as of
December 31, 1994, is recorded in other current liabilities and other
noncurrent liabilities and is offset in financial statements by a
regulatory asset.
Long-Term Contracts
NISCO Power Purchases. In 1988, GSU entered into a joint venture
with a primary term of 20 years with Conoco, Inc., Citgo Petroleum
Corporation, and Vista Chemical Company (Industrial Participants)
whereby GSU's Nelson Units 1 and 2 were sold to a partnership (NISCO)
consisting of the Industrial Participants and GSU. The Industrial
Participants are supplying the fuel for the units, while GSU operates
the units at the discretion of the Industrial Participants and
purchases the electricity produced by the units. GSU is continuing to
sell electricity to the Industrial Participants. For the years ended
December 31, 1994, 1993, and 1992, the purchases of electricity from
the joint venture totaled $58.3 million, $62.6 million, and $37.8
million, respectively.
Natural Gas Contracts. GSU has long-term gas contracts which
will satisfy approximately 75% of its annual requirements. However,
such contracts as a whole only require GSU to purchase in the range of
40% of expected total gas needs. Additional gas requirements are
satisfied under less expensive short-term contracts. GSU entered into
a transportation service agreement which obligated the gas supplier to
provide GSU with flexible natural gas swing service to the Sabine and
Lewis Creek generating stations. This service is provided by the
supplier's pipeline and salt dome gas storage facility, which has a
present capacity of 5.3 billion cubic feet of natural gas.
Coal Contracts. GSU has contracted for a long-term supply of low-
sulfur Wyoming coal for use at Nelson Unit 6. This contract, which is
set to expire in 2004, will provide a supply of 50 million tons over
the term of the contract. Cajun has advised GSU that current
contracts will provide an adequate supply of coal for Big Cajun 2,
Unit 3 until 1997.
Environmental Issues
GSU has been notified by the U. S. Environmental Protection
Agency (EPA) that it has been designated as a potentially responsible
party for the cleanup of sites on which GSU and others have or have
been alleged to have disposed of material designated as hazardous
waste. GSU is currently negotiating with the EPA and state
authorities regarding the cleanup of some of these sites. Several
class action and other suits have been filed in state and federal
courts seeking relief from GSU and others for damages caused by the
disposal of hazardous waste and for asbestos-related disease allegedly
resulting from exposure on GSU premises. While the amounts at issue
in the cleanup efforts and suits may be substantial, GSU believes that
its results of operations and financial condition will not be
materially affected by the outcome of the suits.
As of December 31, 1994, GSU has accrued cumulative amounts
related to the cleanup of six sites at which GSU has been designated a
potentially responsible party, totaling $27.7 million since 1990.
Through December 31, 1994, GSU has expended $7.4 million cumulatively
on the cleanup, resulting in a remaining recorded liability of $20.3
million as of December 31, 1994
Sales/Use Tax Issues
In September 1994, the Louisiana Supreme Court (Court) issued an
opinion (in a case in which none of the System companies was a party)
holding, in part that the Louisiana state legislature's suspension of
state sales and use tax exemptions also had the effect of suspending
exemptions from local sales and use taxes. On January 27, 1995 the
Court, after rehearing, reversed its opinion. Because of the Court's
most recent ruling, sales of electricity and gas, fuels and other
items used by GSU, LP&L, and NOPSI to generate electricity in
Louisiana, as well as other items exempt from sales and use taxes,
continue to be exempt from local sales and use taxes, even though the
state exemptions for sales and use tax have been suspended.
NOTE 9. LEASES
General
As of December 31, 1994, GSU had capital leases and noncancelable
operating leases (excluding nuclear fuel leases) with minimum lease
payments as follows:
Capital Operating
Leases Leases
Year (In Thousands)
1995 $ 12,475 $ 10,695
1996 12,475 10,135
1997 12,475 13,742
1998 12,475 13,703
1999 12,475 13,703
Years thereafter 81,380 92,597
--------- ---------
Minimum lease payments 143,755 $ 154,575
=========
Less: Amount representing interest 55,651
---------
Present value of net minimum lease payments $ 88,104
=========
Rental expense for capital and operating leases (excluding
nuclear fuel leases) amounted to approximately $15.3, $31.9 million,
and $21.9 million in 1994, 1993, and 1992, respectively.
GSU is leasing the Lewis Creek generating station from its wholly
owned consolidated subsidiary, GSG&T.
Nuclear Fuel Lease
GSU has arrangements to lease nuclear fuel in an amount up to
$105 million. The lessor finances its acquisition of nuclear fuel
through a credit agreement and the issuance of notes. The credit
agreement, which was entered into in 1993, has been extended to
December 1997 and the notes have varying remaining maturities of up to
3 years. It is expected that the credit arrangement will be extended
or alternative financing will be secured by the lessor upon the
maturity of the current arrangements. If the lessor cannot arrange
for alternative financing upon the maturity of its borrowings, GSU
must purchase nuclear fuel in an amount sufficient to enable the
lessor to retire such borrowings.
Lease payments are based on nuclear fuel use. Nuclear fuel
expense of $37.2 million, $43.6 million, and $31.6 million (including
interest of $8.7 million, $10.2 million, and $11.5 million) was
charged to operations in 1994, 1993, and 1992, respectively.
NOTE 10.POSTRETIREMENT BENEFITS
Pension Plan
GSU has a defined benefit pension plan covering substantially all
of its employees. The pension plan is noncontributory and provides
pension benefits that are based on employees' credited service and the
average compensation generally during the last five years before
retirement. GSU funds pension costs in accordance with contribution
guidelines established by the Employee Retirement Income Security Act
of 1974, as amended, and the Internal Revenue Code of 1986, as
amended. The assets of the plan consist primarily of common and
preferred stocks and fixed income securities. In 1994, GSU amended
its defined benefit pension plan for non-bargaining unit employees to
be consistent with the other System companies. Additionally,
actuarial assumptions were also changed to be consistent with the
other System companies.
GSU's 1994, 1993, and 1992 pension cost, including amounts
capitalized, included the following components:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Service cost - benefits earned during the period $ 9,497 $10,417 $ 12,396
Interest cost on projected benefit obligation 21,335 17,643 16,307
Actual return on plan assets 6,785 (43,400) (28,117)
Net amortization and deferral (39,405) 14,863 2,926
Other 17,963 - -
-------- ------- --------
Net pension cost $ 16,175 $ (477) $ 3,512
======== ======= ========
The funded status of GSU's pension plan as of December 31, 1994 and 1993,
was:
1994 1993
(In Thousands)
Actuarial present value of benefit obligations:
Vested $273,509 $227,820
Nonvested 1,502 13,667
-------- --------
Accumulated benefit obligation $275,011 $241,487
======== ========
Plan assets at fair market value $313,035 $337,922
Projected benefit obligation 290,802 282,722
-------- --------
Plan assets in excess of projected benefit obligation 22,233 55,200
Unrecognized prior service cost 13,720 11,985
Unrecognized transition asset (14,324) (16,712)
Unrecognized net gain (73,423) (86,092)
-------- --------
Accrued pension liability $(51,794) $(35,619)
======== ========
The accrued pension liability for GSU for 1993 has been restated
to include liabilities for certain Early Retirement Programs. Prior to
1994, GSU accounted for such Early Retirement Programs in separate
liability accounts other than the pension liability. However,
effective in 1994, GSU changed its policy to include such liabilities
in the pension liability account to be consistent with the other
System companies. The significant actuarial assumptions used in
computing the information above for 1994, 1993, and 1992 were as
follows: weighted average discount rate, 8.5% for 1994, 7.5% for 1993,
and 6.50% for 1992; weighted average rate of increase in future
compensation levels, 5.1% for 1994, 5.0% for 1993, and 5.75% for 1992;
and expected long-term rate of return on plan assets, 8.5%. Transition
assets are being amortized over 15 years.
In December 1993, GSU recorded a $17.0 million charge related to
the announced early retirement program in connection with the Merger,
of which $14.9 million was expensed. In 1994, GSU recorded an
additional $18.0 million charge related to early retirement programs
in connection with the Merger, of which $15.2 million was expensed.
Other Postretirement Benefits
GSU also provides certain health care and life insurance benefits
for retired employees. All of GSU's employees may become eligible for
these benefits if they reach retirement age while still working for
GSU. The cost of providing these benefits, recorded on a cash basis,
was $5.3 million for 1992.
Effective January 1, 1993, GSU adopted SFAS 106. This standard
required a change from a cash method to an accrual method of
accounting for postretirement benefits other than pensions. GSU
continues to fund these benefits on a pay-as-you-go-basis. As of
January 1, 1993, the actuarially determined accumulated postretirement
benefit obligation (APBO) earned by retirees and active employees was
estimated to be approximately $128 million. This obligation is being
amortized over a 20-year period beginning in 1993. In 1994, GSU
changed its actuarial assumptions and attribution methodology to be
consistent with the other System companies.
In March 1993, the PUCT issued a ruling applicable to all Texas
utilities that amounts recorded in compliance with SFAS 106 and
included in a rate filing test period, will be recoverable in rates
(at the time of the next general rate case) and that the
postretirement benefit amounts allowed in rates must then be funded by
the utility. The PUCT made no specific provision in its order
permitting deferral, as a regulatory asset, of these costs. The LPSC
ordered GSU to use the pay-as-you-go method for ratemaking purposes
for postretirement benefits other than pensions, but the LPSC retains
the flexibility to examine companies' accounting for postretirement
benefits to determine if special exceptions to this order are
warranted.
GSU's 1994 and 1993 postretirement benefit cost, including
amounts capitalized and deferred, included the following components:
1994 1993
(In Thousands)
Service cost - benefits earned during the period $ 2,169 $ 5,467
Interest cost on APBO 6,449 9,976
Actual return on plan assets - -
Net amortization and deferral 2,832 6,402
------- -------
Net periodic postretirement benefit cost $11,450 $21,845
======= =======
The funded status of GSU's postretirement plan as of December 31,
1994 and 1993, was:
1994 1993
(In Thousands)
Accumulated postretirement benefit obligation:
Retirees $ 39,695 $ 46,270
Other fully eligible participants 26,069 38,091
Other active participants 13,445 18,359
-------- ---------
79,209 102,720
Plan assets at fair value - -
-------- ---------
Plan assets in excess of (less than APBO) (79,209) (102,720)
Unrecognized transition obligation 115,232 121,634
Unrecognized net loss (gain) (57,410) (35,534)
-------- ---------
Accrued postretirement benefit liability $(21,387) $ (16,620)
======== =========
The assumed health care cost trend rate used in measuring the
APBO is 9.4% for 1995, gradually decreasing each successive year until
it reaches 5% in 2011. A one percentage-point increase in the assumed
health care cost trend rate for each year would increase the APBO as
of December 31, 1994, by 10.3% and the sum of the service cost and
interest cost by approximately 12.2%. The assumed discount rate and
rate of increase in future compensation used in determining the APBO
were 8.5% for 1994 and 7.5% for 1993, and 5.1% for 1994 and 5% for
1993, respectively.
NOTE 11.TRANSACTIONS WITH AFFILIATES
GSU purchases electricity from and/or sells electricity to the
other System operating companies, subsequent to the Merger, under rate
schedules filed with FERC. In addition, GSU receives technical and
advisory services from Entergy Services, and receives management and
operating services from Entergy Operations.
Operating revenues include revenues from sales to System operating
companies amounting to $44.4 million in 1994. Operating expenses
include charges from System operating companies for purchased power
and related charges totaling $296.9 million in 1994, and $25.5 million
in 1993, and $38.8 million in 1992, prior to the Merger. GSU pays
directly or reimburses Entergy Operations for costs associated with
operating River Bend (excluding nuclear fuel) which were approximately
$210.2 million in 1994.
NOTE 12. RESTRUCTURING COSTS
During the third quarter of 1994, GSU announced a restructuring
program related to certain of its operating units. The program is
designed to reduce costs, improve operating efficiencies, and increase
shareholder value in order to enable GSU to become a low-cost
producer. The program includes reductions in the number of employees
and the consolidation of offices and facilities. In 1994, GSU
recorded restructuring charges of $6.5 million. These charges
primarily include employee severance costs related to the expected
termination of approximately 450 employees. As of December 31, 1994,
no employees have been terminated and no termination benefits have
been paid under this restructuring program.
NOTE 13. ENTERGY CORPORATION-GSU MERGER
On December 31, 1993, Entergy Corporation and GSU consummated
their Merger. GSU became a wholly-owned subsidiary of Entergy
Corporation and continues to operate as a corporation under the
regulation of FERC, the PUCT, and the LPSC. As consideration to GSU's
shareholders, Entergy Corporation paid $250 million and issued
56,695,724 shares of its common stock in exchange for the 114,055,065
outstanding shares of GSU common stock.
As a result of the December 31, 1993 Merger closing, GSU recorded
expenses totaling $49 million, net of related tax effects, for early
retirement and other severance related plans and the payment to
financial consultants involved in Merger negotiations on behalf of
GSU. Additionally, GSU recorded $23.8 million in 1994 for remaining
severance and augmented retirement benefits related to the Merger.
See Note 2 for information regarding Merger-related rate agreements.
In 1993, Entergy Corporation recorded an acquisition adjustment
in utility plant in the amount of $380 million representing the excess
of the purchase price over the net assets acquired of GSU. The
acquisition adjustment will be amortized on a straight-line basis over
a 31-year period, which approximates the remaining average book life
of GSU's plant. During the allocation period (which expired on
December 31, 1994), Entergy Corporation completed its analyses with
respect to preacquisition contingencies and revised the allocation of
the purchase price for a number of preacquisition contingencies. In
1994, GSU wrote-off assets or recorded liabilities totaling
approximately $137 million net of tax for the Cajun-River Bend
litigation, unfunded Cajun-River Bend costs, environmental cleanup
costs, obsolete spare parts, Louisiana River Bend rate deferrals
previously disallowed by the LPSC, plant held for future use, and the
PUCT Fuel Reconciliation Settlement. Any items recorded in 1995 or
later, will result in write-offs and/or losses charged to operations
on GSU's financial statements and Entergy Corporation's consolidated
financial statements.
NOTE 14.QUARTERLY FINANCIAL DATA (UNAUDITED)
GSU's business is subject to seasonal fluctuations with the peak
period occurring during the third quarter. Operating results for the
four quarters of 1994 and 1993 were:
Income (Loss)
Before
Extraordinary
Items and the
Cumulative Effect Net
Operating Operating of Accounting Income
Revenues Income Changes (Loss)
(In Thousands)
1994:
First Quarter $429,658 $ 58,561 $ 11,043 $ 11,043
Second Quarter $456,855 $ 83,357 $ 33,084 $ 33,084
Third Quarter $545,531 $ 64,853 $(31,662) $(31,662)
Fourth Quarter $365,321 $ 6,880 $(95,220) $(95,220)
1993:
First Quarter $404,178 $ 69,408 $ 15,007 $ 25,667
Second Quarter $442,223 $ 81,989 $ 31,066 $ 30,781
Third Quarter $574,607 $118,032 $ 70,155 $ 69,181
Fourth Quarter $406,612 $ 1,187 $(46,767) $(46,767)
See Note 2 for information regarding the recording of a reserve
rate refund in December 1994, Note 12 for information regarding
the recording of certain restructuring costs in 1994, and Note 13
for information regarding the recording of charges associated
with certain preacquisition contingencies in 1994.
See Note 1 for information regarding the change in accounting for
unbilled revenues in 1993. See Note 2 for information regarding
rate refunds during December 1993, and Note 13 for information
regarding Merger-related charges recorded during the fourth
quarter of 1993.
GULF STATES UTILITIES COMPANY
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1994 1993 1992 1991 1990
(In Thousands)
Operating revenues $1,797,365 $1,827,620 $1,773,374 $1,702,235 $1,690,685
Income (loss) before
extraordinary items and
the cumulative effect of
accounting changes $ (82,755) $ 69,461 $ 139,413 $ 112,391 $ (36,399)
Total assets $6,843,461 $7,137,351 $7,164,447 $7,183,119 $7,135,399
Long-term obligations (1) $2,689,042 $2,772,002 $2,798,768 $2,816,577 $2,663,249
(1) Includes long-term debt (excluding currently maturing debt), preferred and
preference stock with sinking fund, and noncurrent capital lease
obligations.
See Notes 1 and 10 for the effect of accounting changes in 1993 and 1992
and Notes 2 and 8 regarding River Bend rate appeals and litigation with
Cajun.
1994 1993 1992 1991 1990
(Dollars in Thousands)
Electric Department
Operating Revenues:
Residential $ 569,997 $ 585,799 $ 560,552 $ 547,147 $ 523,911
Commercial 414,929 415,267 400,803 383,883 378,253
Industrial 626,047 650,230 642,298 582,568 578,928
Governmental 25,242 26,118 26,195 24,792 24,101
---------- ---------- ---------- ---------- ----------
Total retail 1,636,215 1,677,414 1,629,848 1,538,390 1,505,193
Sales for resale 98,230 31,898 24,485 44,136 48,125
Other (15,244) 38,649 40,203 41,433 43,317
---------- ---------- ---------- ---------- ----------
Total Electric Department $1,719,201 $1,747,961 $1,694,536 $1,623,959 $1,596,635
========== ========== ========== ========== ==========
Billed Electric Energy
Sales (Millions of KWH):
Electric Department
Residential 7,351 7,192 6,825 6,925 6,834
Commercial 6,089 5,711 5,474 5,460 5,388
Industrial 15,026 14,294 14,413 13,629 13,347
Governmental 297 296 302 295 285
---------- ---------- ---------- ---------- ----------
Total retail 28,763 27,493 27,014 26,309 25,854
Sales for resale 3,516 666 540 1,049 1,180
---------- ---------- ---------- ---------- ----------
Total Electric Department 32,279 28,159 27,554 27,358 27,034
Steam Department 1,659 1,597 1,722 1,711 1,930
---------- ---------- ---------- ---------- ----------
Total 33,938 29,756 29,276 29,069 28,964
========== ========== ========== ========== ==========
Louisiana Power & Light Company
1994 Financial Statements
LOUISIANA POWER & LIGHT COMPANY
DEFINITIONS
Certain abbreviations or acronyms used in LP&L's Financial
Statements, Notes to Financial Statements, and Management's Financial
Discussion and Analysis are defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
AP&L Arkansas Power & Light Company
DOE United States Department of Energy
Entergy or System Entergy Corporation and its various direct
and indirect subsidiaries
Entergy Operations Entergy Operations, Inc., a subsidiary of
Entergy Corporation that has operating
responsibility for Grand Gulf 1, Waterford 3,
ANO, and River Bend
Entergy Services Entergy Services, Inc.
EPAct The Energy Policy Act of 1992
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Grand Gulf 1 Unit No. 1 of the Grand Gulf Station
(nuclear)
Grand Gulf 2 Unit No. 2 of the Grand Gulf Station
(nuclear)
Grand Gulf Station Grand Gulf Steam Electric Generating Station
(nuclear)
GSU Gulf States Utilities Company (including
wholly owned subsidiaries - Varibus
Corporation, GSG&T, Inc., Prudential Oil and
Gas, Inc., and Southern Gulf Railway Company)
KWH Kilowatt-Hour(s)
LP&L Louisiana Power & Light Company
LPSC Louisiana Public Service Commission
Money Pool Entergy Money Pool, which allows certain
System companies to borrow from, or lend to,
certain other System companies
MP&L Mississippi Power & Light Company
NOPSI New Orleans Public Service Inc.
OBRA Omnibus Budget Reconciliation Act of 1993
Owner Participant A corporation that, in connection with the
Waterford 3 sale and leaseback transactions,
has acquired a beneficial interest in a
trust, the Owner Trustee of which is the
owner and lessor of an undivided interest in
Waterford 3
Owner Trustee Each institution and/or individual acting as
owner trustee under a trust agreement with an
Owner Participant in connection with the
Waterford 3 sale and leaseback transactions
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
promulgated by the FASB
SFAS 106 SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions"
SFAS 109 SFAS 109, "Accounting for Income Taxes"
System or Entergy Entergy Corporation and its various direct
and indirect subsidiaries
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI,
collectively
Waterford 3 Unit No. 3 of LP&L's Waterford Steam Electric
Generating Station (nuclear)
LOUISIANA POWER & LIGHT COMPANY
REPORT OF MANAGEMENT
The management of Louisiana Power & Light Company has prepared
and is responsible for the financial statements and related financial
information included herein. The financial statements are based on
generally accepted accounting principles. Financial information
included elsewhere in this report is consistent with the financial
statements.
To meet its responsibilities with respect to financial
information, management maintains and enforces a system of internal
accounting controls that is designed to provide reasonable assurance,
on a cost-effective basis, as to the integrity, objectivity, and
reliability of the financial records, and as to the protection of
assets. This system includes communication through written policies
and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and
the training of personnel. This system is also tested by a
comprehensive internal audit program.
The independent public accountants provide an objective
assessment of the degree to which management meets its responsibility
for fairness of financial reporting. They regularly evaluate the
system of internal accounting controls and perform such tests and
other procedures as they deem necessary to reach and express an
opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide
reasonable assurance that its operations are carried out with a high
standard of business conduct.
/s/ Edwin Lupberger /s/ Gerald D. McInvale
EDWIN LUPBERGER GERALD D. MCINVALE
Chairman and Chief Executive Officer Senior Vice President and
Chief Financial Officer
LOUISIANA POWER & LIGHT COMPANY
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Entergy Corporation Board of Directors' Audit Committee
functions as the Audit Committee for Louisiana Power & Light Company.
The Audit Committee is comprised of four directors, who are not
officers of LP&L: H. Duke Shackelford (Chairman), Lucie J. Fjeldstad,
Dr. Norman C. Francis, and James R. Nichols. The committee held four
meetings during 1994.
The Audit Committee oversees LP&L's financial reporting process
on behalf of the Board of Directors and provides reasonable assurance
to the Board that sufficient operating, accounting, and financial
controls are in existence and are adequately reviewed by programs of
internal and external audits.
The Audit Committee discussed with Entergy's internal auditors
and the independent public accountants (Coopers & Lybrand L.L.P.) the
overall scope and specific plans for their respective audits, as well
as LP&L's financial statements and the adequacy of LP&L's internal
controls. The committee met, together and separately, with Entergy's
internal auditors and independent public accountants, without
management present, to discuss the results of their audits, their
evaluation of LP&L's internal controls, and the overall quality of
LP&L's financial reporting. The meetings also were designed to
facilitate and encourage any private communication between the
committee and the internal auditors or independent public accountants.
/s/ H. Duke Shackelford
H. DUKE SHACKELFORD
Chairman, Audit Committee
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
Louisiana Power & Light Company
We have audited the accompanying balance sheet of Louisiana
Power & Light Company as of December 31, 1994, and the related
statements of income, retained earnings and cash flows for the year
then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on
these financial statements based on our audit. The financial
statements of the Company as of December 31, 1993 and for the years
ended December 31, 1993 and 1992, were audited by other auditors,
whose report, dated February 11, 1994, included an explanatory
paragraph that described changes in methods of accounting for income
taxes and postretirement benefits other than pensions which are
discussed in Notes 3 and 10 respectively, to these financial
statements.
We conducted our audit in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position of
the Company as of December 31, 1994, and the result of its operations
and its cash flows for the year then ended in conformity with
generally accepted accounting principles.
/s/ Coopers & Lybrand L.L.P.
COOPERS & LYBRAND L.L.P.
New Orleans, Louisiana
February 21, 1995
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of
Louisiana Power & Light Company
We have audited the accompanying balance sheet of Louisiana Power
& Light Company (LP&L) as of December 31, 1993, and the related
statements of income, retained earnings, and cash flows for each of
the two years in the period ended December 31, 1993. These financial
statements are the responsibility of LP&L's management. Our
responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all
material respects, the financial position of LP&L at December 31,
1993, and the results of its operations and its cash flows for each of
the two years in the period ended December 31, 1993 in conformity with
generally accepted accounting principles.
As discussed in Notes 3 and 10 to the financial statements, in
1993 LP&L changed its methods of accounting for income taxes and
postretirement benefits other than pensions, respectively.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 11, 1994
LOUISIANA POWER & LIGHT COMPANY
BALANCE SHEETS
ASSETS
December 31,
1994 1993
(In Thousands)
Utility Plant:
Electric $4,778,126 $4,646,020
Electric plant under lease 229,468 225,083
Construction work in progress 94,791 133,536
Nuclear fuel under capital lease 44,238 61,375
Nuclear fuel 6,420 3,823
---------- ----------
Total 5,153,043 5,069,837
Less - accumulated depreciation and amortization 1,600,510 1,496,107
---------- ----------
Utility plant - net 3,552,533 3,573,730
---------- ----------
Other Property and Investments:
Nonutility property 20,060 20,060
Decommissioning trust fund 27,076 22,109
Investment in subsidiary company - at equity 14,230 14,230
Other 1,078 984
---------- ----------
Total 62,444 57,383
---------- ----------
Current Assets:
Cash and cash equivalents:
Temporary cash investments - at cost,
which approximates market 28,718 33,489
Special deposits 3,237 19,077
Accounts receivable:
Customer (less allowance for doubtful accounts of
$1.2 million in 1994 and of $1.1 million in 1993) 58,858 66,575
Associated companies 9,827 2,952
Other 11,609 10,656
Accrued unbilled revenues 63,109 64,314
Accumulated deferred income taxes 3,702 6,031
Materials and supplies - at average cost 89,692 87,204
Rate deferrals 28,422 28,422
Prepayments and other 25,291 16,510
---------- ----------
Total 322,465 335,230
---------- ----------
Deferred Debits and Other Assets:
Regulatory Assets:
Rate deferrals 25,609 54,031
SFAS 109 regulatory asset - net 379,263 349,703
Unamortized loss on reacquired debt 43,656 47,853
Other regulatory assets 25,736 26,837
Other 23,733 19,231
---------- ----------
Total 497,997 497,655
---------- ----------
TOTAL $4,435,439 $4,463,998
========== ==========
See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
1994 1993
(In Thousands)
Capitalization:
Common stock, no par value, authorized
250,000,000 shares; issued and outstanding
165,173,180 shares in 1994 and 1993 $1,088,900 $1,088,900
Capital stock expense and other (5,367) (6,109)
Retained earnings 113,420 89,849
---------- ----------
Total common shareholder's equity 1,196,953 1,172,640
Preferred stock:
Without sinking fund 160,500 160,500
With sinking fund 111,265 126,302
Long-term debt 1,403,055 1,457,626
---------- ----------
Total 2,871,773 2,917,068
---------- ----------
Other Noncurrent Liabilities:
Obligations under capital leases 16,238 27,508
Other 54,216 28,909
---------- ----------
Total 70,454 56,417
---------- ----------
Current Liabilities:
Currently maturing long-term debt 75,320 25,315
Notes payable:
Associated companies 7,954 52,041
Other 19,200 -
Accounts payable:
Associated companies 20,793 33,523
Other 82,203 76,284
Customer deposits 54,934 52,234
Taxes accrued (1,860) 15,110
Interest accrued 42,987 42,141
Dividends declared 5,489 5,938
Deferred revenue - gas supplier judgment proceeds - 14,632
Deferred fuel cost 13,983 605
Obligations under capital leases 28,000 33,867
Other 20,156 9,741
---------- ----------
Total 369,159 361,431
---------- ----------
Deferred Credits:
Accumulated deferred income taxes 883,945 834,899
Accumulated deferred investment tax credits 151,259 188,843
Deferred interest - Waterford 3 lease obligation 26,000 25,372
Other 62,849 79,968
---------- ----------
Total 1,124,053 1,129,082
---------- ----------
Commitments and Contingencies (Notes 2, 8, and 9)
TOTAL $4,435,439 $4,463,998
========== ==========
See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Activities:
Net income $213,839 $188,808 $182,989
Noncash items included in net income:
Change in rate deferrals 28,422 28,422 28,422
Depreciation and decommissioning 151,994 142,051 138,290
Deferred income taxes and investment tax credits (15,972) 40,261 42,896
Allowance for equity funds used during construction (3,486) (2,581) (1,714)
Amortization of deferred revenues (14,632) (42,470) (38,646)
Changes in working capital:
Receivables 1,094 (8,046) (5,135)
Accounts payable (6,811) (28,198) 7,733
Taxes accrued (16,970) 6,861 6,002
Interest accrued 846 1,003 2,917
Other working capital accounts 31,064 15,205 (16,037)
Refunds to customers - gas contract settlement - (56,027) (56,066)
Decommissioning trust contributions (4,815) (4,000) (2,000)
Other 3,048 18,299 5,982
-------- -------- --------
Net cash flow provided by operating activities 367,621 299,588 295,633
-------- -------- --------
Investing Activities:
Construction expenditures (140,669) (163,142) (150,527)
Allowance for equity funds used during construction 3,486 2,581 1,714
-------- -------- --------
Net cash flow used in investing activities (137,183) (160,561) (148,813)
-------- -------- --------
Financing Activities:
Proceeds from the issuance of:
First mortgage bonds - 100,000 269,000
Preferred stock - - 87,000
Other long-term debt 19,946 58,000 44,094
Changes in short-term borrowings (24,887) 52,041 -
Retirement of:
First mortgage bonds (25,000) (100,919) (309,205)
Other long-term debt (322) (22,052) (15,977)
Redemption of preferred stock (15,038) (22,500) (63,981)
Dividends paid:
Common stock (167,100) (167,600) (174,600)
Preferred stock (22,808) (25,290) (28,845)
-------- -------- --------
Net cash flow used in financing activities (235,209) (128,320) (192,514)
-------- -------- --------
Net increase (decrease) in cash and cash equivalents (4,771) 10,707 (45,694)
Cash and cash equivalents at beginning of period 33,489 22,782 68,476
-------- -------- --------
Cash and cash equivalents at end of period $28,718 $33,489 $22,782
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $128,000 $127,497 $126,674
Income taxes $96,442 $62,414 $32,668
Noncash investing and financing activities:
Capital lease obligations incurred $9,677 $33,210 $37,689
Deficiency of fair value of decommissioning trust
assets over amount invested ($1,129) - -
See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is important to LP&L due to the capital intensive
nature of its business, which requires large investments in long-lived
assets. While large capital expenditures for the construction of new
generating capacity are not currently planned, LP&L does require
significant capital resources for the periodic maturity of certain
series of debt and preferred stock and ongoing construction. Net cash
flow from operations totaled $368 million, $300 million, and $296
million in 1994, 1993, and 1992, respectively. Net cash flow from
operations in 1993 included payment of the last scheduled refund to
customers of proceeds from a settlement with a gas supplier. In
recent years, this cash flow, supplemented by cash on hand, has been
sufficient to meet substantially all investing and financing
requirements, including capital expenditures, dividends, and
debt/preferred stock maturities. LP&L's ability to fund these capital
requirements results, in part, from its continued efforts to
streamline operations and reduce costs, as well as collections under
its Waterford 3 rate phase-in plan which exceed the current cash
requirements for Waterford 3-related costs. (In the income statement,
these revenue collections are offset by the amortization of previously
deferred costs; therefore, there is no effect on net income.) LP&L's
Waterford 3 rate phase-in plan will continue to contribute to LP&L's
cash position through 1996. See Note 2 for additional information on
LP&L's rate phase-in plan. See Note 8 for additional information on
LP&L's capital and refinancing requirements in 1995 - 1997. Also, to
the extent current market interest and dividend rates allow, LP&L may
continue to refinance high-cost debt and preferred stock prior to
maturity.
Earnings coverage tests and bondable property additions limit the
amount of first mortgage bonds and preferred stock that LP&L can
issue. Based on the most restrictive applicable tests as of
December 31, 1994, and assuming an annual interest or dividend rate of
9.25%, LP&L could have issued $107 million of additional first
mortgage bonds or $784 million of additional preferred stock.
Further, LP&L has the conditional ability to issue first mortgage
bonds against the retirement of first mortgage bonds, in some cases
without satisfying an earnings coverage test.
See Notes 5 and 6 for information on LP&L's financing activities
and Note 4 for information on LP&L's short-term borrowings and lines
of credit.
LOUISIANA POWER & LIGHT COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Revenues $1,708,541 $1,729,666 $1,553,745
---------- ---------- ----------
Operating Expenses:
Operation and maintenance:
Fuel and fuel-related expenses 331,422 338,670 256,313
Purchased power 366,564 381,252 335,750
Nuclear refueling outage expenses 18,187 18,380 19,179
Other operation and maintenance 348,980 340,320 324,020
Depreciation and decommissioning 151,994 142,051 138,290
Taxes other than income taxes 56,101 50,391 49,507
Income taxes 63,751 108,568 83,984
Amortization of rate deferrals 28,422 28,422 28,422
---------- ---------- ----------
Total 1,365,421 1,408,054 1,235,465
---------- ---------- ----------
Operating Income 343,120 321,612 318,280
---------- ---------- ----------
Other Income (Deductions):
Allowance for equity funds used
during construction 3,486 2,581 1,714
Miscellaneous - net 747 2,069 6,676
Income taxes 463 (2,245) (3,053)
---------- ---------- ----------
Total 4,696 2,405 5,337
---------- ---------- ----------
Interest Charges:
Interest on long-term debt 129,952 130,352 135,772
Other interest - net 6,494 6,605 5,591
Allowance for borrowed funds used
during construction (2,469) (1,748) (735)
---------- ---------- ----------
Total 133,977 135,209 140,628
---------- ---------- ----------
Net Income 213,839 188,808 182,989
Preferred Stock Dividend Requirements
and Other 23,319 24,754 28,416
---------- ---------- ----------
Earnings Applicable to Common Stock $190,520 $164,054 $154,573
========== ========== ==========
See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Retained Earnings, January 1 $89,849 $94,510 $117,820
Add:
Net income 213,839 188,808 182,989
-------- -------- --------
Total 303,688 283,318 300,809
-------- -------- --------
Deduct:
Dividends declared:
Preferred stock 22,359 24,553 28,416
Common stock 167,100 167,600 174,600
Capital stock expenses 809 1,316 3,283
-------- -------- --------
Total 190,268 193,469 206,299
-------- -------- --------
Retained Earnings, December 31 (Note 7) $113,420 $ 89,849 $ 94,510
======== ======== ========
See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income increased in 1994 due primarily to the fourth quarter
write-off of the unamortized balances of deferred investment tax
credits pursuant to the FERC settlement as discussed in Litigation and
Regulatory Proceedings below, partially offset by lower electric
operating revenues and higher other operation and maintenance
expenses. Net income increased in 1993 due primarily to increased
retail energy sales partially offset by the effects of implementing
SFAS 109 and SFAS 106.
Significant factors affecting the results of operations and
causing variances between the years 1994 and 1993, and 1993 and 1992,
are discussed under "Revenues and Sales" and "Expenses" below.
Revenues and Sales
See "Selected Financial Data - Five-Year Comparison," following
the notes, for information on operating revenues by source and KWH
sales.
Operating revenues were lower in 1994 due primarily to the
completion of the amortization of the proceeds resulting from
litigation with a gas supplier in the second quarter and lower
wholesale revenues partially offset by higher retail revenues.
Wholesale revenues decreased due primarily to lower sales to non-
associated utilities. Retail revenues increased due primarily to
increases in sales to industrial and commercial customers.
Operating revenues were higher in 1993 due primarily to increased
residential and commercial energy sales resulting primarily from a
return to more normal weather as compared to milder weather in 1992.
Industrial energy sales also increased primarily in the petrochemical
industry.
Expenses
Operating expenses decreased in 1994 due primarily to a decrease
in income tax expense as a result of the write-off of the unamortized
balances of deferred investment tax credits pursuant to a FERC
settlement and lower fuel expense partially offset by higher other
operation and maintenance expense. The decrease in fuel for electric
generation and fuel-related expenses and purchased power expense is
due primarily to lower fuel and purchased power prices. The increase
in other operation and maintenance expense is due primarily to
restructuring costs as discussed in Note 12 and power plant waste
water site closures as discussed in Note 8.
Operating expenses increased in 1993 due primarily to an increase
in fuel expense because of increased generation requirements
resulting primarily from increased retail energy sales and higher fuel
costs. Total income taxes increased in 1993 due primarily to higher
pretax income, an increase in the federal income tax rate as a result
of OBRA, and the effect of implementing SFAS 109.
Interest expense decreased in 1994 and 1993 as a result of the
refinancing of high cost debt during 1993 and 1992.
LOUISIANA POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Competition
The electric utility industry is becoming increasingly
competitive and LP&L is seeking to become a leading competitor in the
changing electric energy business. Competition presents LP&L with
many challenges. The following have been identified by LP&L as its
major competitive challenges.
Retail and Wholesale Rate Issues
Increasing competition in the utility industry brings an
increased need to stabilize or reduce retail rates. The retail
regulatory philosophy is shifting in some jurisdictions from
traditional cost of service regulation to incentive rate regulation.
Incentive and performance-based rate plans encourage efficiencies and
productivity while permitting utilities and their customers to share
in the results. In August 1994, LP&L filed a performance-based
formula rate plan with the LPSC. The proposed formula rate plan would
continue existing LP&L rates at current levels, while providing
financial incentive to reduce costs and maintain high levels of
customer satisfaction and system reliability. Hearings were held
in March 1995. See Note 2 for additional information. Recognizing
that many industrial customers have energy alternatives, LP&L
continues to work with these customers to address their needs. In
certain cases, competitive prices are negotiated, using variable rate
design.
Retail wheeling, the transmission by an electric utility of
energy produced by another entity over the utility's transmission and
distribution system to a retail customer in the electric utility's
area of service, is also evolving. Over a dozen states have been or
are studying the concept of retail competition. In April 1994, the
state of Michigan initiated a five-year experiment that allows limited
competition among public utilities. During the same month, the
California Public Utilities Commission proposed to deregulate that
state's electric power industry, starting on January 1, 1996, to allow
the largest industrial customers to select the lowest cost supplier
for electricity service. Under the proposal, by the year 2002,
smaller companies and residential customers in California would also
be able to buy power from any suppliers. The California Public
Utilities Commission is currently reviewing its proposal and is
expected to make a ruling in the first half of 1995. The retail market
for electricity is expected to become more competitive with such moves
toward deregulation.
In some areas of the country, municipalities (or comparable
entities) whose residents are served at retail by an investor-owned
utility pursuant to a franchise are exploring the possibility of
establishing new or extending existing distribution systems or seeking
new delivery points in order to serve retail customers, especially
large industrial customers, that currently receive service from an
investor-owned utility. These options depend on the terms of a
utility's franchise as well as on state law and regulation. In
addition, FERC's authority to order utilities to transmit for a new or
expanding municipal system is limited in certain respects. Where
successful, however, the establishment of a municipal system or the
acquisition by a municipal system of a utility's customers could
result in the inability to recover costs that the utility has incurred
in serving those customers.
In mid-1994, the FERC issued a notice of proposed rulemaking
concerning a regulatory framework for dealing with recovery of
stranded costs, such as high cost nuclear generating units, which may
be incurred by electric utilities as a result of increased
competition. In addition to addressing recovery of stranded costs
related to wholesale service, the proposal requested comment as to
recovery of retail stranded costs in transmission rates where state
regulatory authorities failed to address the issue or were in
conflict. Comments and reply comments have been filed, and the matter
is pending. The risk of exposure to stranded costs which may result
from competition in the industry will depend on the extent and timing
of retail competition, the resolution of jurisdictional issues
concerning stranded cost recovery, and the extent to which such costs
are recovered from departing or remaining customers, among other
matters.
In the wholesale rate area, FERC approved in 1992, with certain
modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy
Power to sell wholesale power at market-based rates and to provide to
electric utilities "open access" to the System's transmission system
(subject to certain requirements). GSU was later added to this
filing. On October 31, 1994, as amended on January 25, 1995, Entergy
Services filed with FERC revised transmission tariffs intended to
provide access to transmission service on the same or comparable
basis, terms, and conditions as the System operating companies, and
the matter is pending. Open access and market pricing, once in
effect, will increase marketing opportunities for LP&L, but will also
expose LP&L to the risk of loss of load or reduced revenues due to
competition with alternative suppliers.
In light of the rate issues discussed above, LP&L is aggressively
reducing costs to avoid potential earnings erosions that might result
as well as to become more competitive. In 1994, LP&L announced a
restructuring program related to certain of its operating units. This
program is designed to reduce costs and improve operating
efficiencies. See Note 12 for further information. Also, in response
to an increasingly competitive environment, LP&L announced intentions
to revise its initial least cost planning activities.
The Energy Policy Act of 1992
The EPAct addresses a wide range of energy issues and is altering
the way Entergy and the rest of the electric utility industry
operate. The EPAct encourages competition and affords utilities the
opportunities, and the risks, associated with an open and more
competitive market environment. The EPAct creates exemptions from
regulation under the Holding Company Act and creates a class of exempt
wholesale generators consisting of utility affiliates and nonutilities
that are owners and operators of facilities for the generation and
transmission of power for sales at wholesale. The EPAct also gives
FERC the authority to order investor-owned utilities, including LP&L,
to transmit power and energy to or for wholesale purchasers and
sellers. The law creates the potential for electric utilities and
other power producers to gain increased access to the transmission
systems of other entities to facilitate wholesale sales. Both LP&L
and Entergy Power expect to compete in this market.
Litigation and Regulatory Proceedings
In November 1994, FERC approved an agreement settling a long-
standing dispute involving income tax allocation procedures of System
Energy. In accordance with the agreement, System Energy refunded
approximately $8.6 million to LP&L, which will make refunds or credits
to its customers (except for those portions attributable to its
retained share of Grand Gulf 1 costs). Additionally, System Energy
will refund a total of approximately $8.7 million, plus interest, to
LP&L over the period through June 2004. The settlement also required
the write-off of approximately $31.5 million of certain related
unamortized balances of deferred investment tax credits by LP&L.
Property Tax Exemptions
Exemption from the payment of Louisiana local property taxes on
Waterford 3 , which has been in effect for 10 years, will expire in
December 1995. LP&L is working with Louisiana local taxing
authorities to determine the method for calculating the amount of the
property taxes to be paid when the exemption expires. LP&L believes
that assessed property taxes will be recovered from its customers
through rates.
Environmental Issues
During 1993, the Louisiana Department of Environmental Quality
issued new rules for solid waste regulation, including waste water
impoundments. LP&L has determined that certain of its power plant
waste water impoundments are affected by these regulations and has
chosen to either upgrade or close them. The aggregate cost of the
upgrades and closures, to be completed by 1996, is estimated to be $16
million.
Accounting Issues
Proposed Accounting Standards - The FASB has proposed a SFAS on
"Accounting for the Impairment of Long-Lived Assets," effective
January 1, 1996. The proposed standard describes circumstances which
may result in assets being impaired and provides criteria for
recognition and measurement of asset impairment. Certain operations of
LP&L are potentially affected by this standard, and any resulting
write-offs will depend on future operating costs, generating units'
efficiency and availability, and the future market for energy over the
remaining life of the units. Based on current estimates, LP&L
anticipates that future revenues will fully recover the costs of such
operations.
Continued Application of SFAS 71 - LP&L's financial statements
currently reflect assets and costs based on current cost-based
ratemaking regulations, in accordance with SFAS 71, "Accounting for
the Effects of Certain Types of Regulation." As discussed above, the
electric utility industry is changing and these changes could possibly
result in the discontinuance of the application of SFAS 71, which
would result in the elimination of regulatory assets and liabilities.
See Note 1 for further information.
Accounting for Decommissioning Costs - The FASB is currently
reviewing the accounting for decommissioning of nuclear plants. This
project could possibly change the System's, as well as the entire
utility industry's, accounting for such costs. For further
information, see Note 8.
LOUISIANA POWER & LIGHT COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
LP&L maintains accounts in accordance with FERC and other
regulatory guidelines. Certain previously reported amounts have been
reclassified to conform to current classifications.
Revenues and Fuel Costs
LP&L records revenues when billed to its customers and, in
addition, accrues revenue for the nonfuel portion of estimated
revenues for energy delivered since the latest billings.
LP&L's rate schedules include fuel adjustment clauses that allow
deferral of fuel costs until such costs are reflected in the related
revenues.
Utility Plant
Utility plant is stated at original cost. Partial disallowances
of plant cost ordered by the regulators have been recorded as an
adjustment to utility plant. The original cost of utility plant
retired or removed, plus the applicable removal costs, less salvage,
is charged to accumulated depreciation. Maintenance, repairs, and
minor replacement costs are charged to operating expenses.
Substantially all of LP&L's utility plant is subject to the lien of
its first mortgage indenture. In addition, certain assets of LP&L are
subject to the liens of second mortgages related to pollution control
revenue bonds.
Utility plant includes the portions of Waterford 3 that were sold
and are currently under lease. LP&L retired this property from its
continuing property records as formerly owned property released from
and no longer subject to LP&L's first mortgage indenture. LP&L is
reflecting such leased property for financial reporting purposes as
property under lease from others and depreciating this property over
the life of the plant. See Note 9 for additional lease disclosure.
Total LP&L net utility plant in service of $3.41 billion as of
December 31, 1994 includes $2.36 billion of production plant, $.24
billion of transmission plant, $.74 billion of distribution plant, and
$.07 billion of other plant.
Depreciation is computed on the straight-line basis at rates
based on the estimated service lives and costs of removal of the
various classes of property. Depreciation provisions on average
depreciable property approximated 2.8% in 1994, 3.0% in 1993, and 2.9%
in 1992.
AFUDC represents the approximate net composite interest cost of
borrowed funds and a reasonable return on the equity funds used for
construction. Although AFUDC increases utility plant and increases
earnings, it is only realized in cash through depreciation provisions
included in rates. LP&L's effective composite rates for AFUDC were
10.1%, 10.4%, and 10.7%, for 1994, 1993, and 1992, respectively.
Income Taxes
LP&L, its parent, and affiliates file a consolidated federal
income tax return. Income taxes are allocated to LP&L in proportion
to its contribution to consolidated taxable income. SEC regulations
require that no Entergy Corporation subsidiary pay more taxes than it
would have had a separate income tax return been filed. Deferred
taxes are recorded for all temporary differences between book and
taxable income. Investment tax credits are deferred and amortized
based upon the average useful life of the related property in
accordance with rate treatment. As discussed in Note 3, in 1993 LP&L
changed its accounting for income taxes to conform with SFAS 109.
Reacquired Debt
The premiums and costs associated with reacquired debt are being
amortized over the life of the related new issuances, in accordance
with ratemaking treatment.
Cash and Cash Equivalents
LP&L considers all unrestricted highly liquid debt instruments
purchased with an original maturity of three months or less to be cash
equivalents.
Continued Application of SFAS 71
As a result of the EPAct and actions of regulatory commissions,
the electric utility industry is moving toward a combination of
competition and a modified regulatory environment. LP&L's financial
statements currently reflect assets and costs based on current cost-
based ratemaking regulations in accordance with SFAS 71, "Accounting
for the Effects of Certain Types of Regulation." Continued
applicability of SFAS 71 to LP&L's financial statements requires that
rates set by an independent regulator on a cost of service basis
(including a reasonable rate of return on invested capital) can
actually be charged to and collected from customers.
In the event that either all or a portion of a utility's
operations cease to meet those criteria for various reasons, including
deregulation, a change in the method of regulation or a change in the
competitive environment for the utility's regulated services, the
utility should discontinue application of SFAS 71 for the relevant
portion. That discontinuation should be reported by elimination from
the balance sheet of the effects of any actions of regulators
recorded as regulatory assets and liabilities.
As of December 31, 1994, and for the foreseeable future, LP&L's
financial statements continue to follow SFAS 71.
Fair Value Disclosure
The estimated fair value of financial instruments has been
determined by LP&L, using available market information and appropriate
valuation methodologies. However, considerable judgment is required
in developing the estimates of fair value. Therefore, estimates are
not necessarily indicative of the amounts that LP&L could realize in a
current market exchange. In addition, gains or losses realized on
financial instruments may be reflected in future rates and not accrue
to the benefit of stockholders.
LP&L considers the carrying amounts of financial instruments
classified as current assets and liabilities to be a reasonable
estimate of their fair value because of the short maturity of these
instruments. In addition, LP&L does not presently expect that
performance of its obligations will be required in connection with
certain off-balance sheet commitments and guarantees considered
financial instruments. Due to this factor, and because of the related
party nature of these commitments and guarantees, determination of
fair value is not considered practicable. See Notes 5, 6, and 8 for
additional fair value disclosure.
LP&L adopted the provisions of SFAS 115, "Accounting for Certain
Investments in Debt and Equity Securities," effective January 1, 1994.
As a result, at December 31, 1994, LP&L recorded on the balance sheet
a reduction of $1.1 million in decommissioning trust funds,
representing the amount by which the fair value of the securities held
in such funds is less than amounts recovered in rates for
decommissioning and deposited in the funds and the related earnings on
the amounts deposited. Due to the regulatory treatment for
decommissioning trust funds, LP&L recorded an offsetting amount in
unrealized losses on investment securities as a regulatory asset.
NOTE 2. RATE AND REGULATORY MATTERS
LPSC Rate Review
In August 1994, LP&L filed a performance-based formula rate plan
with the LPSC. The proposed formula rate plan would continue existing
LP&L rates at current levels, while providing financial incentive to
reduce costs and maintain high levels of customer satisfaction and
system reliability. A performance rating adjustment feature of the
plan would allow LP&L the opportunity to earn a higher rate of return
if it improves performance over time. Conversely, if performance
declines, the rate of return LP&L could earn would be lowered. This
provides financial incentive for LP&L to maintain continuous
improvement in all three performance categories (customer price,
customer satisfaction, and customer reliability). Under the proposed
plan, if LP&L's earnings fall within a bandwidth around a benchmark
rate of return, there would be no adjustment in rates. If LP&L's
earnings are above the bandwidth, the proposed plan would
automatically reduce LP&L's base rates. Alternatively, if LP&L's
earnings are below the bandwidth, the proposed plan would
automatically increase LP&L's base rates. The reduction or increase
in base rates would be an amount representing 50% of the difference
between the earned rate of return and the nearest limit of the
bandwidth. In no event would the annual adjustment in rates exceed 2%
of LP&L's retail revenues. Hearings were held in March 1995. No
assurance can be given that the LPSC will accept the performance-
based formula rate plan, or that the current rate review will not
result in a rate decrease.
Waterford 3 and Grand Gulf 1
In a series of LPSC orders, court decisions, and agreements
between November 1985 and June 1988, LP&L was granted Waterford 3 and
Grand Gulf 1 rate relief. In addition, LP&L, in accordance with
judicial decisions and LPSC rate orders, deferred a net amount of
$266 million of its Waterford 3 costs related to the period
November 14, 1985 through January 31, 1988. These deferred costs are
being recovered over approximately 8.6 years beginning in April 1988.
In November 1985, LP&L agreed to permanently absorb, and not
recover from its retail customers, 18% of its 14% (approximately
2.52%) FERC-allocated share of the costs of capacity and energy of
Grand Gulf 1. LP&L is allowed to recover through the fuel adjustment
clause 4.6 cents per KWH (as of May 1994) for the energy related to
its retained portion of these costs. Alternatively, LP&L may sell such
energy to nonaffiliated parties at prices above the fuel adjustment
clause recovery amount, subject to LPSC approval. For the year ended
December 31, 1994, $66 million was billed to LP&L by System Energy.
NOTE 3. INCOME TAXES
Income tax expense consisted of the following:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Current:
Federal $68,891 $62,037 $30,326
State 10,369 8,514 6,139
------- -------- -------
Total 79,260 70,551 36,465
------- -------- -------
Deferred - net:
Liberalized depreciation 55,083 54,297 53,751
Unbilled revenue 2,081 3,474 (7,906)
Deferred Waterford 3 expenses (14,043) (14,043) (14,043)
Adjustment of prior years' tax provisions 2,447 2,665 (5,331)
Waterford 3 sale and leaseback (3,571) (3,632) (3,526)
Gas contract settlement 5,483 9,513 15,180
Nuclear refueling and maintenance 3,407 (5,768) 1,989
Materials and supplies inventory adjustments (2,446) (2,505) (2,497)
Alternative minimum tax (14,604) (8,781) -
Property insurance reserve 521 23 3,119
Deferred fuel (5,148) (1,337) 2,977
Bond reacquisition (1,502) (243) 4,868
Decontamination and decommissioning fund 573 5,273 -
Environmental reserve (5,832) 213 -
Other (869) 3,868 3,308
------- -------- -------
Total 21,580 43,017 51,889
------- -------- -------
Investment tax credit adjustments - net (6,048) (2,755) (1,317)
Investment tax credit amortization - FERC settlement (31,504) - -
------- -------- -------
Recorded income tax expense $63,288 $110,813 $87,037
======= ======== =======
Charged to operations $63,751 $108,568 $83,984
Charged to other income (463) 2,245 3,053
------- -------- -------
Recorded income tax expense 63,288 110,813 87,037
Income taxes applied against the debt
component of AFUDC - - 442
------- -------- -------
Total income taxes $63,288 $110,813 $87,479
======= ======== =======
Total income taxes differ from the amounts computed by applying
the statutory federal income tax rate to income before taxes. The
reasons for the differences were:
For the Years Ended December 31,
1994 1993 1992
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
(Dollars in Thousands)
Computed at statutory rate $96,994 35.0 $104,867 35.0 $91,809 34.0
Increases (reductions) in tax resulting from:
State income taxes net of federal
income tax effect 5,147 1.9 6,727 2.2 4,272 1.6
Depreciation 3,219 1.2 2,550 0.9 3,064 1.1
Impact of change in tax rate (2,749) (1.0) (2,767) (0.9) (3,989) (1.5)
Amortization of investment tax credits (6,305) (2.3) (6,876) (2.3) (6,780) (2.5)
Investment tax credit amortization -
FERC Settlement (31,504) (11.3) - - - -
SFAS 109 adjustment - - 4,193 1.4 - -
Other - net (1,514) (0.6) 2,119 0.7 (1,339) (0.5)
------- ---- -------- ---- ------- ----
Recorded income tax expense $63,288 22.9 $110,813 37.0 $87,037 32.2
Income taxes applied against the debt
component of AFUDC - - - - 442 0.2
------- ---- -------- ---- ------- ----
Total income taxes $63,288 22.9 $110,813 37.0 $87,479 32.4
======= ==== ======== ==== ======= ====
Significant components of LP&L's net deferred tax liabilities as
of December 31, 1994 and 1993, were (in thousands):
1994 1993
Deferred tax liabilities:
Net regulatory assets $ (437,468) $ (422,371)
Plant related basis differences (722,653) (665,517)
Rate deferrals (26,695) (40,737)
Bond reacquisition loss (15,866) (17,368)
Other (17,106) (14,429)
----------- -----------
Total $(1,219,788) $(1,160,422)
=========== ===========
Deferred tax assets:
Unbilled revenues $ 11,108 $ 13,190
Accumulated deferred investment tax credit 58,205 72,667
Gas contract settlement 7,539 12,917
Removal cost 52,576 47,603
Alternative minimum tax credit 56,222 41,618
Standard coal plant 12,561 12,898
Waterford 3 sale/leaseback 102,111 98,541
Environmental reserve 6,308 476
Other 32,915 31,644
----------- ----------
Total $ 339,545 $ 331,554
=========== ==========
Net deferred tax liabilities $ (880,243) $ (828,868)
=========== ==========
The alternative minimum tax (AMT) credit as of December 31, 1994,
was $56.2 million. This AMT credit can be carried forward
indefinitely and will reduce LP&L's federal income tax liability in
future years.
In accordance with a System Energy FERC settlement, LP&L wrote
off $31.5 million of unamortized deferred investment tax credits
in 1994.
In 1993, LP&L adopted SFAS 109. SFAS 109 required that deferred
income taxes be recorded for all temporary differences and
carryforwards, and that deferred tax balances be based on enacted tax
laws at tax rates that are expected to be in effect when the temporary
differences reverse. SFAS 109 required that regulated enterprises
recognize adjustments resulting from implementation as regulatory
assets or liabilities if it is probable that such amounts will be
recovered from or returned to customers in future rates. A
substantial majority of the adjustments required by SFAS 109 was
recorded to deferred tax balance sheet accounts with offsetting
adjustments to regulatory assets and liabilities. As a result of the
adoption of SFAS 109, 1993 net income was reduced by $5.7 million,
assets were increased by $309.7 million, and liabilities were
increased by $315.4 million. The cumulative effect of the adoption of
SFAS 109 is included in income tax expense charged to operations.
In August 1994, Entergy received an Internal Revenue Service
report covering the federal income tax audit of Entergy Corporation
and subsidiaries for the years 1988 - 1990. The report asserts an $80
million tax deficiency for the 1990 consolidated federal income tax
returns related primarily to the application of accelerated investment
tax credits associated with Waterford 3 and Grand Gulf nuclear plants.
Entergy believes there is no material tax deficiency and is vigorously
contesting the proposed assessment.
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized LP&L to effect short-term borrowings up to
$150 million, which may be increased to as much as $236 million after
further SEC approval. This authorization is effective through
November 30, 1996. As of December 31, 1994, LP&L had outstanding
short-term lines of credit of $19.2 million from banks within its
service territory. Interest rates associated with these lines of
credit generally are based on the prime rate, the London interbank
offered rate, or a bid rate. Commitment fees on these lines of credit
are .125% of the amount of available credit. In addition, LP&L can
borrow from the Money Pool, subject to its maximum authorized level of
short-term borrowings and the availability of funds. LP&L had $8
million of outstanding borrowings under the Money Pool arrangement as
of December 31, 1994.
NOTE 5. PREFERRED STOCK
The number of shares and dollar value of LP&L's preferred stock
were:
As of December 31,
Shares Call Price Per
Authorized and Total Share as of
Outstanding Dollar Value December 31,
1994 1993 1994 1993 1994
(Dollars in Thousands)
Without sinking fund:
Cumulative, $100 par value
4.96% Series 60,000 60,000 $6,000 $6,000 $104.25
4.16% Series 70,000 70,000 7,000 7,000 $104.21
4.44% Series 70,000 70,000 7,000 7,000 $104.06
5.16% Series 75,000 75,000 7,500 7,500 $104.18
5.40% Series 80,000 80,000 8,000 8,000 $103.00
6.44% Series 80,000 80,000 8,000 8,000 $102.92
7.84% Series 100,000 100,000 10,000 10,000 $103.78
7.36% Series 100,000 100,000 10,000 10,000 $103.36
8.56% Series 100,000 100,000 10,000 10,000 $103.14
Cumulative, $25 par value
8.00% Series (1) 1,480,000 1,480,000 37,000 37,000 -
9.68% Series (1) 2,000,000 2,000,000 50,000 50,000 -
--------- --------- -------- --------
Total without sinking fund 4,215,000 4,215,000 $160,500 $160,500
========= ========= ======== ========
With sinking fund:
Cumulative, $100 par value
7.00% Series (1) 500,000 500,000 $50,000 $50,000 -
8.00% Series (1) 350,000 350,000 35,000 35,000 -
Cumulative, $25 par value
10.72% Series 150,211 390,211 3,756 9,755 $25.67
13.12% Series - 61,121 - 1,528 -
14.72% Series - 416 - 10 -
12.64% Series 900,370 1,200,370 22,509 30,009 $27.37
--------- --------- -------- --------
Total with sinking fund 1,900,581 2,502,118 $111,265 $126,302
========= ========= ======== ========
(1) These series are not redeemable as of December 31, 1994.
The fair value of LP&L's preferred stock with sinking fund was
estimated to be approximately $113.0 million and $141.9 million as of
December 31, 1994 and 1993, respectively. The fair values were
determined using quoted market prices or estimates from nationally
recognized investment banking firms. See Note 1 for additional
information on disclosure of fair value of financial instruments.
Changes in preferred stock, with and without sinking fund, during
the last three years were:
Number of Shares
1994 1993 1992
Preferred stock issuances:
$100 par value - - 500,000
$25 par value - - 1,480,000
Preferred stock retirements:
$100 par value - - (370,000)
$25 par value (601,537) (900,000) (1,015,160)
Cash sinking fund requirements for the next five years for
preferred stock outstanding as of December 31, 1994 are (in millions):
1995 - $6.8; 1996 - $4.5; 1997 - $3.8; 1998 - $3.8; and 1999 - $53.8.
