SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the Fiscal Year Ended December 31, 1993
TRANSITION REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ____________ to ____________
Commission Registrant, State of Incorporation, IRS Employer
File Number Address and Telephone Number Identification No.
- ----------- ----------------------------------- -------------------
1-11299 ENTERGY CORPORATION 13-5550175
(a Delaware corporation)
225 Baronne Street
New Orleans, Louisiana 70112
Telephone (504) 529-5262
1-10764 ARKANSAS POWER & LIGHT COMPANY 71-0005900
(an Arkansas corporation)
425 West Capitol Avenue, 40th Floor
Little Rock, Arkansas 72201
Telephone (501) 377-4000
1-2703 GULF STATES UTILITIES COMPANY 74-0662730
(a Texas corporation)
350 Pine Street
Beaumont, Texas 77701
Telephone (409) 838-6631
1-8474 LOUISIANA POWER & LIGHT COMPANY 72-0245590
(a Louisiana corporation)
639 Loyola Avenue
New Orleans, Louisiana 70113
Telephone (504) 569-4000
0-320 MISSISSIPPI POWER & LIGHT COMPANY 64-0205830
(a Mississippi corporation)
308 East Pearl Street
Jackson, Mississippi 39201
Telephone (601) 969-2311
0-5807 NEW ORLEANS PUBLIC SERVICE INC. 72-0273040
(a Louisiana corporation)
639 Loyola Avenue
New Orleans, Louisiana 70113
Telephone (504) 569-4000
1-9067 SYSTEM ENERGY RESOURCES, INC. 72-0752777
(an Arkansas corporation)
Echelon One
1340 Echelon Parkway
Jackson, Mississippi 39213
Telephone (601) 984-9000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Registrant Title of Class on Which Registered
Entergy Corporation Common Stock, $0.01 Par Value New York Stock
- 230,310,494 Exchange, Inc.
Shares outstanding at Midwest Stock
February 28, 1994 Exchange
Incorporated
Pacific Stock
Exchange
Incorporated
Arkansas Power & $2.40 Preferred Stock, New York Stock
Light Company Cumulative, $0.01 Par Value Exchange, Inc.
($25 Involuntary Liquidation
Value)
Gulf States Utilities Preferred Stock, Cumulative,
Company $100 Par Value:
$4.40 Dividend Series New York Stock
Exchange, Inc.
$4.52 Dividend Series New York Stock
Exchange, Inc.
$5.08 Dividend Series New York Stock
Exchange, Inc.
$8.80 Dividend Series New York Stock
Exchange, Inc.
Adjustable Rate Series B
(Depositary Receipts) New York Stock
Exchange, Inc.
Preference Stock, Cumulative, New York Stock
without Par Value Exchange, Inc.
$1.75 Dividend Series
Louisiana Power & 9.68% Preferred Stock, New York Stock
Light Company Cumulative, $25 Par Value Exchange, Inc.
12.64% Preferred Stock, New York Stock
Cumulative, $25 Par Value Exchange, Inc.
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Class
Arkansas Power & Preferred Stock, Cumulative,
Light Company $100 Par Value
Preferred Stock, Cumulative,
$25 Par Value
Preferred Stock, Cumulative,
$0.01 Par Value
Louisiana Power & Preferred Stock, Cumulative,
Light Company $100 Par Value
Preferred Stock, Cumulative,
$25 Par Value
Mississippi Power & Preferred Stock, Cumulative,
Light Company $100 Par Value
New Orleans Public Preferred Stock, Cumulative,
Service Inc. $100 Par Value
4 3/4% Preferred Stock,
Cumulative, $100 Par
Value
Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrants were required to file such
reports), and (2) have been subject to such filing requirements for
the past 90 days. Yes __X__ No ____
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of the registrants' knowledge, in
definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
The aggregate market value of Entergy Corporation Common Stock,
$0.01 Par Value, held by non-affiliates, was $7.7 billion based on the
reported last sale price of such stock on the New York Stock Exchange
on February 28, 1994. Entergy Corporation is the sole holder of the
common stock of Arkansas Power & Light Company, Gulf States Utilities
Company, Louisiana Power & Light Company, Mississippi Power & Light
Company, New Orleans Public Service Inc., and System Energy Resources,
Inc.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement of Entergy Corporation to be
filed in connection with its Annual Meeting of Stockholders, to be
held May 6, 1994, are incorporated by reference into Part III hereof.
TABLE OF CONTENTS
Page
Number
------
Definitions
Part I
Item 1. Business
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
Part II
Item 5. Market for Registrants' Common Equity and Related
Stockholder Matters
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
Part III
Item 10. Directors and Executive Officers of the Registrants
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners
and Management
Item 13. Certain Relationships and Related Transactions
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K
Experts
Signatures
Consents of Experts
Independent Auditors' Report on Financial Statement Schedules
Index to Financial Statement Schedules
Exhibit Index
This combined Form 10-K is separately filed by Entergy Corporation,
Arkansas Power & Light Company, Gulf States Utilities Company,
Louisiana Power & Light Company, Mississippi Power & Light Company,
New Orleans Public Service Inc., and System Energy Resources, Inc.
Information contained herein relating to any individual company is
filed by such company on its own behalf. Each company makes no
representation as to information relating to the other companies.
This report (including the material incorporated herein by reference)
must be read in its entirety. No one section of the report deals with
all aspects of the subject matter.
DEFINITIONS
Certain abbreviations or acronyms used in the text and notes are
defined below:
Abbreviation
or Acronym Term
------------ ----
AFUDC Allowance for Funds Used During Construction
Algiers 15th Ward of the City of New Orleans, Louisiana
ALJ Administrative Law Judge
Alliance The Alliance for Affordable Energy, Inc.
ANO Arkansas Nuclear One Steam Electric Generating
Station (nuclear)
ANO 2 Unit No. 2 of ANO
AP&L Arkansas Power & Light Company
APSC Arkansas Public Service Commission
Arkansas District Court United States District Court for the Western
District of Arkansas
Availability Agreement Agreement, dated as of June 21, 1974, as
amended, among System Energy and AP&L, LP&L, MP&L,
and NOPSI, and the assignments thereof
Cajun Cajun Electric Power Cooperative, Inc.
Capital Funds Agreement Agreement, dated as of June 21, 1974, as
amended, between System Energy and Entergy
Corporation, and the assignments thereof
CCLM Customer-Controlled Load Management (a DSM
activity utilizing residential time-of-use rates)
City of New Orleans
or City New Orleans, Louisiana
Council Council of the City of New Orleans,
Louisiana
D.C. Circuit United States Court of Appeals for the District of
Columbia Circuit
DOE United States Department of Energy
DSM Demand-Side Management (Least Cost Plan activities
that influence electricity usage by consumers)
Eighth Circuit United States Court of Appeals for the Eighth
Circuit
Energy Act Energy Policy Act of 1992
Entergy or System Entergy Corporation and its various direct and
indirect subsidiaries
Entergy Corporation Entergy Corporation, a Delaware corporation,
successor to Entergy Corporation, a Florida
corporation
Entergy Enterprises Entergy Enterprises, Inc. (formerly Electec, Inc.)
Entergy Operations Entergy Operations, Inc.
Entergy Power Entergy Power, Inc.
Entergy Services Entergy Services, Inc.
EPA Environmental Protection Agency
EWG Exempt Wholesale Generator
February 4 Resolution The Resolution (including the Determinations
and Order referred to therein) adopted by the
Council on February 4, 1988, disallowing the
recovery by NOPSI of $135 million of previously
deferred Grand Gulf 1 related costs
FERC Federal Energy Regulatory Commission
Grand Gulf Station Grand Gulf Steam Electric Generating Station
(nuclear)
Grand Gulf 1 Unit No. 1 of the Grand Gulf Station
Grand Gulf 2 Unit No. 2 of the Grand Gulf Station
GSU Gulf States Utilities Company (including wholly
owned subsidiaries - Varibus Corporation, GSG&T,
Inc., Prudential Oil & Gas, Inc., and Southern
Gulf Railway Company)
Holding Company Act Public Utility Holding Company Act of 1935, as
amended
Independence Station Independence Steam Electric Generating
Station (coal)
Independence 2 Unit No. 2 of the Independence Station
IRS Internal Revenue Service
KV Kilovolts
KWH Kilowatt-Hour(s)
Least Cost Plan Least Cost Integrated Resource Plan (combination
of demand- and supply-side resources to be used by
Entergy to satisfy electricity demand)
LP&L Louisiana Power & Light Company
LPSC Louisiana Public Service Commission
MCF 1,000 cubic feet of gas
Merger The combination transaction, consummated on
December 31, 1993, by which GSU became a
subsidiary of Entergy Corporation and Entergy
Corporation became a Delaware corporation
MP&L Mississippi Power & Light Company
MPSC Mississippi Public Service Commission
MW Megawatt(s)
Nelson Unit 6 Unit No. 6 (coal) of the Nelson Steam Electric
Generating Station
NISCO Nelson Industrial Steam Company
1986 NOPSI Settlement Settlement, effective March 25, 1986, between
NOPSI and the Council regarding NOPSI's Grand Gulf-
related rate issues.
1991 NOPSI Settlement Settlement, retroactive to October 4, 1991,
among NOPSI, the Council, and the Alliance that
settled certain Grand Gulf 1 prudence issues and
certain litigation related to the February 4
Resolution
NOPSI New Orleans Public Service Inc.