LP&L has the annual non-cumulative option to redeem, at par,
additional amounts of certain series of its outstanding preferred
stock.
NOTE 6. LONG-TERM DEBT
LP&L's long-term debt as of December 31, 1994 and 1993, was:
Maturities Interest Rates
From To From To 1994 1993
(In Thousands)
First Mortgage Bonds
1995 1999 5-5/8% 10.36% $ 179,000 $ 204,000
2000 2004 6% 8% 361,520 361,520
2020 2022 8-1/2% 10-1/8% 185,000 185,000
Governmental Obligations*
1994 2009 6-2/5% 8% 40,472 37,794
2010 2023 5.95% 8-1/4% 367,400 350,000
Waterford 3 Lease Obligation, 8.76% (Note 9) 353,600 353,600
Unamortized Premium and Discount - Net (8,617) (8,973)
---------- ----------
Total Long-Term Debt 1,478,375 1,482,941
Less Amount Due Within One Year 75,320 25,315
---------- ----------
Long-Term Debt Excluding Amount Due Within One $1,403,055 $1,457,626
Year ========== ==========
* Consists of pollution control bonds, certain series of which are
secured by non-interest bearing first mortgage bonds.
The fair value of LP&L's long-term debt, excluding Waterford 3
lease obligation and long-term Purchase Agreement, as of December 31,
1994 and 1993 was estimated to be $1,089.2 million and $1,205.1
million, respectively. The fair values were determined using quoted
market prices or estimates from nationally recognized investment
banking firms. See Note 1 for additional information on disclosure of
fair value of financial instruments.
For the years 1995, 1996, 1997, 1998, and 1999, LP&L has
long-term debt maturities and cash sinking fund requirements of (in
millions): $75.3, $35.3, $34.3, $35.3 and $0.2, respectively. In
addition, other sinking fund requirements of approximately
$5.9 million annually may be satisfied by cash or by certification of
property additions at the rate of 167% of such requirements.
NOTE 7. DIVIDEND RESTRICTIONS
LP&L's Restated Articles of Incorporation, as amended, and
certain of its indentures, contain provisions restricting the payment
of cash dividends or other distributions on common stock. As of
December 31, 1994, none of LP&L's retained earnings were restricted
against the payment of cash dividends or other distributions on common
stock. On February 1, 1995, LP&L paid Entergy Corporation a $55.7
million cash dividend on common stock.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Capital Requirements and Financing
Construction expenditures (excluding nuclear fuel) for the years
1995, 1996, and 1997 are estimated to total $115.4 million each year.
LP&L will also require $160 million during the period 1995-1997 to
meet long-term debt and preferred stock maturities and cash sinking
fund requirements. LP&L plans to meet the above requirements with
internally generated funds and cash on hand, supplemented by the
issuance of debt. See Notes 5 and 6 regarding the possible refunding,
redemption, purchase or other acquisition of certain outstanding
series of preferred stock and long-term debt.
Unit Power Sales Agreement
System Energy has agreed to sell all of its 90% owned and leased
share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L,
and NOPSI in accordance with specified percentages (AP&L 36%, LP&L
14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this
agreement are paid in consideration for LP&L's respective entitlement
to receive capacity and energy, and are payable irrespective of the
quantity of energy delivered so long as the unit remains in commercial
operation. The agreement will remain in effect until terminated by
the parties and approved by FERC, most likely upon Grand Gulf 1's
retirement from service. LP&L's monthly obligation for payments under
the agreement is approximately $7 million.
Availability Agreement
AP&L, LP&L, MP&L, and NOPSI are individually obligated to make
payments or subordinated advances to System Energy in accordance with
stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI
24.7%) in amounts that when added to amounts received under the Unit
Power Sales Agreement or otherwise, are adequate to cover all of
System Energy's operating expenses. System Energy has assigned its
rights to payments and advances to certain creditors as security for
certain obligations. Since commercial operation of Grand Gulf 1,
payments under the Unit Power Sales Agreement have exceeded the
amounts payable under the Availability Agreement. Accordingly, no
payments have ever been required. If AP&L, MP&L, or NOPSI fails to
make its Unit Power Sales Agreement payments, and System Energy is
unable to obtain funds from other sources, LP&L could be liable for
payments to System Energy, in amounts that cannot be determined, over
and above its payments under the Unit Power Sales Agreement.
Reallocation Agreement
System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the
Reallocation Agreement relating to the sale of capacity and energy
from the Grand Gulf Station and the related costs, in which LP&L,
MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and
obligations with respect to the Grand Gulf Station under the
Availability Agreement. FERC's decision allocating a portion of Grand
Gulf 1 capacity and energy to AP&L supersedes the Reallocation
Agreement as it relates to Grand Gulf 1. Responsibility for any Grand
Gulf 2 amortization amounts has been individually allocated (LP&L
26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the
Reallocation Agreement. However, the Reallocation Agreement does not
affect AP&L's obligation to System Energy's lenders under the
assignments referred to in the preceding paragraph. AP&L would be
liable for its share of such amounts if LP&L, MP&L, and NOPSI were
unable to meet their contractual obligations. No payments of any
amortization amounts will be required as long as amounts paid to
System Energy under the Unit Power Sales Agreement, including other
funds available to System Energy, exceed amounts required under the
Availability Agreement, which is expected to be the case for the
foreseeable future.
System Fuels
LP&L has a 33% interest in System Fuels, a jointly owned
subsidiary of AP&L, LP&L, MP&L, and NOPSI. The parent companies of
System Fuels, including LP&L, agreed to make loans to System Fuels to
finance its fuel procurement, delivery, and storage activities. As of
December 31, 1994, LP&L had approximately $14.2 million of loans
outstanding to System Fuels which mature in 2008.
In addition, System Fuels entered into a revolving credit
agreement with a bank that provides $45 million in borrowings to
finance System Fuels' nuclear materials and services inventory.
Should System Fuels default on its obligations under its credit
agreement, AP&L, LP&L, and System Energy have agreed to purchase the
nuclear materials and services financed under the agreement.
Long-Term Contracts
LP&L has a long-term agreement through the year 2031 to purchase
energy generated by a hydroelectric facility. During 1994, 1993, and
1992, LP&L made payments under the contract of approximately
$56.3 million, $66.9 million, and $39.1 million, respectively. If the
maximum percentage (94%) of the energy is made available to LP&L,
current production projections would require estimated payments of
approximately $47 million per year through 1996, $54 million in 1997,
and a total of $3.5 billion for the years 1998 through 2031. LP&L
recovers the costs of purchased energy through its fuel adjustment
clause.
In June 1992, LP&L agreed to a renegotiated 20-year natural gas
supply contract. LP&L has agreed to purchase natural gas in annual
amounts equal to approximately one-third of its projected annual fuel
requirements for certain generating units. Annual demand charges
associated with this contract are estimated to be $9 million through
1997, and a total of $124 million for the years 1998 through 2012.
LP&L recovers the cost of fuel consumed during the generation of
electricity through its fuel adjustment clause.
Nuclear Insurance
The Price-Anderson Act limits public liability for a single
nuclear incident to approximately $8.92 billion as of December 31,
1994. LP&L has protection for this liability through a combination of
private insurance (currently $200 million) and an industry assessment
program. Under the assessment program, the maximum amount that would
be required for each nuclear incident would be $79.3 million per
reactor, payable at a rate of $10 million per licensed reactor per
incident per year. LP&L has one licensed reactor. In addition, LP&L
participates in a private insurance program which provides coverage
for worker tort claims filed for bodily injury caused by radiation
exposure. LP&L's maximum assessment under the program is an aggregate
of approximately $3.2 million in the event losses exceed accumulated
reserve funds.
LP&L is a member of certain insurance programs that provide
coverage for property damage, including decontamination and premature
decommissioning expense, to members' nuclear generating plants. As of
December 31, 1994, LP&L was insured against such losses up to
$2.75 billion, with $250 million of this amount designated to cover
any shortfall in the NRC required decommissioning trust funding. In
addition, LP&L is a member of an insurance program that covers certain
costs of replacement power and business interruption incurred due to
prolonged nuclear unit outages. Under the property damage and
replacement power/business interruption insurance programs, LP&L could
be subject to assessments if losses exceed the accumulated funds
available to the insurers. As of December 31, 1994, the maximum
amount of such possible assessments to LP&L was $34.7 million.
The amount of property insurance presently carried by LP&L
exceeds the Nuclear Regulatory Commission's (NRC) minimum requirement
for nuclear power plant licensees of $1.06 billion per site. NRC
regulations provide that the proceeds of this insurance must be used,
first, to place and maintain the reactor in a safe and stable
condition and, second, to complete decontamination operations. Only
after proceeds are dedicated for such use and regulatory approval is
secured, would any remaining proceeds be made available for the
benefit of plant owners or their creditors.
Spent Nuclear Fuel and Decommissioning Costs
LP&L provides for estimated future disposal costs for spent
nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982.
LP&L entered into a contract with the DOE, whereby the DOE will
furnish disposal service at a cost of one mill per net KWH generated
and sold. The fees payable to the DOE may be adjusted in the future to
assure full recovery. LP&L considers all costs incurred or to be
incurred, except accrued interest, for the disposal of spent nuclear
fuel to be proper components of nuclear fuel expense, and provisions
to recover such costs have been accepted by the LPSC.
Delays have occurred in the DOE's program for the acceptance and
disposal of spent nuclear fuel at a permanent repository. In a
statement released February 17, 1993, the DOE asserted that it does
not have a legal obligation to accept spent nuclear fuel without an
operational repository for which it has not yet arranged. Currently
the DOE projects it will begin to accept spent fuel no earlier than
2010. In the meantime, LP&L is responsible for spent fuel storage.
Current on-site spent fuel storage capacity at Waterford 3 is
estimated to be sufficient until 2000. Thereafter, LP&L will provide
additional storage capacity at an estimated initial cost of
$5.0 million to $10.0 million. In addition, approximately
$3.0 million to $5.0 million will be required every four to five years
subsequent to 2000 until the DOE's repository begins accepting
Waterford 3's spent fuel.
Entergy Operations and System Fuels joined in lawsuits against
the DOE, seeking clarification of the DOE's responsibility to receive
spent nuclear fuel beginning in 1998. The original suits, filed June
20, 1994, asked for a ruling stating that the Nuclear Waste Policy Act
require the DOE to begin taking title to the spent fuel and to start
removing it from nuclear power plants in 1998, a mandate for the DOE's
nuclear waste management program to begin accepting fuel in 1998 and
court monitoring of the program, and the potential for escrow of
payments to a nuclear waste fund instead of directly to the DOE.
Decommissioning costs for Waterford 3 were estimated to be
$203.0 million (in 1988 dollars), based on a 1988 update to the
original cost study. LP&L had LPSC authorization to fund and recover
$4.0 million of decommissioning costs annually through 1993, based on
the 1988 study update. LP&L has funded at an annual rate of
$4.8 million since January 1994, in anticipation of a 1994 study
update and a related LPSC review and determination of appropriate
funding levels. The updated cost study completed in 1994 (in 1993
dollars) reflected a cost of decommissioning of $320.1 million. LP&L
filed the updated cost study with the LPSC and requested a rate
adjustment for decommissioning expense, which is being reviewed. The
amounts recovered in rates are deposited in an external trust fund and
are reported at market value. The accumulated decommissioning
liability of $28.2 million as of December 31, 1994 has been recorded
in accumulated depreciation. Decommissioning expense in the amount of
$4.8 million was recorded in 1994. The actual decommissioning costs
may vary from the above estimates because of regulatory requirements,
changes in technology, and increased costs of labor, materials, and
equipment. Management believes that actual decommissioning costs are
likely to be higher than the amounts presented above.
The staff of the SEC has questioned certain of the current
accounting practices of the electric utility industry, regarding the
recognition, measurement, and classification of decommissioning costs
for nuclear generating stations in the financial statements of
electric utilities. In response to these questions, FASB is currently
reviewing the accounting for decommissioning. If current electric
utility industry accounting practices for such decommissioning are
changed, annual provisions for decommissioning could increase, the
estimated cost for decommissioning could be recorded as a liability
rather than as accumulated depreciation, and trust fund income from
the external decommissioning trusts could be reported as investment
income rather than as a reduction to decommissioning expense.
The EPAct has a provision that assesses domestic nuclear
utilities with fees for the decontamination and decommissioning of the
DOE's past uranium enrichment operations. The decontamination and
decommissioning assessments will be used to set up a fund into which
contributions from utilities and the federal government will be
placed. LP&L's annual assessment, which will be adjusted annually for
inflation, is $1.3 million (in 1995 dollars) for approximately 15
years. FERC requires that utilities treat these assessments as costs
of fuel as they are amortized. The cumulative liability of
$14.5 million at December 31, 1994 is recorded in other current
liabilities and other noncurrent liabilities, according to FERC
guidelines, and is offset in the financial statements by a regulatory
asset.
Sales/Use Tax Issues
In September 1994, the Louisiana Supreme Court (Court) issued an
opinion (in a case in which none of the System companies was a party)
holding, in part, that the Louisiana state legislature's suspension of
state sales and use tax exemptions also had the effect of suspending
exemptions from local sales and use taxes. On January 27, 1995 the
Court, after rehearing, reversed its opinion. Because of the Court's
most recent ruling, sales of electricity and gas, fuels and other
items used by LP&L to generate electricity in Louisiana, as well as
other items exempt from sales and use taxes, continue to be exempt
from local sales and use taxes, even though the state exemptions for
sales and use tax have been suspended.
Environmental Issues
During 1993, the Louisiana Department of Environmental Quality
issued new rules for solid waste regulation, including waste water
impoundments. LP&L has determined that certain of its power plant
waste water impoundments are affected by these regulations and has
chosen to either upgrade or close them. The aggregate cost of the
upgrades and closures, to be completed by 1996, is estimated to be $16
million.
NOTE 9. LEASES
General
As of December 31, 1994, LP&L had noncancelable operating leases
with minimum lease payments as follows (in thousands):
1995 $ 4,395
1996 4,038
1997 3,924
1998 3,811
1999 3,505
Years thereafter 3,413
--------
Minimum lease payments $ 23,086
========
Rental expense for operating leases amounted to approximately
$12.1 million, $6.6 million, and $8.7 million in 1994, 1993, and 1992,
respectively.
Nuclear Fuel Lease
LP&L has an arrangement to lease nuclear fuel in an amount up to
$95 million. The lessor finances its acquisition of nuclear fuel
through a credit agreement and the issuance of notes. The credit
agreement, which was entered into in 1989, has been extended to
January 1998, and the notes have varying remaining maturities of up to
4 years. It is expected that the credit arrangement will be extended
or alternative financing will be secured by the lessor upon the
maturity of the current arrangements. If the lessor cannot arrange
for alternative financing upon maturity of its borrowings, LP&L must
purchase nuclear fuel in an amount sufficient to enable the lessor to
retire such borrowings.
Lease payments are based on nuclear fuel use. Nuclear fuel lease
expense of $32.2 million, $39.9 million, and $38.3 million (including
interest of $4.3 million, $4.9 million, and $5.4 million) was charged
to operations in 1994, 1993, and 1992, respectively.
Waterford 3 Lease Obligations
On September 28, 1989, LP&L entered into three substantially
identical, but entirely separate, transactions for the sale (for an
aggregate cash consideration of $353.6 million) and leaseback of three
undivided portions of its 100% ownership interest in Waterford 3. The
three undivided interests in Waterford 3 sold and leased back exclude
certain transmission, pollution control, and other facilities that are
part of Waterford 3. The interests sold and leased back, as described
above, are equivalent on an aggregate cost basis to approximately 9.3%
of Waterford 3. The sales were made to an Owner Trustee under three
separate, but identical, trust agreements with three Owner
Participants. LP&L is leasing back the sold interests from the Owner
Trustee on a net lease basis over an approximate 28-year basic lease
term. LP&L has options to terminate the lease and to repurchase the
sold interests in Waterford 3 at certain intervals during the basic
lease term. Further, at the end of the basic lease term, LP&L has an
option to renew the lease or to repurchase the undivided interests in
Waterford 3.
The Owner Trustee acquired the interests with funds provided by
the Owner Participants and with funds obtained from the issuance and
sale by the Owner Trustee of intermediate-term and long-term bonds.
The lease payments to be made by LP&L will be sufficient to service
the debt incurred by the Owner Trustee.
LP&L did not exercise its option to repurchase the undivided
interests in Waterford 3 on the fifth anniversary (September 1994) of
the closing date of the sale and leaseback transactions. As a result,
LP&L was required to provide collateral to the Owner Participants for
the equity portion of certain amounts payable by LP&L under the lease.
Such collateral was in the form of a new series of non-interest
bearing first mortgage bonds in the aggregate principal amount of
$208.2 million issued by LP&L in September 1994 under its first
mortgage bond indenture.
Upon the occurrence of certain adverse events (including lease
events of default, events of loss, deemed loss events or certain
adverse "Financial Events" with respect to LP&L), LP&L may be
obligated to pay amounts sufficient to permit the Owner Participants
to withdraw from the lease transactions and LP&L may be required to
assume the outstanding bonds issued by the Owner Trustee to finance
its acquisition of the undivided interests in Waterford 3. "Financial
Events" include, among other things, failure by LP&L, following the
expiration of any applicable grace or cure periods, to maintain (1) as
of the end of any fiscal quarter, total equity capital (including
preferred stock) at least equal to 30% of adjusted capitalization, or
(2) in respect of the 12-month period ending on the last day of any
fiscal quarter, a fixed charge coverage ratio of at least 1.50. As of
December 31, 1994, LP&L's total equity capital (including preferred
stock) was 49.10% of adjusted capitalization and its fixed charge
coverage ratio was 3.01.
In accordance with SFAS 98, "Accounting for Leases," due to
"continuing involvement" by LP&L, the sale and leaseback by LP&L of
the undivided portions of Waterford 3, as described above, are
required to be reflected for financial reporting purposes as financing
transactions in LP&L's financial statements even though such portions
are no longer owned by LP&L. See Note 1 for further information
regarding financial reporting treatment.
As of December 31, 1994, LP&L had future minimum lease payments
(reflecting an overall implicit rate of 8.76%) in connection with the
Waterford 3 sale and leaseback transactions as follows (in thousands):
1995 $ 32,569
1996 35,165
1997 39,805
1998 41,447
1999 50,530
Years thereafter 676,214
--------
Minimum lease payments $875,730
========
NOTE 10. POSTRETIREMENT BENEFITS
Pension Plan
LP&L has a defined benefit pension plan covering substantially
all of its employees. The pension plan is noncontributory and
provides pension benefits based on employees' credited service and
average compensation, generally during the last five years before
retirement. LP&L funds pension costs in accordance with contribution
guidelines established by the Employee Retirement Income Security Act
of 1974, as amended, and the Internal Revenue Code of 1986, as
amended. The assets of the plan consist primarily of common and
preferred stocks, fixed income securities, interest in a money market
fund, and insurance contracts.
LP&L's 1994, 1993, and 1992 pension cost, including amounts
capitalized, included the following components:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Service cost - benefits earned during the period $5,441 $4,900 $4,307
Interest cost on projected benefit obligation 14,473 14,684 14,110
Actual return on plan assets 2,024 (26,533) (14,329)
Net amortization and deferral (19,981) 8,712 (3,113)
------- ------- -------
Net pension cost $1,957 $1,763 $975
======= ======= =======
The funded status of LP&L's pension plan as of December 31, 1994
and 1993, was (excluding amounts allocable to NOPSI):
1994 1993
(In Thousands)
Actuarial present value of accumulated pension plan benefits:
Vested $154,927 $179,049
Nonvested 795 768
-------- --------
Accumulated benefit obligation $155,722 $179,817
======== ========
Plan assets at fair value $198,724 $224,203
Projected benefit obligation 178,895 211,928
-------- --------
Plan assets in excess of projected benefit obligation 19,829 12,275
Unrecognized prior service cost 4,881 6,257
Unrecognized transition asset (19,653) (22,460)
Unrecognized net gain (16,677) (5,734)
-------- --------
(11,620) (9,662)
Unfunded portion of NOPSI pension liability (1,584) (12,256)
-------- --------
Accrued pension liability $(13,204) $(21,918)
======== ========
The significant actuarial assumptions used in computing the
information above for 1994, 1993, and 1992 were as follows: weighted
average discount rate, 8.5% for 1994, 7.5% for 1993 and 8.25% for 1992
; weighted average rate of increase in future compensation levels,
5.1% for 1994 and 5.6% for 1993 and 1992; and expected long-term rate
of return on plan assets, 8.5%. Transition assets are being amortized
over 15 years.
Other Postretirement Benefits
LP&L also provides certain health care and life insurance
benefits for retired employees. Substantially all employees may
become eligible for these benefits if they reach retirement age while
still working for LP&L. The cost of providing these benefits,
recorded on a cash basis, to retirees in 1992 was approximately
$3.7 million.
Effective January 1, 1993, LP&L adopted SFAS 106. This standard
required a change from a cash method to an accrual method of
accounting for postretirement benefits other than pensions. LP&L
continues to fund these benefits on a pay-as-you-go basis. As of
January 1, 1993, the actuarially determined accumulated postretirement
benefit obligation (APBO) earned by retirees and active employees was
estimated to be approximately $59.4 million. This obligation is being
amortized over a 20-year period beginning in 1993.
The LPSC ordered LP&L to use the pay-as-you-go method for
ratemaking purposes for postretirement benefits other than pensions,
but the LPSC retains the flexibility to examine individual companies'
accounting for postretirement benefits to determine if special
exceptions to this order are warranted.
LP&L's 1994 and 1993 postretirement benefit cost, including
amounts capitalized and deferred, included the following components:
1994 1993
(In Thousands)
Service cost - benefits earned during the period $2,433 $2,083
Interest cost on APBO 4,422 4,749
Net amortization and deferral 3,066 2,971
------ ------
Net periodic postretirement benefit cost $9,921 $9,803
====== ======
The funded status of LP&L's postretirement plan as of December
31, 1994 and 1993, was as follows:
1994 1993
(In Thousands)
Accumulated postretirement benefit obligation:
Retirees $ 38,401 $ 41,769
Other fully eligible participants 8,550 6,825
Other active participants 9,695 21,085
-------- --------
56,646 69,679
Plan assets at fair value - -
-------- --------
Plan assets less than APBO (56,646) (69,679)
Unrecognized transition obligation 53,488 56,459
Unrecognized net loss (gain) (8,253) 7,579
-------- --------
Accrued postretirement benefit liability $(11,411) $ (5,641)
======== ========
The assumed health care cost trend rate used in measuring the
APBO was 9.4% for 1995, gradually decreasing each successive year
until it reaches 5% in 2011. A one percentage-point increase in the
assumed health care cost trend rate for each year would have increased
the APBO as of December 31, 1994, by 8.9% and the sum of the service
cost and interest cost by approximately 11.4%. The assumed discount
rate and rate of increase in future compensation used in determining
the APBO were 8.5% for 1994 and 7.5% for 1993 and 5.1% for 1994 and
5.5% for 1993, respectively.
NOTE 11. TRANSACTIONS WITH AFFILIATES
LP&L buys electricity from and/or sells electricity to the other
System operating companies and System Energy under rate schedules
filed with FERC. In addition, LP&L purchases fuel from System Fuels,
receives technical and advisory services from Entergy Services, and
receives operating services from Entergy Operations.
Operating revenues include revenues from sales to affiliates
amounting to $1.0 million in 1994, $4.8 million in 1993, and
$5.5 million in 1992. Operating expenses include charges from
affiliates for fuel costs, purchased power and related charges,
management services, and technical and advisory services totaling
$365.8 million in 1994, $322 million in 1993, and $314.3 million in
1992. LP&L pays directly or reimburses Entergy Operations for the
costs associated with operating Waterford 3 (excluding nuclear fuel),
which were approximately $152.5 million in 1994, $118.9 million in
1993, and $152.1 million in 1992.
NOTE 12. RESTRUCTURING COSTS
During the third quarter of 1994, LP&L announced a restructuring
program related to certain of its operating units. The program is
designed to reduce costs, improve operating efficiencies, and increase
shareholder value in order to enable LP&L to become a low-cost
producer. The program includes reductions in the number of employees
and the consolidation of offices and facilities. In 1994, LP&L
recorded restructuring charges of $6.8 million. These charges
primarily include employee severance costs related to the expected
termination of approximately 296 employees. As of December 31, 1994,
no employees have been terminated and no termination benefits have
been paid under this restructuring program.
NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED)
LP&L's business is subject to seasonal fluctuations with the peak
period occurring during the third quarter. Operating results for the
four quarters of 1994 and 1993 were:
Operating Operating Net
Revenues Income Income
(In Thousands)
1994:
First Quarter $383,826 $ 68,668 $37,096
Second Quarter $441,643 $ 80,686 $48,353
Third Quarter $502,458 $ 99,824 $67,029
Fourth Quarter $380,614 $ 93,942 $61,361
1993:
First Quarter $357,856 $ 56,875 $25,733
Second Quarter $399,570 $ 79,472 $46,932
Third Quarter $545,487 $124,789 $92,287
Fourth Quarter $426,753 $ 60,476 $23,856
See "Significant Factors and Known Trends - Litigation and
Regulatory Proceedings" for information regarding the write-off
of certain unamortized deferred investment tax credits in the
fourth quarter of 1994.
LOUISIANA POWER & LIGHT COMPANY
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1994 1993 1992 1991 1990
(In Thousands)
Operating revenues $1,708,541 $1,729,666 $1,553,745 $1,528,934 $1,485,572
Net income $ 213,839 $ 188,808 $ 182,989 $ 166,572 $ 155,049
Total assets $4,435,439 $4,463,998 $4,109,148 $4,131,751 $4,262,124
Long-term obligations (1) $1,530,558 $1,611,436 $1,622,909 $1,582,606 $1,867,369
(1) Includes long-term debt (excluding currently maturing debt),
preferred stock with sinking fund, and noncurrent capital lease
obligations.
See Notes 3 and 10 for the effect of accounting changes in 1993.
1994 1993 1992 1991 1990
(Dollars in Thousands)
Operating Revenues:
Residential $577,084 $572,738 $518,255 $525,594 $520,800
Commercial 358,672 345,254 320,688 318,613 314,700
Industrial 659,061 652,574 578,741 558,036 532,800
Governmental 31,679 29,723 27,780 28,303 26,500
---------- ---------- ---------- ---------- ----------
Total retail 1,626,496 1,600,289 1,445,464 1,430,546 1,394,800
Sales for resale 35,406 49,388 38,632 31,997 41,800
Other 46,639 79,989 69,649 66,391 49,000
---------- ---------- ---------- ---------- ----------
Total $1,708,541 $1,729,666 $1,553,745 $1,528,934 $1,485,600
========== ========== ========== ========== ==========
Billed Electric Energy
Sales (Millions of KWH):
Residential 7,449 7,368 6,996 7,182 7,169
Commercial 4,631 4,435 4,307 4,367 4,299
Industrial 16,561 15,914 15,013 14,832 14,170
Governmental 423 398 385 405 382
------ ------ ------ ------ ------
Total retail 29,064 28,115 26,701 26,786 26,020
Sales for resale 786 1,325 1,305 1,201 1,149
------ ------ ------ ------ ------
Total 29,850 29,440 28,006 27,987 27,169
====== ====== ====== ====== ======
Mississippi Power & Light Company
1994 Financial Statements
MISSISSIPPI POWER & LIGHT COMPANY
DEFINITIONS
Certain abbreviations or acronyms used in MP&L's Financial
Statements, Notes to Financial Statements, and Management's Financial
Discussion and Analysis are defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
AP&L Arkansas Power & Light Company
Entergy or System Entergy Corporation and its various direct
and indirect subsidiaries
Entergy Services Entergy Services, Inc.
EPAct The Energy Policy Act of 1992
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Final Order on Rehearing An order issued by the MPSC on September 16,
1985, with respect to MP&L's Grand Gulf
1-related rate issues
G&R Bonds General and Refunding Mortgage Bonds issued
and issuable under MP&L's G&R Mortgage dated
as of February 1, 1988, as amended
G&R Mortgage General and Refunding Mortgage established by
MP&L effective February 1, 1988, to provide
for issuances of G&R Bonds
Grand Gulf Station Grand Gulf Steam Electric Generating Station
(nuclear)
Grand Gulf 1 Unit No. 1 of the Grand Gulf Station
(nuclear)
Grand Gulf 2 Unit No. 2 of the Grand Gulf Station
(nuclear)
GSU Gulf States Utilities Company (including
wholly owned subsidiaries - Varibus
Corporation, GSG&T, Inc., Prudential Oil and
Gas, Inc., and Southern Gulf Railway Company)
Independence Station Independence Steam Electric Generating
Station
KWH Kilowatt-Hours
LP&L Louisiana Power & Light Company
MWH Megawatt-Hours
Merger The combination transaction, consummated on
December 31, 1993, by which GSU became a
subsidiary of Entergy Corporation and Entergy
Corporation became a Delaware Corporation
Money Pool Entergy Money Pool, which allows certain
System companies to borrow from, or lend to,
certain other System companies
MP&L Mississippi Power & Light Company
MPSC Mississippi Public Service Commission
NOPSI New Orleans Public Service Inc.
OBRA Omnibus Budget Reconciliation Act of 1993
Revised Plan MP&L's Grand Gulf 1-related rate phase-in
plan, originally approved by the MPSC in the
Final Order on Rehearing, as modified by the
MPSC order issued September 29, 1988, to
bring such plan into compliance with the
requirements of SFAS 92
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
promulgated by the FASB
SFAS 106 SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions"
SFAS 109 SFAS 109, "Accounting for Income Taxes"
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System or Entergy Entergy Corporation and its various direct
and indirect subsidiaries
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI,
collectively
MISSISSIPPI POWER & LIGHT COMPANY
REPORT OF MANAGEMENT
The management of Mississippi Power & Light Company has prepared
and is responsible for the financial statements and related financial
information included herein. The financial statements are based on
generally accepted accounting principles. Financial information
included elsewhere in this report is consistent with the financial
statements.
To meet its responsibilities with respect to financial
information, management maintains and enforces a system of internal
accounting controls that is designed to provide reasonable assurance,
on a cost-effective basis, as to the integrity, objectivity, and
reliability of the financial records, and as to the protection of
assets. This system includes communication through written policies
and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and
the training of personnel. This system is also tested by a
comprehensive internal audit program.
The independent public accountants provide an objective
assessment of the degree to which management meets its responsibility
for fairness of financial reporting. They regularly evaluate the
system of internal accounting controls and perform such tests and
other procedures as they deem necessary to reach and express an
opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide
reasonable assurance that its operations are carried out with a high
standard of business conduct.
/s/ Edwin Lupberger /s/ Gerald D. McInvale
EDWIN LUPBERGER GERALD D. MCINVALE
Chairman and Chief Executive Officer Senior Vice President and
Chief Financial Officer
MISSISSIPPI POWER & LIGHT COMPANY
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Entergy Corporation Board of Directors' Audit Committee
functions as the Audit Committee for Mississippi Power & Light
Company. The Audit Committee is comprised of four directors, who are
not officers of MP&L: H. Duke Shackelford (Chairman), Lucie J.
Fjeldstad, Dr. Norman C. Francis, and James R. Nichols. The committee
held four meetings during 1994.
The Audit Committee oversees MP&L's financial reporting process
on behalf of the Board of Directors and provides reasonable assurance
to the Board that sufficient operating, accounting, and financial
controls are in existence and are adequately reviewed by programs of
internal and external audits.
The Audit Committee discussed with Entergy's internal auditors
and the independent public accountants (Coopers & Lybrand L.L.P.) the
overall scope and specific plans for their respective audits, as well
as MP&L's financial statements and the adequacy of MP&L's internal
controls. The committee met, together and separately, with Entergy's
internal auditors and independent public accountants, without
management present, to discuss the results of their audits, their
evaluation of MP&L's internal controls, and the overall quality of
MP&L's financial reporting. The meetings also were designed to
facilitate and encourage any private communication between the
committee and the internal auditors or independent public accountants.
/s/ H. Duke Shackelford
H. DUKE SHACKELFORD
Chairman, Audit Committee
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
Mississippi Power & Light Company
We have audited the accompanying balance sheet of Mississippi
Power & Light Company as of December 31, 1994, and the related
statements of income, retained earnings and cash flows for the year
then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on
these financial statements based on our audit. The financial
statements of the Company as of December 31, 1993 and for the years
ended December 31, 1993 and 1992, were audited by other auditors,
whose report, dated February 11, 1994, included an explanatory
paragraph that described changes in methods of accounting for
revenues, income taxes and postretirement benefits other than pensions
which are discussed in Notes 1, 3 and 9 respectively, to these
financial statements.
We conducted our audit in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position of
the Company as of December 31, 1994, and the result of its operations
and its cash flows for the year then ended in conformity with
generally accepted accounting principles.
/s/ Coopers & Lybrand L.L.P.
COOPERS & LYBRAND L.L.P.
New Orleans, Louisiana
February 21, 1995
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of
Mississippi Power & Light Company
We have audited the accompanying balance sheet of Mississippi
Power & Light Company (MP&L) as of December 31, 1993, and the related
statements of income, retained earnings, and cash flows for each of
the two years in the period ended December 31, 1993. These financial
statements are the responsibility of MP&L's management. Our
responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all
material respects, the financial position of MP&L at December 31,
1993, and the results of its operations and its cash flows for each of
the two years in the period ended December 31, 1993 in conformity with
generally accepted accounting principles.
As discussed in Note 1 to the financial statements, MP&L changed
its method of accounting for revenues in 1993 and, as discussed in
Notes 3 and 9 to the financial statements, in 1993 MP&L changed its
methods of accounting for income taxes and postretirement benefits
other than pensions, respectively.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 11, 1994
MISSISSIPPI POWER & LIGHT COMPANY
BALANCE SHEETS
ASSETS
December 31,
1994 1993
(In Thousands)
Utility Plant:
Electric $1,475,322 $1,389,229
Construction work in progress 67,119 62,699
---------- ----------
Total 1,542,441 1,451,928
Less - accumulated depreciation and amortization 582,514 577,728
---------- ----------
Utility plant - net 959,927 874,200
---------- ----------
Other Property and Investments:
Investment in subsidiary company - at equity 5,531 5,531
Other 5,624 4,760
---------- ----------
Total 11,155 10,291
---------- ----------
Current Assets:
Cash and cash equivalents:
Cash 5,080 7,999
Temporary cash investments - at cost,
which approximates market
Associated companies 276 -
Other 4,242 -
---------- ----------
Total cash and cash equivalents 9,598 7,999
Notes receivable 9,681 7,118
Accounts receivable:
Customer (less allowance for doubtful accounts of
$2.1 million in 1994 and $2.5 million in 1993) 21,087 33,155
Associated companies 4,680 7,342
Other 2,789 3,672
Accrued unbilled revenues 39,873 57,414
Fuel inventory - at average cost 4,780 8,652
Materials and supplies - at average cost 20,642 20,886
Rate deferrals 106,538 96,935
Prepayments and other 10,672 13,763
---------- ----------
Total 230,340 256,936
---------- ----------
Deferred Debits and Other Assets:
Regulatory Assets:
Rate deferrals 385,720 504,428
Unamortized loss on reacquired debt 10,488 11,656
Other regulatory assets 10,168 2,949
Long-term receivables 13,078 9,951
Other 8,569 6,326
---------- ----------
Total 428,023 535,310
---------- ----------
TOTAL $1,629,445 $1,676,737
========== ==========
See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
1994 1993
(In Thousands)
Capitalization:
Common stock, no par value, authorized
15,000,000 shares; issued and outstanding
8,666,357 shares in 1994 and 1993 $199,326 $199,326
Capital stock expense and other (1,762) (1,864)
Retained earnings 232,011 236,337
---------- ----------
Total common shareholder's equity 429,575 433,799
Preferred stock:
Without sinking fund 57,881 57,881
With sinking fund 31,770 46,770
Long-term debt 475,233 516,156
---------- ----------
Total 994,459 1,054,606
---------- ----------
Other Noncurrent Liabilities:
Obligations under capital leases 552 686
Other 8,984 6,231
---------- ----------
Total 9,536 6,917
---------- ----------
Current Liabilities:
Currently maturing long-term debt 65,965 48,250
Notes payable:
Associated companies - 11,568
Other 30,000 -
Accounts payable:
Associated companies 2,350 29,181
Other 30,205 12,157
Customer deposits 22,793 21,474
Taxes accrued 20,821 24,252
Accumulated deferred income taxes 47,515 41,758
Interest accrued 20,377 23,171
Dividends declared 1,626 1,985
Other 28,692 17,303
---------- ----------
Total 270,344 231,099
---------- ----------
Deferred Credits:
Accumulated deferred income taxes 301,288 311,616
Accumulated deferred investment tax credits 29,528 37,193
SFAS 109 regulatory liability - net 13,099 23,626
Other 11,191 11,680
---------- ----------
Total 355,106 384,115
---------- ----------
Commitments and Contingencies (Notes 2 and 8)
TOTAL $1,629,445 $1,676,737
========== ==========
See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Activities:
Net income $48,779 $101,743 $65,036
Noncash items included in net income:
Cumulative effect of a change in accounting principle - (32,706) -
Change in rate deferrals 109,105 71,555 17,530
Depreciation and amortization 36,592 32,152 31,493
Deferred income taxes and investment tax credits (34,409) (17,881) 18,685
Allowance for equity funds used during construction (1,660) (928) (668)
Changes in working capital:
Receivables 33,154 (11,814) (924)
Fuel inventory 3,872 (1,327) 2,061
Accounts payable (8,783) 5,055 (14,365)
Other working capital accounts 13,480 (1,120) 1,918
Other 1,209 8,073 (4,272)
-------- -------- --------
Net cash flow provided by operating activities 195,114 149,382 118,773
Investing Activities: -------- -------- --------
Construction expenditures (121,386) (66,404) (53,481)
Allowance for equity funds used during construction 1,660 928 668
-------- -------- --------
Net cash flow used in investing activities (119,726) (65,476) (52,813)
-------- -------- --------
Financing Activities:
Proceeds from issuance of:
General and refunding bonds 24,534 250,000 65,000
Other long-term debt 15,652 - -
Common stock - - 25,000
Preferred stock - - 19,777
Retirement of:
First mortgage bonds (18,000) (204,501) (101,416)
General and refunding bonds (30,000) (55,000) -
Other long-term debt (16,045) (230) (210)
Redemption of preferred stock (15,000) (16,500) (9,500)
Dividends paid:
Common stock (45,600) (85,800) (68,400)
Preferred stock (7,762) (9,452) (9,445)
Changes in short-term borrowings 18,432 11,568 -
-------- -------- --------
Net cash flow used in financing activities (73,789) (109,915) (79,194)
-------- -------- --------
Net increase (decrease) in cash and cash equivalents 1,599 (26,009) (13,234)
Cash and cash equivalents at beginning of period 7,999 34,008 47,242
-------- -------- --------
Cash and cash equivalents at end of period $9,598 $7,999 $34,008
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $52,737 $52,459 $62,727
Income taxes $39,000 $58,831 $14,866
See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is important to MP&L due to the capital intensive
nature of its business, which requires large investments in long-lived
assets. While large capital expenditures for the construction of new
generating capacity are not currently planned, MP&L does require
significant capital resources for the periodic maturity of certain
series of debt and preferred stock and ongoing construction
expenditures. Net cash flow from operations totaled $195 million,
$149 million, and $119 million in 1994, 1993, and 1992, respectively.
Net cash flow from operations increased in 1994 due primarily to
increased collections under the phase-in plan, as discussed below. In
recent years, this cash flow, supplemented by cash on hand and
issuances of debt and common and preferred stock, has been sufficient
to meet substantially all investing and financing requirements,
including capital expenditures, dividends, and debt/preferred stock
maturities. MP&L's ability to fund these capital requirements
results, in part, from its continued efforts to streamline operations
and reduce costs, as well as collections under its Grand Gulf 1 rate
phase-in plan, which exceed the current cash requirements for Grand
Gulf 1-related costs. (In the income statement, these revenue
collections are offset by the amortization of previously deferred
costs; therefore, there is no effect on net income.) MP&L's Grand Gulf
1 rate phase-in plan will continue to contribute to MP&L's cash
position through 1998. See Note 2 for additional information on
MP&L's rate phase-in plan. See Note 8 for additional information on
MP&L's capital and refinancing requirements in 1995 - 1997. Also, to
the extent current market interest and dividend rates allow, MP&L may
continue to refinance high-cost debt and preferred stock prior to
maturity.
In March 1994, the MPSC issued a final order adopting a formulary
incentive rate plan. The order also adopted previously agreed-upon
stipulations of a required return on equity of 11% and certain
accounting adjustments that resulted in a 4.3% ($28.1 million)
reduction in MP&L's June 30, 1993, test-year base revenues effective
March 25, 1994. The plan allows for periodic small adjustments in
rates based on an annual comparison of earned to benchmark rates of
return and upon certain other performance factors. See Note 2 for
additional information.
Earnings coverage tests, bondable property additions, and
accumulated deferred Grand Gulf 1-related costs recorded as assets,
limit the amount of G&R Bonds and preferred stock that MP&L can issue.
Based on the most restrictive applicable tests as of December 31, 1994
and assuming an annual interest or dividend rate of 9.25%, MP&L could
have issued $246 million of additional G&R Bonds or $95 million of
additional preferred stock. Further, MP&L has the conditional ability
to issue G&R Bonds against the retirement of bonds, in some cases
without satisfying an earnings coverage test.
See Notes 5 and 6 for information on MP&L's financing activities
and Note 4 for information on MP&L's short-term borrowings and lines
of credit.
MP&L's liquidity was adversely affected during 1994 due to
incurring $77 million of repairs and improvements associated with an
ice storm in February. See Note 2 for information regarding a rate
increase in September to recover ice storm costs.
MISSISSIPPI POWER & LIGHT COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Revenues $847,888 $895,806 $817,650
---------- ---------- ----------
Operating Expenses:
Operation and maintenance:
Fuel and fuel-related expenses 160,227 140,391 112,032
Purchased power 235,019 289,016 301,912
Other operation and maintenance 156,954 156,405 146,440
Depreciation and amortization 36,592 32,152 31,493
Taxes other than income taxes 43,963 41,878 40,738
Income taxes 16,651 33,074 21,681
Rate deferrals:
Rate deferrals - - (22,876)
Amortization of rate deferrals 102,725 77,570 61,456
---------- ---------- ----------
Total 752,131 770,486 692,876
---------- ---------- ----------
Operating Income 95,757 125,320 124,774
---------- ---------- ----------
Other Income (Deductions):
Allowance for equity funds used
during construction 1,660 928 668
Miscellaneous - net (1,117) 948 4,562
Income taxes - (debit) 4,176 (3,462) (1,467)
---------- ---------- ----------
Total 4,719 (1,586) 3,763
---------- ---------- ----------
Interest Charges:
Interest on long-term debt 47,835 53,558 62,394
Other interest - net 4,929 1,802 1,672
Allowance for borrowed funds used
during construction (1,067) (663) (565)
---------- ---------- ----------
Total 51,697 54,697 63,501
---------- ---------- ----------
Income before Cumulative Effect of
a Change in Accounting Principle 48,779 69,037 65,036
Cumulative Effect to January 1, 1993
of Accruing Unbilled Revenues
(net of income taxes of $19,456) - 32,706 -
---------- ---------- ----------
Net Income 48,779 101,743 65,036
Preferred Stock Dividend Requirements
and Other 7,624 9,160 9,513
---------- ---------- ----------
Earnings Applicable to Common Stock $41,155 $92,583 $55,523
========== ========== ==========
See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Retained Earnings, January 1 $236,337 $230,201 $243,819
Add:
Net income 48,779 101,743 65,036
-------- -------- --------
Total 285,116 331,944 308,855
-------- -------- --------
Deduct:
Dividends declared:
Preferred stock 7,404 8,964 9,513
Common stock 45,600 85,800 68,400
Preferred stock expenses 101 843 741
-------- -------- --------
Total 53,105 95,607 78,654
-------- -------- --------
Retained Earnings, December 31 (Note 7) $232,011 $236,337 $230,201
======== ======== ========
See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income decreased in 1994 due primarily to the one-time
recording in the first quarter of 1993 of the cumulative effect of the
change in accounting principle for unbilled revenues. In addition,
net income was reduced by the rate reduction in connection with the
formula incentive rate plan, partially offset by a FERC settlement
(see Litigation and Regulatory Proceedings below). Net income
increased in 1993 due primarily to the one-time recording of the
cumulative effect of the change in accounting principle for unbilled
revenues and its ongoing effects, partially offset by the effects of
implementing SFAS 109 and SFAS 106. Effective January 1, 1993, MP&L
began accruing as revenues the charges for energy delivered to
customers but not yet billed. Electric revenues were previously
recorded on a cycle-billing basis. Excluding the above mentioned
items, net income for 1993 would have been $71.9 million. This $6.9
million increase is due primarily to an increase in retail energy
sales and a decrease in interest expense from the refinancing of high-
cost debt.
Significant factors affecting the results of operations and
causing variances between the years 1994 and 1993, and 1993 and 1992,
are discussed under "Revenues and Sales," "Expenses," and "Other"
below.
Revenues and Sales
See "Selected Financial Data - Five-Year Comparison" following
the notes, for information on operating revenues by source and KWH
sales.
Operating revenues decreased in 1994 due to the impact of the
rate reduction in connection with the incentive rate plan that went
into effect in March 1994, partially offset by higher energy sales.
In addition to the factors cited above for revenues, accrued unbilled
revenues decreased due to a change in the cycle billing dates offset
by an increase in billed revenues. This decrease was partially offset
by increased retail energy sales resulting from increased commercial
and industrial sales.
Operating revenues were higher in 1993 due to increased
residential and commercial energy sales resulting primarily from a
return to more normal weather as compared to milder weather in 1992.
Industrial energy sales also increased due to higher sales to the
rubber and plastics, petroleum refining, and petroleum pipelines
sectors. Sales for resale to associated companies were higher due to
changes in generation availability and requirements among AP&L, LP&L,
MP&L and NOPSI. Additionally, electric operating revenues increased
due to increased fuel adjustment revenues and increased collections of
previously deferred Grand Gulf 1-related costs, neither of which
affects net income. These increases were partially offset by a
decrease in other revenue related to MP&L's rate deferral over/under
recovery which reflects adjustments for the difference between actual
and estimated costs, and does not affect net income.
Expenses
Operating expenses decreased in 1994 due primarily to lower
purchased power and income tax expense partially offset by increased
amortization of rate deferrals. Operating expenses increased in 1993
due primarily to higher fuel and maintenance expenses and increased
amortization of rate deferrals.
Purchased power expense decreased in 1994 due primarily to
changes in generation availability and requirements among the System
operating companies. A lower per unit price for power purchased also
contributed to the decrease in purchased power in 1994.
Fuel for electric generation and fuel-related expenses increased
in 1993 due primarily to an increase in generation requirements
resulting primarily from increased energy sales, as discussed in
"Revenues and Sales" above, and increased fuel costs.
Other operation and maintenance expense was higher in 1993 due
primarily to an increase in scheduled maintenance at MP&L's power
plants.
Income taxes decreased in 1994 due primary to lower pretax
income, and the write-off of unamortized deferred investment tax
credits in accordance with a FERC settlement. Income taxes increased
in 1993 due to the effect of high pretax income, an increase in the
federal income tax rate as a result of OBRA, and the effect of
implementing SFAS 109.
The amortization of rate deferrals increased in 1994 and 1993
reflecting the fact that MP&L, based on the Revised Plan, collected
more Grand Gulf 1-related costs from its customers in 1994 than it
recovered in 1993 and 1992.
Interest expense decreased in 1994 and 1993 due primarily to the
refinancing of high-cost long-term debt and the maturity of high-cost
long-term debt.
MISSISSIPPI POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Competition
The electric utility industry is becoming increasingly
competitive and MP&L is seeking to become a leading competitor in the
changing electric energy business. Competition presents MP&L with
many challenges. The following have been identified by MP&L as its
major competitive challenges.
Retail and Wholesale Rate Issues
The retail regulatory philosophy is shifting in some
jurisdictions from traditional cost of service regulation to incentive
rate regulation. Incentive and performance-based rate plans encourage
efficiencies and productivity while permitting utilities and their
customers to share in the results. MP&L implemented an incentive rate
plan in 1994. Recognizing that many industrial customers have energy
alternatives, MP&L continues to work with these customers to address
their needs. In certain cases, competitive prices are negotiated,
using variable rate designs.
MP&L's formulary incentive rate plan allows for periodic small
adjustments in rates based on a comparison of earned to benchmark
returns and upon certain performance factors. In addition, certain
previously agreed-upon stipulations of a required return on equity of
11% and certain accounting adjustments resulted in a 4.3% ($28.1
million) reduction in MP&L's revenues effective March 25, 1994. For
further information see Note 2.
In connection with the Merger, MP&L agreed with their respective
retail regulators not to request any general retail rate increases
that would take effect before November 1998, with certain exceptions.
Retail wheeling, the transmission by an electric utility of
energy produced by another entity over the utility's transmission and
distribution system to a retail customer in the electric utility's
service territory, is evolving. Over a dozen states have been
studying the concept of retail competition. In April 1994, the state
of Michigan agreed to a five-year experiment that allows limited
competition among public utilities. During the same month, the
California Public Utilities Commission proposed to deregulate that
state's electric power industry, starting on January 1, 1996, to allow
the largest industrial customers to select the lowest cost supplier
for electricity service. Under the proposal, by the year 2002,
smaller companies and residential customers in California would also
be able to buy power from any suppliers. The California Public
Utilities Commission is currently reviewing its decision and is
expected to make a ruling in the first half of 1995. The retail market
for electricity is expected to become more competitive with such moves
toward deregulation.
In some areas of the country, municipalities (or comparable
entities) whose residents are served at retail by an investor-owned
utility pursuant to a franchise are exploring the possibility of
establishing new or extending existing distribution systems or seeking
new delivery points in order to serve retail customers, especially
large industrial customers, that currently receive service from an
investor-owned utility. These options depend on the terms of a
utility's franchise as well as on state law and regulation. In
addition, FERC's authority to order utilities to transmit for a new or
expanding municipal system is limited in certain respects. Where
successful, however, the establishment of a municipal system or the
acquisition by a municipal system of a utility's customers could
result in the inability to recover costs that the utility has incurred
in serving those customers.
On October 11, 1994, twelve Mississippi cities filed a complaint
in state court against MP&L and eight electric power associations
seeking a judgment from the court declaring unconstitutional certain
Mississippi statutes that establish the procedure that must be
followed before a municipality can acquire the facilities and
certificate rights of a utility serving in the municipality.
Specifically, the suit requests that the court declare
unconstitutional certain 1987 amendments to the Mississippi Public
Utilities Act that require that the MPSC cancel a utility's
certificate to serve in the municipality before a municipality may
acquire a utility's facilities located in the municipality. The suit
also requests that the court find that Mississippi municipalities can
serve any consumer in the boundaries of the municipality and within
one mile thereof. Such a finding would be contrary to Mississippi
Supreme Court decisions that have held that a municipality cannot
serve in another utility's service area even where the municipal
boundaries extend into such service area. On January 6, 1995, MP&L
and the other defendants filed motions to dismiss. The matter is
pending and will be vigorously contested by MP&L.
In mid-1994, the FERC issued a notice of proposed rulemaking
concerning a regulatory framework for dealing with recovery of
stranded costs, such as high cost nuclear generating units, which may
be incurred by electric utilities as a result of increased
competition. In addition to addressing recovery of stranded costs
related to wholesale service, the proposal requested comment as to
recovery of retail stranded costs in transmission rates where state
regulatory authorities failed to address the issue or were in
conflict. Comments and reply comments have been filed, and the matter
is pending. The risk of exposure to stranded costs which may result
from competition in the industry will depend on the extent and timing
of retail competition, the resolution of jurisdictional issues
concerning stranded cost recovery and the extent to which such costs
are recovered from departing or remaining customers, among other
matters.
In the wholesale rate area, FERC approved in 1992, with certain
modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy
Power, Inc. to sell wholesale power at market-based rates and to
provide to electric utilities "open access" to the System's
transmission system (subject to certain requirements). GSU was later
added to this filing. On January 25, 1995, Entergy Services filed
with FERC revised transmission tariffs intended to provide access to
transmission service on the same or comparable basis, terms, and
conditions as the System operating companies. Open access and market
pricing, once in effect, will increase marketing opportunities for
MP&L, but will also expose MP&L to the risk of loss of load or reduced
revenues due to competition with alternative suppliers.
In light of the rate issues discussed above, MP&L is aggressively
reducing costs to avoid potential earnings erosions that might result
as well as to become more competitive. In 1994, MP&L announced a
restructuring program related to certain of its operating units. This
program is designed to reduce costs and improve operating
efficiencies. See Note 12 for further information. Also, in response
to an increasingly competitive environment, MP&L announced intentions
to revise its initial least cost planning activities.
The Energy Policy Act of 1992
The EPAct addresses a wide range of energy issues and is altering
the way Entergy and the rest of the electric utility industry
operate. The EPAct encourages competition and affords utilities the
opportunities, and the risks, associated with an open and more
competitive market environment. The EPAct creates exemptions from
regulation under the Holding Company Act and creates a class of exempt
wholesale generators consisting of utility affiliates and nonutilities
that are owners and operators of facilities for the generation and
transmission of power for sales at wholesale. The EPAct also gives
FERC the authority to order investor-owned utilities, including MP&L,
to transmit power and energy to or for wholesale purchasers and
sellers. The law creates the potential for electric utilities and
other power producers to gain increased access to the transmission
systems of other entities to facilitate wholesale sales. Both MP&L
and Entergy Power expect to compete in this market. In addition, the
EPAct allows utilities to own and operate foreign generation,
transmission, and distribution facilities.
Litigation and Regulatory Proceedings
In November 1994, FERC approved an agreement settling a long-
standing dispute involving income tax allocation procedures of System
Energy. In accordance with the agreement, System Energy refunded
approximately $20.4 million to MP&L, which will in turn make refunds
or credits to its customers. Additionally, System Energy will refund
a total of approximately $20.5 million, plus interest, to MP&L over
the period through June 2004. The settlement also required the write-
off of approximately $6 million of certain unamortized deferred
investment tax credits by MP&L.
Accounting Issues
Proposed Accounting Standards - The FASB has proposed a SFAS on
"Accounting for the Impairment of Long-Lived Assets," effective
January 1, 1996. The proposed standard describes circumstances which
may result in assets being impaired and provides criteria for
recognition and measurement of asset impairment. Certain operations of
MP&L are potentially affected by this standard, and any resulting
write-offs will depend on future operating costs, generating units'
efficiency and availability, and the future market for energy over the
remaining life of the units. Based on current estimates, MP&L
anticipates that future revenues will fully recover the costs of such
operations.
Continued Application of SFAS 71 - MP&L's financial statements
currently reflect assets and costs based on current cost-based
ratemaking regulations, in accordance with SFAS 71, "Accounting for
the Effects of Certain Types of Regulation." As discussed above, the
electric utility industry is changing and these changes could possibly
result in the discontinuance of the application of SFAS 71, which
would result in the elimination of regulatory assets and liabilities.
See Note 1 for further information.
MISSISSIPPI POWER & LIGHT COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
MP&L maintains accounts in accordance with FERC and other
regulatory guidelines. Certain previously reported amounts have been
reclassified to conform to current classifications.
Revenues and Fuel Costs
Prior to January 1, 1993, MP&L recorded revenues when billed to
its customers with no accrual for energy delivered but not yet billed.
To provide a better matching of revenues and expenses, effective
January 1, 1993, MP&L adopted a change in accounting principle to
provide for accrual of estimated unbilled revenues. The cumulative
effect of this accounting change as of January 1, 1993 increased net
income by $32.7 million. Had this new accounting method been in
effect during prior years, net income before the cumulative effect
would not have been materially different from that shown in the
accompanying financial statements.
MP&L's rate schedules include fuel adjustment clauses that allow
current recovery of estimated fuel costs, with subsequent adjustments
of estimates to actual.
Utility Plant
Utility plant is stated at original cost. The original cost of
utility plant retired or removed, plus the applicable removal costs,
less salvage, is charged to accumulated depreciation. Maintenance,
repairs, and minor replacement costs are charged to operating
expenses. Substantially all of MP&L's utility plant is subject to the
lien of its first mortgage bond indenture and the second lien of its
G&R mortgage bond indenture.
Total MP&L net utility plant in service of $893 million as of
December 31, 1994 includes $220 million of production plant, $249
million of transmission plant, $358 million of distribution plant, and
$66 million of other plant.
Depreciation is computed on the straight-line basis at rates
based on the estimated service lives and costs of removal of the
various classes of property. Depreciation provisions on average
depreciable property approximated 2.4% in 1994 and 1993, and 2.5% in
1992.
AFUDC represents the approximate net composite interest cost of
borrowed funds and a reasonable return on the equity funds used for
construction. Although AFUDC increases utility plant and increases
earnings, it is only realized in cash through depreciation provisions
included in rates. MP&L's effective composite rates for AFUDC were
8.0%, 11.8%, and 12.0%, for 1994, 1993, and 1992, respectively.
Jointly-Owned Generating Station
MP&L owns 25% of the Independence Station, a two-unit, coal-fired
generating station located near Newark, Arkansas. The total
capability of Independence Station is 1,678 megawatts. MP&L records
its investment in and expenses associated with this station to the
extent of its ownership and interest. MP&L's investment in the
Independence Station was approximately $222 million less accumulated
depreciation of approximately $73.6 million as of December 31, 1994.
Notes Receivable
MP&L currently has a program, wherein it finances heat pumps for
its customers through notes receivable. Such notes are repayable in
equal monthly installments of principal and interest over a five-year
period and bear interest at a market-based rate at the time of sale.
The amounts financed are classified on its balance sheet as current
and noncurrent notes receivable.
Income Taxes
MP&L, its parent, and affiliates file a consolidated federal
income tax return. Income taxes are allocated to MP&L in proportion
to its contribution to consolidated taxable income. SEC regulations
require that no Entergy Corporation subsidiary pay more taxes than it
would have had a separate income tax return been filed. Deferred
taxes are recorded for all temporary differences between book and
taxable income. Investment tax credits are deferred and amortized
based upon the average useful life of the related property, in
accordance with rate treatment. As discussed in Note 3, in 1993 MP&L
changed its accounting for income taxes to conform with SFAS 109.
In addition, MP&L files a consolidated Mississippi state income
tax return with certain other System companies.
Cash and Cash Equivalents
MP&L considers all unrestricted highly liquid debt instruments
purchased with an original maturity of three months or less to be cash
equivalents.
Continued Application of SFAS 71
As a result of the EPAct and actions of regulatory commissions,
the electric utility industry is moving toward a combination of
competition and a modified regulatory environment. MP&L's financial
statements currently reflect assets and costs based on current cost-
based ratemaking regulations, in accordance with SFAS 71, "Accounting
for the Effects of Certain Types of Regulation." Continued
applicability of SFAS 71 to MP&L's financial statements requires that
rates set by an independent regulator on a cost of service basis
(including a reasonable rate of return on invested capital) can
actually be charged to and collected from customers.
In the event that either all or a portion of a utility's
operations cease to meet those criteria for various reasons, including
deregulation, a change in the method of regulation, or a change in the
competitive environment for the utility's regulated services, the
utility should discontinue application of SFAS 71 for the relevant
portion. That discontinuation should be reported by elimination from
the balance sheet of the effects of any actions of regulators
recorded as regulatory assets and liabilities.
As of December 31, 1994, and for the foreseeable future, MP&L's
financial statements continue to follow SFAS 71.
Fair Value Disclosure
The estimated fair value of financial instruments has been
determined by MP&L, using available market information and appropriate
valuation methodologies. However, considerable judgment is required
in developing the estimates of fair value. Therefore, estimates are
not necessarily indicative of the amounts that MP&L could realize in a
current market exchange. In addition, gains or losses realized on
financial instruments may be reflected in future rates and not accrue
to the benefit of stockholders.
MP&L considers the carrying amounts of financial instruments
classified as current assets and liabilities to be a reasonable
estimate of their fair value because of the short maturity of these
instruments. In addition, MP&L does not presently expect that
performance of its obligations will be required in connection with
certain off-balance sheet commitments and guarantees considered
financial instruments. Due to this factor, and because of the related
party nature of these commitments and guarantees, determination of
fair value is not considered practicable. See Notes 5 and 6 for
additional fair value disclosure.
NOTE 2. RATE AND REGULATORY MATTERS
Formula Rate Plan
Under a formulary incentive rate plan (Formula Rate Plan)
effective March 25, 1994, MP&L's earned rate of return is calculated
automatically every 12 months and compared to and adjusted against a
benchmark rate of return (calculated under a separate formula within
the Formula Rate Plan). The Formula Rate Plan allows for periodic
small adjustments in rates based on a comparison of earned to
benchmark returns and upon certain performance factors. In the same
proceeding, the MPSC conducted a general review of MP&L's current
rates and on March 1, 1994, issued a final order adopting the Formula
Rate Plan and previously agreed-upon stipulations of (1) a required
return on equity of 11% and (2) certain accounting adjustments that
resulted in a 4.3% ($28.1 million) reduction in MP&L's June 30, 1993,
test-year base revenues. The MPSC's order required MP&L to file rates
designed to provide for this reduction in operating revenues for the
test year on or before March 18, 1994, which became effective March
25, 1994. The final order was appealed to the Mississippi Supreme
Court on May 17, 1994, by Mississippi Valley Gas Company (MVG) on the
grounds that the MPSC issued the final order without having reviewed
the cost of MP&L's promotional practices, some of which MVG alleged to
be improper. On October 28, 1994, the Mississippi Supreme Court
granted MVG's motion to dismiss the appeal.
Merger - Related Rate Agreement
In November 1993, MP&L and the MPSC entered into a settlement
agreement whereby the MPSC agreed to withdraw its request for hearings
and its objections in the SEC proceeding related to the Merger. MP&L
agreed that MP&L's retail ratepayers would be protected from (1)
increases in MP&L's cost of capital resulting from risks associated
with the Merger; (2) recovery of any portion of the acquisition
premium or transactional costs associated with the Merger; (3) certain
direct allocations of costs associated with GSU's River Bend nuclear
unit; and (4) any losses of GSU resulting from resolution of
litigation in connection with its ownership of River Bend. In a
related stipulation, MP&L also agreed (a) that retail base rates under
its formula rate plan would not be increased above November 1, 1993
levels, and (b) that MP&L would not request any general retail rate
increase that would increase retail rates above the level of MP&L's
rates in effect as of November 1, 1993, except for, among other
things, increases associated with the recovery of deferred Grand Gulf
1-related costs, recovery under the fuel adjustment clause,
adjustments for certain taxes, and force majeure (defined to include,
among other things, war, natural catastrophes, and high inflation), in
each case for a period of five years beginning November 9, 1993.
Grand Gulf 1
MP&L's Revised Plan provides, among other things, for the
recovery by MP&L, in equal annual installments over ten years
beginning October 1, 1988, of all Grand Gulf 1-related costs deferred
through September 30, 1988 pursuant to the Final Order on Rehearing.
Additionally, the Revised Plan provided that MP&L defer, in decreasing
amounts, a portion of its Grand Gulf 1-related costs over four years
beginning October 1, 1988. These deferrals are being recovered by
MP&L over a six-year period beginning in October 1992 and ending in
September 1998. The Revised Plan also allows for the current recovery
of carrying charges on all deferred amounts.
February 1994 Ice Storm/Rate Rider
In early February 1994, an ice storm left more than 80,000 MP&L
customers without electric power across the service area. The storm
was the most severe natural disaster ever to affect the System,
causing damage to transmission and distribution lines, equipment,
poles, and facilities in certain areas, primarily in Mississippi.
Repair costs totaled approximately $77.2 million, with $64.6 million
of these amounts capitalized as plant-related costs. The remaining
balances have been recorded as a deferred debit. On April 15, 1994,
MP&L filed for rate recovery of costs related to the ice storm.
MP&L's filing, as subsequently amended, requested recovery of the
revenue requirement associated with MP&L's ice storm costs recorded
through April 30, 1994, representing approximately 86% of the total
estimated ice storm costs. MP&L may make another ice storm rate
filing with the MPSC during 1995 to recover ice storm costs recorded
by MP&L after April 30, 1994. In August 1994, MP&L and the MPSC's
Public Utilities Staff entered into a stipulation with respect to the
recovery of ice storm costs recorded through April 30, 1994, and in
September 1994, the MPSC approved the stipulation. Under the
stipulation, MP&L implemented an ice storm rider schedule, which went
into effect on September 29, 1994, that will increase rates
approximately $8 million annually for five years. At the end of the
five-year period, the revenue requirement associated with the
undepreciated ice storm capitalized costs will be included in MP&L's
base rates to the extent that this revenue requirement does not result
in MP&L's rate of return on rate base being above the benchmark rate
of return under MP&L's formula rate plan.
NOTE 3. INCOME TAXES
Income tax expense consisted of the following:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Current:
Federal $ 39,505 $46,744 $4,532
State 7,379 7,673 (69)
-------- ------- -------
Total 46,884 54,417 4,463
-------- ------- -------
Deferred - net:
Federal reclassification due to net operating loss - - 28,561
State reclassification due to net operating loss - - 4,883
Liberalized depreciation 15,880 5,293 9,448
Rate deferral - net (45,565) (31,317) (11,220)
Unbilled revenue 3,167 21,373 (5,722)
Pension liability 434 (647) (1,233)
Adjustments of prior year taxes (1,954) 4,299 (3,471)
Bond reacquisition (447) 3,208 264
Other 1,722 (1,670) (1,079)
-------- ------- -------
Total (26,763) 539 20,431
-------- ------- -------
Investment tax credit adjustments - net (1,673) 1,036 (1,746)
Investment tax credit amortization - FERC settlement (5,973) - -
-------- ------- -------
Recorded income tax expense $12,475 $55,992 $23,148
======== ======= =======
Charged to operations $16,651 $33,074 $21,681
Charged (credited) to other income (4,176) 3,462 1,467
Charged to cumulative effect - 19,456 -
-------- ------- -------
Total income taxes $12,475 $55,992 $23,148
======== ======= =======
Total income taxes differ from the amounts computed by applying
the statutory federal income tax rate to income before taxes. The
reasons for the differences were:
For the Years Ended December 31,
1994 1993 1992
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
(Dollars in Thousands)
Computed at statutory rate $21,438 35.0 $55,207 35.0 $29,983 34.0
Increases (reductions) in tax resulting from:
State income taxes net of federal income
tax effect 2,465 4.0 3,253 2.0 2,703 3.1
Depreciation 1,930 3.2 (5,890) (3.7) (2,571) (2.9)
Amortization of excess deferred income taxes (3,810) (6.2) (4,680) (3.0) (2,456) (2.8)
Amortization of investment tax credits (1,674) (2.7) (1,772) (1.1) (1,746) (2.0)
Investment tax credit amortization -
FERC settlement (5,973) (9.8) - - - -
Adjustments of prior year taxes (1,954) (3.2) 5,228 3.3 (2,760) (3.2)
SFAS 109 adjustment - - 3,439 2.2 - -
Other - net 53 .1 1,207 0.8 (5) -
------- ---- ------- ---- ------- ----
Total income taxes $12,475 20.4 $55,992 35.5 $23,148 26.2
======= ==== ======= ==== ======= ====
Significant components of MP&L's net deferred tax liabilities as
of December 31, 1994 and 1993, were (in thousands):
1994 1993
Deferred tax liabilities:
Plant related basis differences $(173,965) $(166,650)
Rate deferrals (201,037) (246,604)
Other (13,318) (6,406)
--------- ---------
Total $(388,320) $(419,660)
========= =========
Deferred tax assets:
Net regulatory liabilities $ 1,804 $ 9,411
Accumulated deferred investment tax credits 11,295 13,420
Recoverable income tax - 13,854
Alternative minimum tax credit - 1,192
Removal cost 2,824 10,725
Standard coal plant 4,717 4,854
Pension related items 3,182 2,488
Other 15,695 10,342
-------- --------
Total $ 39,517 $ 66,286
======== ========
Net deferred tax liabilities $(348,803) $(353,374)
========= =========
In accordance with a System Energy FERC settlement, MP&L wrote
off $6.0 million of unamortized deferred investment tax credits in 1994.
In 1993, MP&L adopted SFAS 109. SFAS 109 required that deferred
income taxes be recorded for all temporary differences and
carryforwards, and that deferred tax balances be based on enacted tax
laws at tax rates that are expected to be in effect when the temporary
differences reverse. SFAS 109 required that regulated enterprises
recognize adjustments resulting from implementation as regulatory
assets or liabilities if it is probable that such amounts will be
recovered from or returned to customers in future rates. A
substantial majority of the adjustments required by SFAS 109 was
recorded to deferred tax balance sheet accounts with offsetting
adjustments to regulatory assets and liabilities. As a result of the
adoption of SFAS 109, 1993 net income was reduced by $1.7 million,
assets were increased by $50.2 million, and liabilities were
increased by $51.9 million. The cumulative effect of the adoption of
SFAS 109 is included in income tax expense charged to operations
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized MP&L to effect short-term borrowings up to
$100 million, which may be increased to as much as $108 million after
further SEC approval. This authorization is effective through
November 30, 1996. As of December 31, 1994, MP&L had outstanding
short-term lines of credit of $30 million from banks within its
service territory. Interest rates associated with these lines of
credit generally are based on the prime rate, the London interbank
offered rate, or a bid rate. Commitment fees on these lines of credit
are .125% of the amount of available credit. In addition, MP&L can
borrow from the Money Pool, subject to its maximum authorized level of
short-term borrowings and the availability of funds. MP&L's
short-term borrowings are limited by the terms of its G&R Mortgage to
amounts not exceeding the greater of 10% of capitalization or 50% of
Grand Gulf 1 rate deferrals available to support the issuance of G&R
Bonds. MP&L had no outstanding borrowings under the Money Pool
arrangement as of December 31, 1994.
NOTE 5. PREFERRED AND COMMON STOCK
The number of shares and dollar value of MP&L's cumulative, $100
par value preferred stock were:
As of December 31,
Shares Call Price Per
Authorized and Total Share as of
Outstanding Dollar Value December 31,
1994 1993 1994 1993 1994
(Dollars in Thousands)
Without sinking fund:
4.36% Series 59,920 59,920 $5,992 $5,992 $103.86
4.56% Series 43,888 43,888 4,389 4,389 $107.00
4.92% Series 100,000 100,000 10,000 10,000 $102.88
7.44% Series 100,000 100,000 10,000 10,000 $102.81
8.36% Series (1) 200,000 200,000 20,000 20,000 -
9.16% Series 75,000 75,000 7,500 7,500 $104.06
------- ------- ------- -------
Total without sinking fund 578,808 578,808 $57,881 $57,881
======= ======= ======= =======
With sinking fund:
9.00% Series 70,000 140,000 $7,000 $14,000 $106.75
9.76% Series 210,000 280,000 21,000 28,000 $102.17
12.00% Series 37,700 47,700 3,770 4,770 $106.00
------- ------- ------- -------
Total with sinking fund 317,700 467,700 $31,770 $46,770
======= ======= ======= =======
(1) This series is not redeemable as of December 31, 1994.
The fair value of MP&L's preferred stock with sinking fund was
estimated to be approximately $32.5 million and $49.3 million as of
December 31, 1994 and 1993, respectively. The fair values were
determined using quoted market prices or estimates from nationally
recognized investment banking firms. See Note 1 for additional
information on disclosure of fair value of financial instruments.
Changes in the common stock and preferred stock, with and without
sinking fund, during the last three years were:
Number of Shares
1994 1993 1992
Common stock issuances($23 issuance price) - - 1,086,957
Preferred stock issuances: - - 200,000
Preferred stock retirements: (150,000) (165,000) (95,000)
Cash sinking fund requirements for the next five years for
preferred stock outstanding as of December 31, 1994, are (in
millions): 1995 - $15, 1996 - $7.5, 1997 - $7.5, 1998 - $0.5; and
1999 - $0.5. MP&L has the annual non-cumulative option to redeem at
par, additional amounts of its 12.00% Series preferred stock
outstanding.
NOTE 6. LONG-TERM DEBT
The long-term debt of MP&L as of December 31, 1994 and 1993, was:
Maturities Interest Rates
From To From To 1994 1993
(In Thousands)
First Mortgage Bonds
1995 1996 4-5/8% 6-3/8% $55,000 $55,000
G&R Bonds
1995 1997 5.95% 14.95%* 167,000 215,000
2003 2023 6-5/8% 8.65% 275,000 250,000
Governmental Obligations**
1995 2004 7-1/2% 8-1/2% 1,880 17,925
2012 2022 7% 11-1/2% 46,030 30,000
Unamortized Premium and Discount-Net (3,712) (3,519)
-------- --------
Total Long-Term Debt 541,198 564,406
Less Amount Due Within One Year 65,965 48,250
-------- --------
Long-Term Debt Excluding Amount Due $475,233 $516,156
Within One Year ======== ========
* The 14.95% series of $20 million was due February 1, 1995. All
other series are at interest rates within the range of 5.95% -
11.2%.
** Consists of pollution control revenue bonds, certain series of
which are secured by non-interest bearing first mortgage bonds.
The fair value of MP&L's long-term debt as of December 31, 1994
and 1993, was estimated to be $523.1 million and $594.0 million,
respectively. The fair values were determined using quoted market
prices or estimates from nationally recognized investment banking
firms. See Note 1 for additional information on disclosure of fair
value of financial instruments.
For the years 1995, 1996, 1997, 1998 and 1999, MP&L has long-term
debt maturities and cash sinking fund requirements of (in millions)
$66, $61, $96, $0, and $0, respectively. In addition, other sinking
fund requirements of approximately $0.4 million for 1995 may be
satisfied by cash or by certification of property additions at the
rate of 167% of such requirements.
The G&R Mortgage prohibits the issuance of additional first
mortgage bonds (including for refunding purposes) under MP&L's first
mortgage indenture, except such first mortgage bonds as may hereafter
be issued from time to time at MP&L's option to the corporate trustee
under the G&R Mortgage to provide additional security for MP&L's G&R
Bonds.
Under MP&L's G&R Mortgage Indenture and subject to the earnings
coverage test discussed below, G&R Bonds are issuable based upon 70%
of property additions since December 31, 1987, plus up to 50% of
cumulative deferred Grand Gulf 1-related costs recorded as an asset on
the books of MP&L, provided that the maximum amount of G&R Bonds
issuable against cumulative deferred Grand Gulf 1-related costs may
not exceed $400 million. The G&R Mortgage contains an earnings
coverage test requiring a minimum earnings coverage (except for
certain refunding issues) of twice the pro-forma annual mortgage
interest requirements for the issuance of additional G&R Bonds. As of
December 31, 1994, the total amount of G&R Bonds outstanding
aggregated $442 million.
NOTE 7. DIVIDEND RESTRICTIONS
MP&L's bond indentures relating to long-term debt contain
provisions restricting the payment of cash dividends or other
distributions on common stock. As of December 31, 1994, $139.3 million
of MP&L's retained earnings were restricted against the payment of
cash dividends or other distributions on common stock. On February 1,
1995, MP&L paid Entergy Corporation a $8.3 million cash dividend on
common stock.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Capital Requirements and Financing
Construction expenditures for the years 1995, 1996, and 1997 are
estimated to total $67.9 each year. MP&L will also require
$253 million during the period 1995-1997 to meet long-term debt and
preferred stock maturities and cash sinking fund requirements. MP&L
plans to meet the above requirements with internally generated funds
and cash on hand, supplemented by the issuance of long-term debt. See
Notes 5 and 6 regarding the possible issuance, refunding, redemption,
purchase or other acquisition of certain outstanding series of
preferred stock and long-term debt.
Unit Power Sales Agreement
System Energy has agreed to sell all of its 90% owned and leased
share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L,
and NOPSI in accordance with specified percentages (AP&L 36%,
LP&L 14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under
this agreement are paid in consideration for MP&L's respective
entitlement to receive capacity and energy, and are payable
irrespective of the quantity of energy delivered so long as the unit
remains in commercial operation. The agreement will remain in effect
until terminated by the parties and approved by FERC, most likely upon
Grand Gulf 1's retirement from service. MP&L's monthly obligation for
payments under the agreement is approximately $16 million.
Availability Agreement
AP&L, LP&L, MP&L, and NOPSI are individually obligated to make
payments or subordinated advances to System Energy in accordance with
stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI
24.7%) in amounts that when added to amounts received under the Unit
Power Sales Agreement or otherwise, are adequate to cover all of
System Energy's operating expenses. System Energy has assigned its
rights to payments and advances to certain creditors as security for
certain obligations. Since commercial operation of Grand Gulf 1,
payments under the Unit Power Sales Agreement have exceeded the
amounts payable under the Availability Agreement. Accordingly, no
payments have ever been required.
Reallocation Agreement
System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the
Reallocation Agreement relating to the sale of capacity and energy
from the Grand Gulf Station and the related costs, in which LP&L,
MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and
obligations with respect to the Grand Gulf Station under the
Availability Agreement. FERC's decision allocating a portion of Grand
Gulf 1 capacity and energy to AP&L supersedes the Reallocation
Agreement as it relates to Grand Gulf 1. Responsibility for any Grand
Gulf 2 amortization amounts has been individually allocated
(LP&L 26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the
Reallocation Agreement. However, the Reallocation Agreement does not
affect AP&L's obligation to System Energy's lenders under the
assignments referred to in the preceding paragraph. AP&L would be
liable for its share of such amounts if LP&L, MP&L, and NOPSI were
unable to meet their contractual obligations. No payments of any
amortization amounts will be required as long as amounts paid to
System Energy under the Unit Power Sales Agreement, including other
funds available to System Energy, exceed amounts required under the
Availability Agreement, which is expected to be the case for the
foreseeable future.
System Fuels
MP&L has a 19% interest in System Fuels, a jointly-owned
subsidiary of AP&L, LP&L, MP&L, and NOPSI. The parent companies of
System Fuels, including MP&L, agreed to make loans to System Fuels to
finance its fuel procurement, delivery, and storage activities. As of
December 31, 1994, MP&L had approximately $5.5 million of loans
outstanding to System Fuels which mature in 2008.
On April 30, 1993, AP&L assumed System Fuels' rights and
obligations in connection with System Fuels' coal car leases. The
other parent companies of System Fuels have been released from their
obligations with respect to the coal car leases. However, MP&L, as a
co-owner of the Independence Station, which uses the coal transported
by the leased coal cars, will continue to reimburse AP&L for MP&L's
share of the costs associated with the leases.
Fuel Purchase Commitments
MP&L owns certain coal mining equipment and facilities at a mine
in Wyoming. The mine's estimated reserves are presently expected to
provide the projected requirements of the Independence Station through
at least 2011.
NOTE 9. POSTRETIREMENT BENEFITS
Pension Plan
MP&L has a defined benefit pension plan covering substantially
all of its employees. The pension plan is noncontributory and provides
pension benefits based on employees' credited service and average
compensation, generally during the last five years before retirement.
MP&L funds pension costs in accordance with contribution guidelines
established by the Employee Retirement Income Security Act of 1974, as
amended, and the Internal Revenue Code of 1986, as amended. The
assets of the plan consist primarily of common and preferred stocks,
fixed income securities, interest in a money market fund, and
insurance contracts.
MP&L's 1994, 1993, and 1992 pension cost, including amounts
capitalized, included the following components:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Service cost - benefits earned during the period $2,484 $2,409 $ 2,059
Interest cost on projected benefit obligation 8,648 8,583 8,269
Actual return on plan assets 1,507 (15,053) (8,474)
Net amortization and deferral (11,843) 5,325 (1,009)
------- ------- ------
Net pension cost $796 $1,264 $845
======= ======= ======
The funded status of MP&L's pension plan as of December 31, 1994
and 1993, was:
1994 1993
(In Thousands)
Actuarial present value of accumulated pension plan benefits:
Vested $ 94,978 $101,664
Nonvested 299 390
-------- --------
Accumulated benefit obligation $ 95,277 $102,054
======== ========
Plan assets at fair value $117,853 $126,990
Projected benefit obligation 109,250 122,056
-------- --------
Plan assets in excess of projected benefit obligation 8,603 4,934
Unrecognized prior service cost 4,198 3,574
Unrecognized transition asset (8,752) (10,003)
Unrecognized net gain (8,138) (1,798)
-------- --------
Accrued pension liability $ (4,089) $ (3,293)
======== ========
The significant actuarial assumptions used in computing the
information above for 1994, 1993, and 1992 were as follows: weighted
average discount rate, 8.5% for 1994, 7.5% for 1993 and 8.25% for
1992; weighted average rate of increase in future compensation levels,
5.1% for 1994 and 5.6% for 1993 and 1992; and expected long-term rate
of return on plan assets, 8.5%. Transition assets are being amortized
over 15 years.
Other Postretirement Benefits
MP&L also provides certain health care and life insurance
benefits for retired employees. Substantially all employees may
become eligible for these benefits if they reach retirement age while
still working for MP&L. The cost of providing these benefits,
recorded on a cash basis, to retirees in 1992 was approximately
$1.6 million.
Effective January 1, 1993, MP&L adopted SFAS 106. This standard
required a change from a cash method to an accrual method of
accounting for postretirement benefits other than pensions. At
January 1, 1993, the actuarially determined accumulated postretirement
benefit obligation (APBO) earned by retirees and active employees was
estimated to be approximately $30 million. This obligation is being
amortized over a 20-year period beginning in 1993. MP&L is expensing
its SFAS 106 costs, which is reflected in rates pursuant to an order
from the MPSC in connection with MP&L's formulary incentive rate plan
(see Note 2). In conjunction with such rate incentive plan, MP&L has
established and commenced funding two Voluntary Employee's Beneficiary
Association (VEBA) trusts (for bargaining and non-bargaining unit
employees). During 1994, MP&L funded $2.9 million to these VEBA
trusts. The trust's assets are invested in a money market fund.
MP&L's 1994 and 1993 postretirement benefit cost, including
amounts capitalized and deferred, included the following components:
1994 1993
(In Thousands)
Service cost - benefits earned during the period $ 876 $ 812
Interest cost on APBO 1,833 2,400
Net amortization and deferral 1,122 1,502
------ ------
Net periodic postretirement benefit cost $3,831 $4,714
====== ======
The funded status of MP&L's postretirement plan as of December
31, 1994 and 1993, was
1994 1993
Accumulated postretirement benefit obligations: (In Thousands)
Retirees $15,531 $21,435
Other fully eligible participants 4,293 5,816
Other active participants 3,561 7,794
------- -------
23,385 35,045
Plan assets at fair value 2,949 -
------- -------
Plan assets less than APBO (20,436) (35,045)
Unrecognized transition obligation 27,035 28,537
Unrecognized net loss (gain) (8,636) 3,745
------- -------
Accrued post retirement benefit liability $(2,037) $(2,763)
======= =======
The assumed health care cost trend rate used in measuring the
APBO was 9.4% for 1995, gradually decreasing each successive year
until it reaches 5.0% in 2011. A one percentage-point increase in the
assumed health care cost trend rate for each year would have increased
the APBO as of December 31, 1994, by 7.4% and the sum of the service
cost and interest cost by approximately 9.5%. The assumed discount
rate and rate of increase in future compensation used in determining
the APBO were 8.5% for 1994 and 7.5% for 1993 and 5.1% for 1994 and
5.5% for 1993, respectively.
NOTE 10. TRANSACTIONS WITH AFFILIATES
MP&L buys electricity from and/or sells electricity to the other
System operating companies and System Energy under rate schedules
filed with FERC. In addition, MP&L purchases fuel from System Fuels
and receives technical and advisory services from Entergy Services.
Operating revenues include revenues from sales to affiliates
amounting to $45.8 million in 1994, $40.6 million in 1993, and $18
million in 1992. Operating expenses include charges from affiliates
for fuel costs, purchased power and related charges, and technical and
advisory services totaling $280.2 million in 1994, $360.5 million in
1993, and $364 million in 1992.
See Note 1 for information on MP&L's jointly-owned generating
station.
NOTE 11. RESTRUCTURING COSTS
During the third quarter of 1994, MP&L announced a restructuring
program related to certain of its operating units. The program is
designed to reduce costs, improve operating efficiencies, and increase
shareholder value in order to enable MP&L to become a low-cost
producer. The program includes reductions in the number of employees
and the consolidation of offices and facilities. In 1994, MP&L
recorded restructuring charges of $6.2 million. These charges
primarily include employee severance costs related to the expected
termination of approximately 262 employees. As of December 31, 1994,
no employees have been terminated and no termination benefits have
been paid under this restructuring program.
NOTE 12. QUARTERLY FINANCIAL DATA (UNAUDITED)
MP&L's business is subject to seasonal fluctuations with the peak
period occurring during the third quarter. Operating results for the
four quarters of 1994 and 1993 were:
Operating Operating Net
Revenues Income Income
(In Thousands)
1994:
First Quarter $187,417 $18,715 $ 6,249
Second Quarter $229,790 $33,828 $21,653
Third Quarter $234,274 $23,675 $10,856
Fourth Quarter $196,407 $19,539 $10,021
1993:
First Quarter $179,467 $24,134 $42,782
Second Quarter $229,506 $38,471 $25,339
Third Quarter $264,419 $39,896 $26,921
Fourth Quarter $222,414 $22,819 $ 6,701
See Note 1 for information regarding the recording of the
cumulative effect of the change in accounting principle for
unbilled revenues in January 1993.
MISSISSIPPI POWER & LIGHT COMPANY
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1994 1993 1992 1991 1990
(In Thousands)
Operating revenues $ 847,888 $ 895,806 $ 817,650 $ 754,632 $ 761,188
Income before cumulative
effect of a change in
accounting principle $ 48,779 $ 69,037 $ 65,036 $ 63,088 $ 60,830
Total assets $1,629,445 $1,676,737 $1,660,726 $1,672,275 $1,616,522
Long-term obligations (1) $ 507,555 $ 563,612 $ 576,787 $ 576,599 $ 679,458
(1) Includes long-term debt (excluding currently maturing debt),
preferred stock with sinking fund, and noncurrent capital lease
obligations.
See Notes 1, 3, and 9 for the effect of accounting changes in
1993.
1994 1993 1992 1991 1990
(Dollars in Thousands)
Operating Revenues:
Residential $331,007 $343,585 $308,346 $307,283 $302,622
Commercial 255,898 252,798 235,137 229,597 227,140
Industrial 183,398 183,537 168,853 162,072 160,007
Governmental 27,349 28,708 26,250 25,630 25,117
-------- -------- -------- -------- --------
Total retail 797,652 808,628 738,586 724,582 714,886
Sales for resale 54,475 55,740 37,983 25,487 35,678
Other (4,239) 31,438 41,081 4,563 10,624
-------- -------- -------- -------- --------
Total $847,888 $895,806 $817,650 $754,632 $761,188
======== ======== ======== ======== ========
Billed Electric Energy
Sales (Millions of KWH):
Residential 4,014 3,983 3,644 3,739 3,701
Commercial 3,151 2,928 2,804 2,807 2,802
Industrial 2,985 2,787 2,631 2,582 2,564
Governmental 330 336 318 321 318
------ ------ ------ ------ ------
Total retail 10,480 10,034 9,397 9,449 9,385
Sales for resale 1,591 1,428 1,190 1,032 902
------ ------ ------ ------ ------
Total 12,071 11,462 10,587 10,481 10,287
====== ====== ====== ====== ======
New Orleans Public Service Inc.
1994 Financial Statements
NEW ORLEANS PUBLIC SERVICE INC.
DEFINITIONS
Certain abbreviations or acronyms used in NOPSI's Financial
Statements, Notes to Financial Statements, and Management's Financial
Discussion and Analysis are defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
Alliance Alliance for Affordable Energy, and others
AP&L Arkansas Power & Light Company
City of New Orleans
or City New Orleans, Louisiana
Council Council of the City of New Orleans, Louisiana
Entergy or System Entergy Corporation and its various direct
and indirect subsidiaries
Entergy Services Entergy Services, Inc.
EPAct The Energy Policy Act of 1992
FASB Financial Accounting Standards Board
February 4 Resolution The Resolution (including the Determinations
and Order referred to therein) adopted by the
Council on February 4, 1988, disallowing the
recovery by NOPSI of $135 million of previously
deferred Grand Gulf 1-related costs
FERC Federal Energy Regulatory Commission
G&R Bonds General and Refunding Mortgage Bonds issued and
issuable by NOPSI
Grand Gulf 1 Unit No. 1 of the Grand Gulf Station (nuclear)
Grand Gulf 2 Unit No. 2 of the Grand Gulf Station (nuclear)
Grand Gulf Station Grand Gulf Steam Electric Generating Station (nuclear)
GSU Gulf States Utilities Company (including wholly
owned subsidiaries - Varibus Corporation, GSG&T, Inc.,
Prudential Oil and Gas, Inc., and Southern Gulf
Railway Company)
KWH Kilowatt-Hour(s)
LP&L Louisiana Power & Light Company
Merger The combination transaction, consummated on
December 31, 1993, by which GSU became a subsidiary
of Entergy Corporation and Entergy Corporation became
a Delaware Corporation
Money Pool Entergy Money Pool, which allows certain
System companies to borrow from, or lend to,
certain other System companies
MP&L Mississippi Power & Light Company
1986 Rate Settlement Agreement, effective March 25, 1986, between
NOPSI and the Council regarding NOPSI's Grand
Gulf 1-related rate issues
1989 Settlement
Agreement An agreement between the Council and NOPSI,
effective July 21, 1989, that settled certain
local retail rate issues regarding Grand Gulf 1
1991 NOPSI Settlement Settlement, retroactive to October 4, 1991,
among NOPSI, the Council and the Alliance
that settled certain Grand Gulf 1 prudence
issues and litigation related to the
February 4 Resolution
NOPSI New Orleans Public Service Inc.
OBRA Omnibus Budget Reconciliation Act of 1993
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
promulgated by the FASB
SFAS 106 SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions"
SFAS 109 SFAS 109, "Accounting for Income Taxes"
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively
System or Entergy Entergy Corporation and its various direct
and indirect subsidiaries
NEW ORLEANS PUBLIC SERVICE INC.
REPORT OF MANAGEMENT
The management of New Orleans Public Service Inc. has prepared
and is responsible for the financial statements and related financial
information included herein. The financial statements are based on
generally accepted accounting principles. Financial information
included elsewhere in this report is consistent with the financial
statements.
To meet its responsibilities with respect to financial
information, management maintains and enforces a system of internal
accounting controls that is designed to provide reasonable assurance,
on a cost-effective basis, as to the integrity, objectivity, and
reliability of the financial records, and as to the protection of
assets. This system includes communication through written policies
and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and
the training of personnel. This system is also tested by a
comprehensive internal audit program.
The independent public accountants provide an objective
assessment of the degree to which management meets its responsibility
for fairness of financial reporting. They regularly evaluate the
system of internal accounting controls and perform such tests and
other procedures as they deem necessary to reach and express an
opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide
reasonable assurance that its operations are carried out with a high
standard of business conduct.
/s/ Edwin Lupberger /s/ Gerald D. McInvale
EDWIN LUPBERGER GERALD D. MCINVALE
Chairman and Chief Executive Officer Senior Vice President and
Chief Financial Officer
NEW ORLEANS PUBLIC SERVICE INC.
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Entergy Corporation Board of Directors' Audit Committee
functions as the Audit Committee for New Orleans Public Service Inc.
The Audit Committee is comprised of four directors, who are not
officers of NOPSI: H. Duke Shackelford (Chairman), Lucie J.
Fjeldstad, Dr. Norman C. Francis, and James R. Nichols. The committee
held four meetings during 1994.
The Audit Committee oversees NOPSI's financial reporting process
on behalf of the Board of Directors and provides reasonable assurance
to the Board that sufficient operating, accounting, and financial
controls are in existence and are adequately reviewed by programs of
internal and external audits.
The Audit Committee discussed with Entergy's internal auditors
and the independent public accountants (Coopers & Lybrand L.L.P.) the
overall scope and specific plans for their respective audits, as well
as NOPSI's financial statements and the adequacy of NOPSI's internal
controls. The committee met, together and separately, with Entergy's
internal auditors and independent public accountants, without
management present, to discuss the results of their audits, their
evaluation of NOPSI's internal controls, and the overall quality of
NOPSI's financial reporting. The meetings also were designed to
facilitate and encourage any private communication between the
committee and the internal auditors or independent public accountants.
/s/ H. Duke Shackelford
H. DUKE SHACKELFORD
Chairman, Audit Committee
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
New Orleans Public Service Inc.
We have audited the accompanying balance sheet of New Orleans
Public Service Inc. as of December 31, 1994, and the related
statements of income, retained earnings and cash flows for the year
then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on
these financial statements based on our audit. The financial
statements of the Company as of December 31, 1993 and for the years
ended December 31, 1993 and 1992, were audited by other auditors,
whose report, dated February 11, 1994, included an explanatory
paragraph that described changes in methods of accounting for
revenues, income taxes and postretirement benefits other than pensions
which are discussed in Notes 1, 3 and 9 respectively, to these
financial statements.
We conducted our audit in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position of
the Company as of December 31, 1994, and the result of its operations
and its cash flows for the year then ended in conformity with
generally accepted accounting principles.
/s/ Coopers & Lybrand L.L.P.
COOPERS & LYBRAND L.L.P.
New Orleans, Louisiana
February 21, 1995
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of
New Orleans Public Service Inc.
We have audited the accompanying balance sheet of New Orleans
Public Service Inc. (NOPSI) as of December 31, 1993, and the related
statements of income, retained earnings, and cash flows for each of
the two years in the period ended December 31, 1993. These financial
statements are the responsibility of NOPSI's management. Our
responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all
material respects, the financial position of NOPSI at December 31,
1993, and the results of its operations and its cash flows for each of
the two years in the period ended December 31, 1993 in conformity with
generally accepted accounting principles.
As discussed in Note 1 to the financial statements, NOPSI changed
its method of accounting for revenues in 1993 and, as discussed in
Notes 3 and 9 to the financial statements, in 1993 NOPSI changed its
methods of accounting for income taxes and postretirement benefits
other than pensions, respectively.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 11, 1994
NEW ORLEANS PUBLIC SERVICE INC.
BALANCE SHEETS
ASSETS
December 31,
1994 1993
(In Thousands)
Utility Plant:
Electric $470,560 $476,976
Natural gas 119,508 113,666
Construction work in progress 7,284 15,205
-------- --------
Total 597,352 605,847
Less - accumulated depreciation and amortization 319,576 330,268
-------- --------
Utility plant - net 277,776 275,579
-------- -------
Other Investments:
Investment in subsidiary company - at equity 3,259 3,259
-------- --------
Current Assets:
Cash and cash equivalents:
Cash 849 1,176
Temporary cash investments - at cost,
which approximates market:
Associated companies 2,472 10,034
Other 4,710 32,107
-------- --------
Total cash and cash equivalents 8,031 43,317
Accounts receivable:
Customer (less allowance for doubtful
accounts of $0.8 million in 1994 and 1993) 23,938 35,801
Associated companies 3,503 1,378
Other 600 876
Accrued unbilled revenues 14,295 19,643
Deferred electric fuel and resale gas costs 856 6,323
Materials and supplies - at average cost 9,676 9,795
Rate deferrals 31,544 24,587
Income tax receivable 20,172 -
Prepayments and other 5,636 5,084
-------- --------
Total 118,251 146,804
-------- --------
Deferred Debits and Other Assets:
Regulatory Assets:
Rate deferrals 173,127 204,190
SFAS 109 regulatory asset - net 8,792 9,004
Unamortized loss on reacquired debt 2,361 2,790
Other regulatory assets 5,647 4,027
Other 3,681 1,952
-------- --------
Total 193,608 221,963
-------- --------
TOTAL $592,894 $647,605
======== ========
See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC.
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
1994 1993
(In Thousands)
Capitalization:
Common stock, $4 par value, authorized
10,000,000 shares; issued and outstanding
8,435,900 shares in 1994 and 1993 $33,744 $33,744
Paid-in capital 36,201 36,156
Retained earnings subsequent to the elimination of
the accumulated deficit on November 30, 1988 78,886 100,556
-------- --------
Total common shareholder's equity 148,831 170,456
Preferred stock:
Without sinking fund 19,780 19,780
With sinking fund 3,450 4,950
Long-term debt 164,160 188,312
-------- --------
Total 336,221 383,498
-------- --------
Other Noncurrent Liabilities:
Accumulated provision for losses 17,318 18,062
Other 1,745 3,351
-------- --------
Total 19,063 21,413
-------- --------
Current Liabilities:
Currently maturing long-term debt 24,200 15,000
Accounts payable:
Associated companies 6,456 23,080
Other 19,503 22,011
Customer deposits 17,422 16,617
Accumulated deferred income taxes 4,925 4,968
Taxes accrued 2,329 5,161
Interest accrued 5,242 5,472
Other 19,982 7,367
-------- --------
Total 100,059 99,676
-------- --------
Deferred Credits:
Accumulated deferred income taxes 89,246 105,096
Accumulated deferred investment tax credits 9,251 11,592
Other 39,054 26,330
-------- --------
Total 137,551 143,018
-------- --------
Commitments and Contingencies (Notes 2 and 8)
TOTAL $592,894 $647,605
======== ========
See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Activities:
Net income $13,211 $47,709 $26,424
Noncash items included in net income:
Cumulative effect of a change in accounting principle - (10,948) -
Change in rate deferrals 24,106 15,842 2,856
Depreciation and amortization 19,275 17,284 16,619
Deferred income taxes and investment tax credits (18,006) (2,132) (865)
Allowance for equity funds used during construction (331) (141) (119)
Net pension expense - - (23,131)
Changes in working capital:
Receivables 15,362 (6,725) 1,579
Accounts payable (19,132) 1,169 (1,455)
Taxes accrued (2,832) (82) 1,473
Interest accrued (230) (1,319) (1,687)
Income tax receivable (20,172) - -
Other working capital accounts 18,454 1,365 (6,344)
Other 8,851 8,345 7,047
-------- -------- --------
Net cash flow provided by operating activities 38,556 70,367 22,397
-------- -------- --------
Investing Activities:
Construction expenditures (22,777) (24,813) (21,043)
Allowance for equity funds used during construction 331 141 119
-------- -------- --------
Net cash flow used in investing activities (22,446) (24,672) (20,924)
-------- -------- --------
Financing Activities:
Proceeds from the issuance of general
and refunding bonds - 100,000 -
Retirement of:
First mortgage bonds - (56,823) (28,000)
General and refunding bonds (15,000) (44,400) -
Redemption of preferred stock (1,500) (1,500) (1,500)
Dividends paid:
Common stock (33,300) (43,900) (32,154)
Preferred stock (1,596) (1,825) (2,057)
-------- -------- --------
Net cash flow used in financing activities (51,396) (48,448) (63,711)
-------- -------- --------
Net decrease in cash and cash equivalents (35,286) (2,753) (62,238)
Cash and cash equivalents at beginning of period 43,317 46,070 108,308
-------- -------- --------
Cash and cash equivalents at end of period $8,031 $43,317 $46,070
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $17,707 $21,953 $26,330
Income taxes $45,984 $25,661 $15,632
See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is important to NOPSI due to the capital intensive
nature of its business, which requires large investments in long-lived
assets. While large capital expenditures for the construction of new
generating capacity are not currently planned, NOPSI does require
significant capital resources for the periodic maturity of certain
series of debt and preferred stock and ongoing construction
expenditures. Net cash flow from operations totaled $39 million, $70
million, and $22 million in 1994, 1993, and 1992, respectively. Net
cash flow from operations decreased in 1994 due primarily to the
effects of the 1994 NOPSI Settlement, as discussed below. In recent
years, this cash flow, supplemented by cash on hand, has been
sufficient to meet substantially all investing and financing
requirements, including capital expenditures, dividends, and
debt/preferred stock maturities. NOPSI's ability to fund these
capital requirements results, in part, from its continued efforts to
streamline operations and reduce costs, as well as collections under
its Grand Gulf 1 rate phase-in plan which exceed the current cash
requirements for Grand Gulf 1-related costs. (In the income
statement, these revenue collections are offset by the amortization of
previously deferred costs; therefore, there is no effect on net
income.) NOPSI's Grand Gulf 1 rate phase-in plan will continue to
contribute to NOPSI's cash position through 2001. See Note 2 for
additional information on NOPSI's rate phase-in plan. See Note 8 for
additional information on NOPSI's capital and refinancing requirements
in 1995 - 1997. Also, to the extent current market interest and
dividend rates allow, NOPSI may continue to refinance high-cost debt
and preferred stock prior to maturity.
As discussed in Note 2, NOPSI agreed to reduce electric and gas
rates and issue credits and refunds to customers pursuant to the 1994
NOPSI Settlement. Under the terms of the settlement, NOPSI
implemented rate reductions totaling $44.9 million effective January
1, 1995. NOPSI will implement an additional $4.4 million rate
reduction on October 31, 1995. In addition, the 1994 NOPSI Settlement
requires NOPSI to credit its customers $25 million over a 21-month
period beginning January 1, 1995, in order to resolve disputes with
the Council regarding the interpretation of the 1991 NOPSI Settlement.
The 1994 NOPSI Settlement also required NOPSI to refund $9.3 million
of overcollections associated with Grand Gulf 1 operating costs and
$10.5 million of refunds associated with the settlement by System
Energy of a FERC tax audit. See Note 2 for additional information.
Earnings coverage tests, bondable property additions, and
accumulated deferred Grand Gulf 1-related costs recorded as assets,
limit the amount of G&R Bonds and preferred stock that NOPSI can
issue. Based on the most restrictive applicable tests as of
December 31, 1994, and an assumed annual interest or dividend rate of
9.25%, NOPSI could have issued $73 million of additional G&R Bonds or
$17 million of additional preferred stock. Further, NOPSI has the
conditional ability to issue G&R Bonds against the retirement of
bonds, in some cases without satisfying an earnings coverage test.
See Notes 5 and 6 for information on NOPSI's financing activities
and Note 4 for information on NOPSI's short-term borrowings and lines
of credit.
NEW ORLEANS PUBLIC SERVICE INC.
STATEMENTS OF INCOME
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Revenues:
Electric $360,430 $423,830 $391,936
Natural gas 87,357 90,992 72,943
---------- ---------- ----------
Total 447,787 514,822 464,879
---------- ---------- ----------
Operating Expenses:
Operation and maintenance:
Fuel, fuel-related expenses
and gas purchased for resale 113,735 112,451 90,778
Purchased power 145,935 165,963 170,703
Other operation and maintenance 80,656 87,797 91,735
Depreciation and amortization 19,275 17,284 16,619
Taxes other than income taxes 27,814 26,643 27,487
Income taxes 3,602 24,232 14,382
Rate deferrals:
Rate deferrals - (1,651) (1,300)
Amortization of rate deferrals 27,009 22,351 4,426
---------- ---------- ----------
Total 418,026 455,070 414,830
---------- ---------- ----------
Operating Income 29,761 59,752 50,049
---------- ---------- ----------
Other Income (Deductions):
Allowance for equity funds used
during construction 331 141 119
Miscellaneous - net 2,141 (1,055) 3,056
Income taxes (998) (1,115) (1,683)
---------- ---------- ----------
Total 1,474 (2,029) 1,492
---------- ---------- ----------
Interest Charges:
Interest on long-term debt 17,092 20,076 23,510
Other interest - net 1,179 1,016 1,714
Allowance for borrowed funds used
during construction (247) (130) (107)
---------- ---------- ----------
Total 18,024 20,962 25,117
---------- ---------- ----------
Income before Cumulative Effect
of a Change in Accounting Principle 13,211 36,761 26,424
Cumulative Effect to January 1, 1993
of Accruing Unbilled Revenues
(net of income taxes of $6,592) - 10,948 -
---------- ---------- ----------
Net Income 13,211 47,709 26,424
Preferred Stock Dividend
Requirements and Other 1,581 1,768 1,999
---------- ---------- ----------
Earnings Applicable to Common Stock $11,630 $45,941 $24,425
========== ========== ==========
See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC.
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Retained Earnings, January 1 $100,556 $98,560 $106,341
Add:
Net income 13,211 47,709 26,424
-------- -------- --------
Total 113,767 146,269 132,765
-------- -------- --------
Deduct:
Dividends declared:
Preferred stock 1,536 1,768 1,999
Common stock 33,300 43,900 32,154
Capital stock expenses 45 45 52
-------- -------- --------
Total 34,881 45,713 34,205
-------- -------- --------
Retained Earnings, December 31 (Note 7) $ 78,886 $100,556 $ 98,560
======== ======== ========
See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income decreased in 1994 due primarily to the effects of the
1994 NOPSI Settlement (see Note 2) and the one-time recording of the
cumulative effect of the change in accounting principle for unbilled
revenues in 1993, partially offset by lower operating expenses. Net
income increased in 1993 due primarily to the one-time recording of
the cumulative effect of the change in accounting principle for
unbilled revenues (see Note 1) and its ongoing effects, partially
offset by the effect of implementing SFAS 106 (see Note 9).
Effective January 1, 1993, NOPSI began accruing as revenues the
charges for energy delivered to customers but not yet billed.
Electric and gas revenues were previously recorded on a cycle-billing
basis. Excluding the above mentioned items, net income for 1993
would have been $37.8 million. This $11.4 million increase is due
primarily to increased gas revenues and increased electric retail
energy sales.
Significant factors affecting the results of operations and
causing variances between the years 1994 and 1993, and 1993 and 1992,
are discussed under "Revenues and Sales" and "Expenses" below.
Revenues and Sales
See "Selected Financial Data-Five-Year Comparison," following
the notes, for information on electric operating revenues by source
and KWH sales.
Electric operating revenues decreased in 1994 due primarily to
the effects of the 1994 NOPSI Settlement as discussed in Note 2.
Electric energy sales increased slightly in 1994. Electric operating
revenues were higher in 1993 due primarily to increased fuel
adjustment revenues and increased collections of previously deferred
Grand Gulf 1-related costs, neither of which affects net income, and
increased residential energy sales resulting primarily from a return
to more normal weather as compared to milder weather in 1992.
Gas operating revenues decreased slightly in 1994 as a result of
lower gas sales. Gas operating revenues increased in 1993 due
primarily to an increase in gas rates and increased fuel adjustment
revenues resulting from higher average per unit cost for gas
purchased.
Expenses
Operating expenses decreased in 1994 due primarily to lower
purchased power expense and lower income tax expense. Operating
expenses increased in 1993 due primarily to higher fuel expenses,
higher income tax expense, and increased amortization of rate
deferrals.
Purchased power expense decreased in 1994 due primarily to
changes in generation availability and requirements among the System
operating companies and lower costs. Fuel for electric generation
and fuel-related expenses increased in 1993 due primarily to
increased gas costs and increased generation requirements resulting
primarily from increased energy sales as discussed in "Revenues and
Sales" above.
Gas purchased for resale decreased in 1994 due to decreased gas
sales. Gas purchased for resale increased in 1993 due primarily to a
higher average per unit cost for gas purchased.
Income taxes decreased in 1994 due primarily to lower pretax
income, resulting from the 1994 NOPSI Settlement, and the write-off
of the unamortized balances of deferred investment tax credits
pursuant to the FERC Settlement. Total income taxes increased in 1993
due primarily to higher pretax income and an increase in the federal
income tax rate as a result of OBRA.
The increases in the amortization of rate deferrals in 1994 and
1993 is primarily a result of the collection of larger amounts of
previously deferred costs under the 1991 NOPSI Settlement, which
allowed NOPSI to record an additional $90 million of previously
incurred Grand Gulf 1-related costs.
NEW ORLEANS PUBLIC SERVICE INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Competition
The electric utility industry is becoming increasingly
competitive and NOPSI is seeking to become a leading competitor in the
changing electric energy business. Competition presents NOPSI with
many challenges. The following have been identified by NOPSI as its
major competitive challenges.
Retail and Wholesale Rate Issues
Increasing competition in the utility industry brings an
increased need to stabilize or reduce retail rates. In connection
with the Merger, NOPSI agreed with the Council to reduce its annual
electric base rates by $4.8 million effective for bills rendered on or
after November 1, 1993. As a result of the 1994 NOPSI Settlement
discussed in Note 2, NOPSI agreed to reduce electric and gas rates and
issue credits and refunds to customers. Effective January 1, 1995,
NOPSI implemented a $31.8 million permanent reduction in electric base
rates and a $3.1 million permanent reduction in gas base rates. These
adjustments resolved issues associated with NOPSI's return on equity
exceeding 13.76% for the test year ended September 30, 1994. Under
the 1991 NOPSI Settlement, NOPSI is recovering from its retail
customers its allocable share of certain costs related to Grand Gulf
1. NOPSI's base rates to recover those costs were derived from
estimates of those costs made at that time. Any overrecovery of costs
is required to be returned to customers. Grand Gulf 1 has experienced
lower operating costs than previously estimated, and NOPSI accordingly
is reducing its base rates in two steps to more accurately match the
current costs related to Grand Gulf 1. On January 1, 1995, NOPSI
implemented a $10 million permanent reduction in base electric rates
to reflect the reduced costs related to Grand Gulf 1, to be followed
by an additional $4.4 million rate reduction on October 31, 1995.
These Grand Gulf 1 rate reductions, which are expected to be largely
offset by lower operating costs, may reduce NOPSI's after-tax net
income by approximately $1.4 million per year beginning November 1,
1995. The next scheduled Grand Gulf 1 phase-in rate increase in the
amount of $4.4 million on October 31, 1995, will not be affected by
the 1994 NOPSI Settlement.
The 1994 NOPSI Settlement also requires NOPSI to credit its
customers $25 million over a 21-month period beginning January 1,
1995, in order to resolve disputes with the Council regarding the
interpretation of the 1991 NOPSI Settlement. NOPSI reduced its
revenues and recorded a $15.4 million net-of-tax reserve associated
with the credit in the fourth quarter of 1994. The 1994 NOPSI
Settlement further required NOPSI to refund, in December 1994, $13.3
million of credits previously scheduled to be made to customers during
the period January 1995 through July 1995. These credits were
associated with a July 7, 1994, Council resolution that ordered a
$24.95 million rate reduction based on NOPSI's overearnings during the
test year ended September 30, 1993. Accordingly, NOPSI recorded an $8
million net-of-tax charge in the fourth quarter of 1994.
Retail wheeling, the transmission by an electric utility of
energy produced by another entity over the utility's transmission and
distribution system to a retail customer in the electric utility's
area of service, is also evolving. Over a dozen states have been or
are studying the concept of retail competition. In April 1994, the
state of Michigan initiated a five-year experiment that allows limited
competition among public utilities. During the same month, the
California Public Utilities Commission proposed to deregulate that
state's electric power industry, starting on January 1, 1996, to allow
the largest industrial customers to select the lowest cost supplier
for electricity service. Under the proposal, by the year 2002,
smaller companies and residential customers in California would also
be able to buy power from any suppliers. The California Public
Utilities Commission is currently reviewing its proposal and is
expected to make a ruling in the first half of 1995. The retail market
for electricity is expected to become more competitive with such moves
toward deregulation.
In some areas of the country, municipalities (or comparable
entities) whose residents are served at retail by an investor-owned
utility pursuant to a franchise are exploring the possibility of
establishing new or extending existing distribution systems or seeking
new delivery points in order to serve retail customers, especially
large industrial customers, that currently receive service from an
investor-owned utility. These options depend on the terms of a
utility's franchise as well as on state law and regulation. In
addition, FERC's authority to order utilities to transmit for a new or
expanding municipal system is limited in certain respects. Where
successful, however, the establishment of a municipal system or the
acquisition by a municipal system of a utility's customers could
result in the inability to recover costs that the utility has incurred
in serving those customers.
In mid-1994, the FERC issued a notice of proposed rulemaking
concerning a regulatory framework for dealing with recovery of
stranded costs, such as high cost nuclear generating units, which may
be incurred by electric utilities as a result of increased
competition. In addition to addressing recovery of stranded costs
related to wholesale service, the proposal requested comment as to
recovery of retail stranded costs in transmission rates where state
regulatory authorities failed to address the issue or were in
conflict. Comments and reply comments have been filed, and the matter
is pending. The risk of exposure to stranded costs which may result
from competition in the industry will depend on the extent and timing
of retail competition, the resolution of jurisdictional issues
concerning stranded cost recovery, and the extent to which such costs
are recovered from departing or remaining customers, among other
matters.
In the wholesale rate area, FERC approved in 1992, with certain
modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy
Power to sell wholesale power at market-based rates and to provide to
electric utilities "open access" to the System's transmission system
(subject to certain requirements). GSU was later added to this
filing. On October 31, 1994, as amended on January 25, 1995, Entergy
Services filed with FERC revised transmission tariffs intended to
provide access to transmission service on the same or comparable
basis, terms, and conditions as the System operating companies, and
the matter is pending. Open access and market pricing, once in
effect, will increase marketing opportunities for NOPSI, but will
also expose NOPSI to the risk of loss of load or reduced revenues due
to competition with alternative suppliers.
In light of the rate issues discussed above, NOPSI is
aggressively reducing costs to avoid potential earnings erosions that
might result as well as to become more competitive. In 1994, NOPSI
announced a restructuring program related to certain of its operating
units. This program is designed to reduce costs and improve
operating efficiencies. See Note 12 for further information. Also,
in response to an increasingly competitive environment, NOPSI
announced intentions to revise its initial least cost planning
activities.
The Energy Policy Act of 1992
The EPAct addresses a wide range of energy issues and is altering
the way Entergy and the rest of the electric utility industry
operate. The EPAct encourages competition and affords utilities the
opportunities, and the risks, associated with an open and more
competitive market environment. The EPAct creates exemptions from
regulation under the Holding Company Act and creates a class of exempt
wholesale generators consisting of utility affiliates and nonutilities
that are owners and operators of facilities for the generation and
transmission of power for sales at wholesale. The EPAct also gives
FERC the authority to order investor-owned utilities, including NOPSI,
to transmit power and energy to or for wholesale purchasers and
sellers. The law creates the potential for electric utilities and
other power producers to gain increased access to the transmission
systems of other entities to facilitate wholesale sales. Both NOPSI
and Entergy Power expect to compete in this market. In addition, the
EPAct allows utilities to own and operate foreign generation,
transmission, and distribution facilities.
Litigation and Regulatory Proceedings
In November 1994, FERC approved an agreement settling a long-
standing dispute involving income tax allocation procedures of System
Energy. In accordance with the agreement, System Energy refunded
approximately $10.5 million to NOPSI, which in turn made refunds on
December 31, 1994, to customers. Additionally, System Energy will
refund a total of approximately $10.5 million, plus interest, to NOPSI
over the period through June 2004. The settlement also required the
write-off of approximately $1.7 million of certain unamortized
deferred investment tax credits by NOPSI.
Accounting Issues
Proposed Accounting Standards - The FASB has proposed a SFAS on
"Accounting for the Impairment of Long-Lived Assets," effective
January 1, 1996. The proposed standard describes circumstances which
may result in assets being impaired and provides criteria for
recognition and measurement of asset impairment. Certain operations
of NOPSI are potentially affected by this standard, and any resulting
write-offs will depend on future operating costs, generating units'
efficiency and availability, and the future market for energy over the
remaining life of the units. Based on current estimates, NOPSI
anticipates that future revenues will fully recover the costs of such
operations.
Continued Application of SFAS 71 - NOPSI's financial statements
currently reflect assets and costs based on current cost-based
ratemaking regulations, in accordance with SFAS 71, "Accounting for
the Effects of Certain Types of Regulation." As discussed above, the
electric utility industry is changing and these changes could possibly
result in the discontinuance of the application of SFAS 71, which
would result in the elimination of regulatory assets and liabilities.
See Note 1 for further information.
NEW ORLEANS PUBLIC SERVICE INC.
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NOPSI maintains accounts in accordance with FERC and other
regulatory guidelines. Certain previously reported amounts have been
reclassified to conform to current classifications.
Revenues and Fuel Costs
Prior to January 1, 1993, NOPSI recorded revenues when billed to
its customers with no accrual for energy delivered but not yet billed.
To provide a better matching of revenues and expenses, effective
January 1, 1993, NOPSI adopted a change in accounting principle to
provide for accrual of the nonfuel portion of estimated unbilled
revenues. The cumulative effect of this accounting change as of
January 1, 1993 increased net income by $10.9 million. Had this new
accounting method been in effect during prior years, net income before
the cumulative effect would not have been materially different from
that shown in the accompanying financial statements.
NOPSI's rate schedules include electric fuel adjustment and gas
cost adjustment clauses that allow deferral of fuel costs until such
costs are reflected in the related revenues.
Utility Plant
Utility plant is stated at original cost. The original cost of
utility plant retired or removed, plus the applicable removal costs,
less salvage, is charged to accumulated depreciation. Maintenance,
repairs, and minor replacement costs are charged to operating
expenses. Substantially all of NOPSI's utility plant is subject to
the liens of its mortgage bond indentures.
Total NOPSI net electric utility plant in service of $205 million
as of December 31, 1994 includes $26 million of production plant, $20
million of transmission plant, $141 million of distribution plant, and
$18 million of other plant. Total net gas utility plant of $66
million as of December 31, 1994 is primarily comprised of $60 million
of distribution plant.
Depreciation is computed on the straight-line basis at rates
based on the estimated service lives and costs of removal of the
various classes of property. Depreciation provisions on average
depreciable property approximated 3.1% in 1994, 1993, and 1992.
AFUDC represents the approximate net composite interest cost of
borrowed funds and a reasonable return on the equity funds used for
construction. Although AFUDC increases utility plant and increases
earnings, it is only realized in cash through depreciation provisions
included in rates. NOPSI's effective composite rates for AFUDC were
10.4%, 11.4%, and 12.1% for 1994, 1993, and 1992, respectively.
Income Taxes
NOPSI, its parent, and affiliates file a consolidated federal
income tax return. Income taxes are allocated to NOPSI in proportion
to its contribution to consolidated taxable income. SEC regulations
require that no Entergy Corporation subsidiary pay more taxes than it
would have had a separate income tax return been filed. Deferred
taxes are recorded for all temporary differences between book and
taxable income. Investment tax credits are deferred and amortized
based upon the average useful life of the related property in
accordance with rate treatment. As discussed in Note 3, in 1993 NOPSI
changed its accounting for income taxes to conform with SFAS 109.
Other Noncurrent Liabilities
NOPSI records provisions for uninsured risks and claims for
injuries and damages through charges to operations expenses on an
accrual basis. Provisions for these accruals, classified as other
noncurrent liabilities, have been allowed for ratemaking purposes.
Cash and Cash Equivalents
NOPSI considers all unrestricted highly liquid debt instruments
purchased with an original maturity of three months or less to be cash
equivalents.
Continued Application of SFAS 71
As a result of the EPAct and actions of regulatory commissions,
the electric utility industry is moving toward a combination of
competition and a modified regulatory environment. NOPSI's financial
statements currently reflect assets and costs based on current cost-
based ratemaking regulations in accordance with SFAS 71, "Accounting
for the Effects of Certain Types of Regulation." Continued
applicability of SFAS 71 to NOPSI's financial statements requires that
rates set by an independent regulator on a cost of service basis
(including a reasonable rate of return on invested capital) can
actually be charged to and collected from customers.
In the event that either all or a portion of a utility's
operations cease to meet those criteria for various reasons, including
deregulation, a change in the method of regulation or a change in the
competitive environment for the utility's regulated services, the
utility should discontinue application of SFAS 71 for the relevant
portion. That discontinuation should be reported by elimination from
the balance sheet of the effects of any actions of regulators
recorded as regulatory assets and liabilities.
As of December 31, 1994, and for the foreseeable future, NOPSI's
financial statements continue to follow SFAS 71.
Fair Value Disclosure
The estimated fair value of financial instruments has been
determined by NOPSI, using available market information and
appropriate valuation methodologies. However, considerable judgment
is required in developing the estimates of fair value. Therefore,
estimates are not necessarily indicative of the amounts that NOPSI
could realize in a current market exchange. In addition, gains or
losses realized on financial instruments may be reflected in future
rates and not accrue to the benefit of stockholders.