NRC Nuclear Regulatory Commission
PRP Potentially Responsible Party (a person or entity
that may be responsible for remediation of
environmental contamination)
PUCT Public Utility Commission of Texas
PURPA Public Utility Regulatory Policies Act
REA Rural Electrification Administration
Reallocation Agreement 1981 Agreement, superseded in part by a
June 13, 1985 decision of FERC, among AP&L, LP&L,
MP&L, NOPSI, and System Energy relating to the
sale of capacity and energy from the Grand Gulf
Station
Ritchie 2 Unit No. 2 of the R. E. Ritchie Steam Electric
Generating Station (gas/oil)
River Bend River Bend Steam Electric Generating Station
(nuclear), owned 70% by GSU.
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards,
promulgated by the Financial Accounting Standards
Board
SRG&T Sam Rayburn G&T, Inc.
SRMPA Sam Rayburn Municipal Power Agency
System Agreement Agreement, effective January 1, 1983, as modified,
among the System operating companies relating to
the sharing of generating capacity and other power
resources
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively
Unit Power Sales
Agreement Agreement, dated as of June 10, 1982, as
amended and approved by FERC, among AP&L, LP&L,
MP&L, NOPSI, and System Energy, relating to the
sale of capacity and energy from System Energy's
share of Grand Gulf 1
Waterford 3 Unit No. 3 (nuclear) of the Waterford Steam
Electric Generating Station
PART I
Item 1. Business
BUSINESS OF ENTERGY
General
Entergy Corporation was originally incorporated under the laws of
the State of Florida on May 27, 1949. On December 31, 1993, in
connection with the Merger (see "Entergy Corporation-GSU Merger,"
below), Entergy Corporation merged with and into Entergy-GSU Holdings,
Inc., a Delaware corporation (Holdings), and Holdings was renamed
Entergy Corporation. Entergy Corporation is a holding company
registered under the Holding Company Act and does not own or operate
any physical properties. Entergy Corporation owns all of the
outstanding common stock of five retail operating electric utility
subsidiaries, AP&L, GSU, LP&L, MP&L, and NOPSI. AP&L was incorporated
under the laws of the State of Arkansas in 1926; GSU was incorporated
under the laws of the State of Texas in 1925; LP&L and NOPSI were
incorporated under the laws of the State of Louisiana in 1974 and
1926, respectively; and MP&L was incorporated under the laws of the
State of Mississippi in 1963. As of December 31, 1993, these
operating companies provided electric service to approximately
2.3 million customers in the States of Arkansas, Louisiana,
Mississippi, Missouri, and Texas. In addition, GSU furnished gas
service in the Baton Rouge, Louisiana area, and NOPSI furnished gas
service in the City of New Orleans. GSU's steam products department
produces and sells, on an unregulated basis, process steam and by-
product electricity supplied from its steam electric extraction plant
to a large industrial customer. The business of the System is subject
to seasonal fluctuations with the peak period occurring during the
third quarter. During 1993, the System's (excluding GSU) electricity
sales as a percentage of total System energy sales were: residential -
28.1%; commercial - 19.9%; and industrial - 36.9%. Electric revenues
from these sectors as a percentage of total System electric revenues
were: 36.3% - residential; 24.4% - commercial; and 27.3% - industrial.
Sales to governmental and municipal sectors and to nonaffiliated
utilities accounted for the balance of energy sales. During 1993,
GSU's electric department sales as a percentage of total GSU energy
sales were: residential - 25.5%; commercial - 20.3%; and industrial -
50.8%. Electric revenues from these sectors as a percentage of total
GSU electric revenues were: 33.5% - residential; 23.8% - commercial;
and 37.2% - industrial. Sales to governmental and municipal sectors
and to nonaffiliated utilities accounted for the balance of GSU's
energy sales. The System's major industrial customers are in the
chemical processing, petroleum refining, paper products, and food
products industries.
Entergy Corporation also owns all of the outstanding common stock
of System Energy, Entergy Services, Entergy Operations, Entergy Power,
and Entergy Enterprises. System Energy is a nuclear generating
company that was incorporated under the laws of the State of Arkansas
in 1974. System Energy sells the capacity and energy at wholesale
from its 90% interest in Grand Gulf 1 to its only customers, AP&L,
LP&L, MP&L, and NOPSI (see "Capital Requirements and Future Financing
- - Certain System Financial and Support Agreements - Unit Power Sales
Agreement," below). System Energy has approximately a 78.5% ownership
interest and an 11.5% leasehold interest in Grand Gulf 1. Entergy
Services provides general executive and advisory services, and
accounting, engineering, and other technical services to certain of
the System companies, generally at cost. Entergy Operations is a
nuclear management company that operates ANO, River Bend, Waterford 3,
and Grand Gulf 1, subject to the owner oversight of AP&L, GSU, LP&L,
and System Energy, respectively. Entergy Power, an independent power
producer, owns 809 MW of generating capacity and markets its capacity
and energy in the wholesale market outside Arkansas and Missouri and
in markets not otherwise presently served by the System. (For further
information on regulatory proceedings related to Entergy Power, see
"Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters -
Entergy Power," below). Entergy Enterprises is a nonutility company
that invests in businesses whose products and activities are of
benefit to the System's utility business (see "Corporate Development,"
below). Entergy Enterprises also markets technical expertise
developed by the System companies when it is not required in the
System's operations. Entergy Enterprises has received SEC approval to
provide services to certain nonutility companies in the System. In
1992 and 1993, several new Entergy Corporation subsidiaries were
formed to participate in utility projects located outside the System's
retail service territory, both domestically and in foreign countries
(see "Corporate Development," below).
AP&L, LP&L, MP&L, and NOPSI own, in ownership percentages of 35%,
33%, 19%, and 13%, respectively, all of the common stock of System
Fuels, a non-profit subsidiary, that implements and/or maintains
certain programs to procure, deliver, and store fuel supplies for the
System.
GSU has four wholly-owned subsidiaries: Varibus Corporation,
GSG&T, Inc., Southern Gulf Railway Company, and Prudential Oil & Gas,
Inc. Varibus Corporation operates intrastate gas pipelines in
Louisiana, which are used primarily to transport fuel to two of GSU's
generating stations, and has marketed computer-aided engineering and
drafting technologies and related computer equipment and services.
GSG&T, Inc. owns the Lewis Creek Station, a 532 MW (as of December 31,
1993) gas-fired generating plant, which is leased and operated by GSU.
Southern Gulf Railway Company will own and operate several miles of
rail track being constructed in Louisiana for the purpose of
transporting coal for use as a boiler fuel at Nelson Unit 6.
Prudential Oil & Gas, Inc., which was formerly in the business of
exploring, developing, and operating oil and gas properties in Texas
and Louisiana, is presently inactive.
Entergy Corporation-GSU Merger
On December 31, 1993, Entergy Corporation consummated its
acquisition of GSU. Entergy Corporation merged with and into
Holdings, and Holdings was renamed Entergy Corporation. GSU became a
wholly-owned subsidiary of Entergy Corporation and continues to
operate as a public utility under the regulation of the PUCT and the
LPSC. As consideration to GSU's shareholders, Entergy Corporation
paid $250 million in cash and issued 56,667,726 shares of its common
stock at a price of $35.8417 per share, in exchange for outstanding
shares of GSU common stock. In addition, $33.5 million of transaction
costs were capitalized in connection with the Merger. See "Rate
Matters and Regulation - Regulation - Other Regulation and
Litigation," for, information on requests for rehearing and appeals of
certain regulatory approvals of the Merger.
The information contained in this Form 10-K is filed on behalf of
all the registrants of Entergy, including GSU. Unless otherwise
noted, consolidated financial and statistical information contained in
this report that is stated as of December 31, 1993 (such as assets,
liabilities, and property), includes the associated GSU amounts, and
consolidated financial and statistical information for periods ending
before January 1, 1994 (such as revenues, sales, and expenses), does
not include GSU amounts; those amounts are presented separately for
GSU herein.
Certain Industry and System Challenges
The System's business is affected by various challenges and
issues including those that confront the electric utility industry in
general. These issues and challenges include:
- an increasingly competitive environment (see "Competition,"
below);
- compliance with regulatory requirements with respect to
nuclear operations (see "Rate Matters and Regulation -
Regulation - Regulation of the Nuclear Power Industry,"
below) and environmental matters (see "Rate Matters and
Regulation - Regulation - Environmental Regulation," below);
- adaptation to structural changes in the electric utility
industry, including increased emphasis on least cost planning
and changes in the regulation of generation and transmission
of electricity (see "Competition - General" and "Competition
- Least Cost Planning," below);
- continued cost management (particularly in the area of
operation and maintenance costs at nuclear units) to improve
financial results and to delay or to minimize the need for
rate increase requests in light of current rate freezes and
rate caps at the System operating companies (see "Rate
Matters and Regulation - Rate Matters - Retail Rate Matters,"
below);
- integrating GSU into the System's operations and achieving
cost savings (see "Entergy Corporation-GSU Merger," above);
- achieving enhanced earnings in light of lower returns and slow
growth in the domestic utility business (see "Corporate
Development," below); and
- resolving GSU's major contingencies, including potential write-
offs and refunds related to River Bend (see "Rate Matters and
Regulation - Rate Matters - Retail Rate Matters - GSU,"
below) and litigation with Cajun relating to its ownership
interest in River Bend (see "Rate Matters and Regulation -
Regulation - Other Regulation and Litigation - GSU," below).