NOPSI considers the carrying amounts of financial instruments
classified as current assets and liabilities to be a reasonable
estimate of their fair value because of the short maturity of these
instruments. In addition, NOPSI does not presently expect that
performance of its obligations will be required in connection with
certain off-balance sheet commitments and guarantees considered
financial instruments. Due to this factor, and because of the related
party nature of these commitments and guarantees, determination of
fair value is not considered practicable. See Notes 5 and 6 for
additional fair value disclosure.
NOTE 2. RATE AND REGULATORY MATTERS
1994 NOPSI Settlement
In a settlement with the Council that was approved on December
29, 1994, NOPSI agreed to reduce electric and gas rates and issue
credits and refunds to customers. Effective January 1, 1995, NOPSI
implemented a $31.8 million permanent reduction in electric base rates
and a $3.1 million permanent reduction in gas base rates. These
adjustments resolved issues associated with NOPSI's return on equity
exceeding 13.76% for the test year ended September 30, 1994. Under
the 1991 NOPSI Settlement, NOPSI is recovering from its retail
customers its allocable share of certain costs related to Grand Gulf
1. NOPSI's base rates to recover those costs were derived from
estimates of those costs made at that time. Any overrecovery of costs
is required to be returned to customers. Grand Gulf 1 has experienced
lower operating costs than previously estimated, and NOPSI accordingly
is reducing its base rates in two steps to more accurately match the
current costs related to Grand Gulf 1. On January 1, 1995, NOPSI
implemented a $10 million permanent reduction in base electric rates
to reflect the reduced costs related to Grand Gulf 1, to be followed
by an additional $4.4 million rate reduction on October 31, 1995.
These Grand Gulf rate reductions, which are expected to be largely
offset by lower operating costs, may reduce NOPSI's after-tax net
income by approximately $1.4 million per year beginning November 1,
1995. The next scheduled Grand Gulf 1 phase-in rate increase in the
amount of $4.4 million on October 31, 1995 will not be affected by the
1994 NOPSI Settlement.
The 1994 NOPSI Settlement also requires NOPSI to credit its
customers $25 million over a 21-month period beginning January 1,
1995, in order to resolve disputes with the Council regarding the
interpretation of the 1991 NOPSI Settlement. NOPSI reduced its
revenues by $25 million and recorded a $15.4 million net-of-tax
reserve associated with the credit in the fourth quarter of 1994. The
1994 NOPSI Settlement further required NOPSI to refund, in December
1994, $13.3 million of credits previously scheduled to be made to
customers during the period January 1995 through July 1995. These
credits were associated with a July 7, 1994, Council resolution that
ordered a $24.95 million rate reduction based on NOPSI's overearnings
during the test year ended September 30, 1993. Accordingly, NOPSI
recorded an $8 million net-of-tax charge in the fourth quarter of
1994.
The 1994 NOPSI Settlement also required NOPSI to refund $9.3
million of overcollections associated with Grand Gulf 1 operating
costs, and $10.5 million of refunds associated with the settlement by
System Energy of a FERC tax audit. The settlement of the FERC tax
audit by System Energy required refunds to be passed on to NOPSI and
to other Entergy subsidiaries and then on to customers. These refunds
have no effect on current period net income.
Merger - Related Rate Agreement
In 1993, the Council adopted resolutions accepting a proposal by
NOPSI to settle certain issues related to the Merger. Pursuant to the
resolutions, the Council agreed to withdraw from the SEC proceeding
related to the Merger. In return NOPSI agreed, among other things,
that retail ratepayers in the City of New Orleans would be protected
from (1) increases in NOPSI's cost of capital resulting from risks
associated with the Merger; (2) recovery of any portion of the
acquisition premium or transactional costs associated with the Merger;
(3) certain direct allocations of costs associated with GSU's River
Bend nuclear unit; and (4) any losses of GSU resulting from resolution
of litigation in connection with its ownership of River Bend. NOPSI
was required to reduce its annual electric base rates by $4.8 million
effective for bills rendered on or after November 1, 1993, and to
expense its SFAS 106 costs. NOPSI's SFAS 106 expenses through October
31, 1996, will be allowed by the Council for purposes of evaluating
the appropriateness of NOPSI's rates. The Council also agreed not to
seek to disallow the first $3.5 million of costs incurred through
October 31, 1993, in connection with the Least Cost Plan.
Prudence Settlement and Finalized Phase-In Plan
The February 4 Resolution required NOPSI to write off, and not
recover from its retail electric customers, $135 million of its
previously deferred costs associated with Grand Gulf 1. This
write-off, which was recorded in NOPSI's 1987 financial statements,
was in addition to the $51.2 million of Grand Gulf 1-related costs
originally absorbed and not recovered by NOPSI as part of the 1986
Rate Settlement. In 1991, NOPSI reached a settlement (1991 NOPSI
Settlement) with the Council and with the Alliance that resolved the
Grand Gulf 1 prudence issues and the pending litigation related to the
February 4 Resolution.
The 1991 NOPSI Settlement supersedes both the 1986 Rate
Settlement (which established a rate phase-in plan designed to reduce
the immediate effect on ratepayers of the inclusion of Grand Gulf 1
costs in rates) and the February 4 Resolution, and provides that there
will be no further disallowance of the recovery of any Grand
Gulf 1-related costs incurred by NOPSI based on any alleged imprudence
by NOPSI that may have occurred or may be alleged to have occurred
prior to the effective date of the 1991 NOPSI Settlement. The 1991
NOPSI Settlement included a rate decrease in 1991, followed by a
series of rate increases. The last of the rate increases will become
effective on October 31, 1995, in the amount of $4.4 million.
In connection with the rate changes, NOPSI implemented a
finalized phase-in plan, covering a ten-year period from October 1,
1991 through September 30, 2001, for recovery of all Grand Gulf 1
deferred costs, including associated carrying charges.
NOPSI agreed to a five-year electric base rate freeze extending
through October 31, 1996, excluding the annual rate increases provided
for above and except for increases to reflect an increase in state
and/or federal income tax rates or a catastrophic event such as a
hurricane. NOPSI also agreed that during the period October 1, 1992
through October 31, 1996 the Council will have the right to
investigate the appropriateness of NOPSI's rates if NOPSI's return on
average equity on its electric operations (calculated in accordance
with the applicable provisions of the 1991 NOPSI Settlement) for
twelve month periods subsequent to September 30, 1992 were to exceed
13.76%, and, after hearing(s), to impose a credit on NOPSI's
customers' bills in an amount that would have allowed NOPSI, during
the relevant test year, to earn a return on equity incident to its
electric operations of no less than 12.76% (see discussion below).
The Council agreed otherwise not to reduce NOPSI's base electric rates
during the period through October 31, 1996 except to reflect a
decrease in state and/or federal income tax rates; however, this was
amended by the 1994 NOPSI Settlement discussed above.
NOPSI will include in the "over/under" provision of its fuel
adjustment clause on a monthly basis the difference, if any, between
the non-fuel Grand Gulf 1 costs billed by System Energy to NOPSI and
the estimate of such costs attached to the 1991 NOPSI Settlement, with
the Council having the right to suspend this provision in the event of
a catastrophe involving Grand Gulf 1. In the event the Council
suspends this provision, NOPSI will have the right to seek a rate
increase notwithstanding the five-year electric base rate freeze
discussed above. In addition, the 1994 NOPSI Settlement now requires
interest to be included in the "over/under" provision.
Gas Rate Filing
In May 1992, NOPSI and the Council reached a settlement regarding
NOPSI's application for an increase in gas rates. The settlement
includes the following terms, among others:
(i) an aggregate net rate increase of $7.5 million,
effective on May 22, 1992, phased in over a two-year period. The
year one net increase is stipulated to be $3.8 million, with an
additional $3.0 million being deferred for recovery in equal
annual installments in years two through six. The net increase
in year two of $3.7 million includes $730,000 for recovery of the
costs deferred in year one (including associated carrying
charges).
(ii) except as provided above, and except for increases to
reflect an increase in state and/or federal income tax rates or a
catastrophic event such as a hurricane, NOPSI has agreed to a gas
base rate freeze through October 31, 1996; however, this was
amended by the 1994 NOPSI Settlement discussed above.
In addition, the settlement provides that earnings from gas
operations will be included with those from electric operations for
purposes of the return on average equity ceiling provisions of the
1991 NOPSI Settlement (discussed above) and revises the method of
calculating such return on equity ceiling.
NOTE 3. INCOME TAXES
Income tax expense consisted of the following:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Current:
Federal $19,557 $23,400 $16,575
State 3,049 4,079 -
------- ------- -------
Total 22,606 27,479 16,575
------- ------- -------
Deferred - net:
Rate deferrals - net (6,325) (7,395) (1,185)
Net operating loss carryforward - 42 2,747
utilization
Unbilled revenue 2,761 4,621 (2,800)
Pension expense 1,308 2,935 (1,044)
Liberalized depreciation 841 (19) (286)
Deferred fuel or gas costs (2,104) 2,251 1,904
Bond reacquisition 165 1,074 328
Alternative minimum tax 1,116 2,317 (3)
Rate refund (9,620) - -
Severance accrual (1,518) - -
Other (2,298) (623) (1)
------ ------ ------
Total (15,674) 5,203 (340)
------ ------ ------
Investment tax credit adjustments - net (681) (743) (170)
Investment tax credit amortization -
FERC settlement (1,651) - -
------ ------ -------
Recorded income tax expense $4,600 $31,939 $16,065
====== ======= =======
Charged to operations $3,602 $24,232 $14,382
Charged to other income 998 1,115 1,683
Charged to cumulative effect - 6,592 -
------ ------- -------
Total income taxes $4,600 $31,939 $16,065
====== ======= =======
Total income taxes differ from the amounts computed by applying
the statutory federal income tax rate to income before taxes. The
reasons for the differences were:
For the Years Ended December 31,
1994 1993 1992
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
(Dollars in Thousands)
Computed at statutory rate $6,234 35.0 $27,877 35.0 $14,446 34.0
Increases (reductions) in tax
resulting from:
State income taxes net of
federal income
tax effect 456 2.6 3,411 4.3 1,462 3.5
Depreciation (586) (3.3) (780) (1.0) (731) (1.7)
Amortization of investment (681) (3.8) (745) (0.9) (752) (1.8)
tax credits
Investment tax credit
amortization -
FERC settlement (1,651) (9.2)
Amortization of excess
deferred income tax 714 4.0 384 0.5 376 0.9
Adjustment of prior year 0.9
taxes (423) (2.4) 2,413 3.0 391
SFAS 109 adjustment - - (1,170) (1.5) - -
Other - net 537 3.0 549 0.7 873 2.0
------ ---- ------- ---- ------- ----
Total income taxes $4,600 25.9 $31,939 40.1 $16,065 37.8
====== ==== ======= ==== ======= ====
Significant components of NOPSI's net deferred tax liabilities as
of December 31, 1994 and 1993, were:
1994 1993
(In Thousands)
Deferred tax liabilities:
Net regulatory assets $(12,946) $(13,465)
Plant related basis differences (50,624) (49,753)
Rate deferrals (74,054) (80,380)
Other (3,303) (5,194)
--------- ---------
Total $(140,927) $(148,792)
========= =========
Deferred tax assets:
Unbilled revenues $ 3,051 $ 5,812
Accumulated deferred investment tax credit 4,154 4,460
Pension related items 4,497 5,804
Removal cost 9,146 8,197
Standard coal plant 2,783 2,861
Operating reserves 6,665 6,934
Rate refund 9,620 -
Other 6,840 4,660
-------- --------
Total $ 46,756 $ 38,728
======== ========
Net deferred tax liabilities $(94,171) $(110,064)
======== =========
In accordance with a System Energy FERC settlement, NOPSI wrote
off $1.7 million of unamortized deferred investment tax credits in 1994.
In 1993, NOPSI adopted SFAS 109. SFAS 109 required that deferred
income taxes be recorded for all temporary differences and
carryforwards, and that deferred tax balances be based on enacted tax
laws at tax rates that are expected to be in effect when the temporary
differences reverse. SFAS 109 required that regulated enterprises
recognize adjustments resulting from implementation as regulatory
assets or liabilities if it is probable that such amounts will be
recovered from or returned to customers in future rates. A
substantial majority of the adjustments required by SFAS 109 was
recorded to deferred tax balance sheet accounts with offsetting
adjustments to regulatory assets and liabilities. As a result of the
adoption of SFAS 109, 1993 net income was increased by $0.3 million,
assets were increased by $4.1 million, and liabilities were increased
by $3.8 million. The cumulative effect of the adoption of SFAS 109 is
included in income tax expense charged to operations.
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized NOPSI to effect short-term borrowings of
up to $39 million. This authorization is effective through November
30, 1996. In addition, NOPSI can borrow from the Money Pool, subject
to its maximum authorized level of short-term borrowings and the
availability of funds. NOPSI's short-term borrowings are also limited
by the terms of its G&R Bond indenture to amounts not exceeding, in
general, the greater of 10% of capitalization or 50% of Grand Gulf 1
rate deferrals available to support the issuance of G&R Bonds. NOPSI
had no outstanding borrowings under these arrangements as of December
31, 1994.
NOTE 5. PREFERRED STOCK
The number of shares and dollar value of NOPSI's cumulative, $100
par value preferred stock were:
As of December 31,
Shares Call Price Per
Authorized and Total Share as of
Outstanding Dollar Value December 31,
1994 1993 1994 1993 1994
(Dollars in Thousands)
Without sinking fund:
4 3/4% Preferred Stock 77,798 77,798 $7,780 $7,780 $105.00
4.36% Series 60,000 60,000 6,000 6,000 $104.58
5.56% Series 60,000 60,000 6,000 6,000 $102.59
------- ------- ------- -------
Total without sinking fund 197,798 197,798 $19,780 $19,780
======= ======= ======= =======
With sinking fund:
15.44% Series 34,495 49,495 $3,450 $4,950 $107.72
======= ======= ======= =======
The fair value of NOPSI's preferred stock with sinking fund was
estimated to be approximately $3.6 million and $5.3 million as of
December 31, 1994 and 1993, respectively. The fair values were
determined using quoted market prices or estimates from nationally
recognized investment banking firms. See Note 1 for additional
information on disclosure of fair value of financial instruments.
Changes in the preferred stock during the last three years were:
Number of Shares
1994 1993 1992
Preferred stock retirements:
$100 par value (15,000) (15,000) (15,000)
Cash sinking fund requirements for the next five years for
preferred stock outstanding as of December 31, 1994, are (in millions)
1995 - $1.5; 1996 - $0.75; 1997 - $0.75 and 1998 - $0.45. NOPSI has
the annual non-cumulative option to redeem, at par, up to an
additional $750,000 of its 15.44% Series preferred stock outstanding.
NOTE 6. LONG-TERM DEBT
NOPSI's long-term debt as of December 31, 1994 and 1993, was:
Maturities Interest Rates
From To From To 1994 1993
(In Thousands)
First Mortgage Bonds
1995 1998 5-5/8% 5-7/8% $35,250 $35,250
G&R Bonds
1995 1998 10.95% 13.9% 54,200 69,200
1999 2023 7.0% 8.0% 100,000 100,000
Unamortized Premium and Discount-Net (1,090) (1,138)
-------- --------
Total Long-Term Debt 188,360 203,312
Less Amount Due Within One Year 24,200 15,000
-------- --------
Long-Term Debt Excluding Amount Due Within One Year $164,160 $188,312
======== ========
The fair value of NOPSI's long-term debt as of December 31, 1994
and 1993 was estimated to be $178.7 million and $211.5 million,
respectively. Fair values were determined using bid prices reported
by dealer markets and by nationally recognized investment banking
firms. See Note 1 for additional information on disclosure of fair
value of financial instruments.
For the years 1995, 1996, 1997 and 1998, NOPSI has long-term debt
maturities of (in millions) $24.2, $38.3, $27 and $0, respectively.
In addition, other sinking fund requirements of approximately $0.4
million and $0.1 million for 1995 and 1996, respectively, may be
satisfied by cash or by certification of property additions at the
rate of 167% of such requirements.
Under NOPSI's G&R Mortgage, G&R Bonds are issuable based upon 70%
of bondable property additions or based upon 50% of accumulated
deferred Grand Gulf 1-related costs. The G&R Mortgage precludes the
issuance of any additional bonds based upon property additions if the
total amount of outstanding Rate Recovery Mortgage Bonds issued on the
basis of the uncollected balance of deferred Grand Gulf 1-related
costs exceeds 66 2/3% of the balance of such deferred costs. As of
December 31, 1994, the total amount of Rate Recovery Mortgage Bonds
outstanding aggregated $54.2 million, or 26.5% of NOPSI's accumulated
deferred Grand Gulf 1-related costs.
NOTE 7. DIVIDEND RESTRICTIONS
NOPSI's Restatement of Articles of Incorporation, as amended,
and certain of its indentures contain provisions restricting the
payment of cash dividends or other distributions on common stock. As
of December 31, 1994, $24.2 million of NOPSI's retained earnings were
restricted against the payment of cash dividends or other
distributions on common stock.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Capital Requirements and Financing
Construction expenditures for the years 1995, 1996, and 1997 are
estimated to total $28.6 million each year. NOPSI will also require
$92.5 million during the period 1995-1997 to meet long-term debt and
preferred stock maturities and cash sinking fund requirements. NOPSI
plans to meet the above requirements with internally generated funds,
cash on hand, and the issuance of long-term debt. See Notes 5 and 6
regarding the possible refinancing, redemption, purchase, or other
acquisition of certain outstanding series of preferred stock and long-
term debt.
Unit Power Sales Agreement
System Energy has agreed to sell all of its 90% owned and leased
share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L,
and NOPSI in accordance with specified percentages (AP&L 36%, LP&L
14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this
agreement are paid in consideration for NOPSI's respective entitlement
to receive capacity and energy, and are payable irrespective of the
quantity of energy delivered so long as the unit remains in commercial
operation. The agreement will remain in effect until terminated by
the parties and approved by FERC, most likely upon Grand Gulf 1's
retirement from service. NOPSI's monthly obligation for payments under
the agreement is approximately $8 million.
Availability Agreement
AP&L, LP&L, MP&L, and NOPSI are individually obligated to make
payments or subordinated advances to System Energy in accordance with
stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI
24.7%) in amounts that when added to amounts received under the Unit
Power Sales Agreement or otherwise, are adequate to cover all of
System Energy's operating expenses. System Energy has assigned its
rights to payments and advances to certain creditors as security for
certain obligations. Since commercial operation of Grand Gulf 1,
payments under the Unit Power Sales Agreement have exceeded the
amounts payable under the Availability Agreement. Accordingly, no
payments have ever been required. If AP&L, LP&L, or MP&L fails to
make its Unit Power Sales Agreement payments, and System Energy is
unable to obtain funds from other sources, NOPSI could be liable for
payments to System Energy, in amounts that cannot be determined, over
and above its payments under the Unit Power Sales Agreement.
Reallocation Agreement
System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the
Reallocation Agreement relating to the sale of capacity and energy
from the Grand Gulf Station and the related costs, in which LP&L,
MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and
obligations with respect to the Grand Gulf Station under the
Availability Agreement. FERC's decision allocating a portion of Grand
Gulf 1 capacity and energy to AP&L supersedes the Reallocation
Agreement as it relates to Grand Gulf 1. Responsibility for any Grand
Gulf 2 amortization amounts has been individually allocated (LP&L
26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the
Reallocation Agreement. However, the Reallocation Agreement does not
affect AP&L's obligation to System Energy's lenders under the
assignments referred to in the preceding paragraph. AP&L would be
liable for its share of such amounts if LP&L, MP&L, and NOPSI were
unable to meet their contractual obligations. No payments of any
amortization amounts will be required as long as amounts paid to
System Energy under the Unit Power Sales Agreement, including other
funds available to System Energy, exceed amounts required under the
Availability Agreement, which is expected to be the case for the
foreseeable future.
System Fuels
NOPSI has a 13% interest in System Fuels, a jointly owned
subsidiary of AP&L, LP&L, MP&L, and NOPSI. The parent companies of
System Fuels, including NOPSI, agreed to make loans to System Fuels to
finance its fuel procurement, delivery, and storage activities. As of
December 31, 1994, NOPSI had approximately $3.3 million of loans
outstanding to System Fuels which mature in 2008.
City Franchise Ordinances
NOPSI provides electric and gas service in the City of New
Orleans pursuant to City franchise ordinances that state, among other
things, that the City has a continuing option to purchase NOPSI's
electric and gas utility properties.
Sales/Use Tax Issues
In September 1994, the Louisiana Supreme Court (Court) issued an
opinion (in a case in which none of the System companies was a party)
holding, in part, that the Louisiana state legislature's suspension of
state sales and use tax exemptions also had the effect of suspending
exemptions from local sales and use taxes. On January 27, 1995 the
Court, after rehearing, reversed its opinion. Because of the Court's
most recent ruling, sales of electricity and gas, fuels and other
items used by NOPSI to generate electricity in Louisiana, as well as
others exempt from sales and use taxes, continue to be exempt from
local sales and use taxes, even though the state exemptions for sales
and use tax have been suspended.
NOTE 9. POSTRETIREMENT BENEFITS
Pension Plan
NOPSI is a participating employer in a defined benefit pension
plan sponsored by LP&L, covering substantially all employees. The
pension plan is noncontributory and provides pension benefits based on
employees' credited service and average compensation, generally during
the last five years before retirement. Pension costs are funded in
accordance with contribution guidelines established by the Employee
Retirement Income Security Act of 1974, as amended, and the Internal
Revenue Code of 1986, as amended. The assets of the plan consist
primarily of common and preferred stocks, fixed income securities,
interest in a money market fund, and insurance contracts.
NOPSI's 1994, 1993, and 1992 pension cost, including amounts
capitalized, included the following components:
For the Years Ended December 31,
1994* 1993* 1992*
(In Thousands)
Service cost - benefits earned during the
period $ 1,502 $1,387 $1,253
Interest cost on projected benefit
obligation 2,740 2,422 2,119
Net amortization and deferral (970) (49) 173
------- ------ ------
Net pension cost $ 3,272 $3,760 $3,545
======= ====== ======
* Pension cost represents NOPSI's allocated portion of the total
pension expense (as calculated by an independent actuary) for the
defined benefit pension plan sponsored by LP&L.
The funded status of LP&L's pension plan allocable to NOPSI
employees as of December 31, 1994 and 1993, was:
1994* 1993*
(In Thousands)
Actuarial present value of accumulated
pension plan benefits:
Vested $26,291 $26,173
Nonvested 41 36
------- -------
Accumulated benefit obligation $26,332 $26,209
======= =======
Plan assets at fair value $18,180 $7,523
Projected benefit obligation 33,738 36,831
------- -------
Plan assets less than projected benefit (15,558) (29,308)
obligation
Unrecognized prior service cost 2,291 2,462
Unrecognized transition asset (1,159) (1,354)
Unrecognized net loss 5,779 12,184
------ ------
(8,647) (16,016)
Unfunded portion of NOPSI pension liability 1,584 12,256
------- -------
Accrued pension liability $(7,063) $(3,760)
======= =======
The significant actuarial assumptions used in computing the
information above for 1994, 1993, and 1992 were as follows: weighted
average discount rate, 8.5% for 1994, 7.5% for 1993 and 8.25% for
1992; weighted average rate of increase in future compensation levels,
5.1% for 1994 and 5.6% for 1993 and 1992; and expected long-term rate
of return on plan assets, 8.5%. Transition assets are being amortized
over the average remaining service period of active participants.
Other Postretirement Benefits
NOPSI also provides certain health care and life insurance
benefits for retired employees. Substantially all employees may
become eligible for these benefits if they reach retirement age while
still working for NOPSI. The cost of providing these benefits,
recorded on a cash basis, to retirees in 1992 was approximately $3.7
million. Prior to 1992, the cost of providing these benefits for
retirees was not separable from the cost of providing benefits for
active employees.
Effective January 1, 1993, NOPSI adopted SFAS 106. This standard
requires a change from a cash method to an accrual method of
accounting for postretirement benefits other than pensions. As of
January 1, 1993, the actuarially determined accumulated postretirement
benefit obligation (APBO) earned by retirees and active employees was
estimated to be approximately $53.6 million. This obligation is being
amortized over a 20-year period beginning in 1993.
NOPSI is expensing its SFAS 106 costs pursuant to resolutions
adopted in November 1993 by the Council related to the Merger.
NOPSI's SFAS 106 expenses through October 31, 1996, will be allowed by
the Council for purposes of evaluating the appropriateness of NOPSI's
rates. Furthermore, due to the Council resolutions, NOPSI has
established and commenced funding a Voluntary Employee's Beneficiary
Association (VEBA) trust. During 1994, NOPSI funded $6.8 million to
the VEBA trust. The trusts assets are invested in a money market fund.
NOPSI's 1994 and 1993 postretirement benefit cost, including
amounts capitalized and deferred, included the following components:
1994 1993
(In Thousands)
Service cost - benefits earned during the period $ 813 $ 822
Interest cost on APBO 3,502 4,248
Net deferral and amortization 2,569 2,678
------ ------
Net periodic postretirement benefit cost $6,884 $7,748
====== ======
The funded status of NOPSI's postretirement plan as of December
31, 1994 and 1993, was (in thousands):
1994 1993
(In Thousands)
Accumulated postretirement benefit obligation:
Retirees $38,059 $46,218
Other fully eligible participants 3,351 3,565
Other active participants 3,551 9,152
------- ------
44,961 58,935
Plan assets at fair value 6,784 -
------- ------
Plan assets less than APBO (38,177) (58,935)
Unrecognized transition obligation 48,217
50,895
Unrecognized net loss (10,057) 4,835
------- ------
Accrued post retirement benefit liability $ (17) $(3,205)
======= =======
The assumed health care cost trend rate used in measuring the
APBO was 9.4% for 1995, gradually decreasing each successive year
until it reaches 5.0% in 2011. A one percentage-point increase in the
assumed health care cost trend rate for each year would have increased
the APBO as of December 31, 1994, by 8.6% and the sum of the service
cost and interest cost by approximately 10.0% The assumed discount
rate and rate of increase in future compensation used in determining
the APBO were 8.5% for 1994 and 7.5% for 1993 and 5.1%, for 1994 and
5.5% for 1993, respectively.
NOTE 10. TRANSACTIONS WITH AFFILIATES
NOPSI buys electricity from and/or sells electricity to the other
System operating companies and System Energy under rate schedules
filed with FERC. In addition, NOPSI purchases fuel from System Fuels
and receives technical and advisory services from Entergy Services.
Operating revenues include revenues from sales to affiliates
amounting to $2.1 million in 1994, $2.5 million in 1993, and
$3.1 million in 1992. Operating expenses include charges from
affiliates for fuel costs, purchased power and related charges, and
technical and advisory services totaling $170.1 million in 1994,
$176.3 million in 1993, and $183.0 million in 1992.
NOTE 11. BUSINESS SEGMENT INFORMATION
NOPSI supplies electric and natural gas services in the City.
NOPSI's segment information follows:
1994 1993 1992
Electric Gas Electric Gas Electric Gas
(In Thousands)
Operating revenues $360,430 $87,357 $423,830 $90,992 $391,936 $72,943
Revenue from sales to
unaffiliated customers (1) $358,369 $87,357 $421,343 $90,992 $388,851 $72,943
Operating income (loss)
before income taxes $ 23,976 $ 9,387 $ 72,572 $11,412 $ 63,167 $ 1,264
Operating income (loss) $ 22,358 $ 7,403 $ 52,046 $ 7,706 $ 47,194 $ 2,855
Net utility plant $209,901 $67,875 $211,776 $63,803 $206,402 $61,783
Depreciation expense $ 15,743 $ 3,310 $ 14,308 $ 2,976 $ 13,776 $ 2,843
Construction expenditures $ 16,997 $ 5,780 $ 19,774 $ 5,039 $ 15,724 $ 5,319
(1) NOPSI's intersegment transactions are not material (less than 1%
of sales to unaffiliated customers).
NOTE 12. RESTRUCTURING COSTS
During the third quarter of 1994, NOPSI announced a restructuring
program related to certain of its operating units. The program is
designed to reduce costs, improve operating efficiencies, and increase
shareholder value in order to enable NOPSI to become a low-cost
producer. The program includes reductions in the number of employees
and the consolidation of offices and facilities. In 1994, NOPSI
recorded restructuring charges of $3.4 million. These charges
primarily include employee severance costs related to the expected
termination of approximately 146 employees. As of December 31, 1994,
no employees have been terminated and no termination benefits have
been paid under this restructuring program.
NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED)
NOPSI's business is subject to seasonal fluctuations with the
peak periods occurring during the third quarter for electric and
during the first quarter for gas. Operating results for the four
quarters of 1994 and 1993 were:
Net
Operating Operating Income
Revenues Income (Loss)
(In Thousands)
1994:
First Quarter $ 117,088 $ 6,459 $ 1,813
Second Quarter $ 124,402 $ 17,880 $ 13,812
Third Quarter $ 133,574 $ 15,941 $ 11,933
Fourth Quarter $ 72,723 $(10,519) $(14,347)
1993:
First Quarter $ 108,566 $ 8,828 $ 14,930
Second Quarter $ 120,182 $ 17,789 $ 12,714
Third Quarter $ 154,610 $ 29,648 $ 24,843
Fourth Quarter $ 131,464 $ 3,487 $ (4,778)
See Note 2 for information regarding credits and refunds recorded
in 1994 as a result of the 1994 NOPSI Settlement.
See Note 1 for information regarding the recording of the
cumulative effect of the change in accounting principle for
unbilled revenues in January 1993.
NEW ORLEANS PUBLIC SERVICE INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1994 1993 1992 1991 1990
(In Thousands)
Operating revenues $447,787 $514,822 $464,879 $476,165 $485,246
Income before cumulative
effect of a change in
accounting principle $ 13,211 $ 36,761 $ 26,424 $ 74,699 $ 27,542
Total assets $592,894 $647,605 $621,691 $685,217 $577,283
Long-term obligations (1) $167,610 $193,262 $165,917 $231,901 $243,239
(1) Includes long-term debt (excluding currently maturing debt) and
preferred stock with sinking fund.
See Notes 1, 3, and 9 for the effect of accounting changes in
1993.
1994 1993 1992 1991 1990
(Dollars in Thousands)
Electric Operating Revenues:
Residential $142,013 $151,423 $137,668 $136,030 $141,900
Commercial 162,410 167,788 160,229 159,118 162,600
Industrial 25,422 26,205 23,860 24,062 27,000
Governmental 58,726 61,548 56,023 55,097 53,500
-------- ------- ------- ------- -------
Total retail 388,571 406,964 377,780 374,307 385,000
Sales for resale 9,573 11,778 10,320 9,805 8,400
Other (37,714) 5,088 3,836 15,102 3,900
-------- ------- ------- ------- -------
Total $360,430 $423,830 $391,936 $399,214 $397,300
======== ======== ======== ======== ========
Billed Electric Energy Sales
(Millions of KWH):
Residential 1,896 1,914 1,806 1,844 1,903
Commercial 2,031 1,989 1,977 2,023 2,054
Industrial 518 499 457 487 530
Governmental 951 924 888 887 846
----- ----- ----- ----- -----
Total retail 5,396 5,326 5,128 5,241 5,333
Sales for resale 294 351 405 418 294
----- ----- ----- ----- -----
Total 5,690 5,677 5,533 5,659 5,627
===== ===== ===== ===== =====
System Energy Resources, Inc.
1994 Financial Statements
SYSTEM ENERGY RESOURCES, INC.
DEFINITIONS
Certain abbreviations or acronyms used in System Energy's
Financial Statements, Notes to Financial Statements, and Management's
Financial Discussion and Analysis are defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
ALJ Administrative Law Judge
AP&L Arkansas Power & Light Company
APSC Arkansas Public Service Commission
Capital Funds Agreement Agreement, dated as of June 21, 1974, as
amended, between System Energy and Entergy
Corporation, and the assignments thereof
City of New Orleans New Orleans, Louisiana
or City
DOE United States Department of Energy
Entergy Operations Entergy Operations, Inc., a subsidiary of
Entergy Corporation that has operating
responsibility for Grand Gulf 1, Waterford 3,
ANO, and River Bend
Entergy or System Entergy Corporation and its various direct
and indirect subsidiaries
Entergy Services Entergy Services, Inc.
EPAct The Energy Policy Act of 1992
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FERC Complaint Case Settlement, effective May 21, 1991, whereby
Settlement System Energy credited approximately
$47.6 million in the aggregate (including
interest) against its June 1991 bills to
AP&L, LP&L, MP&L, and NOPSI for capacity and
energy from Grand Gulf 1
FERC Return on Equity Settlement, effective October 25, 1993,
case whereby System Energy refunded
approximately $29.6 million in the
aggregate (including interest) against its
October 1993 bills to AP&L, LP&L, MP&L, and
NOPSI when FERC reduced System Energy's
Return on Equity from 13% to 11%
prospectively from November 3, 1992
Grand Gulf Station Grand Gulf Steam Electric Generating Station
(nuclear)
Grand Gulf 1 Unit No. 1 of the Grand Gulf Station
(nuclear)
Grand Gulf 2 Unit No. 2 of the Grand Gulf Station
(nuclear)
GSU Gulf States Utilities Company (including
wholly owned subsidiaries - Varibus
Corporation, GSG&T, Inc., Prudential Oil and
Gas, Inc., and Southern Gulf Railway Company)
KWH Kilowatt-Hours
LP&L Louisiana Power & Light Company
LPSC Louisiana Public Service Commission
Money Pool Entergy Money Pool which allows certain
System companies to borrow from, or lend to,
certain other System companies
MP&L Mississippi Power & Light Company
MPSC Mississippi Public Service Commission
NOPSI New Orleans Public Service Inc.
NRC Nuclear Regulatory Commission
OBRA Omnibus Budget Reconciliation Act of 1993
Reallocation Agreement 1981 Agreement, superseded in part by a
June 13, 1985 decision of FERC, among AP&L,
LP&L, MP&L, NOPSI, and System Energy relating
to the sale of capacity and energy from the
Grand Gulf Station
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
promulgated by the FASB
SFAS 109 SFAS 109, "Accounting for Income Taxes"
SMEPA South Mississippi Electric Power Association
System or Entergy Entergy Corporation and its various direct
and indirect subsidiaries
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI,
collectively
Unit Power Sales
Agreement Agreement, dated as of June 10, 1982, as
amended, among AP&L, LP&L, MP&L, NOPSI, and
System Energy, relating to the sale of
capacity and energy from System Energy's
share of Grand Gulf 1
SYSTEM ENERGY RESOURCES, INC.
REPORT OF MANAGEMENT
The management of System Energy Resources, Inc. has prepared and
is responsible for the financial statements and related financial
information included herein. The financial statements are based on
generally accepted accounting principles. Financial information
included elsewhere in this report is consistent with the financial
statements.
To meet its responsibilities with respect to financial
information, management maintains and enforces a system of internal
accounting controls that is designed to provide reasonable assurance,
on a cost-effective basis, as to the integrity, objectivity, and
reliability of the financial records, and as to the protection of
assets. This system includes communication through written policies
and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and
the training of personnel. This system is also tested by a
comprehensive internal audit program.
The independent public accountants provide an objective
assessment of the degree to which management meets its responsibility
for fairness of financial reporting. They regularly evaluate the
system of internal accounting controls and perform such tests and
other procedures as they deem necessary to reach and express an
opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide
reasonable assurance that its operations are carried out with a high
standard of business conduct.
/s/ Donald C. Hintz /s/ Gerald D. McInvale
DONALD C. HINTZ GERALD D. MCINVALE
President and Chief Executive Officer Senior Vice President and
Chief Financial Officer
SYSTEM ENERGY RESOURCES, INC.
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Entergy Corporation Board of Directors' Audit Committee
functions as the Audit Committee for System Energy. The Audit
Committee is comprised of four directors, who are not officers of
System Energy: H. Duke Shackelford (Chairman), Lucie J. Fjeldstad,
Dr. Norman C. Francis, and James R. Nichols. The committee held four
meetings during 1994.
The Audit Committee oversees System Energy's financial reporting
process on behalf of the Board of Directors and provides reasonable
assurance to the Board that sufficient operating, accounting, and
financial controls are in existence and are adequately reviewed by
programs of internal and external audits.
The Audit Committee discussed with Entergy's internal auditors
and the independent public accountants (Coopers & Lybrand L.L.P.) the
overall scope and specific plans for their respective audits, as well
as System Energy's financial statements and the adequacy of System
Energy's internal controls. The committee met, together and
separately, with Entergy's internal auditors and independent public
accountants, without management present, to discuss the results of
their audits, their evaluation of System Energy's internal controls,
and the overall quality of System Energy's financial reporting. The
meetings also were designed to facilitate and encourage any private
communication between the committee and the internal auditors or
independent public accountants.
/s/ H. Duke Shackelford
H. DUKE SHACKELFORD
Chairman, Audit Committee
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholder of
System Energy Resources, Inc.
We have audited the accompanying balance sheet of System Energy
Resources, Inc. as of December 31, 1994, and the related statements of
income, retained earnings and cash flows for the year then ended.
These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements based on our audit. The financial statements of
the Company as of December 31, 1993 and for the years ended December
31, 1993 and 1992, were audited by other auditors, whose report, dated
February 11, 1994, included explanatory paragraphs that described a
change in a method of accounting for income taxes discussed in Note 3
to these financial statements and an uncertainty relating to a
regulatory proceeding which is discussed in Note 2 to these financial
statements.
We conducted our audit in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position of
the Company as of December 31, 1994, and the result of its operations
and its cash flows for the year then ended in conformity with
generally accepted accounting principles.
/s/ Coopers & Lybrand L.L.P.
COOPERS & LYBRAND L.L.P.
New Orleans, Louisiana
February 21, 1995
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of Directors of
System Energy Resources, Inc.
We have audited the accompanying balance sheet of System Energy
Resources, Inc. (System Energy) as of December 31, 1993, and the
related statements of income, retained earnings, and cash flows for
each of the two years in the period ended December 31, 1993. These
financial statements are the responsibility of System Energy's
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all
material respects, the financial position of System Energy at December
31, 1993, and the results of its operations and its cash flows for
each of the two years in the period ended December 31, 1993 in
conformity with generally accepted accounting principles.
As discussed in Notes 3 to the financial statements, in 1993
System Energy changed its methods of accounting for income taxes.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 11, 1994 (November 30, 1994 as to Note 2, "Rate and
Regulatory Matters - FERC Settlement")
SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
ASSETS
December 31,
1994 1993
(In Thousands)
Utility Plant:
Electric $2,939,384 $3,027,537
Electric plant under lease 439,378 437,941
Construction work in progress 46,547 41,442
Nuclear fuel under capital lease 46,688 79,625
Nuclear fuel 26,360 -
---------- ----------
Total 3,498,357 3,586,545
Less - accumulated depreciation 751,717 669,666
---------- ----------
Utility plant - net 2,746,640 2,916,879
---------- ----------
Other Investments:
Decommissioning trust fund 30,359 24,787
---------- ----------
Current Assets:
Cash and cash equivalents:
Cash - 2,424
Temporary cash investments - at cost,
which approximates market:
Associated companies 5,489 46,601
Other 84,214 147,107
---------- ----------
Total cash and cash equivalents 89,703 196,132
Accounts receivable:
Associated companies 7,450 57,216
Other 3,412 2,057
Materials and supplies - at average cost 71,991 69,765
Recoverable income taxes - 63,400
Prepayments and other 5,429 4,835
---------- ----------
Total 177,985 393,405
---------- ----------
Deferred Debits and Other Assets:
Regulatory Assets:
SFAS 109 regulatory asset - net 389,264 384,317
Unamortized loss on reacquired debt 54,577 17,258
Other regulatory assets 199,080 108,518
Recoverable income taxes - 29,289
Other 15,454 16,613
---------- ----------
Total 658,375 555,995
---------- ----------
TOTAL $3,613,359 $3,891,066
========== ==========
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
1994 1993
(In Thousands)
Capitalization:
Common stock, no par value, authorized
1,000,000 shares; issued and outstanding
789,350 shares in 1994 and 1993 $789,350 $789,350
Paid-in capital 7 7
Retained earnings 85,681 228,574
---------- ----------
Total common shareholder's equity 875,038 1,017,931
Long-term debt 1,438,305 1,511,914
---------- ----------
Total 2,313,343 2,529,845
---------- ----------
Other Noncurrent Liabilities:
Obligations under capital leases 18,688 24,679
Other 14,342 18,229
---------- ----------
Total 33,030 42,908
---------- ----------
Current Liabilities:
Currently maturing long-term debt 105,000 230,000
Accounts payable:
Associated companies 32,272 1,928
Other 23,204 18,223
Taxes accrued 35,382 20,952
Interest accrued 40,796 48,929
Obligations under capital leases 28,000 55,000
Other 19,794 2,805
---------- ----------
Total 284,448 377,837
---------- ----------
Deferred Credits:
Accumulated deferred income taxes 746,502 775,630
Accumulated deferred investment tax credits 110,584 113,849
FERC Settlement - refund obligation 60,388 -
Other 65,064 50,997
---------- ----------
Total 982,538 940,476
---------- ----------
Commitments and Contingencies (Notes 2, 7, and 8)
TOTAL $3,613,359 $3,891,066
========== ==========
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Activities:
Net income $5,407 $93,927 $130,141
Noncash items included in net income:
Depreciation and decommissioning 93,861 90,920 85,932
Deferred income taxes and investment tax credits (30,640) 15,832 70,356
Allowance for equity funds used during construction (1,090) (772) (681)
Amortization of debt discount 4,388 4,520 6,417
Amortization of loss on reacquired debt 2,343 - -
Changes in working capital:
Receivables 48,411 6,199 225
Accounts payable 35,469 (15,123) (30,517)
Taxes accrued 14,430 (2,272) 2,672
Interest accrued (8,133) (1,631) 1,252
Other working capital accounts 14,024 2,832 (4,412)
Recoverable income taxes 92,689 130,152 (3,475)
Decommissioning trust contributions (5,157) (4,911) (5,641)
FERC Settlement - refund obligation 60,388 - -
Other 10,597 (1,617) 86
-------- -------- --------
Net cash flow provided by operating activities 336,987 318,056 252,355
-------- -------- --------
Investing Activities:
Construction expenditures (20,766) (23,083) (21,671)
Allowance for equity funds used during construction 1,090 772 681
Nuclear fuel purchases (26,414) (32,822) (13,724)
Proceeds from sale/leaseback of nuclear fuel - 32,822 28,094
-------- -------- --------
Net cash flow used in investing activities (46,090) (22,311) (6,620)
-------- -------- --------
Financing Activities:
Proceeds from the issuance of first mortgage bonds 59,410 60,000 220,000
Retirement of first mortgage bonds (260,000) (108,308) (240,750)
Premium and expenses paid on refinancing sale/leaseback bonds (48,436) - -
Common stock dividends paid (148,300) (233,100) (137,700)
-------- -------- --------
Net cash flow used in financing activities (397,326) (281,408) (158,450)
-------- -------- --------
Net increase (decrease) in cash and cash equivalents (106,429) 14,337 87,285
Cash and cash equivalents at beginning of period 196,132 181,795 94,510
-------- -------- --------
Cash and cash equivalents at end of period $89,703 $196,132 $181,795
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized $176,503 $186,786 $201,287
Income taxes (refund) ($39,586) ($65,992) $21,431
Noncash investing and financing activities:
Capital lease obligations incurred - $45,089 $28,094
Deficiency of fair value of decommissioning trust
assets under amount invested ($1,515) - -
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
The financial condition of System Energy significantly depends on
the continued commercial operation of Grand Gulf 1 and on the receipt
of payments from AP&L, LP&L, MP&L, and NOPSI. Payments under the Unit
Power Sales Agreement are System Energy's only source of operating
revenues. Net cash flow from operations totaled $337 million, $318
million, and $252 million in 1994, 1993, and 1992, respectively. In
recent years, this cash flow has been sufficient to meet substantially
all investing and financing requirements, including capital
expenditures, dividends, and debt maturities. See Note 7 for
information on System Energy's capital and refinancing requirements in
1995 - 1997. Also, to the extent current market interest and dividend
rates allow, System Energy may continue to refinance high-cost debt
prior to maturity.
As discussed in Note 2, in November 1994, FERC approved an
agreement settling a long-standing dispute involving income tax
allocation procedures of System Energy. In connection with this
settlement, System Energy refunded approximately $61.7 million to
AP&L, LP&L, MP&L, and NOPSI, which in turn have made or will make
refunds or credits to their customers (except for those portions
attributable to AP&L's and LP&L's retained share of Grand Gulf 1
costs). Additionally, System Energy will refund a total of
approximately $62 million, plus interest, to AP&L, LP&L, MP&L, and
NOPSI over the period through June 2004. AP&L, LP&L, MP&L, and NOPSI
also wrote-off certain related unamortized balances of deferred
investment tax credits. See Note 2 for further information on the
FERC Settlement.
As a result of the charges associated with the FERC Settlement,
System Energy obtained the consent of certain banks (parties to the
Reimbursement Agreement) to waive temporarily the fixed charge
coverage covenant in the letters of credit and Reimbursement Agreement
related to the Grand Gulf 1 sale and leaseback transaction, until
November 30, 1995. System Energy expects that upon expiration of the
waiver period, it will be in compliance with the fixed charge coverage
covenant. Absent a waiver, System Energy's failure to perform this
covenant could cause a draw under the letters of credit and/or early
termination of the letters of credit. If the letters of credit were
not replaced in a timely manner, a default or early termination of
System Energy's leases could result.
Earnings coverage tests, bondable property additions, and equity
ratio requirements contained in its mortgage, and in its letters of
credit and Reimbursement Agreement in connection with the Grand Gulf 1
sale and leaseback transactions, limit the amount of first mortgage
bonds that System Energy can issue. Based on the most restrictive
applicable tests as of December 31, 1994, and assuming an annual
interest rate of 9.25%, System Energy could have issued $241 million
of additional first mortgage bonds. System Energy has the conditional
ability to issue first mortgage bonds against the retirement of first
mortgage bonds, in some cases, without satisfying an earnings coverage
test.
In connection with the financing of Grand Gulf 1, Entergy
Corporation has undertaken, in the Capital Funds Agreement, to provide
to System Energy sufficient capital to (1) maintain System Energy's
equity capital at an amount equal to at least 35% of System Energy's
total capitalization (excluding short-term debt), (2) permit the
continuation of commercial operation of Grand Gulf 1, and (3) enable
System Energy to pay in full all borrowings, whether at maturity, on
prepayment, on acceleration, or otherwise. In addition, Entergy
Corporation has agreed in the Capital Funds Agreement to make certain
cash capital contributions, if required, to enable System Energy to
make payments when due on specific issues of its long-term debt.
See Note 4 for information regarding System Energy's short-term
borrowings.
SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF INCOME
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Revenues $474,963 $650,768 $723,410
---------- ---------- ----------
Operating Expenses:
Operation and maintenance:
Fuel and fuel-related expenses 48,107 42,296 55,110
Other operation and maintenance 96,504 135,349 132,341
Depreciation and decommissioning 93,861 90,920 90,628
Taxes other than income taxes 26,637 26,589 28,717
Income taxes 38,087 83,412 93,438
---------- ---------- ----------
Total 303,196 378,566 400,234
---------- ---------- ----------
Operating Income 171,767 272,202 323,176
---------- ---------- ----------
Other Income (Deductions):
Allowance for equity funds used
during construction 1,090 772 681
Miscellaneous - net 6,402 6,518 5,816
Income taxes 1,250 4,859 4,584
---------- ---------- ----------
Total 8,742 12,149 11,081
---------- ---------- ----------
Interest Charges:
Interest on long-term debt 169,248 189,338 203,035
Other interest - net 7,257 1,600 1,506
Allowance for borrowed funds
used during construction (1,403) (514) (425)
---------- ---------- ----------
Total 175,102 190,424 204,116
---------- ---------- ----------
Net Income $5,407 $93,927 $130,141
========== ========== ==========
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Retained Earnings, January 1 $228,574 $367,747 $375,306
Add:
Net income 5,407 93,927 130,141
-------- -------- --------
Total 233,981 461,674 505,447
-------- -------- --------
Deduct:
Dividends declared 148,300 233,100 137,700
-------- -------- --------
Retained Earnings, December 31 (Note 6) $ 85,681 $228,574 $367,747
======== ======== ========
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income decreased in 1994 primarily due to the effect of the
FERC Settlement which reduced income by $80.2 million (see Note 2)
and a lower rate of return on System Energy's decreasing investment
in Grand Gulf 1, partially offset by a decrease in interest expense.
Net income decreased in 1993 primarily due to the impact of the FERC
Return on Equity Case settlement regarding the return on equity
component of System Energy's formula wholesale rates, as discussed in
Note 2. This decrease in revenue was partially offset by a reduction
in interest expense due to the retirement of high-cost debt.
Significant factors affecting the results of operations and
causing variances between the years 1994 and 1993, and 1993 and 1992
are discussed under "Revenues" and "Expenses" below.
Revenues
Operating revenues recover operating expenses, depreciation, and
capital costs attributable to Grand Gulf 1. The capital costs are
computed by allowing a return, currently set at a rate of 11.0%, (see
Note 2 for further information on the FERC Return on Equity Case) on
System Energy's common equity funds allocable to its net investment
in Grand Gulf 1 plus System Energy's effective interest cost for its
debt allocable to its investment in Grand Gulf 1.
Operating revenues decreased in 1994 due primarily to the effect
of the FERC Settlement as discussed in "Net Income" above, a lower
return on System Energy's decreasing investment in Grand Gulf 1
(caused by depreciation of the unit) and decreased operation and
maintenance expenses. Future revenues attributable to the return on
investment are expected to decline each year as a result of the
depreciation of System Energy's investment in Grand Gulf 1. Operating
revenues decreased in 1993 due primarily to the effect of the FERC
Return on Equity Case settlement which reduced System Energy's return
on equity as discussed in "Net Income" above and a lower return on
System Energy's decreasing investment in Grand Gulf 1.
Expenses
Operating expenses decreased in 1994 due primarily to lower
other operation and maintenance expense and lower income tax expense.
Operating expenses decreased in 1993 due primarily to lower fuel and
lower income tax expense.
Grand Gulf 1 was on-line for 345 of 365 days in 1994 as compared
with 284 of 365 days in 1993. The unit capability factor, which is a
measure of the unit's performance (based on a ratio of available
energy generation to the maximum power capability multiplied by the
period hours), was 92.26% for 1994 as compared with 76.1% for 1993.
These variances are primarily due to the unit's sixth refueling
outage that lasted from September 28, 1993 to December 3, 1993,
(67 days) and to a lesser extent, the unplanned outages in 1994
totaling 20 days, compared to 1993 of 14 days. The lower level of
outages for 1994 increased fuel for electric generation, partially
offset by less expensive nuclear fuel and increased operating
efficiency. Nonfuel operation and maintenance expense decreased
significantly in 1994 also due to the lower level of outages. The
1993 decrease in fuel for electric generation and fuel related
expenses is primarily due to the sixth refueling outage and to
refueling with less expensive nuclear fuel. Increased operating
efficiency was another contributor to the 1993 decrease. Nonfuel
operation and maintenance expense increased in 1993 due primarily to
the sixth refueling outage as discussed above.
Total income taxes decreased in 1994 due primarily to lower
pretax book income. Total income taxes decreased in 1993 due
primarily to lower pretax book income partially offset by an increase
in the federal income tax rate as a result of OBRA.
Interest expense decreased in 1994 due primarily to the
refinancing and maturity of high-cost long-term debt partially offset
by interest associated with the FERC Settlement refunds (see Note 2).
SYSTEM ENERGY RESOURCES, INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
FERC Settlement
See Note 2 for information with respect to a settlement between
System Energy and FERC in which System Energy refunded approximately
$61.7 million to AP&L, LP&L, MP&L, and NOPSI, which in turn have made
or will make refunds or credits to their customers (except for those
portions attributable to AP&L's and LP&L's retained share of Grand
Gulf costs). Additionally, System Energy will refund a total of
approximately $62 million, plus interest, to AP&L, LP&L, MP&L, and
NOPSI over the period through June 2004. AP&L, LP&L, MP&L, and NOPSI
also wrote-off certain related unamortized balances of deferred
investment tax credits.
Accounting Issues
Proposed Accounting Standard - The FASB has proposed a SFAS on
"Accounting for the Impairment of Long-Lived Assets," effective
January 1, 1996. The proposed standard describes circumstances which
may result in assets being impaired and provides criteria for
recognition and measurement of asset impairment. Certain operations of
System Energy are potentially affected by this standard, and any
resulting write-offs will depend on future operating costs, efficiency
and availability of Grand Gulf 1, and the future market for energy
over the remaining life of the unit. Based on current estimates,
System Energy anticipates that future revenues will fully recover the
costs of such operations.
Continued Application of SFAS 71 - System Energy's financial
statements currently reflect assets and costs based on current cost-
based ratemaking regulations, in accordance with SFAS 71, "Accounting
for the Effects of Certain Types of Regulation." The electric utility
industry is changing and these changes could possibly result in the
discontinuance of the application of SFAS 71 which would result in the
elimination of regulatory assets and liabilities. See Note 1 for
further information.
Accounting for Decommissioning Costs - The FASB is currently
reviewing the accounting for decommissioning of nuclear plants. This
project could possibly change System Energy's, as well as the entire
utility industry's, accounting for such costs. For further
information, see Note 7.
SYSTEM ENERGY RESOURCES, INC.
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
System Energy maintains accounts in accordance with FERC
guidelines. Certain previously reported amounts have been
reclassified to conform to current classifications.
Organization
System Energy is a generating company providing electricity to
AP&L, LP&L, MP&L, and NOPSI and has a 90% interest in Grand Gulf 1, a
nuclear generating station with a total capability of 1,143 MW that
began operation in 1985. In June 1990, Entergy Operations assumed
responsibility for the operation and maintenance of Grand Gulf 1.
System Energy has a combined ownership and leasehold interest of
90% and SMEPA has an undivided ownership interest of 10% in Grand Gulf
1. System Energy records its investment associated with Grand Gulf 1
to the extent to which it owns and maintains a leasehold interest in
the generating station. Likewise, System Energy's operating expenses
reflected in the accompanying financial statements represent 90% of
such Grand Gulf 1 expenses.
Utility Plant
Utility plant is stated at original cost. The original cost of
utility plant retired or removed, plus the applicable removal costs,
less salvage, is charged to accumulated depreciation. Maintenance,
repairs, and minor replacement costs are charged to operating
expenses. Substantially all of the utility plant owned by System
Energy is subject to the lien of its first mortgage bond indenture.
Utility plant includes the portions of Grand Gulf 1 that were
sold and are currently under lease. System Energy retired this
property from its continuing property records as formerly owned
property released from and no longer subject to System Energy's
mortgage and deed of trust. System Energy is reflecting such leased
property for financial reporting purposes as property under lease from
others and is depreciating this property over the life of the basic
lease term. Such depreciation is being deferred as a regulatory asset
until recoverable from customers in future periods (see Note 8).
Depreciation is computed on a straight-line basis at rates based
on the estimated service lives and costs of removal of the various
classes of property. Depreciation provisions on average depreciable
property approximated 3.0% in 1994 and 2.9% in 1993 and 1992.
AFUDC represents the approximate net composite interest cost of
borrowed funds and a reasonable return on the equity funds used for
construction. Although AFUDC increases utility plant and increases
earnings, it is only realized in cash through depreciation provisions
included in rates. System Energy's effective composite rates for
AFUDC were 10.7%, 11.6%, and 12.3% for 1994, 1993, and 1992,
respectively.
Income Taxes
System Energy, its parent, and affiliates file a consolidated
federal income tax return. Income taxes are allocated to System
Energy in proportion to its contribution to consolidated taxable
income. SEC regulations require that no Entergy Corporation
subsidiary pay more taxes than it would have had a separate income tax
return been filed. Deferred taxes are recorded for all temporary
differences between book and taxable income. Investment tax credits
are deferred and amortized based upon the average useful life of the
related property in accordance with rate treatment. As discussed in
Note 3, in 1993 System Energy changed its accounting for income taxes
to conform with SFAS 109.
In addition, System Energy files a consolidated Mississippi state
income tax return with certain other System companies.
Reacquired Debt
The premiums and costs associated with reacquired debt are being
amortized over the life of the related new issuances, in accordance
with ratemaking treatment.
Cash and Cash Equivalents
System Energy considers all unrestricted highly liquid debt
instruments purchased with an original maturity of three months or
less to be cash equivalents.
Continued Application of SFAS 71
As a result of the EPAct and actions of regulatory commissions,
the electric utility industry is moving toward a combination of
competition and a modified regulatory environment. System Energy's
financial statements currently reflect assets and costs based on
current cost-based ratemaking regulations, in accordance with SFAS 71,
"Accounting for the Effects of Certain Types of Regulation".
Continued applicability of SFAS 71 to System Energy's financial
statements requires that rates set by an independent regulator on a
cost of service basis (including a reasonable rate of return on
invested capital) can actually be charged to and collected from
customers.
In the event that either all or a portion of a utility's
operations cease to meet those criteria for various reasons, including
deregulation, a change in the method of regulation, or a change in the
competitive environment for the utility's regulated services, the
utility should discontinue application of SFAS 71 for the relevant
portion. That discontinuation should be reported by elimination from
the balance sheet of the effects of any actions of regulators
recorded as regulatory assets and liabilities.
As of December 31, 1994, and for the foreseeable future, System
Energy's financial statements continue to follow SFAS 71.
Fair Value Disclosure
The estimated fair value of financial instruments has been
determined by System Energy, using available market information and
appropriate valuation methodologies. However, considerable judgment
is required in developing the estimates of fair value. Therefore,
estimates are not necessarily indicative of the amounts that System
Energy could realize in a current market exchange. In addition, gains
or losses realized on financial instruments may be reflected in future
rates and not accrue to the benefit of stockholders.
System Energy considers the carrying amounts of financial
instruments classified as current assets and liabilities to be a
reasonable estimate of their fair value because of the short maturity
of these instruments. In addition, System Energy does not presently
expect that performance of its obligations will be required in
connection with certain off-balance sheet commitments and guarantees
considered financial instruments. Due to this factor, and because of
the related party nature of these commitments and guarantees,
determination of fair value is not considered practicable. See Notes
5 and 7 for additional fair value disclosure.
System Energy adopted the provisions of SFAS 115, "Accounting for
Certain Investments in Debt and Equity Securities," effective January
1, 1994. As a result, at December 31, 1994, System Energy has
recorded on the balance sheet a reduction of $1.5 million in
decommissioning trust funds, representing the amount by which the fair
value of the securities held in such funds is less than amounts
recovered in rates for decommissioning and deposited in the funds and
the related earnings on the amounts deposited. Due to the regulatory
treatment for decommissioning trust funds, System Energy recorded an
offsetting amount in unrealized losses on investment securities as a
regulatory asset.
NOTE 2. RATE AND REGULATORY MATTERS
FERC Settlement
In November 1994, FERC approved an agreement settling a long-
standing dispute involving income tax allocation procedures of System
Energy. In accordance with the agreement, System Energy refunded
approximately $61.7 million to AP&L, LP&L, MP&L, and NOPSI, which in
turn have made or will make refunds or credits to their customers
(except for those portions attributable to AP&L's and LP&L's retained
share of Grand Gulf 1 costs). Additionally, System Energy will refund
a total of approximately $62 million, plus interest, to AP&L, LP&L,
MP&L, and NOPSI over the period through June 2004. The settlement
also required the write-off of certain related unamortized balances of
deferred investment tax credits by AP&L, LP&L, MP&L, and NOPSI. The
settlement reduced Entergy Corporation's consolidated net income for
the year ended December 31, 1994, by approximately $68.2 million,
offset by the write-off of the unamortized balances of related
deferred investment tax credits of approximately $69.4 million ($2.9
million for Entergy Corporation; $27.3 million for AP&L; $31.5 million
for LP&L; $6 million for MP&L; and $1.7 million for NOPSI). System
Energy also reclassified from utility plant to other deferred debits
approximately $81 million of other Grand Gulf 1 costs. Although
excluded from rate base, System Energy will be permitted to recover
such costs over a 10-year period. Interest on the $62 million refund
and the loss of the return on the $81 million of other Grand Gulf 1
costs will reduce Entergy's and System Energy's net income by
approximately $10 million annually over the next 10 years.