Corporate Development
Entergy continues to consider new opportunities to expand its
regulated electric utility business, as well as to expand into utility
and utility-related businesses that are not regulated by state and
local regulatory authorities (nonregulated businesses). Investments
in nonregulated businesses are likely to draw upon the System's skills
in power generation and customer service as well as its strengths in
the fuels area. Entergy Corporation's investment strategy with
respect to nonregulated businesses is to invest in nonregulated
business opportunities wherein Entergy Corporation has the potential
to earn a greater rate of return compared to its regulated utility
operations. Entergy Corporation's nonregulated businesses fall into
two broad categories: overseas power development and new electro-
technologies. Entergy Corporation has made investments in Argentina's
electric energy infrastructure, as described below, and is pursuing
additional projects in Central America, South America, South Africa,
and Asia. Entergy Corporation will also open offices in Buenos Aires,
Argentina and Hong Kong in 1994. In addition, Entergy Corporation is
seeking to provide telecommunications services based upon its
experience with interactive communications systems that allow
customers to control energy usage. Entergy Corporation expects to
invest approximately $150 million per year in nonregulated businesses.
Current investments in nonregulated businesses include the
following:
(1) Entergy Corporation's subsidiary, Entergy Power
Development Corporation (an EWG under the provisions of the
Energy Act), through its subsidiary (which is also an EWG)
Entergy Richmond Power Corporation, owns a 50% interest in an
independent power plant in Richmond, Virginia. The power plant
is jointly-owned and operated by the Enron Power Corporation, a
developer of independent power projects. The plant owners have a
25-year contract to sell electricity to Virginia Electric & Power
Company. Entergy Corporation's investment in the project totals
approximately $12.5 million.
(2) Entergy Enterprises has a 9.95% equity interest in
First Pacific Networks, Inc. (FPN), a communications company, and
a license from FPN in connection with utility applications, being
jointly developed by Entergy Enterprises and FPN, for FPN's
patented communications technology. Entergy Enterprises'
investment in FPN is approximately $20.1 million, of which $9.7
million is equity investment.
(3) Entergy Enterprises' subsidiary, Entergy Systems and
Service, Inc. (Entergy SASI), holds a 9.95% equity interest in
Systems and Service International, Inc. (SASI), a manufacturer of
efficient lighting products. This subsidiary also made a loan to
SASI, acquired the business and assets of SASI's distribution
subsidiary, and entered into an agreement to distribute SASI's
products. Entergy Enterprises' initial investment in this
business was approximately $11 million (of which $2.3 million is
invested in SASI common stock). Entergy Corporation has provided
to Entergy SASI $6.0 million in loans, as of December 31, 1993,
to fund Entergy SASI's installment sale agreements with its
customers.
(4) Entergy Corporation's subsidiary, Entergy, S.A.,
participated in a consortium with other nonaffiliated companies
that acquired a 60% interest in Argentina's Costanera steam
electric generating facility consisting of seven natural gas- and
oil-fired generating units, with a total installed capacity of
1,260 MW. Entergy Corporation's initial investment to acquire
its 10% interest in the consortium was approximately $11 million
and its maximum financial obligation currently authorized by the
SEC in connection with this investment is $22.5 million.
(5) In January 1993, Entergy Corporation, through a new
subsidiary, Entergy Argentina, S.A., participated in a consortium
with other nonaffiliated companies that acquired a 51% interest
in a foreign electric distribution company providing service to
Buenos Aires, Argentina. Entergy Corporation's initial
investment to acquire its 10% interest in the consortium was
approximately $58 million and its maximum financial obligation
currently authorized by the SEC in connection with this
investment is $77.5 million.
(6) In July 1993, Entergy Corporation, through a new
subsidiary, Entergy Transener, S.A., participated in a consortium
with other nonaffiliated companies that acquired a 65% interest
in a foreign transmission system providing service in the country
of Argentina. Entergy Corporation's initial investment to
acquire its 15% interest in the consortium was $18.5 million.
In the near term, these investments are likely to have a
minimal effect on earnings; but the possibility exists that they
could contribute to future earnings growth. However, due to the
absence of an allowed rate of return, these investments involve a
higher degree of risk.
International operations are subject to certain risks that
are inherent in conducting business abroad, including possible
nationalization or expropriation, price and exchange controls,
limitations on foreign participation in local governmental
enterprises, and other restrictive actions. Changes in the
relative value of currencies take place from time to time and
their effects may be favorable or unfavorable on results of
operations. In addition, there are exchange control restrictions
in certain countries relating to repatriation of earnings.