As a result of the charges associated with the settlement, System
Energy obtained the consent of certain banks (parties to the
Reimbursement Agreement) to waive temporarily the fixed charge
coverage covenant in the letters of credit and Reimbursement Agreement
related to the Grand Gulf 1 sale and leaseback transaction until
November 30, 1995. System Energy expects that upon expiration of the
waiver period, it will be in compliance with the fixed charge coverage
covenant. Absent a waiver, System Energy's failure to perform this
covenant could cause a draw under the letters of credit and/or early
termination of the letters of credit. If the letters of credit were
not replaced in a timely manner, a default or early termination of
System Energy's leases could result.
FERC Return on Equity Case
In August 1992, FERC instituted an investigation of the return on
equity (ROE) component of all formula wholesale rates for System
Energy as well as AP&L, LP&L, MP&L, and NOPSI. Payments received by
System Energy under the Unit Power Sales Agreement are its only source
of operating revenue. Rates under the Unit Power Sales Agreement are
based on System Energy's cost of service including a return on common
equity which had been set at 13% (see below).
In August 1993, Entergy and the state regulatory agencies that
intervened in the proceeding reached an agreement (Settlement
Agreement) in this matter. The Settlement Agreement, which was
approved by FERC on October 25, 1993, provides that an 11.0% ROE will
be included in the formula rates under the Unit Power Sales Agreement.
The Unit Power Sales Agreement formula rate, including the 11.0% ROE
component, will remain in effect without change for two years, until
early August 1995. System Energy's refunds payable to AP&L, LP&L,
MP&L, and NOPSI, which were due prospectively from November 3, 1992,
were reflected as a credit to their bills in October 1993. These
refunds decreased System Energy's 1993 revenues and net income by
approximately $29.4 million and $18.2 million, respectively.
NOTE 3. INCOME TAXES
Income tax expense consisted of the following:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Current:
Federal $54,295 $59,050 $13,890
State 13,182 3,671 6,786
------- ------- -------
Total 67,477 62,721 20,676
------- ------- -------
Deferred - net:
Liberalized depreciation 24,910 46,600 43,873
Nuclear fuel 790 2,706 (3,299)
Capitalized interest (1,024) (456) (1,402)
Taxes capitalized (929) (929) (935)
Decontamination and decommissioning fund 1,117 5,601 -
Bond reacquisition 626 (787) 852
Accrued FERC Settlement (23,098) - -
Alternative minimum tax (17,727) (1,579) -
Adjustment to GG2 tax basis (14,037) - -
Adjustment of prior year taxes 2,747 (3,249) 1,157
Other (750) (1,623) (2,191)
------- ------- -------
Total (27,375) 46,284 38,055
------- ------- -------
Investment tax credit adjustments - net (3,265) (30,452) 30,123
------- ------- -------
Recorded income tax expense $36,837 $78,553 $88,854
======= ======= =======
Charged to operations $38,087 $83,412 $93,438
Credited to other income (1,250) (4,859) (4,584)
------- ------- -------
Recorded income tax expense 36,837 78,553 88,854
Income taxes applied against the debt - - 253
component of AFUDC
------- ------- -------
Total income taxes $36,837 $78,553 $89,107
======= ======= =======
Total income taxes differ from the amounts computed by applying
the statutory federal income tax rate to income or loss before taxes.
The reasons for the differences were:
For the Years Ended December 31,
1994 1993 1992
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
(Dollars in Thousands)
Computed at statutory rate $14,785 35.0 $60,368 35.0 $74,458 34.0
Increases (reductions) in tax resulting from:
Depreciation 14,541 34.4 12,839 7.4 11,520 5.3
State income taxes net of federal
income tax effect 7,565 17.9 6,778 3.9 8,380 3.8
Amortization of investment tax credits (3,476) (8.2) (3,759) (2.2) (3,865) (1.8)
Adjustment of Prior Year Taxes 2,947 7.0 5,292 3.0 - -
Other - (net) 475 1.1 (2,965) (1.6) (1,639) (0.7)
------- ---- ------- ---- ------- ----
Recorded income tax expense 36,837 87.2 78,553 45.5 88,854 40.6
Income taxes applied against the debt
component of AFUDC - - - - 253 0.1
------- ---- ------- ---- ------- ----
Total income taxes $36,837 87.2 $78,553 45.5 $89,107 40.7
======= ==== ======= ==== ======= ====
Significant components of System Energy's net deferred tax
liabilities, as of December 31, 1994 and 1993, were:
1994 1993
(In Thousands)
Deferred tax liabilities:
Net regulatory assets $ (428,492) $(425,318)
Plant related basis differences (577,286) (552,782)
Other (14,350) (16,343)
----------- ---------
Total $(1,020,128) $(994,443)
=========== =========
Deferred tax assets:
Sale and leaseback $ 145,731 $ 142,850
FERC Settlement 23,098 -
Accumulated deferred investment tax credit 42,298 43,547
Alternative minimum tax credit 38,179 20,452
Recoverable income tax - 92,689
Adjustment to GG2 tax basis 14,037 -
Other 10,283 11,964
----------- ---------
Total $ 273,626 $ 311,502
=========== =========
Net deferred tax liabilities $ (746,502) $(682,941)
=========== =========
The alternative minimum tax (AMT) credit at December 31, 1994
was $38.2 million This AMT credit can be carried forward indefinitely
and will reduce System Energy's federal income tax liability in the
future.
In 1993, System Energy adopted SFAS 109. SFAS 109 required that
deferred income taxes be recorded for all temporary differences and
carryforwards, and that deferred tax balances be based on enacted tax
laws at tax rates that are expected to be in effect when the temporary
differences reverse. SFAS 109 requires that regulated enterprises
recognize adjustments resulting from implementation as regulatory
assets or liabilities if it is probable that such amounts will be
recovered from or returned to customers in future rates. A
substantial majority of the adjustments required by SFAS 109 was
recorded to deferred tax balance sheet accounts with offsetting
adjustments to regulatory assets and liabilities. As a result of the
adoption of SFAS 109, 1993 net income was reduced by $0.4 million,
assets were increased by $327.9 million, and liabilities were
increased by $327.5 million. The cumulative effect of the adoption of
SFAS 109 is included in income tax expense charged to operations.
In connection with an Internal Revenue Service (IRS) audit of
Entergy's 1988, 1989, and 1990 consolidated federal income tax
returns, the IRS proposed that adjustments be made to the Grand Gulf 2
abandonment loss deduction claimed on Entergy's 1989 consolidated
federal income tax return. The final agreement with the IRS required
Entergy Corporation to pay $4.3 million in connection with the
abandonment loss issue.
In August 1994, Entergy received an IRS report covering the
federal income tax audit of Entergy Corporation and subsidiaries for
the years 1988 - 1990. The report asserts an $80 million tax
deficiency for the 1990 consolidated federal income tax returns
related primarily to the application of accelerated investment tax
credits associated with Waterford 3 and Grand Gulf nuclear plants.
Entergy believes there is no material tax deficiency and is vigorously
contesting the proposed assessment.
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized System Energy to effect short-term
borrowings up to $125 million, which may be increased to as much as
$195 million after further SEC approval. This authorization is
effective through November 30, 1996. In addition, System Energy can
borrow from the Money Pool, subject to its maximum authorized level of
short-term borrowings and the availability of funds. System Energy
had no outstanding borrowings under the Money Pool arrangement or
under bank lines of credit as of December 31, 1994.
NOTE 5. LONG-TERM DEBT
The long-term debt of System Energy as of December 31, 1994 and
1993, was as follows:
Maturities Interest Rates
From To From To 1994 1993
(In Thousands)
First Mortgage Bonds
1995 1999 6.0% 10-1/2% $475,000 $615,000
2002 8-1/4% 70,000 130,000
2016 11-3/8% 90,319 90,319
Governmental Obligations*
2013 2016 8-1/4% 12-1/2% 416,600 416,600
Grand Gulf Lease Obligation, 7.02% (Note 8) 500,000 500,000
Unamortized Discount (8,614) (10,005)
---------- ----------
Total Long-Term Debt 1,543,305 1,741,914
Less Amount Due Within One Year 105,000 230,000
---------- ----------
Long-Term Debt Excluding Amount Due $1,438,305 $1,511,914
Within One Year ========== ==========
* Consists of pollution control bonds, certain series of which
are secured by non-interest bearing first mortgage bonds.
The fair value of System Energy's long-term debt, excluding Grand
Gulf lease obligation, as of December 31, 1994 and 1993, was estimated
to be $1,091 million and $1,397.8 million, respectively. Fair values
were determined using bid prices reported by dealer markets and by
nationally recognized investment banking firms. For the years 1995,
1996, 1997, 1998, and 1999 System Energy has long-term debt maturities
and sinking fund requirements (in millions) of $105, $250, $10, $70,
and $70, respectively.
NOTE 6. DIVIDEND RESTRICTIONS
Various agreements relating to the long-term debt of System
Energy restrict the payment of cash dividends or other distributions
on its common stock. As of December 31, 1994, $41.7 million of System
Energy's retained earnings were restricted against the payment of cash
dividends or other distributions on common stock.
NOTE 7. COMMITMENTS AND CONTINGENCIES
Capital Requirements and Financing
Construction expenditures (excluding nuclear fuel) for the years
1995, 1996, and 1997 are estimated to total $22 million, $21.6
million, and $19.1 million, respectively. System Energy will also
require $365 million during the period 1995-1997 to meet long-term
debt maturities. System Energy plans to meet the above requirements
with internally generated funds and cash on hand, supplemented by the
issuance of long-term debt. See Note 5 for the possible issuance of
new first mortgage bonds and the potential refunding, redemption,
purchase, or other acquisition of certain series of outstanding first
mortgage bonds.
Capital Funds Agreement
Entergy Corporation has agreed to supply to System Energy
sufficient capital to (1) maintain System Energy's equity capital at
an amount equal to a minimum of 35% of its total capitalization
(excluding short-term debt), and (2) permit the continuation of
commercial operation of Grand Gulf 1 and to pay in full all
indebtedness for borrowed money of System Energy when due under any
circumstances. In addition, under supplements to the Capital Funds
Agreement assigning System Energy's rights as security for specific
debt of System Energy, Entergy Corporation has agreed to make cash
capital contributions to enable System Energy to make payments on such
debt when due.
System Energy has entered into various agreements with AP&L,
LP&L, MP&L, and NOPSI, whereby AP&L, LP&L, MP&L, and NOPSI are
obligated to purchase their respective entitlements of capacity
(discussed below) and energy from System Energy's 90% ownership and
leasehold interest in Grand Gulf 1, and to make payments that,
together with other available funds, are adequate to cover System
Energy's operating expenses. System Energy would have to secure funds
from other sources, including Entergy's obligations under the Capital
Funds Agreement, to cover any shortfalls from payments received from
AP&L, LP&L, MP&L, and NOPSI under these agreements.
Unit Power Sales Agreement
System Energy has agreed to sell all of its 90% owned and leased
share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L,
and NOPSI in accordance with specified percentages (AP&L 36%, LP&L
14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this
agreement are paid in consideration for the respective entitlements of
AP&L, LP&L, MP&L, and NOPSI to receive capacity and energy, and are
payable irrespective of the quantity of energy delivered so long as
the unit remains in commercial operation. The agreement will remain
in effect until terminated by the parties and approved by FERC, most
likely upon Grand Gulf 1's retirement from service. The monthly
obligation for payments from AP&L, LP&L, MP&L, and NOPSI to System
Energy is approximately $49 million.
Availability Agreement
AP&L, LP&L, MP&L, and NOPSI are individually obligated to make
payments or subordinated advances to System Energy in accordance with
stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and
NOPSI 24.7%) in amounts that, when added to amounts received under the
Unit Power Sales Agreement or otherwise, are adequate to cover all of
System Energy's operating expenses as defined, including an amount
sufficient to amortize Grand Gulf 2 over 27 years. System Energy has
assigned its rights to payments and advances to certain creditors
as security for certain obligations. Since commercial operation
of Grand Gulf 1, payments under the Unit Power Sales Agreement have
exceeded the amounts payable under the Availability Agreement.
Accordingly, no payments have ever been required.
Reallocation Agreement
System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the
Reallocation Agreement relating to the sale of capacity and energy
from the Grand Gulf Station and the related costs, in which LP&L,
MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and
obligations with respect to the Grand Gulf Station under the
Availability Agreement. FERC's decision allocating a portion of Grand
Gulf 1 capacity and energy to AP&L supersedes the Reallocation
Agreement as it relates to Grand Gulf 1. Responsibility for any Grand
Gulf 2 amortization amounts has been individually allocated (LP&L
26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the
Reallocation Agreement. However, the Reallocation Agreement does not
affect AP&L's obligation to System Energy's lenders under the
assignments referred to in the preceding paragraph. AP&L would be
liable for its share of such amounts if LP&L, MP&L, and NOPSI were
unable to meet their contractual obligations. No payments of any
amortization amounts will be required as long as amounts paid to
System Energy under the Unit Power Sales Agreement, including other
funds available to System Energy, exceed amounts required under the
Availability Agreement, which is expected to be the case for the
foreseeable future.
Reimbursement Agreement
In December 1988, System Energy entered into two entirely
separate, but identical, arrangements for the sales and leasebacks of
an approximate aggregate 11.5% ownership interest in Grand Gulf 1 (see
Note 8). In connection with the equity funding of the sale and
leaseback arrangements, letters of credit are required to be
maintained to secure certain amounts payable for the benefit of the
equity investors by System Energy under the leases. The current
letters of credit are effective until January 15, 1997.
Under the provisions of the Reimbursement Agreement, as amended,
related to the letters of credit, System Energy has agreed to a number
of covenants relating to the maintenance of certain capitalization and
fixed charge coverage ratios. System Energy agreed, during the term
of the Reimbursement Agreement, to maintain its equity at not less
than 33% of its adjusted capitalization (as defined in the
Reimbursement Agreement to include certain amounts not included in
capitalization for financial statement purposes). In addition, System
Energy must maintain, with respect to each fiscal quarter during the
term of the Reimbursement Agreement, a ratio of adjusted net income to
interest expense (calculated, in each case, as specified in the
Reimbursement Agreement) of at least 1.60. As of December 31, 1994,
System Energy's equity approximated 34.25% of its adjusted
capitalization, and its fixed charge coverage ratio was 1.23.
As a result of the charges associated with an agreement with FERC
settling a long-standing dispute involving income tax allocation
procedures, System Energy has obtained the consent of certain banks
(parties to the Reimbursement Agreement) to waive temporarily the
fixed charge coverage covenant in the letters of credit and
Reimbursement Agreement, until November 30, 1995. (See Note 2 for
information on the FERC Settlement.) System Energy expects that upon
expiration of the waiver period, it will be in compliance with the
fixed charge coverage covenant. Absent a waiver, System Energy's
failure to perform this covenant could cause a draw under the letters
of credit and/or early termination of the letters of credit. If the
letters of credit were not replaced in a timely manner, a default or
early termination of System Energy's leases could result. Draws under
the letters of credit must be repaid by System Energy within 5 days
(or in some cases, 90 days) following the date of the drawing.
Nuclear Insurance
The Price-Anderson Act limits public liability for a single
nuclear incident to approximately $8.92 billion as of December 31,
1994. System Energy has protection for this liability through a
combination of private insurance (currently $200 million) and an
industry assessment program. Under the assessment program, the
maximum amount that would be required for each nuclear incident would
be $79.3 million per reactor, payable at a rate of $10 million per
licensed reactor per incident per year. As a co-licensee of Grand
Gulf 1 with System Energy, SMEPA would share 10% of this obligation.
System Energy has one licensed reactor. In addition, System Energy
participates in a private insurance program which provides coverage
for worker tort claims filed for bodily injury caused by radiation
exposure. System Energy's maximum assessment under the program is an
aggregate of approximately $3.2 million in the event losses exceed
accumulated reserve funds.
System Energy on behalf of itself and other insured interests
(including other co-owners of Grand Gulf 1) is a member of certain
insurance programs that provide coverage for property damage,
including decontamination and premature decommissioning expense. As
of December 31, 1994, System Energy was insured against such losses up
to $2.75 billion with $250 million of this amount designated to cover
any shortfall in the NRC required decommission trust funding. Under
the property damage insurance programs, System Energy could be subject
to assessments if losses exceed the accumulated funds available to the
insurers. As of December 31, 1994, the maximum amount of such
possible assessments to System Energy was $29.7 million. Under its
agreement with System Energy, SMEPA would share in System Energy's
obligation.
The amount of property insurance presently carried by System
Energy exceeds the NRC's minimum requirement for nuclear power plant
licensees of $1.06 billion per site. NRC regulations provide that the
proceeds of this insurance must be used, first, to place and maintain
the reactor in a safe and stable condition and, second, to complete
decontamination operations. Only after proceeds are dedicated for
such use and regulatory approval is secured, would any remaining
proceeds be made available for the benefit of plant owners or their
creditors.
Spent Nuclear Fuel and Decommissioning Costs
System Energy provides for estimated future disposal costs for
spent nuclear fuel in accordance with the Nuclear Waste Policy Act of
1982. System Energy entered into a contract with the DOE, whereby the
DOE will furnish disposal service at a cost of one mill per net KWH
generated and sold. The fees payable to the DOE may be adjusted in
the future to assure full recovery. System Energy considers all costs
incurred or to be incurred for the disposal of spent nuclear fuel to
be proper components of nuclear fuel expense and recovers such costs
in rates.
Delays have occurred in the DOE's program for the acceptance and
disposal of spent nuclear fuel at a permanent repository. In a
statement released February 17, 1993, the DOE asserted that it does
not have a legal obligation to accept spent nuclear fuel without an
operational repository for which it has not yet arranged. Currently
the DOE projects it will begin to accept spent fuel no earlier than
2010. In the meantime, System Energy is responsible for spent fuel
storage. Current on-site spent fuel pool storage capacity at Grand
Gulf 1 is estimated to be sufficient until 2004. Thereafter, System
Energy will provide additional storage capacity at an initial cost of
$5 million to $10 million. In addition, approximately $3 million
to $5 million will be required every four to five years subsequent
to 2004 until the DOE's repository begins accepting Grand Gulf 1's
spent fuel.
Entergy Operations and System Fuels joined in lawsuits against
the DOE, seeking clarification of the DOE's responsibility to receive
spent nuclear fuel beginning in 1998. The original suits, filed June
20, 1994, asked for a ruling stating that the Nuclear Waste Policy Act
require the DOE to begin taking title to the spent fuel and to start
removing it from nuclear power plants in 1998, a mandate for the DOE's
nuclear waste management program to begin accepting fuel in 1998 and
court monitoring of the program, and the potential for escrow of
payments to the Nuclear Waste Fund instead of directly to the DOE.
Decommissioning costs were estimated to approximate $248.7
million in 1989 dollars for System Energy's 90% interest in Grand Gulf
1, based on a 1989 decommissioning cost study. However, as a result of
the FERC Complaint Case settlement, the amount to be collected in
rates for the total cost of decommissioning System Energy's 90%
interest in Grand Gulf 1 was set at approximately $198 million (in
1989 dollars). System Energy completed an updated cost study in 1994
which reflected a decommissioning cost of $365.9 million (in 1993
dollars) for System Energy's 90% interest. A filing with FERC to
request the updated decommissioning costs in rates is under
consideration by System Energy. The amounts recovered in rates are
deposited in external trust funds and reported at market value. The
accumulated decommissioning liability of $31.9 million as of December
31, 1994, has been recorded in other deferred credits.
Decommissioning expense in the amount of $5.2 million was recorded in
1994. The actual decommissioning costs may vary from the estimates
because of regulatory requirements, changes in technology, and
increased costs of labor, materials, and equipment. Management
believes that actual decommissioning costs are likely to be higher
than the amounts presented above.
The staff of the SEC has questioned certain of the current
accounting practices of the electric utility industry, regarding the
recognition, measurement, and classification of decommissioning costs
for nuclear generating stations in the financial statements of
electric utilities. In response to these questions, the FASB is
currently reviewing the accounting for decommissioning. If current
electric utility industry accounting practices for such
decommissioning are changed, annual provisions for decommissioning
could increase, the estimated cost for decommissioning could be
recorded as a liability rather than as accumulated depreciation, and
trust fund income from the external decommissioning trusts could be
reported as investment income rather than as a reduction to
decommissioning expense.
The EPAct has a provision that assesses domestic nuclear
utilities with fees for the decontamination and decommissioning of
DOE's past uranium enrichment operations. The decontamination and
decommissioning provisions will be used to set up a fund into which
contributions from utilities and the federal government will be
placed. System Energy's annual assessment, which will be adjusted
annually for inflation, is approximately $1.4 million (in 1995
dollars) for approximately 15 years. FERC requires that utilities
treat these assessments as costs of fuel as they are amortized. The
cumulative liability of $15.8 million as of December 31, 1994, is
recorded in other current liabilities and other non-current
liabilities, according to FERC guidelines, and is offset in the
financial statements by a regulatory asset.
System Fuels
System Fuels entered into a revolving credit agreement with a
bank that provides $45 million in borrowings to finance System Fuels'
nuclear materials and services inventory. Should System Fuels default
on its obligations under its credit agreement, AP&L, LP&L, and System
Energy have agreed to purchase the nuclear materials and services
financed under the agreement.
NOTE 8. LEASES
Nuclear Fuel Lease
System Energy has an arrangement to lease nuclear fuel in an
aggregate amount up to $105 million. The lessor finances its
acquisition of nuclear fuel through a credit agreement and the
issuance of notes. The credit agreement which was entered into in
1989 has been extended to February 1998 and the notes have varying
remaining maturities of up to 3 years. It is expected that the credit
arrangements will be extended or alternative financing will be secured
by the lessor upon the maturity of the current arrangements. If the
lessor cannot arrange for alternative financing upon maturity of its
borrowings, System Energy must purchase nuclear fuel in an amount
sufficient to enable the lessor to retire such borrowings.
Lease payments are based on nuclear fuel use. Nuclear fuel lease
expense of $37.8 million, $36.2 million, and $48.4 million (including
interest of $6.8 million, $5.1 million, and $8.5 million) was charged
to operations in 1994, 1993, and 1992, respectively.
Sale and Leaseback Transactions
On December 28, 1988, System Energy entered into two entirely
separate, but identical, arrangements for the sales and leasebacks of
an approximate aggregate 11.5% undivided ownership interest in Grand
Gulf 1 for an aggregate cash consideration of $500 million. System
Energy is leasing back the undivided interest on a net lease basis
over a 26 1/2-year basic lease term. System Energy has options to
terminate the leases and to repurchase the undivided interest in Grand
Gulf 1 at certain intervals during the basic lease term. Further, at
the end of the basic lease term, System Energy has an option to renew
the leases or to repurchase the undivided interest in Grand Gulf 1.
See Note 7 with respect to certain other terms of the transactions.
On January 18, 1994, System Energy refinanced the debt portion of
the sale and leaseback arrangements of the undivided portions of Grand
Gulf 1. The secured lease obligation bonds of $356 million, 7.43%
series due 2011, and $79 million, 8.2% series due 2014, will be
indirectly secured by liens on, and a security interest in, certain
ownership interests and the respective leases relating to Grand Gulf
1. See Note 7 for information on letters of credit maintained by
System Energy for the benefit of the equity investors in the
transactions.
In accordance with SFAS 98, "Accounting for Leases," due to
"continuing involvement" by System Energy, the sale and leaseback
arrangements of the undivided portions of Grand Gulf 1, as described
above, are required to be reflected for financial reporting purposes
as financing transactions in System Energy's financial statements.
The amounts charged to expense for financial reporting purposes
include the interest portion of the lease obligations and depreciation
of the plant. However, operating revenues include the recovery of the
lease payments because the transactions are accounted for as sales and
leasebacks for rate-making purposes. The total of interest and
depreciation expense exceeds the corresponding revenues realized
during the early part of the lease term. Consistent with a
recommendation contained in a FERC audit report, System Energy
recorded as a deferred asset the difference between the recovery of
the lease payments and the amounts expensed for interest and
depreciation and is recording such difference as a deferred asset on
an ongoing basis. The amount of this deferred asset was $78.5 million
and $71.2 million as of December 31, 1994 and 1993, respectively. See
Note 1 for further information regarding the accounting for the sale
and leaseback transactions.
As of December 31, 1994, System Energy had future minimum lease
payments (reflecting an implicit rate of 7.02% after the above
refinancing) as follows (in thousands):
1995 $ 42,464
1996 42,753
1997 42,753
1998 42,753
1999 42,753
Years thereafter 802,820
----------
Total $1,016,296
==========
NOTE 9. POSTRETIREMENT BENEFITS
Pension Plan
System Energy participates in a defined benefit pension plan
sponsored by Entergy. Effective June 1990, all of System Energy's
employees became employees of Entergy Operations. However, the
employees still remain under System Energy's plan and no transfers of
related pension liabilities and assets have been made. The pension
plan, which covers substantially all of its employees, is
noncontributory and provides pension benefits based on employees'
credited service and average compensation, generally during the last
five years before retirement. System Energy funds pension costs in
accordance with contribution guidelines established by the Employee
Retirement Income Security Act of 1974, as amended, and the Internal
Revenue Code of 1986, as amended. The assets of the plan consist
primarily of common and preferred stocks, fixed income securities,
interest in a money market fund, and insurance contracts.
System Energy's 1994, 1993, and 1992 pension cost, including
amounts capitalized, included the following components:
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Service cost - benefits earned during the period $2,619 $2,045 $1,737
Interest cost on projected benefit obligation 2,148 1,709 1,439
Actual return on plan assets 498 (3,828) (2,070)
Net amortization and deferral (3,535) 972 (587)
------ ------ ------
Net pension cost $1,730 $ 898 $ 519
====== ====== ======
The funded status of System Energy's pension plan as of
December 31, 1994 and 1993, was:
1994 1993
(In Thousands)
Actuarial present value of accumulated pension plan benefits:
Vested $13,305 $16,728
Nonvested 986 615
------- -------
Accumulated benefit obligation $14,291 $17,343
======= =======
Plan assets at fair value $33,285 $33,914
Projected benefit obligation 27,239 28,933
------- -------
Plan assets in excess of projected benefit obligation 6,046 4,981
Unrecognized prior service cost 1,242 879
Unrecognized transition asset (6,484) (7,080)
Unrecognized net loss (gain) (1,952) 1,802
------- -------
Accrued pension asset $(1,148) $ 582
======= =======
The significant actuarial assumptions used in computing the
information above for 1994, 1993, and 1992, were as follows: weighted
average discount rate, 8.5% for 1994, 7.5% for 1993 and 8.25% for
1992; weighted average rate of increase in future compensation levels,
5.1% for 1994 and 5.6% for 1993 and 1992; and expected long-term rate
of return on plan assets, 8.5%. Transition assets are being amortized
over the average remaining service period of active participants.
NOTE 10. TRANSACTIONS WITH AFFILIATES
System Energy sells all of the capacity and energy from its share
of Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI under rate schedules
approved by FERC. Accordingly, all of System Energy's operating
revenues consist of billings to AP&L, LP&L, MP&L, and NOPSI.
MP&L provides a minimal amount of technical and advisory services
and other miscellaneous services to System Energy. In addition,
pursuant to a service agreement, System Energy receives technical and
advisory services from Entergy Services. Charges from MP&L and
Entergy Services for technical, advisory and miscellaneous services
amounted to approximately $10.5 million in 1994, $12.3 million in
1993, and $13.8 million in 1992. System Energy pays directly or
reimburses Entergy Operations for the costs associated with operating
Grand Gulf 1 (excluding nuclear fuel) which were approximately $179.6
million in 1994, $151.3 million in 1993, and $179 million in 1992.
In addition, certain materials and services required for
fabrication of nuclear fuel are acquired and financed by System Fuels
and then sold to System Energy as needed. Charges for these materials
and services, which represent additions to nuclear fuel, amounted to
approximately $27.8 million in 1994, $32.8 million in 1993, and $13.7
million in 1992.
NOTE 11. QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating results for the four quarters of 1994 and 1993 were:
Operating Operating Net
Revenue Income (Loss) Income (Loss)
(In Thousands)
1994:
First Quarter $147,847 $ 64,342 $ 21,549
Second Quarter $151,219 $ 65,779 $ 25,212
Third Quarter $150,949 $ 65,869 $ 24,934
Fourth Quarter $ 24,948 $(24,223) $(66,288)
1993:
First Quarter $164,630 $ 76,331 $ 31,782
Second Quarter $153,527 $ 65,539 $ 21,268
Third Quarter $155,071 $ 63,992 $ 23,040
Fourth Quarter $177,540 $ 66,340 $ 17,837
See Note 2 for information regarding the recording of refunds in
connection with the FERC Settlement in November 1994.
See Note 2 for information regarding the recording of refunds as
a result of the FERC Return on Equity Case settlement in the third
quarter of 1993.
SYSTEM ENERGY RESOURCES, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1994 1993 1992 1991 1990
(Dollars in Thousands)
Operating revenues $ 474,963 $ 650,768 $ 723,410 $ 686,664 $ 801,618
Net income $ 5,407 $ 93,927 $ 130,141 $ 104,622 $ 168,677
Total assets $3,613,359 $3,891,066 $3,672,441 $3,642,203 $3,883,241
Long-term obligations (1) $1,456,993 $1,536,593 $1,768,299 $1,707,470 $1,849,000
Electric energy sales
(Millions of KWH) 8,653 7,113 7,354 8,220 6,666
(1) Includes long-term debt (excluding current maturities) and
noncurrent capital lease obligations.
See Note 2 for information with respect to refunds and charges
resulting from the FERC Settlement in 1994 and Note 3 for the effect
of the accounting change for income taxes in 1993.
Item 9. Changes In and Disagreements With Accountants On Accounting
and Financial Disclosure.
No event that would be described in response to this item has
occurred with respect to Entergy, System Energy, AP&L, GSU, LP&L,
MP&L, or NOPSI.
PART III
Item 10. Directors and Executive Officers of the Registrants.
All officers and directors listed below held the specified
positions with their respective companies as of the date of filing
this report.
ENTERGY CORPORATION
Directors
Information required by this item concerning directors of Entergy
Corporation is set forth under the heading "Election of Directors"
contained in the Proxy Statement of Entergy Corporation to be filed in
connection with its Annual Meeting of Stockholders to be held May 26,
1995, and is incorporated herein by reference.
Name Age Position Period
Officers
Edwin Lupberger(a) 58 Chairman of the Board and Chief 1985-Present
Executive Officer of Entergy
Corporation
Chairman of the Board and Chief 1993-Present
Executive Officer of AP&L, LP&L,
MP&L, and NOPSI
Chairman of the Board and Chief 1994-Present
Executive Officer of GSU
Chairman of the Board of System Energy 1986-Present
and Entergy Enterprises
Chairman of the Board of Entergy 1990-Present
Operations
Chairman of the Board of Entergy 1985-Present
Services
Chief Executive Officer of Entergy 1991-Present
Services
President of Entergy Services and 1994-Present
Entergy Enterprises
Director of AP&L, LP&L, MP&L, NOPSI, 1986-Present
and System Energy
Director of Entergy Operations and 1994-Present
Entergy Services
Director of Entergy Enterprises 1984-Present
Chief Executive Officer of Entergy 1993-Present
Power, Entergy Power Development
Corporation, and Entergy-Richmond
Power Corporation
Chief Executive Officer of Entergy 1994-Present
Pakistan, Ltd. and Entergy Power
Asia, Ltd.
President of Entergy Corporation 1985-1991
Chairman of the Board of Entergy Power 1990-1993
Chief Executive Officer of Entergy 1991-1994
Enterprises
President of Entergy Services and 1990-1991
Entergy Enterprises
Chairman of the Board of System Fuels 1986-1990
Director of System Fuels 1986-1992
Jerry L. Maulden 58 President and Chief Operating Officer 1993-Present
of Entergy Corporation
Vice Chairman and Chief Operating 1993-Present
Officer of AP&L, GSU, LP&L, MP&L,
and NOPSI
Director of AP&L 1979-Present
Director of GSU 1993-Present
Director of LP&L and NOPSI 1991-Present
Director of MP&L 1988-Present
Director of Entergy Operations 1990-Present
Director of System Energy 1987-Present
Vice Chairman of Entergy Services 1992-Present
Director of Entergy Services 1979-Present
Chairman of the Board of AP&L 1989-1993
Chief Executive Officer of AP&L 1979-1993
Chairman of the Board and Chief 1991-1993
Executive Officer of LP&L and NOPSI
Chairman of the Board and Chief 1989-1993
Executive Officer of MP&L
Group President, System Executive - 1991-1993
Transmission, Distribution, and
Customer Service of Entergy
Corporation
Senior Vice President, System 1988-1991
Executive -
Arkansas/Mississippi/Missouri
Division of Entergy Corporation
Director of System Fuels 1979-1992
Group President, System Executive - 1991-1992
Transmission, Distribution, and
Customer Service of Entergy Services
Director of Entergy Enterprises 1984-1991
Jerry D. Jackson 50 Executive Vice President - Marketing 1994-Present
and External Affairs of Entergy
Corporation
Executive Vice President - Marketing 1995-Present
and External Affairs of AP&L, GSU,
LP&L, MP&L, and NOPSI
Executive Vice President - Marketing 1994-Present
and External Affairs of Entergy
Services
Secretary of GSU 1994-1995
Director of AP&L,LP&L, MP&L, and NOPSI 1992-Present
Director of GSU 1994-Present
Director of System Energy 1993-Present
Director of Entergy Services 1990-Present
Executive Vice President - Finance and 1990-1994
External Affairs of Entergy
Corporation
Executive Vice President - Finance and 1992-1994
External Affairs and Secretary of
AP&L, LP&L, MP&L, and NOPSI
Executive Vice President - Finance and 1993-1994
External Affairs of GSU
Executive Vice President - Finance and 1990-1992
External Affairs of Entergy Services
President and Chief Administrative 1992-1994
Officer of Entergy Services
Secretary of Entergy Corporation 1991-1994
President of Entergy Enterprises 1991-1992
Director of Entergy Power and Entergy 1990-1992
Enterprises
Senior Vice President, System 1987-1990
Executive - Legal and External
Affairs of Entergy Corporation and
Entergy Services
Donald C. Hintz 52 Executive Vice President and Chief 1994-Present
Nuclear Officer of Entergy
Corporation
Executive Vice President - Nuclear of 1994-Present
AP&L, GSU, and LP&L
Director of AP&L, LP&L, MP&L, System 1992-Present
Energy, System Fuels, and Entergy
Services
Director of GSU 1993-Present
Chief Executive Officer and President 1992-Present
of System Energy and Entergy
Operations
Director of Entergy Operations 1990-Present
Director of GSG&T, Prudential Oil & 1994-Present
Gas, Southern Gulf Railway, and
Varibus Corporation
Senior Vice President and Chief 1993-1994
Nuclear Officer of Entergy
Corporation
Senior Vice President - Nuclear of 1990-1994
AP&L
Senior Vice President - Nuclear of GSU 1993-1994
Senior Vice President - Nuclear of 1992-1994
LP&L
Director of NOPSI 1992-1994
President of Entergy Operations 1992-1992
Chief Operating Officer and Executive 1990-1992
Vice President of Entergy Operations
Group Vice President - Nuclear of LP&L 1990-1992
Chief Operating Officer and Executive 1989-1990
Vice President of System Energy
Gerald D. McInvale 51 Senior Vice President and Chief 1991-Present
Financial Officer of Entergy
Corporation, AP&L, LP&L, MP&L,
NOPSI, System Energy, Entergy
Operations, Entergy Services, and
Entergy Enterprises
Senior Vice President and Chief 1993-Present
Financial Officer of GSU
Senior Vice President and Chief 1994-Present
Financial Officer of System Fuels
Vice President, Treasurer, and 1993-Present
Director of Entergy Power
Director of System Fuels 1992-Present
Treasurer of Entergy Enterprises 1992-Present
Director and Acting Chief Operating 1994-Present
Officer of Entergy Enterprises
Chairman of the Board of Entergy 1994-Present
Systems and Service, Inc.
Director of Entergy Systems and 1993-Present
Service, Inc.
Vice President, Treasurer, and 1993-Present
Director of Entergy Power
Development Corporation and Entergy-
Richmond Power Corporation
Senior Vice President, Treasurer, and 1994-Present
Director of Entergy Pakistan, Ltd.
and Entergy Power Asia, Ltd.
President - Executive Information 1990-1991
Strategies (Consulting Firm),
Dallas, Texas
Senior Vice President and Chief 1987-1990
Financial Officer of Frito-Lay, Inc.
(Subsidiary of PepsiCo, Inc.),
Dallas, Texas
Michael G. Thompson 54 Senior Vice President and Chief Legal 1992-Present
Officer of Entergy Corporation and
Entergy Services
Senior Vice President, Chief Legal 1992-Present
Officer, and Secretary of Entergy
Enterprises
Senior Vice President, Secretary, and 1994-Present
Director of Entergy Pakistan, Ltd.
and Entergy Power Asia, Ltd.
Vice President, Secretary, and 1994-Present
Director of Entergy Power
Vice President and Secretary of 1993-Present
Entergy Systems and Service, Inc.
Vice President, Secretary, and 1992-Present
Director of Entergy Power
Development and Entergy-Richmond
Power Corporation
Secretary of Entergy Corporation 1994-Present
Secretary of AP&L, GSU, LP&L, MP&L, 1995-Present
and NOPSI
Director of Entergy Systems and 1992-Present
Service, Inc.
Senior Vice President and Chief Legal 1993-1994
Officer of Entergy Power
Assistant Secretary of Entergy 1993-1994
Corporation
Senior Partner of Friday, Eldredge & 1987-1992
Clark (law firm)
S. M. Henry Brown, Jr. 56 Vice President - Federal Governmental 1989-Present
Affairs of Entergy Corporation and
Entergy Services
Charles L. Kelly 58 Vice President - Corporate 1992-Present
Communications and Public Relations
of Entergy Corporation
Vice President - Corporate 1991-Present
Communications and Public Relations
of Entergy Services
Vice President - Corporate 1981-1991
Communications of AP&L
Lee W. Randall 45 Vice President and Chief Accounting 1991-Present
Officer of Entergy Corporation,
AP&L, LP&L, MP&L, NOPSI, System
Energy, Entergy Operations, and
Entergy Services
Vice President, Chief Accounting 1993-Present
Officer, and Assistant Secretary of
GSU
Assistant Secretary of AP&L, LP&L, 1991-Present
MP&L, NOPSI, Entergy Operations, and
Entergy Services
Senior Vice President - Finance and 1988-1991
Administration and Chief Financial
Officer of AP&L
Secretary of AP&L 1989-1991
Assistant Treasurer of AP&L 1988-1991
ARKANSAS POWER & LIGHT COMPANY
Directors
Michael B. Bemis(b) 47 Executive Vice President - Customer 1992-Present
Service and Director of AP&L, LP&L,
and MP&L
Executive Vice President - Customer 1993-Present
Service of GSU
Executive Vice President - Customer 1992-Present
Service of NOPSI and Entergy
Services
Director of GSU 1994-Present
Director of System Fuels 1992-Present
Director of Varibus Corporation, 1994-Present
Prudential Oil & Gas, Inc., GSG&T,
Inc., and Southern Gulf Railway
Company
Director of NOPSI 1992-1994
President and Chief Operating Officer 1992-1992
of LP&L and NOPSI
President and Chief Operating Officer 1989-1991
of MP&L
Secretary of MP&L 1991-1991
Donald C. Hintz 52 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry D. Jackson 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
R. Drake Keith 59 President and Director of AP&L 1989-Present
Chief Operating Officer of AP&L 1989-1992
Secretary of AP&L 1991-1992
Edwin Lupberger 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Officers
Edwin Lupberger 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
R. Drake Keith 59 See the information under the AP&L
Directors Section above,
incorporated herein by reference.
Michael B. Bemis 47 See the information under the AP&L
Directors Section above,
incorporated herein by reference.
Jerry D. Jackson 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Frank F. Gallaher 49 Executive Vice President - Fossil 1993-Present
Operations of AP&L, LP&L, MP&L,
NOPSI, and Entergy Services
President of GSU 1994-Present
Director of GSU 1993-Present
Chairman of the Board of System Fuels 1992-Present
Chairman of the Board of Varibus 1993-Present
Corporation, Prudential Oil & Gas,
Inc., GSG&T, Inc., and Southern Gulf
Railway Company
Director of Entergy Services and 1992-Present
System Fuels
Senior Vice President - Fossil 1992-1993
Operations of AP&L, LP&L, MP&L,
NOPSI, and Entergy Services
Vice President and Chief Engineer of 1985-1990
MP&L
Vice President - System Planning of 1990-1992
Entergy Services
Donald C. Hintz 52 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Gerald D. McInvale 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael G. Thompson 54 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael R. Niggli 45 Senior Vice President - Marketing of 1993-Present
AP&L, GSU, LP&L, MP&L, NOPSI, and
Entergy Services
Vice President - Customer Services of 1993-1993
LP&L, NOPSI, and Entergy Services
Vice President - Strategic Planning of 1990-1992
Entergy Services
Vice President - Fuels Management of 1988-1990
Entergy Services
Vice President and Director of Entergy 1991-1992
Enterprises
Cecil L. Alexander(c) 59 Vice President - Governmental Affairs 1991-Present
of AP&L
Vice President - Public Affairs of 1989-1991
AP&L
Richard J. Landy 49 Vice President - Human Resources and 1991-Present
Administration of AP&L, LP&L, MP&L,
NOPSI, Entergy Services, and EOI
Vice President - Human Resources and 1993-Present
Administration of GSU
Vice President - Human Resources and 1986-1990
Administration of System Energy
Vice President - Human Resources and 1990-1991
Administration of Entergy Operations
James S. Pilgrim 59 Vice President - Customer Service of 1994-Present
AP&L
Director, Central Region, TDCS 1993-1994
Customer Service
Central Division Manager of MP&L 1991-1993
Northern Division Manager of MP&L 1988-1991
Lee W. Randall 45 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
C. Hiram Walters 58 Vice President - Customer Service of 1993-Present
AP&L
Vice President - Customer Service of 1994-Present
LP&L
Vice President - Customer Service, 1993-Present
Central Region of Entergy Services
Vice President - Customer Service of 1984-1991
MP&L
Senior Vice President - Customer 1991-1992
Service of Entergy Services
GULF STATES UTILITIES COMPANY
Directors
Michael B. Bemis 47 See the information under the AP&L
Directors Section above,
incorporated herein by reference.
Frank F. Gallaher 49 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Donald C. Hintz 52 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry D. Jackson 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Edwin Lupberger 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Officers
Edwin Lupberger 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Frank F. Gallaher 49 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Michael B. Bemis 47 See the information under the AP&L
Directors Section above,
incorporated herein by reference.
Jerry D. Jackson 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Donald C. Hintz 52 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Gerald D. McInvale 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael G. Thompson 54 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael R. Niggli 45 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Richard J. Landy 49 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
William E. Colston 59 Vice President - Customer Service of 1994-Present
GSU
Vice President - Customer Service of 1993-Present
LP&L
Vice President - Customer Service of 1993-Present
Southern Region of Entergy Services
Vice President - Division Manager of 1988-1991
LP&L
Regional Director of LP&L 1992-1993
Calvin J. Hebert 60 Vice President - Customer Service of 1993-Present
GSU
Senior Vice President - Division 1992-1993
Operations of GSU
Senior Vice President - External 1986-1992
Affairs of GSU
Karen Johnson 50 Vice President - Governmental Affairs 1994-Present
of GSU - Texas
Executive Director of State Bar of 1990-1994
Texas
Attorney at Law, Akin Gump Strauss 1988-1990
Hauer & Feld
Lee W. Randall 45 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
LOUISIANA POWER & LIGHT COMPANY
Directors
Michael B. Bemis 47 See the information under the AP&L
Directors Section above,
incorporated herein by reference.
John J. Cordaro 61 President and Director of LP&L and 1992-Present
NOPSI
Group Vice President - External 1989-1992
Affairs of LP&L and NOPSI
Donald C. Hintz 52 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry D. Jackson 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Edwin Lupberger 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Officers
Edwin Lupberger 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
John J. Cordaro 61 See the information under the LP&L
Directors Section above,
incorporated herein by reference.
Michael B. Bemis 47 See the information under the AP&L
Directors Section above,
incorporated herein by reference.
Jerry D. Jackson 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Frank F. Gallaher 49 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Donald C. Hintz 52 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Gerald D. McInvale 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael G. Thompson 54 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael R. Niggli 45 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Richard C. Guthrie 52 Vice President - Governmental Affairs 1992-Present
of LP&L and NOPSI
Vice President - Public Affairs of 1986-1992
LP&L and NOPSI
Richard J. Landy 49 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
James D. Bruno 55 Vice President - Customer Service of 1994-Present
LP&L and NOPSI
Vice President - Metro Region of 1993-Present
Entergy Services
Region Director - Metro Region of 1991-1993
Entergy Services
Vice President - Division Manager - 1988-1991
Orleans Division of Entergy Services
William E. Colston 59 See the information under the GSU
Officers Section above, incorporated
herein by reference.
Lee W. Randall 45 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
C. Hiram Walters 58 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
MISSISSPPI POWER & LIGHT COMPANY
Directors
Michael B. Bemis 47 See the information under the AP&L
Directors Section above,
incorporated herein by reference.
Donald C. Hintz 52 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry D. Jackson 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Edwin Lupberger 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Donald E. Meiners(d) 59 President and Director of MP&L 1992-Present
Senior Vice President, System 1988-1990
Executive - Services Division of
Entergy Corporation
President and Chief Operating Officer 1990-1991
of LP&L and NOPSI
Chief Operating Officer and Secretary 1992-1992
of MP&L
President and Chief Executive Officer 1987-1990
of Entergy Services, System Fuels,
and Entergy Enterprises
Officers
Edwin Lupberger 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Donald E. Meiners 59 See the information under the MP&L
Directors Section above,
incorporated herein by reference.
Michael B. Bemis 47 See the information under the AP&L
Directors Section above,
incorporated herein by reference.
Jerry D. Jackson 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Frank F. Gallaher 49 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Gerald D. McInvale 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael G. Thompson 54 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael R. Niggli 45 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Bill F. Cossar 56 Vice President - Governmental Affairs 1987-Present
of MP&L
Johnny D. Ervin 45 Vice President - Customer Service of 1991-Present
MP&L
Director of Entergy Enterprises 1991-1992
Vice President - Marketing of LP&L and 1988-1991
NOPSI
Vice President - Division Manager of 1989-1991
LP&L
Richard J. Landy 49 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Lee W. Randall 45 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
NEW ORLEANS PUBLIC SERVICE INC.
Directors
John J. Cordaro 61 See the information under the LP&L
Directors Section above,
incorporated herein by reference.
Jerry D. Jackson 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Edwin Lupberger 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Officers
Edwin Lupberger 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
John J. Cordaro 61 See the information under the LP&L
Directors Section above,
incorporated herein by reference.
Michael B. Bemis 47 See the information under the AP&L
Directors Section above,
incorporated herein by reference.
Jerry D. Jackson 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Frank F. Gallaher 49 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Gerald D. McInvale 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael G. Thompson 54 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael R. Niggli 45 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Richard C. Guthrie 52 See the information under the LP&L
Officers Section above, incorporated
herein by reference.
Daniel F. Packer 47 Vice President - Regulatory and 1994-Present
Governmental Affairs of NOPSI
General Manager - Plant Operations at 1991-1994
Waterford 3
Manager - Operations and Maintenance 1990-1991
at Waterford 3
Richard J. Landy 49 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
James D. Bruno 55 See the information under the LP&L
Officers Section above, incorporated
herein by reference.
Lee W. Randall 45 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
SYSTEM ENERGY RESOURCES, INC.
Directors
Donald C. Hintz 52 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry D. Jackson 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Edwin Lupberger 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Officers
Edwin Lupberger 58 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Donald C. Hintz 52 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Gerald D. McInvale 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Lee W. Randall 45 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Joseph L. Blount 48 Secretary of System Energy and Entergy 1991-Present
Operations
Vice President Legal and External 1989-1990
Affairs of System Energy
Vice President Legal and External 1990-1993
Affairs of Entergy Operations
Assistant Secretary for System Energy 1987-1991
Assistant Secretary for Entergy 1990-1991
Operations
(a) Mr. Lupberger is a director of First Commerce Corporation,
New Orleans, LA, International Shipholding Corporation, New Orleans,
LA, and First National Bank of Commerce, New Orleans, LA.
(b) Mr. Bemis is a director of Deposit Guaranty National Bank, Jackson,
MS and Deposit Guaranty Corporation, Jackson, MS.
(c) Mr. Alexander is a director of First National Bank of Cleburne County,
Heber Springs, AR.
(d) Mr. Meiners is a director of Trustmark National Bank, Jackson, MS,
and Trustmark Corporation, Jackson, MS.
Each director and officer of the applicable System company is
elected yearly to serve until the first Board Meeting following the
Annual Meeting of Stockholders and until a successor is elected and
qualified. Annual meetings are currently expected to be held as
follows:
Entergy Corporation - May 26, 1995
AP&L - May 17, 1995
GSU - May 17, 1995
LP&L - May 17, 1995
MP&L - May 17, 1995
NOPSI - May 17, 1995
System Energy - April 14, 1995
Directorships shown above are generally limited to entities
subject to Section 12 or 15(d) of the Securities and Exchange Act of
1934 or to the Investment Company Act of 1940.
Section 16(a) of the Securities Exchange Act of 1934 and Section
17(a) of the Public Utility Holding Company Act of 1935 require each
registrant's officers, directors and persons who own more than 10% of
a registered class of such registrant's equity securities to file
reports of ownership and changes in ownership concerning the
securities of Entergy Corporation and its subsidiaries with the SEC
and to furnish Entergy Corporation with copies of all Section 16(a)
and 17(a) forms they file. Shortly following the Merger, certain
individuals were elected as officers of GSU. Although none of these
individuals owned any reportable securities of GSU, their initial
Forms 3 for GSU were not timely filed. These officers of GSU were:
Michael B. Bemis, Frank F. Gallaher, Glenn E. Harder, Donald C. Hintz,
Jerry D. Jackson, Richard J. Landy, Edwin Lupberger, Jerry L. Maulden,
Gerald D. McInvale, Michael R. Niggli, and Lee W. Randall. Four
individuals considered officers of the Corporation for purposes of
Section 16 failed to report on their 1993 Forms 5 their receipt during
1993 of certain restricted shares of the Corporation's stock under the
Equity Ownership Plan. These individuals and their respective
unreported shares were: S.M. Henry Brown, 4,000 shares; Frank F.
Gallaher, 4,000 shares; Charles L. Kelly, 4,000 shares, and Edwin
Lupberger, 5,000 shares. Glenn E. Harder, a former officer of the
Corporation, failed to timely report on a Form 4 the sale in October
1994 of 15 shares of the Corporation's stock which he had held in the
Corporation's dividend reinvestment plan. Each of the above
transactions has now been correctly reported.
Item 11. Executive Compensation
ENTERGY CORPORATION
Information called for by this item concerning the directors and
officers of Entergy Corporation and the Personnel Committee of Entergy
Corporation's Board of Directors is set forth under the headings
"Executive Compensation" and "Personnel Committee Interlocks and
Insider Participation" contained in the Proxy Statement of Entergy
Corporation to be filed in connection with its Annual Meeting of
Stockholders to be held on May 26, 1995, which information is
incorporated herein by reference.
AP&L, GSU, LP&L, MP&L, NOPSI, AND SYSTEM ENERGY
Summary Compensation Tables
The following tables include the Chief Executive Officers and the
four other most highly compensated executive officers in office as of
December 31, 1994 at AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy.
This determination was based on total annual base salary and bonuses
(excluding bonuses of an extraordinary and nonrecurring nature) from
all System sources earned by each officer during the year 1994. See
Item 10, "Directors and Executive Officers of the Registrants",
incorporated herein by reference, for information on the principal
positions of the executive officers named in the table below.
AP&L, GSU, LP&L, MP&L, NOPSI, and System Entergy
As shown in Item 10, most executive officers named below are
employed by several System companies. Because it would be
impracticable to allocate such officers' salaries among the various
companies, the table below includes aggregate compensation paid by all
System companies.
Long-Term Compensation
Annual Compensation Awards Payouts
Other Restricted Securities (b) (c)
(a) Annual Stock Underlying LTIP All Other
Name Year Salary Bonus Compensation Awards Options Payouts Compensation
Michael B. Bemis 1994 $288,846 $ 76,923 $32,940 (d) 2,500 shares $ 28,275 $22,982
1993 258,538 161,142 62,372 (d) 2,500 50,125 74,619
1992 258,059 170,186 35,927 (d) 2,500 45,094 71,492
Joseph L. Blount 1994 $115,171 $ 17,064 $ 9,339 (d) 0 shares 0 $12,416
1993 109,090 0 4,416 (d) 0 0 15,926
1992 109,140 13,435 5,092 (d) 0 0 17,591
Donald C. Hintz* 1994 $320,769 $142,749 $52,389 (d) 5,000 shares $ 48,379 $23,056
1993 265,386 166,560 48,548 (d) 5,000 85,774 24,462
1992 228,024 114,822 38,364 (d) 2,500 77,165 24,205
Jerry D. Jackson 1994 $323,711 $106,155 $29,598 (d) 5,000 shares $ 56,550 $23,370
1993 288,559 217,287 36,166 (d) 6,719 100,250 25,961
1992 254,167 152,500 27,008 (d) 5,000 90,188 25,447
Edwin Lupberger** 1994 $681,539 $218,789 $39,961 (d) 10,000 shares $139,525 $29,457
1993 542,077 437,610 20,327 (d) 13,438 248,313 32,957
1992 527,499 374,100 39,760 (d) 10,000 180,375 33,671
Jerry L. Maulden 1994 $426,134 $135,962 $63,994 (d) 5,000 shares $ 56,550 $25,690
1993 385,000 286,985 84,655 (d) 5,000 100,250 25,639
1992 392,233 259,316 79,280 (d) 5,000 90,188 24,920
Gerald D. McInvale 1994 $244,165 $ 66,227 $14,146 (d) 2,500 shares $ 28,275 $19,581
1993 221,696 141,811 48,805 (d) 2,500 50,125 22,667
1992 209,975 93,686 45,585 (d) 2,500 45,094 43,594
Lee W. Randall 1994 $177,001 $ 36,392 $ 7,208 (d) 0 shares $ 0 $14,271
1993 176,321 57,142 8,014 (d) 0 0 17,986
1992 168,859 37,094 6,818 (d) 0 0 19,555
* Chief Executive Officer of System Energy.
** Chief Executive Officer of AP&L, GSU, LP&L, MP&L, and NOPSI.
(a) Includes bonuses earned pursuant to the Annual Incentive Plan as
well as any bonuses of an extraordinary or nonrecurring nature.
(b) Amounts include the value of restricted shares that vested under
Entergy's Equity Ownership Plan.
(c) Includes the following:
(1) 1994 Executive Medical Plan premiums of $1,761 for each
of the above-named executives in 1994.
(2) 1994 employer contributions to the Defined Contribution
Restoration Plan as follows: Mr. Bemis $4,096; Mr. Hintz
$5,210; Mr. Jackson $5,134; Mr. Lupberger $15,946; Mr.
Maulden $8,359; Mr. McInvale $2,775; Mr. Randall $810.
(3) 1994 employer contributions to the System Savings Plan
as follows: Mr. Bemis $4,500; Mr. Blount $3,455; Mr. Hintz
$4,500; Mr. Jackson $4,500; Mr. Lupberger $4,500; Mr.
Maulden $4,500; Mr. McInvale $4,500; Mr. Randall $4,500.
(4) 1994 reimbursements under the Executive Financial
Counseling Program as follows: Mr. Bemis $2,725; Mr.
Hintz $785; Mr. Jackson $1,175; Mr. Lupberger $2,623; Mr.
Maulden $1,350; Mr. McInvale $645.
(5) 1994 payments for personal use under the Private
Ownership Vehicle Plan as follows: Mr. Bemis $9,900; Mr.
Blount $7,200; Mr. Hintz $10,800; Mr. Jackson $10,800; Mr.
Lupberger $4,627; Mr. Maulden $9,720; Mr. McInvale $9,900;
Mr. Randall $7,200.
(d) Restricted stock awarded under the Equity Ownership Plan is
subject to performance based criteria. Restricted stock awards
in 1994 are reported under the "Long-Term Incentive Plan Awards"
table, and reference is made to this table for information on the
aggregate number of restricted shares awarded during 1994 and the
vesting schedule for such shares. At December 31, 1994, the
number and value of the aggregate restricted stock holdings were
as follows: Mr. Bemis: 12,750 shares, $278,907; Mr. Hintz: 17,568
shares, $384,300; Mr. Jackson: 18,000 shares, $393,750; Mr.
Lupberger: 33,950 shares, $742,657; Mr. Maulden: 18,000 shares,
$393,750; and Mr. McInvale: 12,750 shares, $278,907. Accumulated
dividends are paid on restricted stock when vested. The value of
stock for which restrictions were lifted in 1994, and the
applicable portion of accumulated cash dividends, are reported in
the LTIP Payouts column in the above table. The value of
restricted stock awards as of December 31, 1994 are determined by
multiplying the total number of shares awarded by the closing
market price of Entergy Corporation common stock on the New York
Stock Exchange Composite Transactions on December 31, 1994
($21.875 per share).
Option Grants in 1994
The following table summarizes option grants during 1994 to the
executive officers named in the Summary Compensation Table above. The
absence, in the table below, of any named officer indicates that no
options were granted to such officer.
AP&L, GSU, LP&L, MP&L, NOPSI, and System Entergy
Individual Grants Potential Realizable
% of Total Value
Number of Options at Assumed Annual
Securities Granted to Exercise Rates of Stock
Underlying Employees Price Price Appreciation
Options in (per Expiration for Option Term(b)
Name Granted(a) 1994 share)(a) Date 5% 10%
Michael B. Bemis 2,500 3.7% $37.00 01/27/04 $ 58,173 $147,421
Donald C. Hintz 5,000 7.4% 37.00 01/27/04 116,346 294,842
Jerry D. Jackson 5,000 7.4% 37.00 01/27/04 116,346 294,842
Edwin Lupberger 10,000 14.8% 37.00 01/27/04 232,691 589,685
Jerry L. Maulden 5,000 7.4% 37.00 01/27/04 116,346 294,842
Gerald D. McInvale 2,500 3.7% 37.00 01/27/04 58,173 147,421
(a) Options were granted on January 27, 1994, pursuant to the Equity
Ownership Plan. All options granted on this date have an exercise
price equal to the closing price of Entergy Corporation common
stock on the New York Stock Exchange Composite Transactions on
January 27, 1994. These options became exercisable on
July 28, 1994.
(b) Calculation based on the stock option exercise price over a
ten-year period assuming annual compounding. The columns present
estimates of potential values based on simple mathematical
assumptions. The actual value, if any, an executive officer may
realize is dependent upon the market price on the date of option
exercise.
Long-Term Incentive Plan Awards in 1994
AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy
The following table summarizes awards of restricted shares of
Entergy Corporation common stock under the Equity Ownership Plan in
1994 to the executive officers of these companies named in the Summary
Compensation Table above. The absence, in the table below, of any
named officer indicates that no restricted shares were awarded to such
officer in 1994.
Estimated Future Payouts Under
Performance Non-Stock Price-Based Plans(a) (b)
Number Period Until
of Maturation
Name Shares or Payout Threshold Target Maximum
Michael B. Bemis 11,250 01/01/94-12/31/96 3,750 7,500 11,250
Donald C. Hintz 15,000 01/01/94-12/31/96 5,000 10,000 15,000
Jerry D. Jackson 15,000 01/01/94-12/31/96 5,000 10,000 15,000
Edwin Lupberger 25,200 01/01/94-12/31/96 8,400 16,800 25,200
Jerry L. Maulden 15,000 01/01/94-12/31/96 5,000 10,000 15,000
Gerald D. McInvale 11,250 01/01/94-12/31/96 3,750 7,500 11,250
(a) Restricted shares awarded will vest at the end of a three-year
period, subject to the attainment of approved performance goals
for the participants. Restrictions are lifted based upon the
achievement of the cumulative result of these goals for the
performance period. The value an executive officer may realize
is dependent upon both the number of shares that vest and the
future market price of Entergy Corporation common stock.
(b) The Threshold, Target and Maximum levels correspond to the
achievement of 50%, 100%, and 150%, respectively, of Equity
Ownership Plan goals. Achievement of a Threshold, Target or
Maximum level would result in the award of the number of shares
indicated in the respective column. Achievement of a level
between these three specified levels would result in the award of
a number of shares calculated by means of interpolation.
Pension Plan Tables
AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy
Retirement Income Plan Table
Annual
Covered Years of Service
Compensation 15 20 25 30 35
$100,000 $ 22,500 $ 30,000 $ 37,500 $ 45,000 $ 52,000
200,000 45,500 60,000 75,000 90,000 105,000
300,000 67,500 90,000 112,500 135,000 157,500
400,000 90,000 120,000 150,000 180,000 210,000
500,000 112,500 150,000 187,500 225,000 262,500
850,000 191,250 255,000 318,750 382,500 446,250
AP&L, GSU (non-bargaining unit employees), LP&L, MP&L, and System
Energy each individually sponsors or participates in a Retirement
Income Plan (a defined benefit plan) that provides a benefit for
employees at retirement from the System based upon (1) generally all
years of service beginning at age 21 through termination, with a
forty-year maximum, times (2) 1.5% for each year of service, times (3)
the final average compensation. Final average compensation is based on
the highest 60 months of covered compensation in the last 120 months
of service. The normal form of benefit for a single employee is a
lifetime annuity and for a married employee is a 50% joint and
survivor annuity. Other actuarially equivalent options are available
to each retiree. Retirement benefits are not subject to any deduction
for Social Security or other offset amounts. NOPSI is a participating
employer in LP&L's Retirement Income Plan. System Energy is a
participating employer in the Retirement Income Plan sponsored by
Entergy Corporation. Prior to October 1, 1994, GSU sponsored a
defined benefit pension plan for non-bargaining unit employees with
different provisions from the other System Companies. However,
effective October 1, 1994, GSU amended this plan for non-bargaining
unit employees to be consistent with the other System companies.
Bargaining unit employees for GSU are covered by the provisions of the
pre-merger GSU defined benefit plan. The amount of the named executive
officers' annual compensation covered by the plan as of December 31,
1994 is represented by the base salary column in the Summary
Compensation Table of AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy.
The maximum benefit under each Retirement Income Plan is limited
by Sections 401 and 415 of the Internal Revenue Code; however, AP&L,
GSU, LP&L, MP&L, NOPSI, and System Energy have elected to participate
in the Pension Equalization Plan sponsored by Entergy Corporation.
Under this plan, certain executives, including the named executive
officers, would receive an amount equal to the benefit payable under
the Retirement Income Plans, without regard to the limitations, less
the amount actually payable under the Retirement Income Plans.
Each Retirement Income Plan (except GSU) was amended effective
February 1, 1991 to provide a minimum accrued benefit as of that date
to any employee who was vested as of that date. For purposes of
calculating such minimum accrued benefit, each eligible employee was
deemed to have had an additional five years of service and age as of
that date. The additional years of age did not count toward
eligibility for early retirement, but served only to reduce the early
retirement discount factor for those employees who were at least age
50 as of that date. Effective January 1, 1995, the System companies
Retirement Income Plans were amended to transfer assets and related
liabilities to a single Entergy Corporation Retirement Plan for all
non-bargaining unit employees.
The credited years of service under the Retirement Income Plan
(without giving effect to the five additional years of service
credited pursuant to the February 1, 1991 amendment as discussed
above) as of December 31, 1994 for the following executive officers
named in the Summary Compensation Table of AP&L, GSU, LP&L, MP&L,
NOPSI, and System Energy were: Mr. Bemis 12; Mr. Blount 10;
Mr. Maulden 29; and Mr. Randall 15.
The credited years of service under the respective Retirement
Income Plans, as amended, as of December 31, 1994 for the following
executive officers named in the Summary Compensation Table, as a
result of entering into supplemental retirement agreements, were as
follows: Mr. Hintz 23; Mr. Jackson 15; Mr. Lupberger 31; and
Mr. McInvale 22.
In addition to the Retirement Income Plan discussed above, AP&L,
LP&L, MP&L, NOPSI, and System Energy participate in the Supplemental
Retirement Plan of Entergy Corporation and Subsidiaries (SRP) and the
Post-Retirement Plan of Entergy Corporation and Subsidiaries (PRP).
Participation is limited to one of these two plans and is at the
invitation of AP&L, LP&L, MP&L, NOPSI, and System Energy. The
participant may receive from the appropriate System company a monthly
benefit payment not in excess of .025 (under the SRP) or .0333 (under
the PRP) times the participant's average basic annual salary (as
defined in the plans) for a maximum of 120 months. Mr. Hintz has
entered into a SRP participation contract, and all of the other
executive officers of AP&L, LP&L, MP&L, NOPSI, and System Energy named
in the Summary Compensation Table (except for Mr. Blount and
Mr. McInvale) have entered into PRP participation contracts.
System Executive Retirement Plan Table (1)
Annual
Covered Years of Service
Compensation 15 20 25 30+
$ 200,000 $ 90,000 $100,000 $110,000 $120,000
300,000 135,000 150,000 165,000 180,000
400,000 180,000 200,000 220,000 240,000
500,000 225,000 250,000 275,000 300,000
600,000 270,000 300,000 330,000 360,000
700,000 315,000 350,000 385,000 420,000
1,000,000 450,000 500,000 550,000 600,000
___________
(1) Benefits shown are based on a target replacement ratio of 50%
based on the years of service and covered compensation shown. The
benefits for 10, 15, and 20 or more years of service at the 45% and
55% replacement levels would decrease (in the case of 45%) or increase
(in the case of 55%) by the following percentages: 3.0%, 4.5%, and
5.0%, respectively.
In 1993, Entergy Corporation adopted the System Executive
Retirement Plan (SERP). AP&L, GSU, LP&L, MP&L, NOPSI, and System
Energy are participating employers in the SERP. The SERP is an
unfunded defined benefit plan offered at retirement to certain senior
executives, which would currently include all the executive officers
(except for Mr. Blount) named in the Summary Compensation Table of
AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy. Participating
executives choose, at retirement, between the retirement benefits paid
under provisions of the SERP or those payable under the executive
retirement benefit plans discussed above. Covered pay under the SERP
includes final annual base salary (see the Summary Compensation Table
of AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy for the base salary
covered by the SERP as of December 31, 1994) plus the Target Incentive
Award (i.e., a percentage of final annual base salary) for the
participant in effect at retirement. Benefits paid under the SERP are
calculated by multiplying the covered pay times target pay replacement
ratios (45%, 50%, or 55%, dependent on job rating at retirement) that
are attained, according to plan design, at 20 years of credited
service. The target ratios are increased by 1% for each year of
service over 20 years, up to a maximum of 30 years of service. In
accordance with the SERP formula, the target ratios are reduced for
each year of service below 20 years. The credited years of service
under this plan are identical to the years of service for named
executive officers (other than Mr. Bemis, Mr. Jackson and Mr.
McInvale) disclosed above in the "Pension Plan Tables-Retirement
Income Plan Table" section. Mr. Bemis, Mr. Jackson and Mr. McInvale
have 22 years, 21 years and 13 years, respectively, of credited
service under this plan.
The normal form of benefit for a single employee is a lifetime
annuity and for a married employee is a 50% joint and survivor
annuity. All SERP payments are guaranteed for ten years. Other
actuarially equivalent options are available to each retiree. SERP
benefits are offset by any and all defined benefit plan payments from
the company and from prior employers. SERP benefits are not subject
to Social Security offsets.
Eligibility for and receipt of benefits under any of the
executive plans described above are contingent upon several factors.
The participant must agree that, without the specific consent of the
System company for which such participant was last employed, he may
take no employment after retirement with any entity that is in
competition with, or similar in nature to, AP&L, GSU, LP&L, MP&L,
NOPSI, and System Energy or any affiliate thereof. Eligibility for
benefits is forfeitable for various reasons, including violation of an
agreement with AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy,
resignation of employment, or termination for cause.
In addition to the non-bargaining unit employees Retirement
Income Plan discussed above, GSU provides, among other benefits to
officers, an Executive Income Security Plan for key managerial
personnel. The plan provides participants with certain retirement,
disability, termination, and survivors' benefits. To the extent that
such benefits are not funded by the employee benefit plans of GSU or
by vested benefits payable by the participants' former employers, GSU
is obligated to make supplemental payments to participants or their
survivors. The plan provides that upon the death or disability of a
participant during his employment, he or his designated survivors will
receive (i) during the first year following his death or disability an
amount not to exceed his annual base salary, and (ii) thereafter for a
number of years until the participant attains or would have attained
age 65, but not less than nine years, an amount equal to one-half of
the participant's annual base salary. The plan also provides
supplemental retirement benefits for life for participants retiring
after reaching age 65 equal to 1/2 of the participant's average final
compensation rate, with 1/2 of such benefit upon the death of the
participant being payable to a surviving spouse for life.
GSU amended and restated the plan effective March 1, 1991, to
provide such benefits for life upon termination of employment of a
participating officer or key managerial employee without cause (as
defined in the plan) or if the participant separates from employment
for good reason (as defined in the plan), with 1/2 of such benefits to
be payable to a surviving spouse for life. Further, the plan was
amended to provide medical benefits for a participant and his family
when the participant separates from service. These medical benefits
generally continue until the participant is eligible to receive
medical benefits from a subsequent employer; but in the case of a
participant who is over 50 at the time of separation and was
participating in the plan on March 1, 1991, medical benefits continue
for life. By virtue of the 1991 amendment and restatement, benefits
for a participant cannot be modified once he becomes eligible to
participate in the plan.
Compensation of Directors
AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy currently have no
non-employee directors, and each current director is not compensated
for his responsibilities as director. However, for the period January
1, 1994 through May 5, 1994, AP&L, GSU, LP&L, MP&L, and NOPSI did have
non-employee directors. These directors were paid an attendance fee
of $1,000 for attendance at meetings of their respective Board of
Directors, $1,000 (except for the chairman of such committee who was
paid $1,500) for attendance at meetings of committees of the Board and
$1,000 for participation, on behalf of their respective company, in
any inspection trip or conference not held on the same day as a Board
or committee meeting. All non-employee directors were also
compensated on a quarterly basis in the form of fixed awards of
Entergy Corporation common stock pursuant to the Stock Plan for
Outside Directors (Directors Plan) and cash based on 1/2 the value of
the stock awarded pursuant to the Directors Plan. This level of
directors' compensation was set to enable Entergy System companies to
attract and retain persons of outstanding competence to serve on the
Boards of Directors. Directors were paid a portion of their
compensation in the form of Entergy Corporation's common stock in
order to assure that directors would have a personal interest in the
performance of the stock of Entergy Corporation. Non-employee
directors were awarded 50 shares of Entergy Corporation common stock
quarterly, which may have been authorized but unissued shares or
shares acquired in the open market. Effective May 6, 1994, all non-
employee directors of AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy
became advisory directors of the respective Company.
Retired non-employee directors of AP&L, LP&L, MP&L, and NOPSI
with a minimum of five years of service on the respective Boards of
Directors are paid $200 a month for a term corresponding to the number
of years of service. Retired directors with over ten years of service
receive a lifetime benefit of $200 a month. Years of service as an
advisory director are included in calculating this benefit. System
Energy has no retired non-employee directors.
Retired non-employee directors of GSU receive retirement benefits
under a plan in which all directors who served continuously for a
period of years will receive a percentage of their retainer fee in
effect at the time of their retirement for life. The retirement
benefit is 30 percent of the retainer fee for service of not less than
five nor more than nine years, 40 percent for service of not less than
ten nor more than fourteen years, and 50 percent for fifteen or more
years of service. For those directors who retired prior to the
retirement age, their benefits will be reduced. The plan also
provides disability retirement and optional hospital and medical
coverage if the director has served at least five years prior to the
disability. The retired director pays one-third of the premium for
such optional hospital and medical coverage and GSU pays the remaining
two-thirds. Years of service as an advisory director are included in
calculating these benefits.
Employment Contracts and Termination of Employment and Change-in-
Control Arrangements
GSU
GSU established on January 18, 1991, an Executive Continuity Plan
for elected and appointed officers providing for severance benefits
equal to 2.99 times the officer's annual compensation upon termination
of employment for reasons other than cause or upon a resignation of
employment for good reason within two years after a change in control
of GSU. Benefits are prorated if the officer is within three years of
normal retirement age (65) at termination of employment. The plan
further provides for continued participation in medical, dental and
life insurance programs for three years following termination unless
such benefits are available from a subsequent employer. The plan
provides for outplacement assistance to aid a terminated officer in
securing another position. Upon consummation of the Entergy/GSU
merger on December 31, 1993, GSU made a one time contribution of
$16,330,693 to a trust equivalent to the then present value of the
maximum benefits which might be payable under the plan. As of
December 31, 1994, the balance in the trust had been reduced to
$8,102,203. If and to the extent outstanding benefits are not paid
to the participants, the balance in the trust will be returned to GSU.
As a result of the Entergy/GSU merger, GSU is obligated to pay
benefits under the Executive Income Security Plan to those persons who
were participants at the time of the merger and who later terminated
their employment under circumstances described in the plan. For
additional description of the benefits under the Executive Income
Security Plan, see the "Pension Plan Tables-System Executive
Retirement Plan Table" section noted above.
Personnel Committee Interlocks and Insider Participation
The following persons served as members of the Personnel
Committee of AP&L's, GSU's, LP&L's, MP&L's, and NOPSI's Board of
Directors through May 5, 1994:
AP&L - John A. Cooper, Jr.*, Edwin Lupberger, Roy L. Murphy,
Woodson D. Walker
GSU - Monroe J. Rathbone, Jr., M.D., Sam F. Segnar*, Bismark A.
Steinhagen
LP&L - Tex. R. Kilpatrick*, Edwin Lupberger, Wm. Clifford Smith
MP&L - Norman B. Gillis, Robert E. Kennington, II*, Edwin
Lupberger, Robert M. Williams, Jr.
NOPSI - Edwin Lupberger, Anne M. Milling, John B. Smallpage*
______________
* Denotes Chairman of the Personnel Committee
System Energy does not have a Personnel Committee of the Board of
Directors. The compensation of System Energy's executive officers
(with the exception of one officer) was set by the Personnel Committee
of Entergy Corporation's Board of Directors for 1994. After May 5,
1994, the compensation of AP&L, GSU, LP&L, MP&L, and NOPSI executive
officers was set by the Personnel Committee of Entergy Corporation's
Board of Directors due to the elimination of the Personnel Committees
of these companies. No officers or employees of such companies
participated in deliberations concerning compensation during 1994.
The Personnel Committee of Entergy Corporation's Board of Directors is
set forth under the heading "Report of Personnel Committee on
Executive Compensation" contained in the Proxy Statement of Entergy
Corporation to be filed in connection with its Annual Meeting of
Stockholders to be held May 26, 1995, and is incorporated herein by
reference.
Mr. Lupberger is currently and was during 1994 an officer of
AP&L, LP&L, MP&L, and NOPSI and also served as an executive officer of
their subsidiary, System Fuels, from 1981 - 1990.
Item 12. Security Ownership of Certain Beneficial Owners and
Management
Entergy Corporation owns 100% of the outstanding common stock of
registrants AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy. The
information with respect to persons known by Entergy Corporation to be
beneficial owners of more than 5% of Entergy Corporation's common
stock is included under the heading "Voting Securities Outstanding" in
the Proxy Statement of Entergy Corporation to be filed in connection
with its Annual Meeting of Stockholders to be held May 26, 1995, which
information is incorporated herein by reference. The registrants know
of no contractual arrangements that may, at a subsequent date, result
in a change in control of any of the registrants.
The directors, the executive officers named in the Summary
Compensation Tables, and the directors and officers as a group for
Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy,
respectively, beneficially owned directly or indirectly the following
cumulative preferred stock of a System company and common stock of
Entergy Corporation:
As of December 31, 1994
Entergy Corporation
Common Stock
Preferred Stock Amount and Nature
Amount and Nature of of Beneficial
Beneficial Ownership(b) Ownership(b)
Sole Voting Sole Voting Other
and Other and Beneficial
Investment Beneficial Investment Ownership
Name Power(c) Ownership Power(c) (d)(e)(f)(g)
Entergy Corporation
W. Frank Blount* - - 2,934 -
John A. Cooper, Jr.* 6,000 (a) - 5,734 -
Lucie J. Fjeldstad* - - 1,984 -
Dr. Norman C. Francis* - - 500 -
Donald C. Hintz** - - 7,493 32,027
Kaneaster Hodges, Jr.* - - 2,800 -
Jerry D. Jackson** - - 6,402 35,216
Robert v.d. Luft* - - 2,184 -
Edwin Lupberger** - - 8,706 73,687(h)(i)
Jerry L. Maulden** - - 37,420 44,048
Gerald D. McInvale** - - 3,173 20,908
Adm. Kinnaird R. McKee* - - 2,900 -
Paul W. Murrill* - - 2,180 -
James R. Nichols* - - 3,315 -
Eugene H. Owen* - 3,500 (a) 1,692 -
John N. Palmer, Sr.* - - 13,196 -
Robert D. Pugh* - - 5,300 10,000(i)
H. Duke Shackelford* - - 8,750 4,950(i)
Wm. Clifford Smith* - - 3,775 -
Bismark A. Steinhagen* - - 6,437 -
All directors and
executive officers 6,000 3,500 135,419 266,320
AP&L
Michael B. Bemis** - - 7,488 25,540
Donald C. Hintz** - - 7,493 32,027
Jerry D. Jackson** - - 6,402 35,216
R. Drake Keith*** - - 2,891 13,260
Edwin Lupberger** - - 8,706 73,687(h)(i)
Jerry L. Maulden** - - 37,420 44,048
All directors and
executive officers - - 90,631 334,762
GSU
Michael B. Bemis** - - 7,488 25,540
Frank F. Gallaher*** - - 3,725 24,696(j)
Donald C. Hintz** - - 7,493 32,027
Jerry D. Jackson** - - 6,402 35,216
Edwin Lupberger** - - 8,706 73,687(h)(i)
Jerry L. Maulden** - - 37,420 44,048
All directors and
executive officers - - 82,755 313,558
LP&L
Michael B. Bemis** - - 7,488 25,540
John J. Cordaro*** - - 1,747 9,877
Donald C. Hintz** - - 7,493 32,027
Jerry D. Jackson** - - 6,402 35,216
Edwin Lupberger** - - 8,706 73,687(h)(i)
Jerry L. Maulden** - - 37,420 44,048
All directors and
executive officers - - 86,348 335,037
MP&L
Michael B. Bemis** - - 7,488 25,540
Donald C. Hintz* - - 7,493 32,027
Jerry D. Jackson** - - 6,402 35,216
Edwin Lupberger** - - 8,706 73,687(h)(i)
Jerry L. Maulden** - - 37,420 44,048
Gerald D. McInvale** - - 3,173 20,908
Donald E. Meiners*** - - 1,382 15,033(j)
All directors and
executive officers - - 83,958 330,524
NOPSI
Michael B. Bemis** - - 7,488 25,540
John J. Cordaro*** - - 1,747 9,877
Jerry D. Jackson** - - 6,402 35,216
Edwin Lupberger** - - 8,706 73,687(h)(i)
Jerry L. Maulden** - - 37,420 44,048
Gerald D. McInvale** - - 3,173 20,908
All directors and
executive officers - - 78,751 294,663
System Energy
Joseph L. Blount** - - 834 2,287
Donald C. Hintz** - - 7,493 32,027
Jerry D. Jackson* - - 6,402 35,216
Edwin Lupberger** - - 8,706 73,687(h)(i)
Jerry L. Maulden* - - 37,420 44,048
Gerald D. McInvale** - - 3,173 20,908
Lee W. Randall** - - - 4,561
All directors and
executive officers - - 64,028 212,734
* Director of the respective Company
** Named Executive Officer of the respective Company
*** Officer and Director of the respective Company
(a) Stock ownership amounts refer to 6,000 shares of AP&L's $0.01 Par
Value ($25 liquidation value) Preferred Stock held by the John
A. Cooper Trust, and 3,500 shares of AP&L's $0.01 Par Value ($25
liquidation value) Preferred Stock held by Eugene H. Owen. Mr.
Cooper disclaims any personal interest in these shares.
(b) Based on information furnished by the respective individuals.
The ownership amounts shown for each individual and for all
directors and executive officers as a group do not exceed one
percent of the outstanding securities of any class of security so
owned.
(c) Includes all shares that the individual has the sole power to
vote and dispose of, or to direct the voting and disposition of.
(d) Includes, for the named persons, shares of Entergy Corporation
common stock held in the Employee Stock Ownership Plan of the
registrants as follows: Michael B. Bemis, 714 shares; Joseph L.
Blount, 753 shares; John J. Cordaro, 1,007 shares; Frank F.
Gallaher, 941 shares; Donald C. Hintz, 753 shares; Jerry D.
Jackson, 753 shares; R. Drake Keith, 753 shares; Edwin Lupberger,
825 shares; Jerry L. Maulden, 796 shares; Gerald D. McInvale,
110 shares; Donald E. Meiners, 553 shares; and Lee W. Randall,
791 shares.
(e) Includes, for the named persons, shares of Entergy Corporation
common stock held in the System Savings Plan company account as
follows: Michael B. Bemis, 4,576 shares; Joseph L. Blount, 1,534
shares; John J. Cordaro, 1,670 shares; Frank F. Gallaher, 3,455
shares; Donald C. Hintz, 1,206 shares; Jerry D. Jackson, 2,052
shares; R. Drake Keith, 3,833 shares; Edwin Lupberger, 6,088
shares; Jerry L. Maulden, 10,252 shares; Gerald D. McInvale, 548
shares; Donald E. Meiners, 4,404 shares; and Lee W. Randall,
3,770 shares.
(f) Includes, for the named persons, unvested restricted shares of
Entergy Corporation common stock held in the Equity Ownership
Plan as follows: Michael B. Bemis, 12,750 shares; John J.
Cordaro, 2,200 shares; Frank F. Gallaher, 14,800 shares; Donald
C. Hintz, 17,568 shares; Jerry D. Jackson, 18,000 shares; R.
Drake Keith, 1,500 shares; Edwin Lupberger, 33,950 shares; Jerry
L. Maulden, 18,000 shares; Gerald D. McInvale, 12,750 shares; and
Donald E. Meiners, 1,500 shares.
(g) Includes, for the named persons, shares of Entergy Corporation
common stock in the form of unexercised stock options awarded
pursuant to the Equity Ownership Plan as follows: Michael B.
Bemis, 7,500 shares; John J. Cordaro 5,000 shares; Frank F.
Gallaher, 5,000 shares; Donald C. Hintz, 12,500 shares; Jerry D.
Jackson, 14,411 shares; R. Drake Keith, 7,174 shares; Edwin
Lupberger, 28,824 shares; Jerry L. Maulden, 15,000 shares; Gerald
D. McInvale, 7,500 shares; and Donald E. Meiners, 7,500 shares.
(h) Includes 1,500 shares of Entergy Corporation common stock held
jointly between Edwin Lupberger and Ms. E. H. Lupberger.
(i) Includes, for the named persons, shares of Entergy Corporation
common stock held by their spouses. The named persons disclaim
any personal interest in these shares as follows: Edwin
Lupberger, 2,500 shares; Robert D. Pugh, 10,000 shares; and H.
Duke Shackleford, 4,950 shares.
(j) Includes, for the named persons, shares of Entergy Corporation
common stock held jointly with their spouses as follows: Frank
F. Gallaher, 500 shares; and Don E. Meiners, 1,076 shares.
Item 13. Certain Relationships and Related Transactions
Information called for by this item concerning the directors and
officers of Entergy Corporation is set forth under the heading
"Certain Transactions" in the Proxy Statement of Entergy Corporation
to be filed in connection with its Annual Meeting of Stockholders to
be held on May 26, 1995, which information is incorporated herein by
reference.
See Item 11, "Executive Compensation - Personnel Committee
Interlocks and Insider Participation" for information on certain
transactions required to be reported under this item.
Other than as provided under applicable corporate laws, the
System companies do not have policies whereby transactions involving
executive officers and directors of the System are approved by a
majority of disinterested directors. However, pursuant to the Entergy
Corporation Code of Conduct, transactions involving a System company
and its executive officers must have prior approval by the next higher
reporting level of that individual, and transactions involving a
System company and its directors must be reported to the secretary of
the appropriate System company.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a)1. Financial Statements and Independent Auditors' Reports for
Entergy, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy are
listed in the Index to Financial Statements (see pages 56 and 57)
(a)2. Financial Statement Schedules
Reports of Independent Accountants on Financial Statement
Schedules (see pages 385 and 386)
Financial Statement Schedules are listed in the Index to
Financial Statement Schedules (see page S-1)
(a)3. Exhibits
Exhibits for Entergy, AP&L, GSU, LP&L, MP&L, NOPSI, and System
Energy are listed in the Exhibit Index (see page E-1). Each
management contract or compensatory plan or arrangement
required to be filed as an exhibit hereto is identified as such
by footnote in the Exhibit Index.
(b) Reports on Form 8-K
Entergy and GSU
A current report on Form 8-K, dated October 21, 1994, was filed
with the SEC on October 28, 1994, reporting information under
Item 5 "Other Materially Important Events".
A current report on Form 8-K, dated December 14, 1994, was
filed with the SEC on December 16, 1994, reporting information
under Item 5 "Other Materially Important Events".
A current report on Form 8-K, dated December 21, 1994, was
filed with the SEC on December 22, 1994, reporting information
under Item 5 "Other Materially Important Events".
Entergy, GSU, LP&L and NOPSI
A current report on Form 8-K, dated December 9, 1994, was filed
with the SEC on December 9, 1994, reporting information under
Items 4 and 7.
Entergy and NOPSI
A current report on Form 8-K, dated December 9, 1994, was filed
with the SEC on January 9, 1995, reporting information under
Item 5 "Other Materially Important Events".
EXPERTS
All statements in Part I of this Annual Report on Form 10-K as to
matters of law and legal conclusions, based on the belief or opinion
of System Energy or any System operating company or otherwise,
pertaining to the titles to properties, franchises and other operating
rights of certain of the registrants filing this Annual Report on Form
10-K, and their subsidiaries, the regulations to which they are
subject and any legal proceedings to which they are parties are made
on the authority of Friday, Eldredge & Clark, 2000 First Commercial
Building, 400 West Capitol, Little Rock, Arkansas, as to AP&L and as
to Entergy Services in regards to flood litigation; Monroe & Lemann (A
Professional Corporation), 201 St. Charles Avenue, Suite 3300, New
Orleans, Louisiana, as to LP&L and NOPSI; and Wise Carter Child &
Caraway, Professional Association, Heritage Building, Jackson,
Mississippi, as to MP&L and System Energy.
The statements attributed to Clark, Thomas & Winters, a
professional corporation, as to legal conclusions with respect to
GSU's rate regulation in Texas under Item 1. "Rate Matters and
Regulation - Rate Matters - Retail Rate Matters - GSU" and in Note 2
to Entergy Corporation and Subsidiaries Consolidated Financial
Statements and GSU's Financial Statements, "Rate and Regulatory
Matters," have been reviewed by such firm and are included herein upon
the authority of such firm as experts.
The statements attributed to Sandlin Associates regarding the
analysis of River Bend Construction costs of GSU under Item 1. "Rate
Matters and Regulation - Rate Matters - Retail Rate Matters - GSU" and
in Note 2 to Entergy Corporation and Subsidiaries Consolidated
Financial Statements and GSU's Financial Statements, "Rate and
Regulatory Matters," have been reviewed by such firm and are included
herein upon the authority of such firm as experts.
ENTERGY CORPORATION
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
ENTERGY CORPORATION
By LEE W. RANDALL
Lee W. Randall, Vice President
and Chief Accounting Officer
Date: March 27, 1995
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
LEE W. RANDALL
Lee W. Randall Vice President, Chief Accounting March 27, 1995
Officer and Assistant Secretary
(Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer and
Director; Principal Executive Officer); Gerald D. McInvale (Senior
Vice President and Chief Financial Officer; Principal Financial
Officer); W. Frank Blount, John A. Cooper, Jr., N. C. Francis, Lucie
J. Fjeldstad, Kaneaster Hodges, Jr., Robert v.d. Luft, Kinnaird R.
McKee, Paul W. Murrill, James R. Nichols, Eugene H. Owen, John N.
Palmer, Robert D. Pugh, H. Duke Shackelford, Wm. Clifford Smith, and
Bismark A. Steinhagen (Directors).
By: LEE W. RANDALL March 27, 1995
(Lee W. Randall, Attorney-in-fact)
ARKANSAS POWER & LIGHT COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
ARKANSAS POWER & LIGHT COMPANY
By LEE W. RANDALL
Lee W. Randall, Vice President,
Chief Accounting Officer, and
Assistant Secretary
Date: March 27, 1995
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
LEE W. RANDALL
Lee W. Randall Vice President, Chief Accounting March 27, 1995
Officer and Assistant Secretary
(Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer
and Director; Principal Executive Officer); Gerald D. McInvale
(Senior Vice President and Chief Financial Officer; Principal
Financial Officer); Michael B. Bemis, Donald C. Hintz, Jerry D.
Jackson, R. Drake Keith, and Jerry L. Maulden (Directors).
By: LEE W. RANDALL March 27, 1995
(Lee W. Randall, Attorney-in-fact)
GULF STATES UTILITIES COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
GULF STATES UTILITIES COMPANY
By LEE W. RANDALL
Lee W. Randall, Vice President,
Chief Accounting Officer and
Assistant Secretary
Date: March 27, 1995
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
LEE W. RANDALL
Lee W. Randall Vice President, Chief Accounting March 27, 1995
Officer and Assistant Secretary
(Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer
and Director; Principal Executive Officer); Gerald D. McInvale
(Senior Vice President and Chief Financial Officer; Principal
Financial Officer); Michael B. Bemis, Frank F. Gallaher, Donald
C. Hintz, Jerry D. Jackson, and Jerry L. Maulden (Directors).
By: LEE W. RANDALL March 27, 1995
(Lee W. Randall, Attorney-in-fact)
LOUISIANA POWER & LIGHT COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
LOUISIANA POWER & LIGHT COMPANY
By LEE W. RANDALL
Lee W. Randall, Vice President,
Chief Accounting Officer and
Assistant Secretary
Date: March 27, 1995
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
LEE W. RANDALL
Lee W. Randall Vice President, Chief Accounting March 27, 1995
Officer and Assistant Secretary
(Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer
and Director; Principal Executive Officer); Gerald D. McInvale
(Senior Vice President and Chief Financial Officer; Principal
Financial Officer); Michael B. Bemis, John J. Cordaro, Donald
C. Hintz, Jerry D. Jackson, and Jerry L. Maulden (Directors).
By: LEE W. RANDALL March 27, 1995
(Lee W. Randall, Attorney-in-fact)
MISSISSIPPI POWER & LIGHT COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
MISSISSIPPI POWER & LIGHT COMPANY
By LEE W. RANDALL
Lee W. Randall, Vice President,
Chief Accounting Officer and
Assistant Secretary
Date: March 27, 1995
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
LEE W. RANDALL
Lee W. Randall Vice President, Chief Accounting March 27, 1995
Officer and Assistant Secretary
(Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer
and Director; Principal Executive Officer); Gerald D. McInvale
(Senior Vice President and Chief Financial Officer; Principal
Financial Officer); Michael B. Bemis, Donald C. Hintz, Jerry D.
Jackson, Jerry L. Maulden, and Donald E. Meiners (Directors).
By: LEE W. RANDALL March 27, 1995
(Lee W. Randall, Attorney-in-fact)
NEW ORLEANS PUBLIC SERVICE INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
NEW ORLEANS PUBLIC SERVICE INC.
By LEE W. RANDALL
Lee W. Randall, Vice President,
Chief Accounting Officer and
Assiatant Secretary
Date: March 27, 1995
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
LEE W. RANDALL
Lee W. Randall Vice President, Chief Accounting March 27, 1995
Officer and Assistant Secretary
(Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer
and Director; Principal Executive Officer); Gerald D. McInvale
(Senior Vice President and Chief Financial Officer; Principal
Financial Officer); John J. Cordaro, Jerry D. Jackson, and Jerry
L. Maulden (Directors).
By: LEE W. RANDALL March 27, 1995
(Lee W. Randall, Attorney-in-fact)
SYSTEM ENERGY RESOURCES, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
SYSTEM ENERGY RESOURCES, INC.
By LEE W. RANDALL
Lee W. Randall, Vice President
and Chief Accounting Officer
Date: March 27, 1995
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
LEE W. RANDALL
Lee W. Randall Vice President and Chief March 27, 1995
Accounting Officer
(Principal Accounting Officer)
Donald C. Hintz (President, Chief Executive Officer and
Director; Principal Executive Officer); Gerald D.
McInvale (Senior Vice President and Chief Financial
Officer; Principal Financial Officer); Edwin Lupberger
(Chairman of the Board), Donald C. Hintz, Jerry D.
Jackson, and Jerry L. Maulden (Directors).
By: LEE W. RANDALL March 27, 1995
(Lee W. Randall, Attorney-in-fact)
EXHIBIT 23(a)
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in Post-Effective
Amendment Nos. 2, 3, 4A, and 5A on Form S-8 and the related
Prospectuses to registration statement of Entergy Corporation on Form
S-4 (File Number 33-54298), of our reports dated February 21, 1995,
except for the last paragraph of the section of Note 2 to the
consolidated financial statements subtitled "Filings with the PUCT and
Texas Cities" as to which the date is March 20, 1995, on our audit of
the consolidated financial statements and financial statement
schedules of Entergy Corporation as of and for the year ended December
31, 1994, which reports include explanatory paragraphs related to rate-
related contingencies and legal proceedings and are included in this
Annual Report on Form 10-K.
We consent to the incorporation by reference in the registration
statements and the related Prospectuses of Arkansas Power & Light
Company on Form S-3 (File Number 33-36149, 33-48356 and 33-50289) of
our reports dated February 21, 1995 on our audit of the financial
statements and financial statement schedules of Arkansas Power & Light
Company as of and for the year ended December 31, 1994 which are
included in this Annual Report on Form 10-K.
We consent to the incorporation by reference in registration
statements and the related Prospectuses of Gulf States Utilities
Company on Form S-3 (File Numbers 33-49739 and 33-51181) and Form S-8
(File Numbers 2-76551 and 2-98011) of our reports dated February 21,
1995, except for the last paragraph of the section of Note 2 to the
financial statements subtitled "Filings with the PUCT and Texas
Cities" as to which the date is March 20, 1995, on our audits of the
financial statements and financial statement schedules of Gulf States
Utilities Company as of December 31, 1994 and 1993 and for the three
years ended December 31, 1994, which reports include explanatory
paragraphs related to rate-related contingencies, legal proceedings
and changes in accounting for income taxes, postretirement benefits,
unbilled revenue and power plant materials and supplies and are
included in this Annual Report on Form 10-K.
We consent to the incorporation by reference in the registration
statements and the related Prospectuses of Louisiana Power & Light
Company on Form S-3 (File Numbers 33-46085, 33-39221 and 33-50937) of
our reports dated February 21, 1995 on our audit of the financial
statements and financial statement schedules of Louisiana Power &
Light Company as of and for the year ended December 31, 1994 which are
included in this Annual Report on Form 10-K.
We consent to the incorporation by reference in the registration
statements and the related Prospectuses of Mississippi Power & Light
Company on Form S-3 (File Numbers 33-53004, 33-55826 and 33-50507) of
our reports dated February 21, 1995 on our audit of the financial
statements and financial statement schedules of Mississippi Power &
Light Company as of and for the year ended December 31, 1994 which are
included in this Annual Report on Form 10-K.
We consent to the incorporation by reference in the registration
statement and the related Prospectus of New Orleans Public Service
Inc. on Form S-3 (File Number 33-57926) of our reports dated February
21, 1995 on our audit of the financial statements and financial
statement schedules of New Orleans Public Service Inc. as of and for
the year ended December 31, 1994 which are included in this Annual
Report on Form 10-K.
We consent to the incorporation by reference in the registration
statement and the related Prospectus of System Energy Resources, Inc.
on Form S-3 (File Number 33-47662) of our reports dated February 21,
1995 on our audit of the financial statements and financial statement
schedules of System Energy Resources, Inc. as of and for the year
ended December 31, 1994 which are included in this Annual Report on
Form 10-K.
/s/ Coopers & Lybrand L.L.P.
COOPERS & LYBRAND L.L.P.
New Orleans, Louisiana
March 24, 1995
EXHIBIT 23(b)
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Post-Effective
Amendment Nos. 2, 3, 4A, and 5A on Form S-8 to Registration Statement
No. 33-54298 of Entergy Corporation on Form S-4, and the related
Prospectuses, of our reports dated February 11, 1994 (which express an
unqualified opinion and include explanatory paragraphs as to
uncertainties because of certain regulatory and litigation matters),
appearing in this Annual Report on Form 10-K of Entergy Corporation.
We also consent to the incorporation by reference in Registration
Statements Nos. 33-36149, 33-48356 and 33-50289 of Arkansas Power &
Light Company on Form S-3, and the related Prospectuses, of our
reports dated February 11, 1994, appearing in this Annual Report on
Form 10-K of Arkansas Power & Light Company.
We also consent to the incorporation by reference in Registration
Statements Nos. 33-46085, 33-39221 and 33-50937 of Louisiana Power &
Light Company on Form S-3, and the related Prospectuses, of our
reports dated February 11, 1994, appearing in this Annual Report on
Form 10-K of Louisiana Power & Light Company.
We also consent to the incorporation by reference in Registration
Statements Nos. 33-53004, 33-55826 and 33-50507 of Mississippi Power &
Light Company on Form S-3, and the related Prospectuses, of our
reports dated February 11, 1994, appearing in this Annual Report on
Form 10-K of Mississippi Power & Light Company.
We also consent to the incorporation by reference in Registration
Statement No. 33-57926 of New Orleans Public Service Inc. on Form S-3,
and the related Prospectus, of our reports dated February 11, 1994,
appearing in this Annual Report on Form 10-K of New Orleans Public
Service Inc.
We also consent to the incorporation by reference in Registration
Statement No. 33-47662 of System Energy Resources, Inc. on Form S-3,
and the related Prospectus, of our reports dated February 11, 1994
(November 30, 1994 as to Note 2, "Rate and Regulatory Matters - FERC
Settlement"), appearing in this Annual Report on Form 10-K of System
Energy Resources, Inc.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 27, 1995
EXHIBIT 23(c)
CONSENT OF EXPERTS
We consent to the reference to our firm under the heading
"Experts" in this Annual Report on Form 10-K. We further consent to
the incorporation by reference of such reference to our firm into
Arkansas Power & Light Company's ("AP&L") Registration Statements
(Form S-3, File Nos. 33-36149, 33-48356 and 33-50289) and related
Prospectuses, pertaining to AP&L's First Mortgage Bonds and Preferred
Stock.
Very truly yours,
/s/ Friday, Eldredge & Clark
FRIDAY, ELDREDGE & CLARK
Date: March 27, 1995
EXHIBIT 23(d)
CONSENT
We consent to the reference to our firm under the heading
"Experts", and to the inclusion in this Annual Report on Form 10-K of
Gulf States Utilities Company ("GSU") of the statements of legal
conclusions attributed to us herein (the Statements of Legal
Conclusions) under Part I, Item 1. Business - "Rate Matters and
Regulation" and in the discussion of Texas jurisdictional matters set
forth in Note 2 to GSU's Financial Statements and Note 2 to Entergy
Corporation and Subsidiaries Consolidated Financial Statements
appearing as Item 8. of Part II of this Form 10-K, which Statements of
Legal Conclusions have been prepared or reviewed by us (Clark, Thomas
& Winters, a Professional Corporation). We also consent to the
incorporation by reference in the registration statements of GSU on
Form S-3 and Form S-8 (File Numbers 2-76551, 2-98011, 33-49739, and
33-51181) of such reference and Statements of Legal Conclusions.]
/s/ Clark, Thomas & Winters
CLARK, THOMAS & WINTERS
A Professional Corporation
Austin, Texas
March 27, 1995
EXHIBIT 23(e)
CONSENT
We consent to the reference to our firm under the heading
"Experts" and to the inclusion in this Annual Report on Form 10-K of
Gulf States Utilities Company ("GSU") of the statements (Statements)
regarding the analysis by our Firm of River Bend construction costs
which are made herein under Part I, Item 1. Business - "Rate Matters
and Regulation" and in the discussion of Texas jurisdictional matters
set forth in Note 2 to GSU's Financial Statements and Note 2 to
Entergy Corporation and Subsidiaries' Consolidated Financial
Statements appearing as Item 8. of Part II of this Form 10-K, which
Statements have been prepared or reviewed by us (Sandlin Associates).
We also consent to the incorporation by reference in the registration
statements of GSU on Form S-3 and Form S-8 (File Numbers 2-76551, 2-
98011, 33-49739 and 33-51181) of such reference and Statements.
/s/ Sandlin Associates
SANDLIN ASSOCIATES
Management Consultants
Pasco, Washington
March 27, 1995
EXHIBIT 23(f)
CONSENT OF EXPERTS
We consent to the reference to our firm under the heading
"Experts" in this Annual Report on Form 10-K. We further consent to
the incorporation by reference of such reference to our firm into
Louisiana Power & Light Company's ("LP&L") Registration Statements
(Form S-3, File Nos. 33-46085, 33-39221 and 33-50937) and the related
Prospectuses, pertaining to LP&L's First Mortgage Bonds and Preferred
Stock, and into New Orleans Public Service Inc.'s ("NOPSI")
Registration Statement (Form S-3, File No. 33-57926) and the related
Prospectus pertaining to NOPSI's General and Refunding Mortgage Bonds.
Very truly yours,
/s/ Monroe & Lemann
MONROE & LEMANN
Date: March 27, 1995
EXHIBIT 23(g)
CONSENT OF EXPERTS
We consent to the reference to our firm under the heading
"Experts" in this Annual Report on Form 10-K. We further consent to
the incorporation by reference of such reference to our firm into
System Energy Resources, Inc.'s (System Energy) Registration Statement
on Form S-3 (File No. 33-47662) and the related prospectus pertaining
to System Energy's First Mortgage Bonds, and into Mississippi Power &
Light Company's ("MP&L") Registration Statements on Form S-3 (File
Nos. 33-53004, 33-55826 and 33-50507) and the related prospectuses
pertaining to MP&L's Preferred Stock and General and Refunding
Mortgage Bonds.
Very truly yours,
WISE CARTER CHILD & CARAWAY
Professional Association
By /s/ ROBERT B. MCGEHEE
Robert B. McGehee
Date: March 27, 1995
REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULES
To the Shareholders and the Board of Directors
of Entergy Corporation
We have audited the consolidated financial statements of Entergy
Corporation and Subsidiaries and the financial statements of Arkansas
Power & Light Company, Louisiana Power & Light Company, Mississippi
Power & Light Company, New Orleans Public Service Inc., and System
Energy Resources, Inc. as of and for the year ended December 31, 1994,
and the financial statements of Gulf States Utilities Company as of
December 31, 1994 and 1993, and for each of the three years in the
period ended December 31, 1994, and have issued our reports included
elsewhere in this Form 10-K, thereon dated February 21, 1995, except
for the last paragraph of the section of the Entergy Corporation and
Gulf States Utilities Company Note 2 subtitled "Filings with the PUCT
and Texas Cities", as to which the date is March 20, 1995, which
reports as to Entergy Corporation and Gulf States Utilities Company
include explanatory paragraphs related to rate-related contingencies
and legal proceedings, and which report as to Gulf States Utilities
Company includes an explanatory paragraph related to changes in
accounting for income taxes, postretirement benefits, unbilled revenue
and power plant materials and supplies. In connection with our audits
of such financial statements, we have also audited the related
financial statement schedules included in Item 14(a)2 of this Form 10-
K.
In our opinion the financial statement schedules referred to
above, when considered in relation to the basic financial statements
taken as a whole, present fairly in all material respects the
information required to be included therein.
/s/ Coopers & Lybrand L.L.P.
COOPERS & LYBRAND L.L.P.
New Orleans, Louisiana
February 21, 1995, except for the last paragraph
of "Filings with the PUCT and Texas Cities" in
Note 2, as to which the date is March 20, 1995
INDEPENDENT AUDITORS' REPORT ON FINANCIAL STATEMENT SCHEDULES
To the Shareholders and the Board of Directors
of Entergy Corporation
We have audited the consolidated financial statements of Entergy
Corporation and subsidiaries and the financial statements of Arkansas
Power & Light Company, Louisiana Power & Light Company, Mississippi
Power & Light Company, New Orleans Public Service Inc., and System
Energy Resources, Inc. as of December 31, 1993, and for each of the
two years in the period ended December 31, 1993, and have issued our
reports thereon dated February 11, 1994, which report as to Entergy
Corporation includes explanatory paragraphs as to uncertainties
because of certain regulatory and litigation matters, and which report
as to System Energy Resources, Inc. is dated November 30, 1994 as to
Note 2, "Rate and Regulatory Matters - FERC Settlement"; such reports
are included elsewhere in this Form 10-K. Our audits also included
the 1993 and 1992 financial statement schedules of these companies,
listed in Item 14(a)2. These financial statement schedules are the
responsibility of the companies' managements. Our responsibility is
to express an opinion based on our audits. We did not audit the
financial statements of Gulf States Utilities Company (a consolidated
subsidiary of Entergy Corporation acquired on December 31, 1993),
which statements reflect total assets constituting 31% of consolidated
total assets at December 31, 1993. Those statements were audited by
other auditors whose report (which included explanatory paragraphs
regarding uncertainties because of certain regulatory and litigation
matters) has been furnished to us, and our opinion, insofar as it
relates to the amounts included for Gulf States Utilities Company, is
based solely on the report of such other auditors. In our opinion,
based on our audits and the report of the other auditors, such
financial statement schedules, when considered in relation to the
basic financial statements taken as a whole, present fairly in all
material respects the information set forth therein.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 11, 1994
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page
I Financial Statements of Entergy Corporation:
Balance Sheets, December 31, 1994 and 1993 S-2
Statements of Cash Flows - For the Years Ended
December 31, 1994, 1993 and 1992 S-3
Statements of Income - For the Years Ended
December 31, 1994, 1993 and 1992 S-4
Statements of Retained Earnings and Paid-In
Capital - For the Years Ended
December 31, 1994, 1993 and 1992 S-5
II Valuation and Qualifying Accounts
1994, 1993 and 1992:
Entergy Corporation and Subsidiaries S-6
Arkansas Power & Light Company S-7
Gulf States Utilities Company S-8
Louisiana Power & Light Company S-9
Mississippi Power & Light Company S-10
New Orleans Public Service Inc. S-11
Schedules other than those listed above are omitted because they
are not required, not applicable or the required information is shown
in the financial statements or notes thereto.
Columns have been omitted from schedules filed because the
information is not applicable.
ENTERGY CORPORATION
SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
BALANCE SHEETS
December 31,
1994 1993
(In Thousands)
ASSETS
Construction work in progress - $22,861
---------- ----------
Investment in Wholly-owned Subsidiaries $6,110,504 6,449,165
---------- ----------
Current Assets:
Cash equivalents:
Temporary cash investments - at cost,
which approximates market:
Associated companies 83,339 100,401
Other 169,369 52,150
---------- ----------
Total cash equivalents 252,708 152,551
Accounts receivable:
Associated companies 10,413 3,086
Other 375 2,467
Interest receivable 923 1,073
Other 6,901 1,166
---------- ----------
Total 271,320 160,343
---------- ----------
Deferred Debits 55,185 93,479
---------- ----------
TOTAL $6,437,009 $6,725,848
========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $.01 par value in 1994 and 1993:
authorized 500,000,000 shares; issued and
outstanding 230,017,485 shares in 1994 and
231,219,737 shares in 1993 $2,300 $2,312
Paid-in capital 4,202,134 4,223,682
Retained earnings 2,223,739 2,310,082
Less - treasury stock (2,608,908 shares in 1994) 77,378 -
---------- ----------
Total common shareholders' equity 6,350,795 6,536,076
---------- ----------
Current Liabilities:
Notes payable - 43,000
Accounts payable:
Associated companies 4,578 7,556
Other 1,102 10,069
Other current liabilities 5,021 1,849
---------- ----------
Total 10,701 62,474
---------- ----------
Deferred Credits and Noncurrent Liabilities 75,513 127,298
---------- ----------
Total $6,437,009 $6,725,848
========== ==========
See Entergy Corporation and Subsidiaries Notes to Consolidated Financial
Statements in Part II, Item 8.
ENTERGY CORPORATION
SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Operating Activities:
Net income $341,841 $551,930 $437,637
Noncash items included in net income:
Equity in earnings of subsidiaries (369,702) (557,681) (454,947)
Deferred income taxes 7,007 3,771 3,146
Depreciation 959
Changes in working capital:
Receivables (5,085) (1,082) 2,875
Payables (11,945) 1,367 (26,241)
Other working capital accounts (2,563) 531 16,034
Common stock dividends received from subsidiaries 763,400 686,700 487,854
Other (12,136) (20,938) (15,012)
-------- -------- --------
Net cash flow provided by operating activities 711,776 664,598 451,346
-------- -------- --------
Investing Activities:
Merger with GSU - cash paid - (250,000) -
Investment in subsidiaries (49,892) (86,221) (79,228)
Capital expenditures (3,178) (22,861) -
Decrease in other temporary investments - 17,012 114,651
Proceeds received from the sale of property 26,000 - -
Advance to subsidiary (11,840) (24,642) (12,005)
-------- -------- --------
Net cash flow provided by (used in) investing activities (38,910) (366,712) 23,418
-------- -------- --------
Financing Activities:
Changes in short-term borrowings (43,000) 43,000 -
Common stock dividends paid (410,223) (287,483) (256,117)
Retirement of common stock (119,486) (20,558) (105,673)
-------- -------- --------
Net cash flow used in financing activities (572,709) (265,041) (361,790)
-------- -------- --------
Net increase in cash and cash equivalents 100,157 32,845 112,974
Cash and cash equivalents at beginning of period 152,551 119,706 6,732
-------- -------- --------
Cash and cash equivalents at end of period $252,708 $152,551 $119,706
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Noncash investing and financing activities:
Merger with GSU-Common stock issued - $2,031,101 -
See Entergy Corporation and Subsidiaries Notes to Consolidated Financial
Statements in Part II, Item 8.
ENTERGY CORPORATION
SCHEDULE I-FINANCIAL STATEMENTS OF ENTERGY CORPORATION
STATEMENTS OF INCOME
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Income:
Equity in income of subsidiaries $369,701 $557,681 $454,947
Interest on temporary investments 25,496 18,520 20,011
-------- -------- --------
Total 395,197 576,201 474,958
-------- -------- --------
Expenses and Other Deductions:
Administrative and general expenses 57,846 25,129 32,412
Income taxes (credit) (6,350) 3,587 4,734
Taxes other than income (credit) 465 (696) 167
Interest (credit) 1,395 (3,749) 8
-------- -------- --------
Total 53,356 24,271 37,321
-------- -------- --------
Net Income $341,841 $551,930 $437,637
======== ======== ========
See Entergy Corporation and Subsidiaries Notes to consolidated financial
Statements in Part II, Item 8.
ENTERGY CORPORATION
SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL
For the Years Ended December 31,
1994 1993 1992
(In Thousands)
Retained Earnings, January 1 $2,310,082 $2,062,188 $1,943,298
Add:
Net income 341,841 551,930 437,637
---------- ---------- ----------
Total 2,651,923 2,614,118 2,380,935
---------- ---------- ----------
Deduct:
Dividends declared on common stock 411,806 288,342 255,479
Common stock retirements 13,940 13,906 59,187
Capital stock and other expenses 2,438 1,788 4,081
---------- ---------- ----------
Total 428,184 304,036 318,747
---------- ---------- ----------
Retained Earnings, December 31 $2,223,739 $2,310,082 $2,062,188
========== ========== ==========
Paid-in Capital, January 1 $4,223,682 $1,327,589 $1,357,883
Add:
Gain (loss) on reacquisition of
subsidiaries' preferred stock (23) (20) (1,323)
Issuance of 56,695,724 shares of common
stock in the merger with GSU - 2,027,325 -
Issuance of 174,552,011 shares of common
stock at $.01 par value net of the
retirement of 174,552,011 shares of
common stock at $5.00 par value - 871,015 -
---------- ---------- ----------
Total 4,223,659 4,225,909 1,356,560
---------- ---------- ----------
Deduct:
Common stock retirements 22,468 4,389 28,127
Capital stock discounts and other expenses (943) (2,162) 844
---------- ---------- ----------
Total 21,525 2,227 28,971
---------- ---------- ----------
Paid-in Capital, December 31 $4,202,134 $4,223,682 $1,327,589
========== ========== ==========
See Entergy Corporation and Subsidiaries Notes to Consolidated Financial
Statements in Part II, Item 8.
ENTERGY CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1994, 1993, and 1992
(In Thousands)
Column A Column B Column C Column D Column E Column F
Other
Additions Changes
----------------- ----------
Balance at Charged to Deductions Balance
Beginning Charged Other from at
of to Accounts Provisions Acquisition End of
Description Period Income (Note 1) (Note 2) of GSU Period
Year ended December 31, 1994
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $8,808 $8,266 - $10,334 - $6,740
======= ======= === ======= ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $34,546 $25,592 - $27,267 - $32,871
Injuries and damages (Note 3) 23,096 10,993 - 12,023 - 22,066
Environmental 26,753 21,292 - 5,306 - 42,739
------- ------- --- ------- ------- -------
Total $84,395 $57,877 - $44,596 - $97,676
======= ======= === ======= ======= =======
Year ended December 31, 1993
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $6,193 $8,565 - $8,333 $2,383 $8,808
======= ======= === ======= ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $25,177 $5,714 - $7,217 $10,872 $34,546
Injuries and damages (Note 3) 15,978 11,702 - 14,053 9,469 23,096
Environmental 8,006 1,672 - 1,076 18,151 26,753
------- ------- --- ------- ------- -------
Total $49,161 $19,088 - $22,346 $38,492 $84,395
======= ======= === ======= ======= =======
Year ended December 31, 1992
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $8,125 $3,654 - $5,586 - $6,193
======= ======= === ======= ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $35,056 $10,820 - $20,699 - $25,177
Injuries and damages (Note 3) 14,614 11,053 20 9,709 - 15,978
Environmental 8,835 853 - 1,682 - 8,006
------- ------- --- ------- ------- -------
Total $58,505 $22,726 $20 $32,090 - $49,161
======= ======= === ======= ======= =======
___________
Notes:
(1) Charged to clearing and other accounts.
(2) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for
doubtful accounts, such deductions are reduced by recoveries of amounts
previously written off.
(3) Injuries and damages provision is provided to absorb all current expenses
as appropriate and for the estimated cost of settling claims for injuries\
and damages.
ARKANSAS POWER & LIGHT COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1994, 1993, and 1992
(In Thousands)
Column A Column B Column C Column D Column E
Other
Additions Changes
----------------- ----------
Balance at Charged to Deductions Balance
Beginning Charged Other from at
of to Accounts Provisions End of
Description Period Income (Note 1) (Note 2) Period
Year ended December 31, 1994
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $2,050 $1,967 - $2,067 $1,950
======= ======= === ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $2,821 $18,782 - $19,687 $1,916
Injuries and damages (Note 2) 3,259 1,316 - 1,915 2,660
Environmental 6,825 1,510 - 2,985 5,350
------- ------- --- ------- -------
Total $12,905 $21,608 - $24,587 $9,926
======= ======= === ======= =======
Year ended December 31, 1993
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $1,613 $3,439 - $3,002 $2,050
======= ======= === ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $5,182 $1,952 - $4,313 $2,821
Injuries and damages (Note 2) 5,851 4,070 - 6,662 3,259
Environmental 6,766 1,122 - 1,063 6,825
------- ------- --- ------- -------
Total $17,799 $7,144 - $12,038 $12,905
======= ======= === ======= =======
Year ended December 31, 1992
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $3,430 $(3) - $1,814 $1,613
======= ======= === ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $7,827 $4,000 - $6,645 $5,182
Injuries and damages (Note 2) 4,254 7,086 - 5,489 5,851
Environmental 7,595 853 - 1,682 6,766
------- ------- --- ------- -------
Total $19,676 $11,939 - $13,816 $17,799
======= ======= === ======= =======
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for
doubtful accounts, such deductions are reduced by recoveries of amounts
previously written off.
(2) Injuries and damages provision is provided to absorb all current
expenses as appropriate and for the estimated cost of settling claims
for injuries and damages.
GULF STATES UTILITIES COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1994, 1993 and 1992
(In Thousands)
Column A Column B Column C Column D Column E
Other
Additions Changes
----------------- ----------
Balance at Charged to Deductions Balance
Beginning Charged Other from at
of to Accounts Provisions End of
Description Period Income (Note 1) (Note 2) Period
Year ended December 31, 1994
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $2,383 $701 - $2,369 $715
======= ======= === ====== =======
Accumulated Provisions
Not Deducted from Assets--
Property insurance $10,872 $2,170 - $2,591 $10,451
Injuries and damages (Note 3) 9,469 2,970 - 5,517 6,922
Environmental 18,151 2,589 - 426 20,314
------- ------- --- ------ -------
Total $38,492 $7,729 - $8,534 $37,687
======= ======= === ====== =======
Year ended December 31, 1993
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $2,953 $929 - $1,499 $2,383
======= ======= === ====== =======
Accumulated Provisions
Not Deducted from Assets--
Property insurance $9,397 $1,302 - ($173) $10,872
Injuries and damages (Note 3) 6,594 11,511 - 8,636 9,469
Environmental 19,328 3 - 1,180 18,151
------- ------- --- ------ -------
Total $35,319 $12,816 - $9,643 $38,492
======= ======= === ====== =======
Year ended December 31, 1992
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $2,796 $2,271 - $2,114 $2,953
======= ======= === ====== =======
Accumulated Provisions
Not Deducted from Assets--
Property insurance $10,975 ($1,578) - $0 $9,397
Injuries and damages (Note 3) 5,120 3,367 - 1,893 6,594
Environmental 16,184 4,618 - 1,474 19,328
------- ------- --- ------ -------
Total $32,279 $6,407 - $3,367 $35,319
======= ======= === ====== =======
___________
Notes:
(1) Charged to clearing and other accounts.
(2) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for
doubtful accounts, such deductions are reduced by recoveries of
amounts previously written off.
(3) Injuries and damages provision is provided to absorb all current
expenses as appropriate and for the estimated cost of settling
claims for injuries and damages.
LOUISIANA POWER & LIGHT COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1994, 1993, and 1992
(In Thousands)
Column A Column B Column C Column D Column E
Other
Additions Changes
----------------- ----------
Balance at Charged to Deductions Balance
Beginning Charged Other from at
of to Accounts Provisions End of
Description Period Income (Note 1) (Note 2) Period
Year ended December 31, 1994
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $1,075 $2,023 - $1,923 $1,175
======= ======= === ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $2,388 $3,120 - $4,694 814
Injuries and damages (Note 2) 4,779 5,848 - 3,277 7,350
Environmental 1,237 16,868 - 1,711 16,394
------- ------- --- ------- -------
Total $8,404 $25,836 - $9,682 $24,558
======= ======= === ======= =======
Year ended December 31, 1993
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $1,956 $337 - $1,218 $1,075
======= ======= === ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $2,474 $1,800 - $1,886 $2,388
Injuries and damages (Note 2) 6,153 2,748 - 4,122 4,779
Environmental 700 550 - 13 1,237
------- ------- --- ------- -------
Total $9,327 $5,098 - $6,021 $8,404
======= ======= === ======= =======
Year ended December 31, 1992
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $1,956 $1,324 - $1,324 $1,956
======= ======= === ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $9,174 $4,300 - $11,000 $2,474
Injuries and damages (Note 2) 6,153 2,283 - 2,283 6,153
Environmental 700 - - - 700
------- ------- --- ------- -------
Total $16,027 $6,583 - $13,283 $9,327
======= ======= === ======= =======
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for
doubtful accounts, such deductions are reduced by recoveries of amounts
previously written off.