Selected Data
Selected customer and sales data for 1993 are summarized in the
following tables:
1993 - Selected Customer Data
Customers as of
December 31, 1993
------------------
Area Served Electric Gas
----------- -------- ---
AP&L Portions of State of Arkansas 590,862 -
GSU Portions of the States of Texas 593,975 85,040
and Louisiana
LP&L Portions of State of Louisiana 599,991 -
MP&L Portions of State of Mississippi 361,692 -
NOPSI City of New Orleans, except
Algiers, is provided electric
service by LP&L 190,613 154,251
--------- -------
System 2,337,133 239,291
========= =======
1993 - Selected Electric Energy Sales Data
System
System Excluding
AP&L LP&L MP&L NOPSI Energy GSU GSU
---- ---- ---- ----- ------ --------- ---
Sales to retail
customers 15,667 28,115 10,034 5,326 - 59,142 27,493
Sales for resale:
- Affiliates 8,002 112 758 90 7,113 - -
- Others 5,948 1,213 670 261 - 8,291 666
- Sales to steam
products customer - - - - - - 1,597
------ ------ ------ ------ ----- ------ ------
Total 29,617 29,440 11,462 5,677 7,113 67,433 29,756
====== ====== ====== ====== ===== ====== ======
Average use per
residential
customer (KWH) 11,206 13,949 12,903 11,145 - 12,501 13,905
====== ====== ====== ====== ===== ====== ======
NOPSI sold 17,437,292 MCF of natural gas to retail customers in
1993. Revenues from natural gas operations for each of the three
years in the period ended December 31, 1993, were material for NOPSI,
but not material for the System (see "Industry Segments," below, for a
description of NOPSI's business segments).
GSU sold 6,786,794 MCF of natural gas to retail customers in
1993. Revenues from natural gas operations for each of the three
years in the period ended December 31, 1993, were not material for
GSU.
See "Entergy Corporation and Subsidiaries Selected Financial Data
- - Five-Year Comparison," "AP&L Selected Financial Data - Five-Year
Comparison," "GSU Selected Financial Data - Five-Year Comparison,"
"LP&L Selected Financial Data - Five-Year Comparison," "MP&L Selected
Financial Data - Five-Year Comparison," "NOPSI Selected Financial Data
- - Five-Year Comparison," and "System Energy Selected Financial Data -
Five-Year Comparison," (which follow each company's notes to financial
statements herein) incorporated herein by reference, for further
information with respect to operating statistics of the System and of
AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy, respectively.
Employees
As of December 31, 1993, Entergy had 16,679 employees as
follows:
Full-time:
Entergy Corporation 6
AP&L 2,557
GSU (1) 4,765
LP&L 1,727
MP&L 1,236
NOPSI 716
System Energy -
Entergy Operations 3,508
Entergy Services (2) 1,986
Other Subsidiaries 24
------
Total Full-time 16,525
Part-time 154
------
Total Entergy System 16,679
======
__________________
(1) As of December 31, 1993, GSU had not been functionally aligned
into Entergy. In December 1993, GSU recorded $17 million for
an announced early retirement program in connection with the Merger.
Of the 503 employees eligible, 369 employees elected to participate
in the program.
(2) As a result of System realignment of operations along
functional lines, certain employees of AP&L, LP&L, MP&L, and
NOPSI transferred to Entergy Services during 1993.
Competition
General. Entergy and the electric utility industry are
experiencing increased competitive pressures both in the retail and
wholesale markets. The economic, social, and political forces behind
these competitive pressures are numerous and complex. They include
legislative and regulatory changes, technological advances, consumer
demands, greater availability of natural gas, environmental needs, and
others. Entergy looks at these competitive pressures both as
opportunities to compete for new customers and as risks for loss of
customers.
On October 24, 1992, Congress passed the Energy Act. The Energy
Act addresses a wide range of energy issues and alters the way Entergy
and the rest of the electric utility industry will operate in the
future. The Energy Act creates exemptions from regulation under the
Holding Company Act and creates a class of EWG's consisting of utility
affiliates and nonutilities that are owners and operators of
facilities for the generation and transmission of power for sales at
wholesale. These exemptions offer an incentive for Entergy to
participate in the development of wholesale power generation. In
addition, the Holding Company Act has been amended to allow utilities
to compete on a global scale with foreign entities to own and operate
generation, transmission, and distribution facilities. The Energy Act
also gives FERC the authority to order investor-owned utilities,
including the System operating companies, to transmit power and energy
to or for wholesale purchasers and sellers. The law creates the
potential for electric utilities and other power producers to gain
increased access to the transmission systems of other entities to
facilitate wholesale sales. FERC may also require electric utilities
to increase their transmission capacity to provide these services.
The impact of this provision on the System operating companies should
be lessened by their joint filing of open access transmission service
tariffs with FERC in 1991 (see "Rate Matters and Regulation - Rate
Matters - Wholesale Rate Matters," below). The Energy Act also amends
PURPA by requiring states to consider (1) new regulatory standards
that would require electric utilities to undertake integrated resource
planning, and (2) allowing energy efficiency programs to be at least
as profitable as new energy supply options. Entergy is unable to
predict the ultimate impact the Energy Act will have on its
operations.
Wholesale Competition. Entergy has, like other utility systems,
generating capacity (most of which is owned by Entergy Power) and
energy available for a period of time for sale to other utility
systems. The System is in competition with neighboring systems, as
well as EWG's, to sell such capacity and energy. Given this
competition, the ability of the System to sell this capacity and
energy is limited. However, in 1993, the System sold 8,291 million
KWH of energy (compared to 7,979 million KWH in 1992) to nonaffiliated
utilities. The System also sold 1,234 MW of long-term capacity
(compared to 1,048 MW in 1992) to nonaffiliated utilities outside of
the System's service area. These capacity sales represent 8% of the
System's net capability (excluding GSU) at year-end 1993. Under
AP&L's and LP&L's Grand Gulf 1 rate orders, and under GSU's River Bend
rate order in Louisiana, a portion of the capacity of Grand Gulf 1 and
River Bend represents capacity that is available for sale, subject to
regulatory approval, to nonaffiliated parties. In some cases, profits
from such sales must be shared between ratepayers and shareholders.
As discussed in "Rate Matters and Regulation - Rate Matters -
Wholesale Rate Matters - Open Access Transmission," below, Entergy
Power and the System operating companies will be permitted by FERC to
make wholesale capacity sales in bulk power markets at rates based
primarily upon negotiation and market conditions rather than cost of
service. In order to receive authorization to make such sales, AP&L,
LP&L, MP&L, and NOPSI also filed with FERC open access transmission
service tariffs. FERC has approved this filing, subject to certain
modifications. Revisions to the tariffs were filed in December 1993
to recognize GSU's inclusion in the Entergy System. When the modified
tariffs are made effective, Entergy Power and the System operating
companies may engage in sales at market prices. It is anticipated
that these tariffs will enable any electric utility (as defined in
such tariffs) to use Entergy 's integrated transmission system for
the transmission of capacity and energy produced and sold by such
electric utility or by third parties. Other similar open access
transmission tariffs have also been filed with FERC for several large
utility companies or systems and more open access transmission tariffs
are anticipated. Concurrently, capacity resources are being developed
and used to make wholesale sales from a range of non-traditional
sources, including nonutility generators as well as cogenerators and
small power producers qualifying under PURPA.
These developments simultaneously produce increased marketing
opportunities for utility systems such as Entergy and expose the
System to loss of load or reduced sales revenues due to displacement
of System sales by alternative suppliers with access to the System's
primary areas of service. Entergy Power, which owns 809 MW of
capacity, was formed to compete with other utilities and independent
power producers in the bulk power market. As of December 31, 1993,
Entergy Power has accumulated total losses from operations of $52.5
million. Entergy Power has entered into several long-term contracts
for the sale of capacity and associated energy from its resources and
has also made short-term capacity and energy sales. Entergy Power
continues to actively market its capacity and energy in the bulk power
market. (See "Corporate Development," above, for information with
respect to a wholly-owned subsidiary of Entergy, Entergy Power
Development Corporation, organized as an EWG to compete in the
wholesale power market.)
Retail Competition. Scheduled increases in the price of power
sold by the System pursuant to the operation of phase-in plans (see
"Rate Matters and Regulation - Rate matters - Retail Rate Matters,"
below) will affect the competitiveness of certain classes of
industrial customers whose costs of production are energy-sensitive.
Entergy is constantly working with these customers to address their
concerns. It is the practice of the System operating companies to
negotiate the renewal of contracts with large industrial customers
prior to their expiration. In certain cases (particularly for GSU),
contracts or special tariffs that use incentive pricing below total
cost have been negotiated with industrial customers to keep these
customers on the System. These contracts and tariffs have generally
resulted in increased KWH sales at lower margins over incremental
cost. While the System operating companies anticipate they will be
successful in renegotiating such contracts, they cannot assure that
they will be successful or that future revenues will not be lost to
other forms of generation. To date, through these efforts, Entergy
has been largely successful in retaining its industrial load. This
competitive challenge could increase.
Cogeneration is generally defined as the combined production of
electricity and steam. Cogenerated power may be either sold by its
producer to the local utility at its avoided cost under PURPA, or
utilized by the cogenerator to displace purchases from the utility.