(2) Injuries and damages provision is provided to absorb all current expenses
as appropriate and for the estimated cost of settling claims for injuries
and damages.
MISSISSIPPI POWER & LIGHT COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1994, 1993, and 1992
(In Thousands)
Column A Column B Column C Column D Column E
Other
Additions Changes
----------------- ----------
Balance at Charged to Deductions Balance
Beginning Charged Other from at
of to Accounts Provisions End of
Description Period Income (Note 1) (Note 2) Period
Year ended December 31, 1994
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $2,470 $1,897 - $2,297 $2,070
====== ====== === ====== ======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $2,554 $1,520 - $295 $3,779
Injuries and damages (Note 3) 3,478 365 - 118 3,725
Environmental 500 300 - 116 684
------ ------ --- ------ ------
Total $6,532 $2,185 - $529 $8,188
====== ====== === ====== ======
Year ended December 31, 1993
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $1,274 $3,629 - $2,433 $2,470
====== ====== === ====== ======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $2,051 $1,521 - $1,018 $2,554
Injuries and damages (Note 3) 1,645 3,202 - 1,369 3,478
Environmental 500 - - - 500
------ ------ --- ------ ------
Total $4,196 $4,723 - $2,387 $6,532
====== ====== === ====== ======
Year ended December 31, 1992
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $1,389 $834 - $949 $1,274
====== ====== === ====== ======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $3,300 $1,520 - $2,769 $2,051
Injuries and damages (Note 3) 1,863 333 20 571 1,645
Environmental 500 - - - 500
------ ------ --- ------ ------
Total $5,663 $1,853 $20 $3,340 $4,196
====== ====== === ====== ======
___________
Notes:
(1) Charged to clearing and other accounts.
(2) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for
doubtful accounts, such deductions are reduced by recoveries of amounts
previously written off.
(3) Injuries and damages provision is provided to absorb all current expenses
as appropriate and for the estimated cost of settling claims for injuries
and damages.
NEW ORLEANS PUBLIC SERVICE INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1994, 1993, and 1992
(In Thousands)
Column A Column B Column C Column D Column E
Other
Additions Changes
----------------- ----------
Balance at Charged to Deductions Balance
Beginning Charged Other from at
of to Accounts Provisions End of
Description Period Income (Note 1) (Note 2) Period
Year ended December 31, 1994
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $830 $1,678 - $1,678 $830
======= ====== === ====== =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $15,911 - - - $15,911
Injuries and damages (Note 2) 2,111 494 - 1,196 1,409
Environmental 40 25 - 68 (3)
------- ------ --- ------ -------
Total $18,062 $519 - $1,264 $17,317
======= ====== === ====== =======
Year ended December 31, 1993
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $1,350 $1,160 - $1,680 $830
======= ====== === ====== =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $15,470 $441 - - $15,911
Injuries and damages (Note 2) 2,329 1,682 - 1,900 2,111
Environmental 40 - - - 40
------- ------ --- ------ -------
Total $17,839 $2,123 - $1,900 $18,062
======= ====== === ====== =======
Year ended December 31, 1992
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts $1,350 $1,499 - $1,499 $1,350
======= ====== === ====== =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $14,755 $1,000 - $285 $15,470
Injuries and damages (Note 2) 2,344 1,351 - 1,366 2,329
Environmental 40 - - - 40
------- ------ --- ------ -------
Total $17,139 $2,351 - $1,651 $17,839
======= ====== === ====== =======
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for
doubtful accounts, such deductions are reduced by recoveries of
amounts previously written off.
(2) Injuries and damages provision is provided to absorb all current expenses
as appropriate and for the estimated cost of settling claims for injuries
and damages.
EXHIBIT INDEX
The following exhibits indicated by an asterisk preceding the
exhibit number are filed herewith. The balance of the exhibits have
heretofore been filed with the SEC, respectively, as the exhibits and
in the file numbers indicated and are incorporated herein by
reference. The exhibits marked with a (+) are management contracts or
compensatory plans or arrangements required to be filed herewith and
required to be identified as such by Item 14 of Form 10-K. Reference
is made to a duplicate list of exhibits being filed as a part of this
Form 10-K, which list, prepared in accordance with Item 102 of
Regulation S-T of the SEC, immediately precedes the exhibits being
physically filed with this Form 10-K.
(3) (i) Articles of Incorporation
Entergy Corporation
(a) 1 -- Certificate of Incorporation of Entergy Corporation (A-1(a)
to Rule 24 Certificate in 70-8059).
System Energy
(b) 1 -- Amended and Restated Articles of Incorporation of System
Energy, as executed April 28, 1989 (A-1(a) to Form U-1 in
70-5399).
AP&L
(c) 1 -- Amended and Restated Articles of Incorporation of AP&L, as
amended (4(c) in 33-50289).
GSU
(d) 1 -- Restated Articles of Incorporation, as amended, of GSU (A-11
in 70-8059).
(d) 2 -- Statement of Resolution amending Restated Articles of
Incorporation, as amended, of GSU (A-11(a) in 70-8059).
LP&L
(e) 1 -- Restated Articles of Incorporation of LP&L, as amended (3(a)
to Form 10-Q for the quarter ended June 30, 1994 in 1-8474).
MP&L
(f) 1 -- Restated Articles of Incorporation of MP&L, as amended (3(b)
to Form 10-Q for the quarter ended June 30, 1994 in 0-320).
*(f) 2 -- Articles of Amendment to Restated Articles of Incorporation
of MP&L, as amended, as executed January 18, 1995 and March
7, 1995.
NOPSI
(g) 1 -- Restated Articles of Incorporation of NOPSI, as amended (3(c)
to Form 10-Q for the quarter ended June 30, 1994 in 0-5807).
(3) (ii) By-Laws
(a) -- By-Laws of Entergy Corporation (A-2(a) to Rule 24 Certificate
in 70-8059).
(b) -- By-Laws of System Energy (A-2(a) in 70-5399).
(c) -- By-Laws of AP&L (3(d) to Form 10-Q for the quarter ended
June 30, 1994).
(d) -- By-Laws of GSU (3(e) to Form 10-Q for the quarter ended
June 30, 1994).
(e) -- By-Laws of LP&L (A-4 in 70-6962).
(f) -- By-Laws of MP&L (3(f) to Form 10-Q for the quarter ended
June 30, 1994).
(g) -- By-Laws of NOPSI (3(g) to Form 10-Q for the quarter ended
June 30, 1994).
(4) Instruments Defining Rights of Security Holders, Including Indentures
Entergy Corporation
(a) 1 -- See (4)(b) through (4)(g) below for instruments defining the
rights of holders of long-term debt of System Energy, AP&L,
GSU, LP&L, MP&L and NOPSI.
(a) 2 -- Revolving Credit Agreement, dated as of January 31, 1989
between System Fuels and Bank of America National Trust and
Savings Association (B-1(c) to Rule 24 Certificate, dated
February 1, 1989, in 70-7574), as amended by First Amendment
to Revolving Credit Agreement, dated as of August 28, 1990 (A
to Rule 24 Certificate, dated October 31, 1990, in 70-7574).
(a) 3 -- Security Agreement dated as of January 31, 1989 between
System Fuels and Bank of America National Trust and Savings
Association (B-3(c) to Rule 24 Certificate, dated February 1,
1989, in 70-7574).
(a) 4 -- Credit Agreement, dated as of October 3, 1989, between System
Fuels and The Yasuda Trust and Banking Co., Ltd., New York
Branch, as agent (B-1(c) to Rule 24 Certificate, dated
October 6, 1989, in 70-7668).
(a) 5 -- First Amendment, dated as of March 1, 1992, to Credit
Agreement, dated as of October 3, 1989, between System Fuels
and The Yasuda Trust and Banking Co., Ltd., New York Branch,
as agent (4(a)5 to Form 10-K for the year ended December 31,
1991 in 1-3517).
(a) 6 -- Second Amendment, dated as of September 30, 1992, to Credit
Agreement dated as of October 3, 1989, between System Fuels
and The Yasuda Trust and Banking Co., Ltd., New York Branch,
as agent (4(a)6 to Form 10-K for the year ended December 31,
1992 in 1-3517).
(a) 7 -- Security Agreement, dated as of October 3, 1989, as amended,
between System Fuels and The Yasuda Trust and Banking Co.,
Ltd., New York Branch, as agent (B-3(c) to Rule 24
Certificate, dated October 6, 1989, in 70-7668), as amended
by First Amendment to Security Agreement, dated as of
March 14, 1990 (A to Rule 24 Certificate, dated March 7,
1990, in 70-7668).
(a) 8 -- Consent and Agreement, dated as of October 3, 1989, among
System Fuels, The Yasuda Trust and Banking Co., Ltd., New
York Branch, as agent, AP&L, LP&L, and System Energy (B-5(c)
to Rule 24 Certificate, dated October 6, 1989, in 70-7668).
System Energy
(b) 1 -- Mortgage and Deed of Trust, as amended by nineteen
Supplemental Indentures (A-1 in 70-5890 (Mortgage); B and C
to Rule 24 Certificate in 70-5890 (First); B to Rule 24
Certificate in 70-6259 (Second); 20(a)-5 to Form 10-Q for the
quarter ended June 30, 1981, in 1-3517 (Third); A-1(e)-1 to
Rule 24 Certificate in 70-6985 (Fourth); B to Rule 24
Certificate in 70-7021 (Fifth); B to Rule 24 Certificate in
70-7021 (Sixth); A-3(b) to Rule 24 Certificate in 70-7026
(Seventh); A-3(b) to Rule 24 Certificate in 70-7158 (Eighth);
B to Rule 24 Certificate in 70-7123 (Ninth); B-1 to Rule 24
Certificate in 70-7272 (Tenth); B-2 to Rule 24 Certificate in
70-7272 (Eleventh); B-3 to Rule 24 Certificate in 70-7272
(Twelfth); B-1 to Rule 24 Certificate in 70-7382
(Thirteenth); B-2 to Rule 24 Certificate in 70-7382
(Fourteenth); A-2(c) to Rule 24 Certificate in 70-7946
(Fifteenth); A-2(c) to Rule 24 Certificate in 70-7946
(Sixteenth); A-2(d) to Rule 24 Certificate in 70-7946
(Seventeenth); A-2(e) to Rule 24 Certificate dated May 4,
1993 in 70-7946 (Eighteenth); and A-2(g) to Rule 24
Certificate dated May 6, 1994, in 70-7946 (Nineteenth)).
(b) 2 -- Facility Lease No. 1, dated as of December 1, 1988, between
Meridian Trust Company and Stephen M. Carta (Steven Kaba,
successor), as Owner Trustees, and System Energy (B-2(c)(1)
to Rule 24 Certificate dated January 9, 1989 in 70-7561), as
supplemented by Lease Supplement No. 1 dated as of April 1,
1989 (B-22(b) (1) to Rule 24 Certificate dated April 21,
1989 in 70-7561) and Lease Supplement No. 2 dated as of
January 1, 1994 (B-3(d) to Rule 24 Certificate dated
January 31, 1994 in 70-8215).
(b) 3 -- Facility Lease No. 2, dated as of December 1, 1988, between
Meridian Trust Company and Stephen M. Carta (Steven Kaba,
successor), as Owner Trustees, and System Energy (B-2(c)(2)
to Rule 24 Certificate dated January 9, 1989 in 70-7561),
as supplemented by Lease Supplement No. 1 dated as of
April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated
April 21, 1989 in 70-7561) and Lease Supplement No. 2
dated as of January 1, 1994 (B-4(d) Rule 24 Certificate
dated January 31, 1994 in 70-8215).
(b) 4 -- Installment Sale Agreement, dated as of December 1, 1983
between System Energy and Claiborne County, Mississippi
(B-1 to First Rule 24 Certificate in 70-6913).
(b) 5 -- Indenture of Trust, dated as of December 1, 1983, between
Claiborne County, Mississippi and Deposit Guaranty National
Bank (A-1 to First Rule 24 Certificate in 70-6913).
(b) 6 -- Installment Sale Agreement, dated as of June 1, 1984, between
System Energy and Claiborne County, Mississippi (B-2 to Second
Rule 24 Certificate in 70-6913).
(b) 7 -- Indenture of Trust, dated as of June 1, 1984, between
Claiborne Country, Mississippi and Deposit Guaranty National
Bank (A-2 to Second Rule 24 Certificate in 70-6913).
(b) 8 -- Installment Sale Agreement, dated as of December 1, 1984,
between System Energy and Claiborne County, Mississippi
(B-1 to First Rule 24 Certificate in 70-7026).
(b) 9 -- Indenture of Trust, dated as of December 1, 1984, between
Claiborne County, Mississippi and Deposit Guaranty National
Bank (B-2 to First Rule 24 Certificate in 70-7026).
(b) 10 -- Installment Sale Agreement, dated as of June 15, 1985,
between System Energy and Claiborne County, Mississippi
(B-1(b) to Third Rule 24 Certificate in 70-7026).
(b) 11 -- Indenture of Trust, dated as of June 15, 1985, between
Claiborne County, Mississippi and Deposit Guaranty National
Bank (B-2(b) to Third Rule 24 Certificate in 70-7026).
(b) 12 -- Installment Sale Agreement, dated as of May 1, 1986,
between System Energy and Claiborne County, Mississippi
(B-1(b) to Rule 24 Certificate in 70-7158).
(b) 13 -- Indenture of Trust, dated as of May 1, 1986, between
Claiborne County, Mississippi and Deposit Guaranty National
Bank (B-2(b) to Rule 24 Certificate in 70-7158).
AP&L
(c) 1 -- Mortgage and Deed of Trust, as amended by fifty-two
Supplemental Indentures (7(d) in 2-5463 (Mortgage); 7(b) in
2-7121 (First); 7(c) in 2-7605 (Second); 7(d) in 2-8100
(Third); 7(a)-4 in 2-8482 (Fourth); 7(a)-5 in 2-9149 (Fifth);
4(a)-6 in 2-9789 (Sixth); 4(a)-7 in 2-10261 (Seventh); 4(a)-8
in 2-11043 (Eighth); 2(b)-9 in 2-11468 (Ninth); 2(b)-10 in
2-15767 (Tenth); D in 70-3952 (Eleventh); D in 70-4099
(Twelfth); 4(d) in 2-23185 (Thirteenth); 2(c) in 2-24414
(Fourteenth); 2(c) in 2-25913 (Fifteenth); 2(c) in 2-28869
(Sixteenth); 2(d) in 2-28869 (Seventeenth); 2(c) in 2-35107
(Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253
(Twentieth); 2(c) in 2-41080 (Twenty-first); C-1 to Rule 24
Certificate in 70-5151 (Twenty-second); C-1 to Rule 24
Certificate in 70-5257 (Twenty-third); C to Rule 24
Certificate in 70-5343 (Twenty-fourth); C-1 to Rule 24
Certificate in 70-5404 (Twenty-fifth); C to Rule 24
Certificate in 70-5502 (Twenty-sixth); C-1 to Rule 24
Certificate in 70-5556 (Twenty-seventh); C-1 to Rule 24
Certificate in 70-5693 (Twenty-eighth); C-1 to Rule 24
Certificate in 70-6078 (Twenty-ninth); C-1 to Rule 24
Certificate in 70-6174 (Thirtieth); C-1 to Rule 24
Certificate in 70-6246 (Thirty-first); C-1 to Rule 24
Certificate in 70-6498 (Thirty-second); A-4b-2 to Rule 24
Certificate in 70-6326 (Thirty-third); C-1 to Rule 24
Certificate in 70-6607 (Thirty-fourth); C-1 to Rule 24
Certificate in 70-6650 (Thirty-fifth); C-1 to Rule 24
Certificate, dated December 1, 1982, in 70-6774
(Thirty-sixth); C-1 to Rule 24 Certificate, dated
February 17, 1983, in 70-6774 (Thirty-seventh); A-2(a) to
Rule 24 Certificate, dated December 5, 1984, in 70-6858
(Thirty-eighth); A-3(a) to Rule 24 Certificate in 70-7127
(Thirty-ninth); A-7 to Rule 24 Certificate in 70-7068
(Fortieth); A-8(b) to Rule 24 Certificate dated July 6, 1989
in 70-7346 (Forty-first); A-8(c) to Rule 24 Certificate,
dated February 1, 1990 in 70-7346 (Forty-second); 4 to Form
10-Q for the quarter ended September 30, 1990 in 1-10764
(Forty-third); A-2(a) to Rule 24 Certificate, dated
November 30, 1990, in 70-7802 (Forty-fourth); A-2(b) to Rule
24 Certificate, dated January 24, 1991, in 70-7802
(Forty-fifth); 4(d)(2) in 33-54298 (Forty-sixth); 4(c)(2) to
Form 10-K for the year ended December 31, 1992 in 1-10764
(Forty-seventh); 4(b) to Form 10-Q for the quarter ended June
30, 1993 in 1-10764 (Forty-eighth); 4(c) to Form 10-Q for the
quarter ended June 30, 1993 in 1-10764 (Forty-ninth); 4(b) to
Form 10-Q for the quarter ended September 30, 1993 in 1-10764
(Fiftieth); 4(c) to Form 10-Q for the quarter ended September
30, 1993 in 1-10764 (Fifty-first); and 4(a) to Form 10-Q for
the quarter ended June 30, 1994 (Fifty-second)).
GSU
(d) 1 -- Indenture of Mortgage, as amended by certain Supplemental
Indentures (B-a-I-1 in Registration No. 2-2449 (Mortgage); 7-
A-9 in Registration No. 2-6893 (Seventh); B to Form 8-K dated
September 1, 1959 (Eighteenth); B to Form 8-K dated February
1, 1966 (Twenty-second); B to Form 8-K dated March 1, 1967
(Twenty-third); C to Form 8-K dated March 1, 1968 (Twenty-
fourth); B to Form 8-K dated November 1, 1968 (Twenty-fifth);
B to Form 8-K dated April 1, 1969 (Twenty-sixth); 2-A-8 in
Registration No. 2-66612 (Thirty-eighth); 4-2 to Form 10-K
for the year ended December 31, 1984 in 1-2703 (Forty-
eighth); 4-2 to Form 10-K for the year ended December 31,
1988 in 1-2703 (Fifty-second); 4 to Form 10-K for the year
ended December 31, 1991 in 1-2703 (Fifty-third); 4 to Form 8-
K dated July 29, 1992 in 1-2703 (Fifth-fourth); 4 to Form 10-
K dated December 31, 1992 in 1-2703 (Fifty-fifth); 4 to
Form 10-Q for the quarter ended March 31, 1993 in 1-2703
(Fifty-sixth); and 4-2 to Amendment No. 9 to Registration No.
2-76551 (Fifty-seventh)).
(d) 2 -- Indenture, dated March 21, 1939, accepting resignation of The
Chase National Bank of the City of New York as trustee and
appointing Central Hanover Bank and Trust Company as
successor trustee (B-a-1-6 in Registration No. 2-4076).
(d) 3 -- Trust Indenture for 9.72% Debentures due July 1, 1998 (4 in
Registration No. 33-40113).
LP&L
(e) 1 -- Mortgage and Deed of Trust, as amended by forty-nine
Supplemental Indentures (7(d) in 2-5317 (Mortgage); 7(b) in
2-7408 (First); 7(c) in 2-8636 (Second); 4(b)-3 in 2-10412
(Third); 4(b)-4 in 2-12264 (Fourth); 2(b)-5 in 2-12936
(Fifth); D in 70-3862 (Sixth); 2(b)-7 in 2-22340 (Seventh);
2(c) in 2-24429 (Eighth); 4(c)-9 in 2-25801 (Ninth); 4(c)-10
in 2-26911 (Tenth); 2(c) in 2-28123 (Eleventh); 2(c) in
2-34659 (Twelfth); C to Rule 24 Certificate in 70-4793
(Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); 2(b)-2 in
2-39437 (Fifteenth); 2(b)-2 in 2-42523 (Sixteenth); C to
Rule 24 Certificate in 70-5242 (Seventeenth); C to Rule 24
Certificate in 70-5330 (Eighteenth); C-1 to Rule 24
Certificate in 70-5449 (Nineteenth); C-1 to Rule 24
Certificate in 70-5550 (Twentieth); A-6(a) to Rule 24
Certificate in 70-5598 (Twenty-first); C-1 to Rule 24
Certificate in 70-5711 (Twenty-second); C-1 to Rule 24
Certificate in 70-5919 (Twenty-third); C-1 to Rule 24
Certificate in 70-6102 (Twenty-fourth); C-1 to Rule 24
Certificate in 70-6169 (Twenty-fifth); C-1 to Rule 24
Certificate in 70-6278 (Twenty-sixth); C-1 to Rule 24
Certificate in 70-6355 (Twenty-seventh); C-1 to Rule 24
Certificate in 70-6508 (Twenty-eighth); C-1 to Rule 24
Certificate in 70-6556 (Twenty-ninth); C-1 to Rule 24
Certificate in 70-6635 (Thirtieth); C-1 to Rule 24
Certificate in 70-6834 (Thirty-first); C-1 to Rule 24
Certificate in 70-6886 (Thirty-second); C-1 to Rule 24
Certificate in 70-6993 (Thirty-third); C-2 to Rule 24
Certificate in 70-6993 (Thirty-fourth); C-3 to Rule 24
Certificate in 70-6993 (Thirty-fifth); A-2(a) to Rule 24
Certificate in 70-7166 (Thirty-sixth); A-2(a) in 70-7226
(Thirty-seventh); C-1 to Rule 24 Certificate in 70-7270
(Thirty-eighth); 4(a) to Quarterly Report on Form 10-Q for
the quarter ended June 30, 1988, in 1-8474 (Thirty-ninth);
A-2(b) to Rule 24 Certificate in 70-7553 (Fortieth); A-2(d)
to Rule 24 Certificate in 70-7553 (Forty-first); A-3(a) to
Rule 24 Certificate in 70-7822 (Forty-second); A-3(b) to Rule
24 Certificate in 70-7822 (Forty-third); A-2(b) to Rule 24
Certificate in File No. 70-7822 (Forty-fourth); A-3(c) to
Rule 24 Certificate in 70-7822 (Forty-fifth); A-2(c) to Rule
24 Certificate dated April 7, 1993 in 70-7822 (Forty-sixth);
A-3(d) to Rule 24 Certificate dated June 4, 1993 in 70-7822
(Forth-seventh); A-3(e) to Rule 24 Certificate dated December
21, 1993 in 70-7822 (Forty-eighth); and A-3(f) to Rule 24
Certificate dated August 1, 1994 in 70-7822 (Forty-ninth).
(e) 2 -- Facility Lease No. 1, dated as of September 1, 1989, between
First National Bank of Commerce, as Owner Trustee, and LP&L
(4(c)-1 in Registration No. 33-30660).
(e) 3 -- Facility Lease No. 2, dated as of September 1, 1989, between
First National Bank of Commerce, as Owner Trustee, and LP&L
(4(c)-2 in Registration No. 33-30660).
(e) 4 -- Facility Lease No. 3, dated as of September 1, 1989, between
First National Bank of Commerce, as Owner Trustee, and LP&L
(4(c)-3 in Registration No. 33-30660).
MP&L
(f) 1 -- Mortgage and Deed of Trust, as amended by twenty-five
Supplemental Indentures (7(d) in 2-5437 (Mortgage); 7(b) in
2-7051 (First); 7(c) in 2-7763 (Second); 7(d) in 2-8484
(Third); 4(b)-4 in 2-10059 (Fourth); 2(b)-5 in 2-13942
(Fifth); A-11 to Form U-1 in 70-4116 (Sixth); 2(b)-7 in
2-23084 (Seventh); 4(c)-9 in 2-24234 (Eighth); 2(b)-9(a) in
2-25502 (Ninth); A-11(a) to Form U-1 in 70-4803 (Tenth);
A-12(a) to Form U-1 in 70-4892 (Eleventh); A-13(a) to
Form U-1 in 70-5165 (Twelfth); A-14(a) to Form U-1 in 70-5286
(Thirteenth); A-15(a) to Form U-1 in 70-5371 (Fourteenth);
A-16(a) to Form U-1 in 70-5417 (Fifteenth); A-17 to Form U-1
in 70-5484 (Sixteenth); 2(a)-19 in 2-54234 (Seventeenth); C-1
to Rule 24 Certificate in 70-6619 (Eighteenth); A-2(c) to
Rule 24 Certificate in 70-6672 (Nineteenth); A-2(d) to
Rule 24 Certificate in 70-6672 (Twentieth); C-1(a) to Rule 24
Certificate in 70-6816 (Twenty-first); C-1(a) to Rule 24
Certificate in 70-7020 (Twenty-second); C-1(b) to Rule 24
Certificate in 70-7020 (Twenty-third); C-1(a) to Rule 24
Certificate in 70-7230 (Twenty-fourth); and A-2(a) to Rule 24
Certificate in 70-7419 (Twenty-fifth)).
(f) 2 -- Mortgage and Deed of Trust, dated as of February 1, 1988, as
amended by nine Supplemental Indentures (A-2(a)-2 to Rule 24
Certificate in 70-7461 (Mortgage); A-2(b)-2 in 70-7461
(First); A-5(b) to Rule 24 Certificate in 70-7419 (Second);
A-4(b) to Rule 24 Certificate in 70-7554 (Third); A-1(b)-1 to
Rule 24 Certificate in 70-7737 (Fourth); A-2(b) to Rule 24
Certificate dated November 24, 1992 in 70-7914 (Fifth);
A-2(e) to Rule 24 Certificate dated January 22, 1993 in
70-7914 (Sixth); A-2(g) to Form U-1 in 70-7914 (Seventh); A-
2(i) to Rule 24 Certificate dated November 10, 1993 in 70-
7914 (Eighth); and A-2(j) to Rule 24 Certificate dated July
22, 1994 in 70-7914 (Ninth)).
NOPSI
(g) 1 -- Mortgage and Deed of Trust, as amended by eleven Supplemental
Indentures (B-3 in 2-5411 (Mortgage); 7(b) in 2-7674 (First);
4(a)-2 in 2-10126 (Second); 4(b) in 2-12136 (Third); 2(b)-4
in 2-17959 (Fourth); 2(b)-5 in 2-19807 (Fifth); D to Rule 24
Certificate in 70-4023 (Sixth); 2(c) in 2-24523 (Seventh);
4(c)-9 in 2-26031 (Eighth); 2(a)-3 in 2-50438 (Ninth); 2(a)-3
in 2-62575 (Tenth); and A-2(b) to Rule 24 Certificate in
70-7262 (Eleventh)).
(g) 2 -- Mortgage and Deed of Trust, dated as of May 1, 1987, as
amended by four Supplemental Indentures (A-2(c) to Rule 24
Certificate in 70-7350 (Mortgage); A-5(b) to Rule 24
Certificate in 70-7350 (First); A-4(b) to Rule 24 Certificate
in 70-7448 (Second); 4(f)4 to Form 10-K for the year ended
December 31, 1992 in 0-5807 (Third); and 4(a) to Form 10-Q
for the quarter ended September 30, 1993 in 0-5807 (Fourth)).
(10) Material Contracts
Entergy Corporation
(a) 1 -- Agreement, dated April 23, 1982, among certain System
companies, relating to System Planning and Development and
Intra-System Transactions (10(a)1 to Form 10-K for the fiscal
year ended December 31, 1982, in 1-3517).
(a) 2 -- Middle South Utilities System Agency Agreement, dated
December 11, 1970 (5(a)-2 in 2-41080).
(a) 3 -- Amendment, dated February 10, 1971, to Middle South Utilities
System Agency Agreement, dated December 11, 1970 (5(a)-4 in
2-41080).
(a) 4 -- Amendment, dated May 12, 1988, to Middle South Utilities
System Agency Agreement, dated December 11, 1970 (5(a)-4 in
2-41080).
(a) 5 -- Middle South Utilities System Agency Coordination Agreement,
dated December 11, 1970 (5(a)-3 in 2-41080).
(a) 6 -- Service Agreement with Entergy Services, dated as of April 1,
1963 (5(a)-5 in 2-41080).
(a) 7 -- Amendment, dated January 1, 1972, to Service Agreement with
Entergy Services (5(a)-6 in 2-43175).
(a) 8 -- Amendment, dated April 27, 1984, to Service Agreement with
Entergy Services (10(a)-7 to Form 10-K for the fiscal year
ended December 31, 1984, in 1-3517).
(a) 9 -- Amendment, dated August 1, 1988, to Service Agreement with
Entergy Services (10(a)-8 to Form 10-K for the fiscal year
ended December 31, 1988, in 1-3517).
(a) 10 -- Amendment, dated January 1, 1991, to Service Agreement with
Entergy Services (10(a)-9 to Form 10-K for the fiscal year
ended December 31, 1990, in 1-3517).
*(a) 11 -- Amendment, dated January 1, 1992, to Service Agreement with
Entergy Services.
(a) 12 -- Availability Agreement, dated June 21, 1974, among System
Energy and certain other System companies (B to Rule 24
Certificate, dated June 24, 1974, in 70-5399).
(a) 13 -- First Amendment to Availability Agreement, dated as of
June 30, 1977 (B to Rule 24 Certificate, dated June 24, 1977,
in 70-5399).
(a) 14 -- Second Amendment to Availability Agreement, dated as of
June 15, 1981 (E to Rule 24 Certificate, dated July 1, 1981,
in 70-6592).
(a) 15 -- Third Amendment to Availability Agreement, dated as of
June 28, 1984 (B-13(a) to Rule 24 Certificate, dated July 6,
1984, in 70-6985).
(a) 16 -- Fourth Amendment to Availability Agreement, dated as of
June 1, 1989 (A to Rule 24 Certificate, dated June 8, 1989,
in 70-5399).
(a) 17 -- Fourteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(a) 18 -- Fifteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated June 5, 1986, in 70-7158).
(a) 19 -- Sixteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (C to
Rule 24 Certificate, dated June 4, 1986, in 70-7123).
(a) 20 -- Eighteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-2 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(a) 21 -- Nineteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-3 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(a) 22 -- Twenty-fourth Assignment of Availability Agreement, Consent
and Agreement, dated as of July 1, 1992, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(B-2(b) to Rule 24 Certificate, dated July 14, 1992, in
70-7946).
(a) 23 -- Twenty-fifth Assignment of Availability Agreement, Consent
and Agreement, dated as of October 1, 1992, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (B-2(b) to Rule 24 Certificate, dated November 2,
1992, in 70-7946).
(a) 24 -- Twenty-sixth Assignment of Availability Agreement, Consent
and Agreement, dated as of October 1, 1992, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (B-2(c) to Rule 24 Certificate, dated November 2,
1992, in 70-7946).
(a) 25 -- Twenty-seventh Assignment of Availability Agreement, Consent
and Agreement, dated as of April 1, 1993, with United States
Trust Company of New York and Gerard F. Ganey as Trustees (B-
2(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(a) 26 -- Twenty-eighth Assignment of Availability Agreement, Consent
and Agreement, dated as of December 17, 1993, with Chemical
Bank, as Agent (B-2(a) to Rule 24 Certificate dated December
22, 1993 in 70-7561).
(a) 27 -- Twenty-ninth Assignment of Availability Agreement, Consent
and Agreement, dated as of April 1, 1994, with United States
Trust Company of New York and Gerard F. Ganey as Trustees (B-
2(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946).
(a) 28 -- Capital Funds Agreement, dated June 21, 1974, between Entergy
Corporation and System Energy (C to Rule 24 Certificate,
dated June 24, 1974, in 70-5399).
(a) 29 -- First Amendment to Capital Funds Agreement, dated as of
June 1, 1989 (B to Rule 24 Certificate, dated June 8, 1989,
in 70-5399).
(a) 30 -- Fourteenth Supplementary Capital Funds Agreement and
Assignment, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-4(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(a) 31 -- Fifteenth Supplementary Capital Funds Agreement and
Assignment, dated as of May 1, 1986, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-4(b) to Rule 24 Certificate,
dated June 5, 1986, in 70-7158).
(a) 32 -- Sixteenth Supplementary Capital Funds Agreement and
Assignment, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (D to
Rule 24 Certificate, dated June 4, 1986, in 70-7123).
(a) 33 -- Eighteenth Supplementary Capital Funds Agreement and
Assignment, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(D-2 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(a) 34 -- Nineteenth Supplementary Capital Funds Agreement and
Assignment, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(D-3 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(a) 35 -- Twenty-fourth Supplementary Capital Funds Agreement and
Assignment, dated as of July 1, 1992, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(B-3(b) to Rule 24 Certificate dated July 14, 1992 in
70-7946).
(a) 36 -- Twenty-fifth Supplementary Capital Funds Agreement and
Assignment, dated as of October 1, 1992, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(B-3(b) to Rule 24 Certificate dated November 2, 1992 in
70-7946).
(a) 37 -- Twenty-sixth Supplementary Capital Funds Agreement and
Assignment, dated as of October 1, 1992, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(B-3(c) to Rule 24 Certificate dated November 2, 1992 in
70-7946).
(a) 38 -- Twenty-seventh Supplementary Capital Funds Agreement and
Assignment, dated as of April 1, 1993, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (B-
3(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(a) 39 -- Twenty-eighth Supplementary Capital Funds Agreement and
Assignment, dated as of December 17, 1993, with Chemical
Bank, as Agent (B-3(a) to Rule 24 Certificate dated December
22, 1993 in 70-7561).
(a) 40 -- Twenty-ninth Supplementary Capital Funds Agreement and
Assignment, dated as of April 1, 1994, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (B-
3(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946).
(a) 41 -- First Amendment to Supplementary Capital Funds Agreements and
Assignments, dated as of June 1, 1989, by and between Entergy
Corporation, System Energy, Deposit Guaranty National Bank,
United States Trust Company of New York and Gerard F. Ganey
(C to Rule 24 Certificate, dated June 8, 1989, in 70-7026).
(a) 42 -- First Amendment to Supplementary Capital Funds Agreements and
Assignments, dated as of June 1, 1989, by and between Entergy
Corporation, System Energy, United States Trust Company of
New York and Gerard F. Ganey (C to Rule 24 Certificate, dated
June 8, 1989, in 70-7123).
(a) 43 -- First Amendment to Supplementary Capital Funds Agreement and
Assignment, dated as of June 1, 1989, by and between Entergy
Corporation, System Energy and Chemical Bank (C to Rule 24
Certificate, dated June 8, 1989, in 70-7561).
+(a) 44 -- Agreement between Entergy Corporation and Edwin Lupberger
(10(a)-42 to Form 10-K for the fiscal year ended December 31,
1985, in 1-3517).
(a) 45 -- Reallocation Agreement, dated as of July 28, 1981, among
System Energy and certain other System companies (B-1(a) in
70-6624).
(a) 46 -- Joint Construction, Acquisition and Ownership Agreement,
dated as of May 1, 1980, between System Energy and SMEPA
(B-1(a) in 70-6337), as amended by Amendment No. 1, dated as
of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated
as of October 31, 1980 (1 to Rule 24 Certificate, dated
October 30, 1981, in 70-6337).
(a) 47 -- Operating Agreement dated as of May 1, 1980, between System
Energy and SMEPA (B(2)(a) in 70-6337).
(a) 48 -- Assignment, Assumption and Further Agreement No. 1, dated as
of December 1, 1988, among System Energy, Meridian Trust
Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24
Certificate, dated January 9, 1989, in 70-7561).
(a) 49 -- Assignment, Assumption and Further Agreement No. 2, dated as
of December 1, 1988, among System Energy, Meridian Trust
Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24
Certificate, dated January 9, 1989, in 70-7561).
(a) 50 -- Substitute Power Agreement, dated as of May 1, 1980, among
MP&L, System Energy and SMEPA (B(3)(a) in 70-6337).
(a) 51 -- Grand Gulf Unit No. 2 Supplementary Agreement, dated as of
February 7, 1986, between System Energy and SMEPA (10(aaa) in
33-4033).
(a) 52 -- Compromise and Settlement Agreement, dated June 4, 1982,
between Texaco, Inc. and LP&L (28(a) to Form 8-K, dated June
4, 1982, in 1-3517).
+(a) 53 -- Post-Retirement Plan (10(a)37 to Form 10-K for the fiscal
year ended December 31, 1983, in 1-3517).
(a) 54 -- Unit Power Sales Agreement, dated as of June 10, 1982,
between System Energy and AP&L, LP&L, MP&L and NOPSI
(10(a)-39 to Form 10-K for the fiscal year ended December 31,
1982, in 1-3517).
(a) 55 -- First Amendment to Unit Power Sales Agreement, dated as of
June 28, 1984, between System Energy and AP&L, LP&L, MP&L and
NOPSI (19 to Form 10-Q for the quarter ended September 30,
1984, in 1-3517).
(a) 56 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(a) 57 -- Middle South Utilities Inc. and Subsidiary Companies
Intercompany Income Tax Allocation Agreement, dated April 28,
1988 (Exhibit D-1 to Form U5S for the year ended December 31,
1987).
(a) 58 -- First Amendment, dated January 1, 1990, to the Middle South
Utilities Inc. and Subsidiary Companies Intercompany Income
Tax Allocation Agreement (D-2 to Form U5S for the year ended
December 31, 1989).
(a) 59 -- Second Amendment dated January 1, 1992, to the Entergy
Corporation and Subsidiary Companies Intercompany Income Tax
Allocation Agreement (D-3 to Form U5S for the year ended
December 31, 1992).
(a) 60 -- Third Amendment dated January 1, 1994 to Entergy Corporation
and Subsidiary Companies Intercompany Income Tax Allocation
Agreement (D-3(a) to Form U5S for the year ended December 31,
1993).
(a) 61 -- Guaranty Agreement between Entergy Corporation and AP&L,
dated as of September 20, 1990 (B-1(a) to Rule 24
Certificate, dated September 27, 1990, in 70-7757).
(a) 62 -- Guarantee Agreement between Entergy Corporation and LP&L,
dated as of September 20, 1990 (B-2(a) to Rule 24
Certificate, dated September 27, 1990, in 70-7757).
(a) 63 -- Guarantee Agreement between Entergy Corporation and System
Energy, dated as of September 20, 1990 (B-3(a) to Rule 24
Certificate, dated September 27, 1990, in 70- 7757).
(a) 64 -- Loan Agreement between Entergy Operations and Entergy
Corporation, dated as of September 20, 1990 (B-12(b) to Rule
24 Certificate, dated June 15, 1990, in 70-7679).
(a) 65 -- Loan Agreement between Entergy Power and Entergy Corporation,
dated as of August 28, 1990 (A-4(b) to Rule 24 Certificate,
dated September 6, 1990, in 70-7684).
(a) 66 -- Loan Agreement between Entergy Corporation and Entergy
Systems and Service, Inc., dated as of December 29, 1992
(A-4(b) to Rule 24 Certificate in 70-7947).
+(a) 67 -- Executive Financial Counseling Program of Entergy Corporation
and Subsidiaries (10(a) 52 to Form 10-K for the year ended
December 31, 1989, in 1-3517).
+(a) 68 -- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form
10-K for the year ended December 31, 1989, in 1-3517).
+(a) 69 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries
(A-4(a) to Rule 24 Certificate, dated May 24, 1991, in
70-7831).
+(a) 70 -- Retired Outside Director Benefit Plan (10(a)63 to Form 10-K
for the year ended December 31, 1991, in 1-3517).
+(a) 71 -- Agreement between Entergy Corporation and Jerry D. Jackson.
(10(a) 67 to Form 10-K for the year ended December 31, 1992
in 1-3517).
+(a) 72 -- Agreement between Entergy Services, Inc., a subsidiary of
Entergy Corporation, and Gerald D. McInvale (10(a) 68 to Form
10-K for the year ended December 31, 1992 in 1-3517).
+(a) 73 -- Supplemental Retirement Plan (10(a) 69 to Form 10-K for the
year ended December 31, 1992 in 1-3517).
+(a) 74 -- Defined Contribution Restoration Plan of Entergy Corporation
and Subsidiaries (10(a)53 to Form 10-K for the year ended
December 31, 1989 in 1-3517).
+(a) 75 -- Amendment No. 1 to the Equity Ownership Plan of Entergy
Corporation and Subsidiaries (10(a) 71 to Form 10-K for the
year ended December 31, 1992 in 1-3517).
+(a) 76 -- Executive Disability Plan of Entergy Corporation and
Subsidiaries (10(a) 72 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(a) 77 -- Executive Medical Plan of Entergy Corporation and
Subsidiaries (10(a) 73 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(a) 78 -- Stock Plan for Outside Directors of Entergy Corporation and
Subsidiaries, as amended (10(a) 74 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(a) 79 -- Summary Description of Private Ownership Vehicle Plan of
Entergy Corporation and Subsidiaries (10(a) 75 to Form 10-K
for the year ended December 31, 1992 in 1-3517).
(a) 80 -- Agreement and Plan of Reorganization Between Entergy
Corporation and Gulf States Utilities Company, dated June 5,
1992 (1 to Current Report on Form 8-K dated June 5, 1992 in
1-3517).
+(a) 81 -- Amendment to Defined Contribution Restoration Plan of Entergy
Corporation and Subsidiaries (10(a) 81 to Form 10-K for the
year ended December 31, 1993 in 1-11299).
+(a) 82 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for
the year ended December 31, 1993 in 1-11299).
System
Energy
(b) 1 -- Availability Agreement, dated June 21, 1974, among System
Energy and certain other System companies (B to Rule 24
Certificate, dated June 24, 1974, in 70-5399).
(b) 2 -- First Amendment to Availability Agreement, dated as of June
30, 1977 (B to Rule 24 Certificate, dated June 24, 1977, in
70-5399).
(b) 3 -- Second Amendment to Availability Agreement, dated as of June
15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in
70-6592).
(b) 4 -- Third Amendment to Availability Agreement, dated as of June
28, 1984 (B-13(a) to Rule 24 Certificate, dated July 6, 1984,
in 70-6985).
(b) 5 -- Fourth Amendment to Availability Agreement, dated as of June
1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in
70-5399).
(b) 6 -- Fourteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(b) 7 -- Fifteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York, Malcolm J. Hood, and Deposit Guaranty
National Bank, as Trustees (B-3(b) to Rule 24 Certificate,
dated June 5, 1986, in 70-7158).
(b) 8 -- Sixteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (C to
Rule 24 Certificate, dated June 4, 1986, in 70-7123).
(b) 9 -- Eighteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-2 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(b) 10 -- Nineteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-3 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(b) 11 -- Twenty-fourth Assignment of Availability Agreement, Consent
and Agreement, dated as of July 1, 1992, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(B-2(b) to Rule 24 Certificate, dated July 14, 1992, in
70-7946).
(b) 12 -- Twenty-fifth Assignment of Availability Agreement, Consent
and Agreement, dated as of October 1, 1992, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (B-2(b) to Rule 24 Certificate, dated November 2,
1992, in 70-7946).
(b) 13 -- Twenty-sixth Assignment of Availability Agreement, Consent
and Agreement, dated as of October 1, 1992, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (B-2(c) to Rule 24 Certificate, dated November 2,
1992, in 70-7946).
(b) 14 -- Twenty-seventh Assignment of Availability Agreement, Consent
and Agreement, dated as of April 1, 1993, with United States
Trust Company of New York and Gerard F. Ganey as Trustees (B-
2(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(b) 15 -- Twenty-eighth Assignment of Availability Agreement, Consent
and Agreement, dated as of December 17, 1993, with Chemical
Bank, as Agent (B-2(a) to Rule 24 Certificate dated December
22, 1993 in 70-7561).
(b) 16 -- Twenty-ninth Assignment of Availability Agreement, Consent
and Agreement, dated as of April 1, 1994, with United States
Trust Company of New York and Gerard F. Ganey as Trustees (B-
2(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946).
(b) 17 -- Capital Funds Agreement, dated June 21, 1974, between Entergy
Corporation and System Energy (C to Rule 24 Certificate,
dated June 24, 1974, in 70-5399).
(b) 18 -- First Amendment to Capital Funds Agreement, dated as of June
1, 1989 (B to Rule 24 Certificate, dated June 8, 1989, in
70-5399).
(b) 19 -- Fourteenth Supplementary Capital Funds Agreement and
Assignment, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-4(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(b) 20 -- Fifteenth Supplementary Capital Funds Agreement and
Assignment, dated as of May 1, 1986, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-4(b) to Rule 24 Certificate,
dated June 5, 1986, in 70-7158).
(b) 21 -- Sixteenth Supplementary Capital Funds Agreement and
Assignment, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (D to
Rule 24 Certificate, dated June 4, 1986, in 70-7123).
(b) 22 -- Eighteenth Supplementary Capital Funds Agreement and
Assignment, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(D-2 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(b) 23 -- Nineteenth Supplementary Capital Funds Agreement and
Assignment, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(D-3 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(b) 24 -- Twenty-fourth Supplementary Capital Funds Agreement and
Assignment, dated as of July 1, 1992, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(B-3(b) to Rule 24 Certificate dated July 14, 1992, in
70-7946).
(b) 25 -- Twenty-fifth Supplementary Capital Funds Agreement and
Assignment, dated as of October 1, 1992, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(B-3(b) to Rule 24 Certificate dated November 2, 1992, in
70-7946).
(b) 26 -- Twenty-sixth Supplementary Capital Funds Agreement and
Assignment, dated as of October 1, 1992, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(B-3(c) to Rule 24 Certificate dated November 2, 1992, in
70-7946).
(b) 27 -- Twenty-seventh Supplementary Capital Funds Agreement and
Assignment, dated as of April 1, 1993, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (B-
3(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(b) 28 -- Twenty-eighth Supplementary Capital Funds Agreement and
Assignment, dated as of December 17, 1993, with Chemical
Bank, as Agent (B-3(a) to Rule 24 Certificate dated December
22, 1993 in 70-7561).
(b) 29 -- Twenty-ninth Supplementary Capital Funds Agreement and
Assignment; dated as of April 1, 1994, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (B-
2(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946).
(b) 30 -- First Amendment to Supplementary Capital Funds Agreements and
Assignments, dated as of June 1, 1989, by and between Entergy
Corporation, System Energy, Deposit Guaranty National Bank,
United States Trust Company of New York and Gerard F. Ganey,
as Trustees (C to Rule 24 Certificate, dated June 8, 1989, in
70-7026).
(b) 31 -- First Amendment to Supplementary Capital Funds Agreements and
Assignments, dated as of June 1, 1989, by and between Entergy
Corporation, System Energy, United States Trust Company of
New York and Gerard F. Ganey, as Trustees (C to Rule 24
Certificate, dated June 8, 1989, in 70-7123).
(b) 32 -- First Amendment to Supplementary Capital Funds Agreement and
Assignment, dated as of June 1, 1989, by and between Entergy
Corporation, System Energy and Chemical Bank (C to Rule 24
Certificate, dated June 8, 1989, in 70-7561).
(b) 33 -- Reallocation Agreement, dated as of July 28, 1981, among
System Energy and certain other System companies (B-1(a) in
70-6624).
(b) 34 -- Joint Construction, Acquisition and Ownership Agreement,
dated as of May 1, 1980, between System Energy and SMEPA
(B-1(a) in 70-6337), as amended by Amendment No. 1, dated as
of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated
as of October 31, 1980 (1 to Rule 24 Certificate, dated
October 30, 1981, in 70-6337).
(b) 35 -- Operating Agreement, dated as of May 1, 1980, between System
Energy and SMEPA (B(2)(a) in 70-6337).
(b) 36 -- Installment Sale Agreement, dated as of December 1, 1983
between System Energy and Claiborne County, Mississippi (B-1
to First Rule 24 Certificate in 70-6913).
(b) 37 -- Installment Sale Agreement, dated as of June 1, 1984, between
System Energy and Claiborne County, Mississippi (B-2 to
Second Rule 24 Certificate in 70-6913).
(b) 38 -- Installment Sale Agreement, dated as of December 1, 1984,
between System Energy and Claiborne County, Mississippi (B-1
to First Rule 24 Certificate in 70-7026).
(b) 39 -- Installment Sale Agreement, dated as of June 15, 1985,
between System Energy and Claiborne County, Mississippi
(B-1(b) to Third Rule 24 Certificate in 70-7026).
(b) 40 -- Installment Sale Agreement, dated as of May 1, 1986, between
System Energy and Claiborne County, Mississippi (B-1(b) to
Rule 24 Certificate in 70-7158).
(b) 41 -- Facility Lease No. 1, dated as of December 1, 1988, between
Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba,
successor), as Owner Trustees, and System Energy (B-2(c)(1)
to Rule 24 Certificate dated January 9, 1989 in 70-7561), as
supplemented by Lease Supplement No. 1 dated as of April 1,
1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989
in 70-7561) and Lease Supplement No. 2 dated as of January 1,
1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in
70-8215).
(b) 42 -- Facility Lease No. 2, dated as of December 1, 1988 between
Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba,
successor), as Owner Trustees, and System Energy (B-2(c)(2)
to Rule 24 Certificate dated January 9, 1989 in 70-7561), as
supplemented by Lease Supplement No. 1 dated as of April 1,
1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989
in 70-7561) and Lease Supplement No. 2 dated as of January 1,
1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-
8215).
(b) 43 -- Assignment, Assumption and Further Agreement No. 1, dated as
of December 1, 1988, among System Energy, Meridian Trust
Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24
Certificate, dated January 9, 1989, in 70-7561).
(b) 44 -- Assignment, Assumption and Further Agreement No. 2, dated as
of December 1, 1988, among System Energy, Meridian Trust
Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24
Certificate, dated January 9, 1989, in 70-7561).
(b) 45 -- Collateral Trust Indenture, dated as of January 1, 1994,
among System Energy, GG1B Funding Corporation and Bankers
Trust Company, as Trustee (A-3(e) to Rule 24 Certificate
dated January 31, 1994, in 70-8215), as supplemented by
Supplemental Indenture No. 1 dated January 1, 1994, (A-3(f)
to Rule 24 Certificate dated January 31, 1994, in 70-8215).
(b) 46 -- Substitute Power Agreement, dated as of May 1, 1980, among
MP&L, System Energy and SMEPA (B(3)(a) in 70-6337).
(b) 47 -- Grand Gulf Unit No. 2 Supplementary Agreement, dated as of
February 7, 1986, between System Energy and SMEPA (10(aaa) in
33-4033).
(b) 48 -- Unit Power Sales Agreement, dated as of June 10, 1982,
between System Energy and AP&L, LP&L, MP&L and NOPSI
(10(a)-39 to Form 10-K for the fiscal year ended December 31,
1982, in 1-3517).
(b) 49 -- First Amendment to the Unit Power Sales Agreement, dated as
of June 28, 1984, between System Energy and AP&L, LP&L, MP&L
and NOPSI (19 to Form 10-Q for the quarter ended
September 30, 1984, in 1-3517).
(b) 50 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(b) 51 -- Fuel Lease, dated as of March 3, 1989, between River Fuel
Funding Company #3, Inc. and System Energy (B-1(b) to Rule 24
Certificate, dated March 3, 1989, in 70-7604).
(b) 52 -- Sales Agreement, dated as of June 21, 1974, between System
Energy and MP&L (D to Rule 24 Certificate, dated June 26,
1974, in 70-5399).
(b) 53 -- Service Agreement, dated as of June 21, 1974, between System
Energy and MP&L (E to Rule 24 Certificate, dated June 26,
1974, in 70-5399).
(b) 54 -- Partial Termination Agreement, dated as of December 1, 1986,
between System Energy and MP&L (A-2 to Rule 24 Certificate,
dated January 8, 1987, in 70-5399).
(b) 55 -- Middle South Utilities, Inc. and Subsidiary Companies
Intercompany Income Tax Allocation Agreement, dated April 28,
1988 (D-1 to Form U5S for the year ended December 31, 1987).
(b) 56 -- First Amendment, dated January 1, 1990 to the Middle South
Utilities Inc. and Subsidiary Companies Intercompany Income
Tax Allocation Agreement (D-2 to Form U5S for the year ended
December 31, 1989).
(b) 57 -- Second Amendment dated January 1, 1992, to the Entergy
Corporation and Subsidiary Companies Intercompany Income Tax
Allocation Agreement (D-3 to Form U5S for the year ended
December 31, 1992).
(b) 58 -- Third Amendment dated January 1, 1994 to Entergy Corporation
and Subsidiary Companies Intercompany Income Tax Allocation
Agreement (D-3(a) to Form U5S for the year ended December 31,
1993).
(b) 59 -- Service Agreement with Entergy Services, dated as of July 16,
1974, as amended (10(b)-43 to Form 10-K for the fiscal year
ended December 31, 1988, in 1-9067).
(b) 60 -- Amendment, dated January 1, 1991, to Service Agreement with
Entergy Services (10(b)-45 to Form 10-K for the fiscal year
ended December 31, 1990, in 1-9067).
(b) 61 -- Operating Agreement between Entergy Operations and System
Energy, dated as of June 6, 1990 (B-3(b) to Rule 24
Certificate, dated June 15, 1990, in 70-7679).
(b) 62 -- Guarantee Agreement between Entergy Corporation and System
Energy, dated as of September 20, 1990 (B-3(a) to Rule 24
Certificate, dated September 27, 1990, in 70-7757).
+(b) 63 -- Agreement between System Energy and Donald C. Hintz (10(b)47
to Form 10-K for the year ended December 31, 1991, in
1-9067).
+(b) 64 -- Agreement between Entergy Corporation and Edwin Lupberger
(10(a)-42 to Form 10-K for the year ended December 31, 1985
in 1-3517).
+(b) 65 -- Agreement between Entergy Services and Gerald D. McInvale
(10(a)-69 to Form 10-K for the year ended December 31, 1992
in 1-3517).
AP&L
(c) 1 -- Agreement, dated April 23, 1982, among AP&L and certain other
System companies, relating to System Planning and Development
and Intra-System Transactions (10(a) 1 to Form 10-K for the
fiscal year ended December 31, 1982, in 1-3517).
(c) 2 -- Middle South Utilities System Agency Agreement, dated
December 11, 1970 (5(a)2 in 2-41080).
(c) 3 -- Amendment, dated February 10, 1971, to Middle South Utilities
System Agency Agreement, dated December 11, 1970 (5(a)-4 in
2-41080).
(c) 4 -- Amendment, dated May 12, 1988, to Middle South Utilities
System Agency Agreement, dated December 11, 1970 (5(a) 4 in
2-41080).
(c) 5 -- Middle South Utilities System Agency Coordination Agreement,
dated December 11, 1970 (5(a)-3 in 2-41080).
(c) 6 -- Service Agreement with Entergy Services, dated as of April 1,
1963 (5(a)-5 in 2-41080).
(c) 7 -- Amendment, dated January 1, 1972, to Service Agreement with
Entergy Services (5(a)- 6 in 2-43175).
(c) 8 -- Amendment, dated April 27, 1984, to Service Agreement, with
Entergy Services (10(a)- 7 to Form 10-K for the fiscal year
ended December 31, 1984, in 1-3517).
(c) 9 -- Amendment, dated August 1, 1988, to Service Agreement with
Entergy Services (10(c)- 8 to Form 10-K for the fiscal year
ended December 31, 1988, in 1-10764).
(c) 10 -- Amendment, dated January 1, 1991, to Service Agreement with
Entergy Services (10(c)-9 to Form 10-K for the fiscal year
ended December 31, 1990, in 1-10764).
*(c) 11 -- Amendment, dated January 1, 1992, to Service Agreement with
Entergy Services.
(c) 12 -- Availability Agreement, dated June 21, 1974, among System
Energy and certain other System companies (B to Rule 24
Certificate, dated June 24, 1974, in 70-5399).
(c) 13 -- First Amendment to Availability Agreement, dated June 30,
1977 (B to Rule 24 Certificate, dated June 24, 1977, in
70-5399).
(c) 14 -- Second Amendment to Availability Agreement, dated as of June
15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in
70-6592).
(c) 15 -- Third Amendment to Availability Agreement, dated as of June
28, 1984 (B-13(a) to Rule 24 Certificate, dated July 6, 1984,
in 70-6985).
(c) 16 -- Fourth Amendment to Availability Agreement, dated as of June
1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in
70-5399).
(c) 17 -- Fourteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(c) 18 -- Fifteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with Deposit Guaranty
National Bank, United States Trust Company of New York, and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated June 5, 1986, in 70-7158).
(c) 19 -- Sixteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (C to
Rule 24 Certificate, dated June 4, 1986, in 70-7123).
(c) 20 -- Eighteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-2 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(c) 21 -- Nineteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-3 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(c) 22 -- Twentieth Assignment of Availability Agreement, Consent and
Agreement, dated as of November 15, 1987, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-1 to Rule 24 Certificate, dated December 1, 1987, in
70-7382).
(c) 23 -- Twenty-first Assignment of Availability Agreement, Consent
and Agreement, dated as of December 1, 1987, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (C-2 to Rule 24 Certificate, dated December 1, 1987,
in 70-7382).
(c) 24 -- Twenty-third Assignment of Availability Agreement, Consent
and Agreement, dated as of January 11, 1991, with Chemical
Bank, as Agent (B-3(a) to Rule 24 Certificate, dated January
23, 1991, in 70-7561).
(c) 25 -- Twenty-fourth Assignment of Availability Agreement, Consent
and Agreement, dated as of July 1, 1992, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(B-2(b) to Rule 24 Certificate, dated July 14, 1992, in
70-7946).
(c) 26 -- Twenty-fifth Assignment of Availability Agreement, Consent
and Agreement, dated as of October 1, 1992, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (B-2(b) to Rule 24 Certificate, dated November 2,
1992, in 70-7946).
(c) 27 -- Twenty-sixth Assignment of Availability Agreement, Consent
and Agreement, dated as of October 1, 1992, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (B-2(c) to Rule 24 Certificate, dated November 2,
1992, in 70-7946).
(c) 28 -- Twenty-seventh Assignment of Availability Agreement, Consent
and Agreement, dated as of April 1, 1993, with United States
Trust Company of New York and Gerard F. Ganey as Trustees (B-
2(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(c) 29 -- Twenty-eighth Assignment of Availability Agreement, Consent
and Agreement, dated as of December 17, 1993, with Chemical
Bank, as Agent (B-2(a) to Rule 24 Certificate dated December
22, 1993 in 70-7561).
(c) 30 Twenty-ninth Assignment of Availability Agreement, Consent
and Agreement, dated as of April 1, 1994, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (B-
2(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946).
(c) 31 -- Agreement, dated August 20, 1954, between AP&L and the United
States of America (SPA)(13(h) in 2-11467).
(c) 32 -- Amendment, dated April 19, 1955, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-2 in
2-41080).
(c) 33 -- Amendment, dated January 3, 1964, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-3 in
2-41080).
(c) 34 -- Amendment, dated September 5, 1968, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-4 in
2-41080).
(c) 35 -- Amendment, dated November 19, 1970, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-5 in
2-41080).
(c) 36 -- Amendment, dated July 18, 1961, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-6 in
2-41080).
(c) 37 -- Amendment, dated December 27, 1961, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-7 in
2-41080).
(c) 38 -- Amendment, dated January 25, 1968, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-8 in
2-41080).
(c) 39 -- Amendment, dated October 14, 1971, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-9 in
2-43175).
(c) 40 -- Amendment, dated January 10, 1977, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-10 in
2-60233).
(c) 41 -- Agreement, dated May 14, 1971, between AP&L and the United
States of America (SPA) (5(e) in 2-41080).
(c) 42 -- Amendment, dated January 10, 1977, to the United States of
America (SPA) Contract, dated May 14, 1971 (5(e)-1 in
2-60233).
(c) 43 -- Contract, dated May 28, 1943, Amendment to Contract, dated
July 21, 1949, and Supplement to Amendment to Contract, dated
December 30, 1949, between AP&L and McKamie Gas Cleaning
Company; Agreements, dated as of September 30, 1965, between
AP&L and former stockholders of McKamie Gas Cleaning Company;
and Letter Agreement, dated June 22, 1966, by Humble Oil &
Refining Company accepted by AP&L on June 24, 1966 (5(k)-7 in
2-41080).
(c) 44 -- Agreement, dated April 3, 1972, between Entergy Services and
Gulf United Nuclear Fuels Corporation (5(l)-3 in 2-46152).
(c) 45 -- Fuel Lease, dated as of December 22, 1988, between River Fuel
Trust #1 and AP&L (B-1(b) to Rule 24 Certificate in 70-7571).
(c) 46 -- White Bluff Operating Agreement, dated June 27, 1977, among
AP&L and Arkansas Electric Cooperative Corporation and City
Water and Light Plant of the City of Jonesboro, Arkansas
(B-2(a) to Rule 24 Certificate, dated June 30, 1977, in
70-6009).
(c) 47 -- White Bluff Ownership Agreement, dated June 27, 1977, among
AP&L and Arkansas Electric Cooperative Corporation and City
Water and Light Plant of the City of Jonesboro, Arkansas
(B-1(a) to Rule 24 Certificate, dated June 30, 1977, in
70-6009).
(c) 48 -- Agreement, dated June 29, 1979, between AP&L and City of
Conway, Arkansas (5(r)-3 in 2-66235).
(c) 49 -- Transmission Agreement, dated August 2, 1977, between AP&L
and City Water and Light Plant of the City of Jonesboro,
Arkansas (5(r)-3 in 2-60233).
(c) 50 -- Power Coordination, Interchange and Transmission Service
Agreement, dated as of June 27, 1977, between Arkansas
Electric Cooperative Corporation and AP&L (5(r)-4 in
2-60233).
(c) 51 -- Independence Steam Electric Station Operating Agreement,
dated July 31, 1979, among AP&L and Arkansas Electric
Cooperative Corporation and City Water and Light Plant of the
City of Jonesboro, Arkansas and City of Conway, Arkansas
(5(r)-6 in 2-66235).
(c) 52 -- Amendment, dated December 4, 1984, to the Independence Steam
Electric Station Operating Agreement (10(c) 51 to Form 10-K
for the fiscal year ended December 31, 1984, in 1-10764).
(c) 53 -- Independence Steam Electric Station Ownership Agreement,
dated July 31, 1979, among AP&L and Arkansas Electric
Cooperative Corporation and City Water and Light Plant of the
City of Jonesboro, Arkansas and City of Conway, Arkansas
(5(r)-7 in 2-66235).
(c) 54 -- Amendment, dated December 28, 1979, to the Independence Steam
Electric Station Ownership Agreement (5(r)-7(a) in 2-66235).
(c) 55 -- Amendment, dated December 4, 1984, to the Independence Steam
Electric Station Ownership Agreement (10(c) 54 to Form 10-K
for the fiscal year ended December 31, 1984, in 1-10764).
(c) 56 -- Owner's Agreement, dated November 28, 1984, among AP&L, MP&L,
other co-owners of the Independence Station (10(c) 55 to Form
10-K for the fiscal year ended December 31, 1984, in
1-10764).
(c) 57 -- Consent, Agreement and Assumption, dated December 4, 1984,
among AP&L, MP&L, other co-owners of the Independence Station
and United States Trust Company of New York, as Trustee
(10(c) 56 to Form 10-K for the fiscal year ended December 31,
1984, in 1-10764).
(c) 58 -- Power Coordination, Interchange and Transmission Service
Agreement, dated as of July 31, 1979, between AP&L and City
Water and Light Plant of the City of Jonesboro, Arkansas
(5(r)-8 in 2-66235).
(c) 59 -- Power Coordination, Interchange and Transmission Agreement,
dated as of June 29, 1979, between City of Conway, Arkansas
and AP&L (5(r)-9 in 2-66235).
(c) 60 -- Agreement, dated June 21, 1979, between AP&L and Reeves E.
Ritchie ((10)(b)-90 to Form 10-K for the fiscal year ended
December 31, 1980, in 1-10764).
(c) 61 -- Reallocation Agreement, dated as of July 28, 1981, among
System Energy and certain other System companies (B-1(a) in
70-6624).
+(c) 62 -- Post-Retirement Plan (10(b) 55 to Form 10-K for the fiscal
year ended December 31, 1983, in 1-10764).
(c) 63 -- Unit Power Sales Agreement, dated as of June 10, 1982,
between System Energy and AP&L, LP&L, MP&L, and NOPSI (10(a)
39 to Form 10-K for the fiscal year ended December 31, 1982,
in 1-3517).
(c) 64 -- First Amendment to Unit Power Sales Agreement, dated as of
June 28, 1984, between System Energy, AP&L, LP&L, MP&L, and
NOPSI (19 to Form 10-Q for the quarter ended September 30,
1984, in 1-3517).
(c) 65 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(c) 66 -- Contract For Disposal of Spent Nuclear Fuel and/or High-Level
Radioactive Waste, dated June 30, 1983, among the DOE, System
Fuels and AP&L (10(b)-57 to Form 10-K for the fiscal year
ended December 31, 1983, in 1-10764).
(c) 67 -- Middle South Utilities, Inc. and Subsidiary Companies
Intercompany Income Tax Allocation Agreement, dated April 28,
1988 (D-1 to Form U5S for the year ended December 31, 1987).
(c) 68 -- First Amendment, dated January 1, 1990, to the Middle South
Utilities, Inc. and Subsidiary Companies Intercompany Income
Tax Allocation Agreement (D-2 to Form U5S for the year ended
December 31, 1989).
(c) 69 -- Second Amendment dated January 1, 1992, to the Entergy
Corporation and Subsidiary Companies Intercompany Income Tax
Allocation Agreement (D-3 to Form U5S for the year ended
December 31, 1992).
(c) 70 -- Third Amendment dated January 1, 1994, to Entergy Corporation
and Subsidiary Companies Intercompany Income Tax Allocation
Agreement (D-3(a) to Form U5S for the year ended December 31,
1993).
(c) 71 -- Assignment of Coal Supply Agreement, dated December 1, 1987,
between System Fuels and AP&L (B to Rule 24 letter filing,
dated November 10, 1987, in 70-5964).
(c) 72 -- Coal Supply Agreement, dated December 22, 1976, between
System Fuels and Antelope Coal Company (B-1 in 70-5964), as
amended by First Amendment (A to Rule 24 Certificate in
70-5964); Second Amendment (A to Rule 24 letter filing, dated
December 16, 1983, in 70-5964); and Third Amendment (A to
Rule 24 letter filing, dated November 10, 1987 in 70-5964).
(c) 73 -- Operating Agreement between Entergy Operations and AP&L,
dated as of June 6, 1990 (B-1(b) to Rule 24 Certificate,
dated June 15, 1990, in 70-7679).
(c) 74 -- Guaranty Agreement between Entergy Corporation and AP&L,
dated as of September 20, 1990 (B-1(a) to Rule 24
Certificate, dated September 27, 1990, in 70-7757).
(c) 75 -- Agreement for Purchase and Sale of Independence Unit 2
between AP&L and Entergy Power, dated as of August 28, 1990
(B-3(c) to Rule 24 Certificate, dated September 6, 1990, in
70-7684).
(c) 76 -- Agreement for Purchase and Sale of Ritchie Unit 2 between
AP&L and Entergy Power, dated as of August 28, 1990 (B-4(d)
to Rule 24 Certificate, dated September 6, 1990, in 70-7684).
(c) 77 -- Ritchie Steam Electric Station Unit No. 2 Operating Agreement
between AP&L and Entergy Power, dated as of August 28, 1990
(B-5(a) to Rule 24 Certificate, dated September 6, 1990, in
70-7684).
(c) 78 -- Ritchie Steam Electric Station Unit No. 2 Ownership Agreement
between AP&L and Entergy Power, dated as of August 28, 1990
(B-6(a) to Rule 24 Certificate, dated September 6, 1990, in
70-7684).
(c) 79 -- Power Coordination, Interchange and Transmission Service
Agreement between Entergy Power and AP&L, dated as of
August 28, 1990 (10(c)-71 to Form 10-K for the fiscal year
ended December 31, 1990, in 1-10764).
+(c) 80 -- Executive Financial Counseling Program of Entergy Corporation
and Subsidiaries (10(a)52 to Form 10-K for the year ended
December 31, 1989, in 1-3517).
+(c) 81 -- Entergy Corporation Annual Incentive Plan (10(a)54 to Form
10-K for the year ended December 31, 1989, in 1-3517).
+(c) 82 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries
(A-4(a) to Rule 24 Certificate, dated May 24, 1991, in
70-7831).
+(c) 83 -- Agreement between Arkansas Power & Light Company and R. Drake
Keith. (10(c) 78 to Form 10-K for the year ended December 31,
1992 in 1-10764).
+(c) 84 -- Supplemental Retirement Plan (10(a)69 to Form 10-K for the
year ended December 31, 1992 in 1-3517).
+(c) 85 -- Defined Contribution Restoration Plan of Entergy Corporation
and Subsidiaries (10(a)53 to Form 10-K for the year ended
December 31, 1989 in 1-3517).
+(c) 86 -- Amendment No. 1 to the Equity Ownership Plan of Entergy
Corporation and Subsidiaries (10(a)71 to Form 10-K for the
year ended December 31, 1992 in 1-3517).
+(c) 87 -- Executive Disability Plan of Entergy Corporation and
Subsidiaries (10(a)72 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(c) 88 -- Executive Medical Plan of Entergy Corporation and
Subsidiaries (10(a)73 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(c) 89 -- Stock Plan for Outside Directors of Entergy Corporation and
Subsidiaries, as amended (10(a)74 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(c) 90 -- Summary Description of Private Ownership Vehicle Plan of
Entergy Corporation and Subsidiaries (10(a)75 to Form 10-K
for the year ended December 31, 1992 in 1-3517).
+(c) 91 -- Agreement between Entergy Corporation and Edwin Lupberger
(10(a)-42 to Form 10-K for the year ended December 31, 1985
in 1-3517).
+(c) 92 -- Agreement between Entergy Corporation and Jerry D. Jackson
(10(a)-68 to Form 10-K for the year ended December 31, 1992
in 1-3517).
+(c) 93 -- Agreement between Entergy Services and Gerald D. McInvale
(10(a)-69 to Form 10-K for the year ended December 31, 1992
in 1-3517).
+(c) 94 -- Agreement between System Energy and Donald C. Hintz (10(b)-47
to Form 10-K for the year ended December 31, 1991 in 1-9067).
+(c) 95 -- Summary Description of Retired Outside Director Benefit Plan.
(10(c) 90 to Form 10-K for the year ended December 31, 1992
in 1-10764).
+(c) 96 -- Amendment to Defined Contribution Restoration Plan of Entergy
Corporation and Subsidiaries (10(a) 81 to Form 10-K for the
year ended December 31, 1993 in 1-11299).
+(c) 97 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for
the year ended December 31, 1993 in 1-11299).
(c) 98 -- Loan Agreement dated June 15, 1993, between AP&L and
Independence Country, Arkansas (B-1 (a) to Rule 24
Certificate dated July 9, 1993 in 70-8171).
(c) 99 -- Installment Sale Agreement dated January 1, 1991, between
AP&L and Pope Country, Arkansas (B-1 (b) to Rule 24
Certificate dated January 24, 1991 in 70-7802).
(c) 100 -- Installment Sale Agreement dated November 1, 1990, between
AP&L and Pope Country, Arkansas (B-1 (a) to Rule 24
Certificate dated November 30, 1990 in70-7802).
(c) 101 -- Installment Sale Agreement dated December 1, 1985, between
AP&L and Pople Country, Arkansas (B-1(a) to Rule 24
Certificate dated December 19, 1985 in 70-7127).
(c) 102 -- Loan Agreement dated June 15, 1994, between AP&L and
Jefferson County, Arkansas (B-1(a) to Rule 24 Certificate
dated June 30, 1994 in 70-8405).
(c) 103 -- Loan Agreement dated June 15, 1994, between AP&L and Pope
County, Arkansas (B-1(b) to Rule 24 Certificate in 70-8405).
GSU
(d) 1 -- Guaranty Agreement, dated July 1, 1976, between GSU and
American Bank and Trust Company (C and D to Form 8-K, dated
August 6, 1976 in 1-2703).
(d) 2 -- Lease of Railroad Equipment, dated as of December 1, 1981,
between The Connecticut Bank and Trust Company as Lessor and
GSU as Lessee and First Supplement, dated as of December 31,
1981, relating to 605 One Hundred-Ton Unit Train Steel Coal
Porter Cars (4-12 to Form 10-K for the year ended December
31, 1981 in 1-2703).
(d) 3 -- Guaranty Agreement, dated August 1, 1992, between GSU and
Hibernia National Bank, relating to Pollution Control Revenue
Refunding Bonds of the Industrial Development Board of the
Parish of Calcasieu, Inc. (Louisiana) (10-1 to Form 10-K for
the year ended December 31, 1992 in 1-2703).
(d) 4 -- Guaranty Agreement, dated January 1, 1993, between GSU and
Hancock Bank of Louisiana, relating to Pollution Control
Revenue Refunding Bonds of the Parish of Pointe Coupee
(Louisiana) (10-2 to Form 10-K for the year ended December
31, 1992 in 1-2703).
(d) 5 -- Deposit Agreement, dated as of December 1, 1983 between GSU,
Morgan Guaranty Trust Co. as Depositary and the Holders of
Despositary Receipts, relating to the Issue of 900,000
Depositary Preferred Shares, each representing 1/2 share of
Adjustable Rate Cumulative Preferred Stock, Series E-$100 Par
Value (4-17 to Form 10-K for the year ended December 31, 1983
in 1-2703).
(d) 6 -- Letter of Credit and Reimbursement Agreement, dated December
27, 1985, between GSU and Westpack Banking Corporation
relating to Variable Rate Demand Pollution Control Revenue
Bonds of the Parish of West Feliciana, State of Louisiana,
Series 1985-D (4-26 to Form 10-K for the year ended December
31, 1985 in 1-2703) and Letter Agreement amending same dated
October 20, 1992 (10-3 to Form 10-K for the year ended
December 31, 1992 in 1-2703).
(d) 7 -- Reimbursement and Loan Agreement, dated as of April 23, 1986,
by and between GSU and The Long-Term Credit Bank of Japan,
Ltd., relating to Multiple Rate Demand Pollution Control
Revenue Bonds of the Parish of West Feliciana, State of
Louisiana, Series 1985 (4-26 to Form 10-K, for the year ended
December 31, 1986 in 1-2703) and Letter Agreement amending
same, dated February 19, 1993 (10 to Form 10-K for the year
ended December 31, 1992 in 1-2703).
(d) 8 -- Agreement effective February 1, 1964, between Sabine River
Authority, State of Louisiana, and Sabine River Authority of
Texas, and GSU, Central Louisiana Electric Company, Inc., and
Louisiana Power & Light Company, as supplemented (B to Form 8-
K, dated May 6, 1964, A to Form 8-K, dated October 5, 1967, A
to Form 8-K, dated May 5, 1969, and A to Form 8-K, dated
December 1, 1969, in 1-2708).
(d) 9 -- Joint Ownership Participation and Operating Agreement
regarding River Bend Unit 1 Nuclear Plant, dated August 20,
1979, between GSU, Cajun, and SRG&T; Power Interconnection
Agreement with Cajun, dated June 26, 1978, and approved by
the REA on August 16, 1979, between GSU and Cajun; and Letter
Agreement regarding CEPCO buybacks, dated August 28, 1979,
between GSU and Cajun (2, 3, and 4, respectively, to Form 8-
K, dated September 7, 1979, in 1-2703).
(d) 10 -- Ground Lease, dated August 15, 1980, between Statmont
Associates Limited Partnership (Statmont) and GSU, as amended
(3 to Form 8-K, dated August 19, 1980, and A-3-b to Form 10-Q
for the quarter ended September 30, 1983 in 1-2703).
(d) 11 -- Lease and Sublease Agreement, dated August 15, 1980, between
Statmont and GSU, as amended (4 to Form 8-K, dated August 19,
1980, and A-3-c to Form 10-Q for the quarter ended September
30, 1983 in 1-2703).
(d) 12 -- Lease Agreement, dated September 18, 1980, between BLC
Corporation and GSU (1 to Form 8-K, dated October 6, 1980 in
1-2703).
(d) 13 -- Joint Ownership Participation and Operating Agreement for Big
Cajun, between GSU, Cajun Electric Power Cooperative, Inc.,
and Sam Rayburn G&T, Inc, dated November 14, 1980 (6 to Form
8-K, dated January 29, 1981 in 1-2703); Amendment No. 1,
dated December 12, 1980 (7 to Form 8-K, dated January 29,
1981 in 1-2703); Amendment No. 2, dated December 29, 1980 (8
to Form 8-K, dated January 29, 1981 in 1-2703).
(d) 14 -- Agreement of Joint Ownership Participation between SRMPA,
SRG&T and GSU, dated June 6, 1980, for Nelson Station, Coal
Unit #6, as amended (8 to Form 8-K, dated June 11, 1980, A-2-
b to Form 10-Q For the quarter ended June 30, 1982; and 10-1
to Form 8-K, dated February 19, 1988 in 1-2703).
(d) 15 -- Agreements between Southern Company and GSU, dated February
25, 1982, which cover the construction of a 140-mile
transmission line to connect the two systems, purchase of
power and use of transmission facilities (10-31 to Form 10-K,
for the year ended December 31, 1981 in 1-2703).
+(d) 16 -- Executive Income Security Plan, effective October 1, 1980, as
amended, continued and completely restated effective as of
March 1, 1991 (10-2 to Form 10-K for the year ended December
31, 1991 in 1-2703).
(d) 17 -- Joint Ownership Participation Agreement for Big Cajun between
GSU, Cajun, and SRG&T, dated November 14, 1980 (6 to Form 8-
K, dated January 29, 1981 in 1-2703).
(d) 18 -- Amendment No. 1 to the Joint Ownership Participation
Agreement for Big Cajun, between GSU, Cajun, and SRG&T, dated
December 12, 1980 (7 to Form 8-K, dated January 29, 1981 in 1-
2703).
(d) 19 -- Amendment No. 2 to the Joint Ownership Participation
Agreement for Big Cajun, between GSU, Cajun, and SRG&T, dated
December 29, 1980 (8 to Form 8-K, dated January 29, 1981 in 1-
2703).
(d) 20 -- Transmission Facilities Agreement between GSU and Mississippi
Power Company, dated February 28, 1982, and Amendment, dated
May 12, 1982 (A-2-c to Form 10-Q for the quarter ended March
31, 1982 in 1-2703) and Amendment, dated December 6, 1983 (10-
43 to Form 10-K, for the year ended December 31, 1983 in 1-
2703).
(d) 21 -- Lease Agreement dated as of June 29, 1983, between GSU and
City National Bank of Baton Rouge, as Owner Trustee, in
connection with the leasing of a Simulator and Training
Center for River Bend Unit 1 (A-2-a to Form 10-Q for the
quarter ended June 30, 1983 in 1-2703) and Amendment, dated
December 14, 1984 (10-55 to Form 10-K, for the year ended
December 31, 1984 in 1-2703).
(d) 22 -- Participation Agreement, dated as of June 29, 1983, among
GSU, City National Bank of Baton Rouge, PruFunding, Inc. Bank
of the Southwest National Association, Houston and Bankers
Life Company, in connection with the leasing of a Simulator
and Training Center of River Bend Unit 1 (A-2-b to Form 10-Q
for the quarter ended June 30, 1983 in 1-2703).
(d) 23 -- Tax Indemnity Agreement, dated as of June 29, 1983, between
GSU and Prufunding, Inc., in connection with the leasing of a
Simulator and Training Center for River Bend Unit I (A-2-c to
Form 10-Q for the quarter ended June 30, 1993 in 1-2703).
(d) 24 -- Agreement to Lease, dated as of August 28, 1985, among GSU,
City National Bank of Baton Rouge, as Owner Trustee, and
Prudential Interfunding Corp., as Trustor, in connection with
the leasing of improvement to a Simulator and Training
Facility for River Bend Unit I (10-69 to Form 10-K, for the
year ended December 31, 1985 in 1-2703).
(d) 25 -- First Amended Power Sales Agreement, dated December 1, 1985
between Sabine River Authority, State of Louisiana, and
Sabine River Authority, State of Texas, and GSU, Central
Louisiana Electric Co., Inc., and Louisiana Power and Light
Company (10-72 to Form 10-K for the year ended December 31,
1985 in 1-2703).
+(d) 26 -- Deferred Compensation Plan for Directors of GSU and Varibus
Corporation, as amended January 8, 1987, and effective
January 1, 1987 (10-77 to Form 10-K for the year ended
December 31, 1986 in 1-2703). Amendment dated December 4,
1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).
+(d) 27 -- Trust Agreement for Deferred Payments to be made by GSU
pursuant to the Executive Income Security Plan, by and
between GSU and Bankers Trust Company, effective November 1,
1986 (10-78 to Form 10-K for the year ended December 31, 1986
in 1-2703).
+(d) 28 -- Trust Agreement for Deferred Installments under GSU's
Management Incentive Compensation Plan and Administrative
Guidelines by and between GSU and Bankers Trust Company,
effective June 1, 1986 (10-79 to Form 10-K for the year ended
December 31, 1986 in 1-2703).
+(d) 29 -- Nonqualified Deferred Compensation Plan for Officers,
Nonemployee Directors and Designated Key Employees, effective
December 1, 1985, as amended, continued and completely
restated effective as of March 1, 1991 (10-3 to Amendment No.
8 in Registration No. 2-76551).
+(d) 30 -- Trust Agreement for GSU's Nonqualified Directors and
Designated Key Employees by and between GSU and First City
Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank),
effective July 1, 1991 (10-4 to Form 10-K for the year ended
December 31, 1992 in 1-2703).
(d) 31 -- Lease Agreement, dated as of June 29, 1987, among GSG&T,
Inc., and GSU related to the leaseback of the Lewis Creek
generating station (10-83 to Form 10-K for the year ended
December 31, 1988 in 1-2703).
(d) 32 -- Nuclear Fuel Lease Agreement between GSU and River Bend Fuel
Services, Inc. to lease the fuel for River Bend Unit 1, dated
February 7, 1989 (10-64 to Form 10-K for the year ended
December 31, 1988 in 1-2703).
(d) 33 -- Trust and Investment Management Agreement between GSU and
Morgan Guaranty and Trust Company of New York with respect to
decommissioning funds authorized to be collected by GSU,
dated March 15, 1989 (10-66 to Form 10-K for the year ended
December 31, 1988 in 1-2703).
*(d) 34 -- Credit Agreement, dated as of December 29, 1993, among River
Bend Fuel Services, Inc. and Certain Commercial Lending
Institutions and CIBC Inc. as Agent for the Lenders.
(d) 35 -- Partnership Agreement by and among Conoco Inc., and GSU,
CITGO Petroleum Corporation and Vista Chemical Company, dated
April 28, 1988 (10-67 to Form 10-K for the year ended
December 31, 1988 in 1-2703).
+(d) 36 -- Gulf States Utilities Company Executive Continuity Plan,
dated January 18, 1991 (10-6 to Form 10-K for the year ended
December 31, 1990 in 1-2703).
+(d) 37 -- Trust Agreement for GSU's Executive Continuity Plan, by and
between GSU and First City Bank, Texas-Beaumont, N.A. (now
Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10-
K for the year ended December 31, 1992 in 1-2703).
+(d) 38 -- Gulf States Utilities Board of Directors' Retirement Plan,
dated February 15, 1991 (10-8 to Form 10-K for the year ended
December 31, 1990 in 1-2703).
+(d) 39 -- Gulf States Utilities Company Employees' Trustee Retirement
Plan effective July 1, 1955 as amended, continued and
completely restated effective January 1, 1989; and Amendment
No.1 effective January 1, 1993 (10-6 to Form 10-K for the
year ended December 31, 1992 in 1-2703).
(d) 40 -- Agreement and Plan of Reorganization, dated June 5, 1992,
between GSU and Entergy Corporation (2 to Form 8-K, dated
June 8, 1992 in 1-2703).
+(d) 41 -- Gulf States Utilities Company Employee Stock Ownership Plan,
as amended, continued, and completely restated effective
January 1, 1984, and January 1, 1985 (A to Form 11-K, dated
December 31, 1985 in 1-2703).
+(d) 42 -- Trust Agreement under the Gulf States Utilities Company
Employee Stock Ownership Plan, dated December 30, 1976,
between GSU and the Louisiana National Bank, as Trustee (2-A
to Registration No. 2-62395).
+(d) 43 -- Letter Agreement dated September 7, 1977 between GSU and the
Trustee, delegating certain of the Trustee's functions to the
ESOP Committee (2-B to Registration Statement No. 2-62395).
+(d) 44 -- Gulf States Utilities Company Employees Thrift Plan as
amended, continued and completely restated effective as of
January 1, 1992 (28-1 to Amendment No. 8 to Registration No.
2-76551).
+(d) 45 -- Restatement of Trust Agreement under the Gulf States
Utilities Company Employees Thrift Plan, reflecting changes
made through January 1, 1989, between GSU and First City
Bank, Texas-Beaumont, N.A., (now Texas Commerce Bank ), as
Trustee (2-A to Form 8-K dated October 20, 1989 in 1-2703).
(d) 46 -- Operating Agreement between Entergy Operations and GSU, dated
as of December 31, 1993 (B-2(f) to Rule 24 Certificate in 70-
8059).
(d) 47 -- Guarantee Agreement between Entergy Corporation and GSU,
dated as of December 31, 1993 (B-5(a) to Rule 24 Certificate
in 70-8059).
(d) 48 -- Service Agreement with Entergy Services, dated as of December
31, 1993 (B-6(c) to Rule 24 Certificate in 70-8059).
+(d) 49 -- Amendment to Employment Agreement between J. L. Donnelly and
GSU, dated December 22, 1993 (10(d) 57 to Form 10-K for the
year ended December 31, 1993 in 1-2703).
(d) 50 -- Amendment to Letter of Credit and Reimbursement Agreement
between GSU and Westpac Banking Corporation (10(d) 58 to Form
10-K for the year ended December 31, 1993 in 1-2703).
(d) 51 -- Third Amendment, dated January 1, 1994, to Entergy
Corporation and Subsidiary Companies Intercompany Income Tax
Allocation Agreement (D-3(a) to Form U5S for the year ended
December 31, 1993).
(d) 52 -- Refunding Agreement between GSU and West Feliciana Parish
(dated December 20, 1994 (B-12(a) to Rule 24 Certificate
dated December 30, 1994 in 70-8375).
LP&L
(e) 1 -- Agreement, dated April 23, 1982, among LP&L and certain other
System companies, relating to System Planning and Development
and Intra-System Transactions (10(a) 1 to Form 10-K for the
fiscal year ended December 31, 1982, in 1-3517).
(e) 2 -- Middle South Utilities System Agency Agreement, dated
December 11, 1970 (5(a)-2 in 2-41080).
(e) 3 -- Amendment, dated as of February 10, 1971, to Middle South
Utilities System Agency Agreement, dated December 11, 1970
(5(a)-4 in 2-41080).
(e) 4 -- Amendment, dated May 12, 1988, to Middle South Utilities
System Agency Agreement, dated December 11, 1970 (5(a) 4 in
2-41080).
(e) 5 -- Middle South Utilities System Agency Coordination Agreement,
dated December 11, 1970 (5(a)-3 in 2-41080).
(e) 6 -- Service Agreement with Entergy Services, dated as of April 1,
1963 (5(a)-5 in 2-42523).
(e) 7 -- Amendment, dated as of January 1, 1972, to Service Agreement
with Entergy Services (4(a)-6 in 2-45916).
(e) 8 -- Amendment, dated as of April 27, 1984, to Service Agreement
with Entergy Services (10(a) 7 to Form 10-K for the fiscal
year ended December 31, 1984, in 1-3517).
(e) 9 -- Amendment, dated as of August 1, 1988, to Service Agreement
with Entergy Services (10(d)-8 to Form 10-K for the fiscal
year ended December 31, 1988, in 1-8474).
(e) 10 -- Amendment, dated January 1, 1991, to Service Agreement with
Entergy Services (10(d)-9 to Form 10-K for the fiscal year
ended December 31, 1990, in 1-8474).
*(e) 11 -- Amendment, dated January 1, 1992, to Service Agreement with
Entergy Services.
(e) 12 -- Availability Agreement, dated June 21, 1974, among System
Energy and certain other System companies (B to Rule 24
Certificate, dated June 24, 1974, in 70-5399).
(e) 13 -- First Amendment to Availability Agreement, dated as of June
30, 1977 (B to Rule 24 Certificate, dated June 30, 1977, in
70-5399).
(e) 14 -- Second Amendment to Availability Agreement, dated as of June
15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in
70-6592).
(e) 15 -- Third Amendment to Availability Agreement, dated as of June
28, 1984 (B-13(a) to Rule 24 Certificate, dated July 6, 1984,
in 70-6985).
(e) 16 -- Fourth Amendment to Availability Agreement, dated as of June
1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in
70-5399).
(e) 17 -- Fourteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(e) 18 -- Fifteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York, Malcolm J. Hood, and Deposit Guaranty
National Bank, as Trustees (B-3(b) to Rule 24 Certificate,
dated June 5, 1986, in 70-7158).
(e) 19 -- Sixteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (C to
Rule 24 Certificate, dated June 4, 1986, in 70-7123).
(e) 20 -- Eighteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-2 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(e) 21 -- Nineteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-3 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(e) 22 -- Twentieth Assignment of Availability Agreement, Consent and
Agreement, dated as of November 16, 1987, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-1 to Rule 24 Certificate, dated December 1, 1987, in
70-7382).
(e) 23 -- Twenty-first Assignment of Availability Agreement, Consent
and Agreement, dated as of December 1, 1987, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (C-2 to Rule 24 Certificate, dated December 1, 1987,
in 70-7382).
(e) 24 -- Twenty-third Assignment of Availability Agreement, Consent
and Agreement, dated as of January 11, 1991, with Chemical
Bank, as Agent (B-3(a) to Rule 24 Certificate, dated January
23, 1991, in 70-7561).
(e) 25 -- Twenty-fourth Assignment of Availability Agreement, Consent
and Agreement, dated as of July 1, 1992, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(B-2(b) to Rule 24 Certificate, dated July 14, 1992, in
70-7946).
(e) 26 -- Twenty-fifth Assignment of Availability Agreement, Consent
and Agreement, dated as of October 1, 1992, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (B-2(b) to Rule 24 Certificate, dated November 2,
1992, in 70-7946).
(e) 27 -- Twenty-sixth Assignment of Availability Agreement, Consent
and Agreement, dated as of October 1, 1992, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (B-2(c) to Rule 24 Certificate, dated November 2,
1992, in 70-7946).
(e) 28 -- Twenty-seventh Assignment of Availability Agreement, Consent
and Agreement, dated as of April 1, 1993, with United States
Trust Company of New York and Gerard F. Ganey as Trustees (B-
2(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(e) 29 -- Twenty-eighth Assignment of Availability Agreement, Consent
and Agreement, dated as of December 17,1993, with Chemical
Bank, as Agent (B-2(a) to Rule 24 Certificate dated December
22, 1993 in 70-7561).
(e) 30 -- Twenty-ninth Assignment of Availability Agreement, Consent
and Agreement, dated as of April 1, 1994, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees,
(B-2(f) to Rule 24 Certificate dated May 6, 1994 in 70-7946).
(e) 31 -- Fuel Lease, dated as of January 31, 1989, between River Fuel
Company #2, Inc., and LP&L (B-1(b) to Rule 24 Certificate in
70-7580).
(e) 32 -- Reallocation Agreement, dated as of July 28, 1981, among
System Energy and certain other System companies (B-1(a) in
70-6624).
(e) 33 -- Compromise and Settlement Agreement, dated June 4, 1982,
between Texaco, Inc. and LP&L (28(a) to Form 8-K, dated June
4, 1982, in 1-8474).
+(e) 34 -- Post-Retirement Plan (10(c)23 to Form 10-K for the year ended
December 31, 1983, in 1-8474).
(e) 35 -- Unit Power Sales Agreement, dated as of June 10, 1982,
between System Energy and AP&L, LP&L, MP&L and NOPSI (10(a)
39 to Form 10-K for the fiscal year ended December 31, 1982,
in 1-3517).
(e) 36 -- First Amendment to the Unit Power Sales Agreement, dated as
of June 28, 1984, between System Energy and AP&L, LP&L, MP&L
and NOPSI (19 to Form 10-Q for the quarter ended September
30, 1984, in 1-3517).
(e) 37 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(e) 38 -- Middle South Utilities, Inc. and Subsidiary Companies
Intercompany Tax Allocation Agreement, dated April 28, 1988
(D-1 to Form U5S for the year ended December 31, 1987).
(e) 39 -- First Amendment, dated January 1, 1990, to the Middle South
Utilities, Inc. and Subsidiary Companies Intercompany Income
Tax Allocation Agreement, dated January 1, 1990 (D-2 to
Form U5S for the year ended December 31, 1989).
(e) 40 -- Second Amendment dated January 1, 1992, to the Entergy
Corporation and Subsidiary Companies Intercompany Income Tax
Allocation Agreement (D-3 to Form U5S for the year ended
December 31, 1992).
(e) 41 -- Third Amendment dated January 1, 1994 to Entergy Corporation
and Subsidiary Companies Intercompany Income Tax Allocation
Agreement (D-3(a) to Form U5S for the year ended December 31,
1993).
(e) 42 -- Contract for Disposal of Spent Nuclear Fuel and/or High-Level
Radioactive Waste, dated February 2, 1984, among DOE, System
Fuels and LP&L (10(d)33 to Form 10-K for the fiscal year
ended December 31, 1984, in 1-8474).
(e) 43 -- Operating Agreement between Entergy Operations and LP&L,
dated as of June 6, 1990 (B-2(c) to Rule 24 Certificate,
dated June 15, 1990, in 70-7679).
(e) 44 -- Guarantee Agreement between Entergy Corporation and LP&L,
dated as of September 20, 1990 (B-2(a), to Rule 24
Certificate, dated September 27, 1990, in 70-7757).
+(e) 45 -- Executive Financial Counseling Program of Entergy Corporation
and Subsidiaries (10(a) 52 to Form 10-K for the year ended
December 31, 1989, in 1-3517).
+(e) 46 -- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form
10-K for the year ended December 31, 1989, in 1-3517).
+(e) 47 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries
(A-4(a) to Rule 24 Certificate, dated May 24, 1991, in
70-7831).
+(e) 48 -- Supplemental Retirement Plan (10(a) 69 to Form 10-K for the
year ended December 31, 1992 in 1-3517).
+(e) 49 -- Defined Contribution Restoration Plan of Entergy Corporation
and Subsidiaries (10(a) 53 to Form 10-K for the year ended
December 31, 1989 in 1-3517).
+(e) 50 -- Amendment No. 1 to the Equity Ownership Plan of Entergy
Corporation and Subsidiaries (10(a) 71 to Form 10-K for the
year ended December 31, 1992 in 1-3517).
+(e) 51 -- Executive Disability Plan of Entergy Corporation and
Subsidiaries (10(a) 72 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(e) 52 -- Executive Medical Plan of Entergy Corporation and
Subsidiaries (10(a) 73 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(e) 53 -- Stock Plan for Outside Directors of Entergy Corporation and
Subsidiaries (10(a) 74 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(e) 54 -- Summary Description of Private Ownership Vehicle Plan of
Entergy Corporation and Subsidiaries (10(a) 75 to Form 10-K
for the year ended December 31, 1992 in 1-3517).
+(e) 55 -- Agreement between Entergy Corporation and Edwin Lupberger
(10(a) 42 to Form 10-K for the year ended December 31, 1985
in 1-3517).
+(e) 56 -- Agreement between Entergy Corporation and Jerry D. Jackson
(10(a) 68 to Form 10-K for the year ended December 31, 1992
in 1-3517).
+(e) 57 -- Agreement between Entergy Services and Gerald D. McInvale
(10(a) 69 to Form 10-K for the year ended December 31, 1992
in 1-3517).
+(e) 58 -- Agreement between System Energy and Donald C. Hintz (10(b) 47
to Form 10-K for the year ended December 31, 1991 in 1-9067).
+(e) 59 -- Summary Description of Retired Outside Director Benefit Plan
(10(c)90 to Form 10-K for the year ended December 31, 1992 in
1-10764).
+(e) 60 -- Amendment to Defined Contribution Restoration Plan of Entergy
Corporation and Subsidiaries (10(a) 81 to Form 10-K for the
year ended December 31, 1993 in 1-11299).
+(e) 61 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for
the year ended December 31, 1993 in 1-11299).
(e) 62 -- Installment Sale Agreement, dated July 20, 1994, between LP&L
and St. Charles Parish, Louisiana (B-6(e) to Rule 24
Certificate dated August 1, 1994 in 70-7822).
MP&L
(f) 1 -- Agreement dated April 23, 1982, among MP&L and certain other
System companies, relating to System Planning and Development
and Intra-System Transactions (10(a) 1 to Form 10-K for the
fiscal year ended December 31, 1982, in 1-3517).
(f) 2 -- Middle South Utilities System Agency Agreement, dated
December 11, 1970 (5(a)-2 in 2-41080).
(f) 3 -- Amendment, dated February 10, 1971, to Middle South Utilities
System Agency Agreement, dated December 11, 1970 (5(a) 4 in
2-41080).
(f) 4 -- Amendment, dated May 12, 1988, to Middle South Utilities
System Agency Agreement, dated December 11, 1970 (5(a) 4 in 2-
41080).
(f) 5 -- Middle South Utilities System Agency Coordination Agreement,
dated December 11, 1970 (5(a)-3 in 2-41080).
(f) 6 -- Service Agreement with Entergy Services, dated as of April 1,
1963 (D in 37-63).
(f) 7 -- Amendment, dated January 1, 1972, to Service Agreement with
Entergy Services (A to Notice, dated October 14, 1971, in
37-63).
(f) 8 -- Amendment, dated April 27, 1984, to Service Agreement with
Entergy Services (10(a) 7 to Form 10-K for the fiscal year
ended December 31, 1984, in 1-3517).
(f) 9 -- Amendment, dated as of August 1, 1988, to Service Agreement
with Entergy Services (10(e) 8 to Form 10-K for the fiscal
year ended December 31, 1988, in 0-320).
(f) 10 -- Amendment, dated January 1, 1991, to Service Agreement with
Entergy Services (10(e) 9 to Form 10-K for the fiscal year
ended December 31, 1990, in 0-320).
(f) 11 -- Amendment, dated January 1, 1992, to Service Agreement with
Entergy Services.
(f) 12 -- Availability Agreement, dated June 21, 1974, among System
Energy and certain other System companies (B to Rule 24
Certificate, dated June 24, 1974, in 70-5399).
(f) 13 -- First Amendment to Availability Agreement, dated as of June
30, 1977 (B to Rule 24 Certificate, dated June 24, 1977, in
70-5399).
(f) 14 -- Second Amendment to Availability Agreement, dated as of June
15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in
70-6592).
(f) 15 -- Third Amendment to Availability Agreement, dated as of June
28, 1984 (B-13(a) to Rule 24 Certificate, dated July 6, 1984,
in 70-6985).
(f) 16 -- Fourth Amendment to Availability Agreement, dated as of June
1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in
70-5399).
(f) 17 -- Fourteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(f) 18 -- Fifteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York, Malcolm J. Hood, and Deposit Guaranty
National Bank, as Trustees (B-3(b) to Rule 24 Certificate,
dated June 5, 1986, in 70-7158).
(f) 19 -- Sixteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (C to
Rule 24 Certificate, dated June 4, 1986, in 70-7123).
(f) 20 -- Eighteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-2 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(f) 21 -- Nineteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-3 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(f) 22 -- Twenty-fourth Assignment of Availability Agreement, Consent
and Agreement, dated as of July 1, 1992, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(B-2(b) to Rule 24 Certificate, dated July 14, 1992, in
70-7946).
(f) 23 -- Twenty-fifth Assignment of Availability Agreement, Consent
and Agreement, dated as of October 1, 1992, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (B-2(b) to Rule 24 Certificate, dated November 2,
1992, in 70-7946).
(f) 24 -- Twenty-sixth Assignment of Availability Agreement, Consent
and Agreement, dated as of October 1, 1992, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (B-2(c) to Rule 24 Certificate, dated November 2,
1992, in 70-7946).
(f) 25 -- Twenty-seventh Assignment of Availability Agreement, Consent
and Agreement, dated as of April 1, 1993, with United States
Trust Company of New York and Gerard F. Ganey as Trustees (B-
2(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(f) 26 -- Twenty-eighth Assignment of Availability Agreement, Consent
and Agreement, dated as of December 17, 1993, with Chemical
Bank, as Agent (B-2(a) to Rule 24 Certificate dated December
22, 1993 in 70-7561).
(f) 27 -- Twenty-ninth Assignment of Availability Agreement, Consent
and Agreement, dated as of April 1, 1994, with United States
Trust Company of New York and Gerard F. Ganey as Trustees (B-
2(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946).
(f) 28 -- Installment Sale Agreement, dated as of June 1, 1974, between
MP&L and Washington County, Mississippi (B-2(a) to Rule 24
Certificate, dated August 1, 1974, in 70-5504).
(f) 29 -- Installment Sale Agreement, dated as of July 1, 1982, between
MP&L and Independence County, Arkansas, (B-1(c) to Rule 24
Certificate dated July 21, 1982, in 70-6672).
(f) 30 -- Installment Sale Agreement, dated as of December 1, 1982,
between MP&L and Independence County, Arkansas, (B-1(d) to
Rule 24 Certificate dated December 7, 1982, in 70-6672).
(f) 31 -- Amended and Restated Installment Sale Agreement, dated as of
April 1, 1994, between MP&L and Warren County, Mississippi,
(B-6(a) to Rule 24 Certificate dated May 4, 1994, in 70-
7914).
(f) 32 -- Amended and Restated Installment Sale Agreement, dated as of
April 1, 1994, between MP&L and Washington County,
Mississippi, (B-6(b) to Rule 24 Certificate dated May 4,
1994, in 70-7914).
(f) 33 -- Substitute Power Agreement, dated as of May 1, 1980, among
MP&L, System Energy and SMEPA (B-3(a) in 70-6337).
(f) 34 -- Amendment, dated December 4, 1984, to the Independence Steam
Electric Station Operating Agreement (10(c) 51 to Form 10-K
for the fiscal year ended December 31, 1984, in 0-375).
(f) 35 -- Amendment, dated December 4, 1984, to the Independence Steam
Electric Station Ownership Agreement (10(c) 54 to Form 10-K
for the fiscal year ended December 31, 1984, in 0-375).
(f) 36 -- Owners Agreement, dated November 28, 1984, among AP&L, MP&L
and other co- owners of the Independence Station (10(c) 55 to
Form 10-K for the fiscal year ended December 31, 1984, in
0-375).
(f) 37 -- Consent, Agreement and Assumption, dated December 4, 1984,
among AP&L, MP&L, other co-owners of the Independence Station
and United States Trust Company of New York, as Trustee
(10(c) 56 to Form 10-K for the fiscal year ended December 31,
1984, in 0-375).
(f) 38 -- Reallocation Agreement, dated as of July 28, 1981, among
System Energy and certain other System companies (B-1(a) in
70-6624).
+(f) 39 -- Post-Retirement Plan (10(d) 24 to Form 10-K for the fiscal
year ended December 31, 1983, in 0-320).
(f) 40 -- Unit Power Sales Agreement, dated as of June 10, 1982,
between System Energy and AP&L, LP&L, MP&L, and NOPSI (10(a)
39 to Form 10-K for the fiscal year ended December 31, 1982,
in 1-3517).
(f) 41 -- First Amendment to the Unit Power Sales Agreement, dated as
of June 28, 1984, between System Energy and AP&L, LP&L, MP&L,
and NOPSI (19 to Form 10-Q for the quarter ended September
30, 1984, in 1-3517).
(f) 42 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(f) 43 -- Sales Agreement, dated as of June 21, 1974, between System
Energy and MP&L (D to Rule 24 Certificate, dated June 26,
1974, in 70-5399).
(f) 44 -- Service Agreement, dated as of June 21, 1974, between System
Energy and MP&L (E to Rule 24 Certificate, dated June 26,
1974, in 70-5399).
(f) 45 -- Partial Termination Agreement, dated as of December 1, 1986,
between System Energy and MP&L (A-2 to Rule 24 Certificate
dated January 8, 1987, in 70-5399).
(f) 46 -- Middle South Utilities, Inc. and Subsidiary Companies
Intercompany Income Tax Allocation Agreement, dated April 28,
1988 (D-1 to Form U5S for the year ended December 31, 1987).
(f) 47 -- First Amendment dated January 1, 1990 to the Middle South
Utilities Inc. and Subsidiary Companies Intercompany Tax
Allocation Agreement (D-2 to Form U5S for the year ended
December 31, 1989).
(f) 48 -- Second Amendment dated January 1, 1992, to the Entergy
Corporation and Subsidiary Companies Intercompany Income Tax
Allocation Agreement (D-3 to Form U5S for the year ended
December 31, 1992).
(f) 49 -- Third Amendment dated January 1, 1994 to Entergy Corporation
and Subsidiary Companies Intercompany Income Tax Allocation
Agreement (D-3(a) to Form U5S for the year ended December 31,
1993).
+(f) 50 -- Executive Financial Counseling Program of Entergy Corporation
and Subsidiaries (10(a) 52 to Form 10-K for the year ended
December 31, 1989, in 1-3517).
+(f) 51 -- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form
10-K for the year ended December 31, 1989, in 1-3517).
+(f) 52 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries
(A-4(a) to Rule 24 Certificate, dated May 24, 1991, in
70-7831).
+(f) 53 -- Supplemental Retirement Plan (10(a)69 to Form 10-K for the
year ended December 31, 1992 in 1-3517).
+(f) 54 -- Defined Contribution Restoration Plan of Entergy Corporation
and Subsidiaries (10(a)53 to Form 10-K for the year ended
December 31, 1989 in 1-3517).
+(f) 55 -- Amendment No. 1 to the Equity Ownership Plan of Entergy
Corporation and Subsidiaries (10(a)71 to Form 10-K for the
year ended December 31, 1992 in 1-3517).
+(f) 56 -- Executive Disability Plan of Entergy Corporation and
Subsidiaries (10(a)72 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(f) 57 -- Executive Medical Plan of Entergy Corporation and
Subsidiaries (10(a)73 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(f) 58 -- Stock Plan for Outside Directors of Entergy Corporation and
Subsidiaries, as amended (10(a)74 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(f) 59 -- Summary Description of Private Ownership Vehicle Plan of
Entergy Corporation and Subsidiaries (10(a)75 to Form 10-K
for the year ended December 31, 1992 in 1-3517).
+(f) 60 -- Agreement between Entergy Corporation and Edwin Lupberger
(10(a)-42 to Form 10-K for the year ended December 31, 1985
in 1-3517).
+(f) 61 -- Agreement between Entergy Corporation and Jerry D. Jackson
(10(a)-68 to Form 10-K for the year ended December 31, 1992
in 1-3517).
+(f) 62 -- Agreement between Entergy Services and Gerald D. McInvale
(10(a)-69 to Form 10-K for the year ended December 31, 1992
in 1-3517).
+(f) 63 -- Agreement between System Energy and Donald C. Hintz (10(b)-47
to Form 10-K for the year ended December 31, 1991 in 1-9067).
+(f) 64 -- Summary Description of Retired Outside Director Benefit Plan
(10(c)-90 to Form 10-K for the year ended December 31, 1992
in 1-10764).
+(f) 65 -- Amendment to Defined Contribution Restoration Plan of Entergy
Corporation and Subsidiaries (10(a) 81 to Form 10-K for the
year ended December 31, 1993 in 1-11299).
+(f) 66 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for
the year ended December 31, 1993 in 1-11299).
NOPSI
(g) 1 -- Agreement, dated April 23, 1982, among NOPSI and certain
other System companies, relating to System Planning and
Development and Intra-System Transactions (10(a)-1 to Form
10-K for the fiscal year ended December 31, 1982, in 1-3517).
(g) 2 -- Middle South Utilities System Agency Agreement, dated
December 11, 1970 (5(a)-2 in 2-41080).
(g) 3 -- Amendment dated as of February 10, 1971, to Middle South
Utilities System Agency Agreement, dated December 11, 1970
(5(a)-4 in 2-41080).
(g) 4 -- Amendment, dated May 12, 1988, to Middle South Utilities
System Agency Agreement, dated December 11, 1970 (5(a) 4 in
2-41080).
(g) 5 -- Middle South Utilities System Agency Coordination Agreement,
dated December 11, 1970 (5(a)-3 in 2-41080).
(g) 6 -- Service Agreement with Entergy Services dated as of April 1,
1963 (5(a)-5 in 2-42523).
(g) 7 -- Amendment, dated as of January 1, 1972, to Service Agreement
with Entergy Services (4(a)-6 in 2-45916).
(g) 8 -- Amendment, dated as of April 27, 1984, to Service Agreement
with Entergy Services (10(a)7 to Form 10-K for the fiscal
year ended December 31, 1984, in 1-3517).
(g) 9 -- Amendment, dated as of August 1, 1988, to Service Agreement
with Entergy Services (10(f)-8 to Form 10-K for the fiscal
year ended December 31, 1988, in 0-5807).
(g) 10 -- Amendment, dated January 1, 1991, to Service Agreement with
Entergy Services (10(f)-9 to Form 10-K for the fiscal year
ended December 31, 1990, in 0-5807).
*(g) 11 -- Amendment, dated January 1, 1992, to Service Agreement with
Entergy Services.
(g) 12 -- Availability Agreement, dated June 21, 1974, among System
Energy and certain other System companies (B to Rule 24
Certificate, dated June 24, 1974, in 70-5399).
(g) 13 -- First Amendment to Availability Agreement, dated June 30,
1977 (B to Rule 24 Certificate, dated June 30, 1977, in
70-5399).
(g) 14 -- Second Amendment to Availability Agreement, dated as of June
15, 1981 (E to Rule 24 Certificate, dated July 1, 1981, in
70-6592).
(g) 15 -- Third Amendment to Availability Agreement, dated as of June
28, 1984 (B-13(a) to Rule 24 Certificate, dated July 6, 1984,
in 70-6985).
(g) 16 -- Fourth Amendment to Availability Agreement, dated as of June
1, 1989 (A to Rule 24 Certificate, dated June 8, 1989, in
70-5399).
(g) 17 -- Fourteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(g) 18 -- Fifteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York, Malcolm J. Hood and Deposit Guaranty
National Bank, as Trustees (B-3(b) to Rule 24 Certificate,
dated June 5, 1986, in 70-7158).
(g) 19 -- Sixteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (C to
Rule 24 Certificate, dated June 4, 1986, in 70-7123).
(g) 20 -- Eighteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-2 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(g) 21 -- Nineteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-3 to Rule 24 Certificate, dated October 1, 1986, in
70-7272).
(g) 22 -- Twentieth Assignment of Availability Agreement, Consent and
Agreement, dated as of November 15, 1987, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(C-1 to Rule 24 Certificate, dated December 1, 1987, in
70-7382).
(g) 23 -- Twenty-first Assignment of Availability Agreement, Consent
and Agreement, dated as of December 1, 1987, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (C-2 to Rule 24 Certificate, dated December 1, 1987,
in 70-7382).
(g) 24 -- Twenty-third Assignment of Availability Agreement, Consent
and Agreement, dated as of January 11, 1991, with Chemical
Bank, as Agent (B-3(a) to Rule 24 Certificate, dated January
23, 1991, in 70-7561).
(g) 25 -- Twenty-fourth Assignment of Availability Agreement, Consent
and Agreement, dated as of July 1, 1992, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees
(B-2(b) to Rule 24 Certificate, dated July 14, 1992, in
70-7946).
(g) 26 -- Twenty-fifth Assignment of Availability Agreement, Consent
and Agreement, dated as of October 1, 1992, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (B-2(b) to Rule 24 Certificate, dated November 2,
1992, in 70-7946).
(g) 27 -- Twenty-sixth Assignment of Availability Agreement, Consent
and Agreement, dated as of October 1, 1992, with United
States Trust Company of New York and Gerard F. Ganey, as
Trustees (B-2(c) to Rule 24 Certificate, dated November 2,
1992, in 70-7946).
(g) 28 -- Twenty-seventh Assignment of Availability Agreement, Consent
and Agreement, dated as of April 1, 1993, with United States
Trust Company of New York and Gerard F. Ganey as Trustees (B-
2(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(g) 29 -- Twenty-eighth Assignment of Availability Agreement, Consent
and Agreement, dated as of December 17, 1993, with Chemical
Bank, as Agent (B-2(a) to Rule 24 Certificate dated December
22, 1993 in 70-7561).
(g) 30 -- Twenty-ninth Assignment of Availability Agreement, Consent
and Agreement, dated as of April 1, 1994, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (B-
2(f) to Rule 24 Certificate dated May 6, 1994, in 70-7946).
(g) 31 -- Reallocation Agreement, dated as of July 28, 1981, among
System Energy and certain other System companies (B-1(a) in
70-6624).
+(g) 32 -- Post-Retirement Plan (10(e) 22 to Form 10-K for the fiscal
year ended December 31, 1983, in 1-1319).
(g) 33 -- Unit Power Sales Agreement, dated as of June 10, 1982,
between System Energy and AP&L, LP&L, MP&L and NOPSI (10(a)
39 to Form 10-K for the fiscal year ended December 31, 1982,
in 1-3517).
(g) 34 -- First Amendment to the Unit Power Sales Agreement, dated as
of June 28, 1984, between System Energy and AP&L, LP&L, MP&L
and NOPSI (19 to Form 10-Q for the quarter ended September
30, 1984, in 1-3517).
(g) 35 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(g) 36 -- Transfer Agreement, dated as of June 28, 1983, among the City
of New Orleans, NOPSI and Regional Transit Authority (2(a) to
Form 8-K, dated June 24, 1983, in 1-1319).
(g) 37 -- Middle South Utilities, Inc. and Subsidiary Companies
Intercompany Income Tax Allocation Agreement, dated April 28,
1988 (D-1 to Form U5S for the year ended December 31, 1987).
(g) 38 -- First Amendment, dated January 1, 1990, to the Middle South
Utilities, Inc. and Subsidiary Companies Intercompany Income
Tax Allocation Agreement (D-2 to Form U5S for the year ended
December 31, 1989).
(g) 39 -- Second Amendment dated January 1, 1992, to the Entergy
Corporation and Subsidiary Companies Intercompany Income Tax
Allocation Agreement (D-3 to Form U5S for the year ended
December 31, 1992).
(g) 40 -- Third Amendment dated January 1, 1994 to Entergy Corporation
and Subsidiary Companies Intercompany Income Tax Allocation
Agreement (D-3(a) to Form U5S for the year ended December 31,
1993).
+(g) 41 -- Executive Financial Counseling Program of Entergy Corporation
and Subsidiaries (10(a)52 to Form 10-K for the year ended
December 31, 1989, in 1-3517).
+(g) 42 -- Entergy Corporation Annual Incentive Plan (10(a)54 to Form
10-K for the year ended December 31, 1989, in 1-3517).
+(g) 43 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries
(A-4(a) to Rule 24 Certificate, dated May 24, 1991, in
70-7831).
+(g) 44 -- Supplemental Retirement Plan (10(a)69 to Form 10-K for the
year ended December 31, 1992 in 1-3517).
+(g) 45 -- Defined Contribution Restoration Plan of Entergy Corporation
and Subsidiaries (10(a)53 to Form 10-K for the year ended
December 31, 1989 in 1-3517).
+(g) 46 -- Amendment No. 1 to the Equity Ownership Plan of Entergy
Corporation and Subsidiaries (10(a)71 to Form 10-K for the
year ended December 31, 1992 in 1-3517).
+(g) 47 -- Executive Disability Plan of Entergy Corporation and
Subsidiaries (10(a)72 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(g) 48 -- Executive Medical Plan of Entergy Corporation and
Subsidiaries (10(a)73 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(g) 49 -- Stock Plan for Outside Directors of Entergy Corporation and
Subsidiaries, as amended (10(a)74 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(g) 50 -- Summary Description of Private Ownership Vehicle Plan of
Entergy Corporation and Subsidiaries (10(a)75 to Form 10-K
for the year ended December 31, 1992 in 1-3517).
+(g) 51 -- Agreement between Entergy Corporation and Edwin Lupberger
(10(a)-42 to Form 10-K for the year ended December 31, 1985
in 1-3517).
+(g) 52 -- Agreement between Entergy Corporation and Jerry D. Jackson
(10(a)-68 to Form 10-K for the year ended December 31, 1992
in 1-3517).
+(g) 53 -- Agreement between Entergy Services and Gerald D. McInvale
(10(a)-69 to Form 10-K for the year ended December 31, 1992
in 1-3517).
+(g) 54 -- Agreement between System Energy and Donald C. Hintz (10(b)-47
to Form 10-K for the year ended December 31, 1991 in 1-9067).
+(g) 55 -- Summary Description of Retired Outside Director Benefit Plan
(10(c)-90 to Form 10-K for the year ended December 31, 1992
in 1-10764).
+(g) 56 -- Amendment to Defined Contribution Restoration Plan of Entergy
Corporation and Subsidiaries (10(a) 81 to Form 10-K for the
year ended December 31, 1993 in 1-11299).
+(g) 57 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for
the year ended December 31, 1993 in 1-11299).
(12) Statement Re Computation of Ratios
*(a) AP&L's Computation of Ratios of Earnings to Fixed Charges and of
Earnings to Fixed Charges and Preferred Dividends, as
defined.
*(b) GSU's Computation of Ratios of Earnings to Fixed Charges and of
Earnings to Fixed Charges and Preferred Dividends, as
defined.
*(c) LP&L's Computation of Ratios of Earnings to Fixed Charges and of
Earnings to Fixed Charges and Preferred Dividends, as
defined.
*(d) MP&L's Computation of Ratios of Earnings to Fixed Charges and of
Earnings to Fixed Charges and Preferred Dividends, as
defined.
*(e) NOPSI's Computation of Ratios of Earnings to Fixed Charges and of
Earnings to Fixed Charges and Preferred Dividends, as
defined.
*(f) System Energy's Computation of Ratios of Earnings to Fixed
Charges, as defined.
*(21) Subsidiaries of the Registrants
(23) Consents of Experts and Counsel
*(a) The consent of Coopers & Lybrand L.L.P. is contained herein at page 373.
*(b) The consent of Deloitte & Touche LLP is contained herein at page 374.
*(c) The consent of Friday, Eldredge & Clark is contained herein at page 375.
*(d) The consent of Clark, Thomas & Winters is contained herein at page 376.
*(e) The consent of Sandlin Associates is contained herein at page 377.
*(f) The consent of Monroe & Lemann (A Professional Corporation) is
contained herein at page 378.
*(g) The consent of Wise Carter Child & Caraway, Professional Association,
is contained herein at page 379.
*(24) Powers of Attorney
(27) Financial Data Schedule
*(a) Financial Data Schedule for Entergy Corporation and Subsidiaries as
of December 31, 1994.
*(b) Financial Data Schedule for AP&L as of December 31, 1994.
*(c) Financial Data Schedule for GSU as of December 31, 1994.
*(d) Financial Data Schedule for LP&L as of December 31, 1994.
*(e) Financial Data Schedule for MP&L as of December 31, 1994.
*(f) Financial Data Schedule for NOPSI as of December 31, 1994.
*(g) Financial Data Schedule for System Energy as of December 31, 1994.
(99) Additional Exhibits
GSU
(a) 1 Opinion of Clark, Thomas & Winters, a professional corporation, dated
September 30, 1992 regarding the effect of the October 1, 1991 judgment
in GSU v. PUCT in the District Court of Travis County, Texas (99-1 in
Registration No. 33-48889).
(a) 2 Opinion of Clark Clark, Thomas & Winters, a professional corporation,
dated August 8, 1994 regarding recovery of costs deferred purusant to
PUCT order in Docket 6525 (99 (j) to Quarterly Report on Form 10-Q for
the quarter ended June 30, 1994 in No. 1-2703).
*(a) 3 Opinion of Clark, Thomas & Winters, a professional corporation,
confirming its opinions dated September 30, 1992 and August 8, 1994.
_________________
* Filed herewith.
+ Management contracts or compensatory plans or arrangements.