To the extent that cogeneration is used by industrial customers to
meet their own power requirements, the System may suffer loss of
industrial load. Cogenerated power delivered to the System would be
purchased at avoided cost, which for a number of years is expected to
be equivalent to avoided energy cost, and as such, the cost of these
purchases would not impact earnings. To date, only a few cogeneration
facilities have been installed in areas served by the System,
excluding GSU. The primary purpose of these facilities is to displace
power that was purchased from the System. The economic advantage to
the customer is generally due to the customer having waste products
that can be used as fuel. Presently, the loss of load to cogeneration
and the amount of cogenerated power delivered under PURPA to the
System (excluding GSU) is not significant. The System is prepared to
participate (subject to regulatory approval) in various phases of the
design, construction, procurement, and ownership of cogeneration
facilities. The System has entered into several cogeneration deferral
agreements with certain of its retail customers, which give the System
the right of first refusal to participate in any of such customers'
cogeneration activities. Such participation could occur in the event
there are individual customers whose long-term interests, along with
Entergy's, can best be served by installing cogeneration facilities.
No such participation has occurred to date, except by GSU.
Existing qualifying facilities in the GSU service territory are
estimated to total approximately 2,400 MW's or over 10% of Entergy's
total owned and leased generating capability as of December 31, 1993.
GSU currently believes that no significant load will be lost to
cogeneration projects during the next several years; however, GSU is
currently negotiating a contract with a large industrial customer,
which is scheduled to expire in 1996. If the contract is not renewed,
GSU would lose approximately $40 million in base revenues.
Although GSU has competed in the past for various retail and
wholesale customers, the System (excluding GSU) generally is not in
direct competition with privately-owned or municipally-owned electric
utilities for retail sales. However, a few municipalities distribute
electricity within their corporate limits and some of these generate
all or a portion of their requirements. A number of electric
cooperative associations or corporations serve a substantial number of
retail customers in or adjacent to areas served by the System . Sales
of energy by the System to privately- or municipally-owned utilities
amounted to approximately 4.6% of total System energy sales in 1993
(excluding GSU).
Legislatures and regulatory commissions in several states have
considered, or are considering, retail wheeling, which is the
transmission by an electric utility of energy produced by another
entity over the utility's transmission and distribution system to a
retail customer in the electric utility's service territory. Retail
wheeling would permit retail customers to elect to purchase electric
capacity and/or energy from the electric utility in whose service area
they are located or from any other electric utility or independent
power producer. Retail wheeling is not currently required within the
Entergy System service area. See "Rate Matters and Regulation -
Regulation - Other Regulation and Litigation," below for information
on proceedings brought by Cajun seeking transmission access to certain
of GSU's industrial customers.
Least Cost Planning. The System continues to pursue least cost
planning, also known as integrated resource planning, in order to
compete more effectively in both retail and wholesale markets. Least
cost planning is the development of strategies to add resources to
meet future electricity demands reliably and at the lowest possible
cost. The least cost planning process includes the study of electric
supply- and demand-side options. The resultant plan uses demand-side
options, such as changing customer consumption patterns, to limit
electricity usage during times of peak demand, thus delaying the need
for new capacity resources. Least cost planning offers the potential
for the System to minimize customer costs, while providing an
opportunity to earn a return.
On December 1, 1992, AP&L, LP&L, MP&L, and NOPSI each filed a
Least Cost Plan with its respective regulator, and on July 1, 1993,
each company filed a near-term revision to such plan. Each Least Cost
Plan details the resources that the System intends to use to provide
reasonably priced, reliable electric service to its customers over the
next 20 years. Such plan includes 925 MW of DSM resources, such as
programs for efficient air conditioning and heating, high efficiency
lighting, and CCLM. CCLM is the subject of recent Entergy proposals
(filed, or to be filed, by AP&L, LP&L, MP&L, and NOPSI with their
respective regulators) requesting the CCLM pilot be withdrawn from
consideration in the existing Least Cost Plan dockets on the basis of
a new proposal by Entergy to undertake the initial pilot development
of CCLM at Entergy stockholder expense. To date, the Council and the
LPSC are the only regulators that have addressed the proposal. The
System expects to spend a total of approximately $800 million for DSM
resources over the next 20 years. Such plan also includes significant
resource additions, but does not contemplate construction of any
generating facilities at new sites. All incremental supply-side
resources will come from either delayed retirements or repowering of
existing generating units. The System estimates that, over the next
20 years, least cost planning, if implemented in accordance with the
terms of each filed Least Cost Plan, will reduce revenue requirements
by approximately $2.3 billion ($600 million on a net present value
basis), thereby avoiding the need for related rate increase requests.
Each Least Cost Plan includes specific actions that the System will
undertake pursuant to regulatory approval, including the recovery of
costs associated with DSM (for further information, see "Rate Matters
and Regulation - Rate Matters - Retail Rate Matters," below).
CAPITAL REQUIREMENTS AND FUTURE FINANCING
Construction expenditures for the System are estimated to
aggregate $586 million, $560 million, and $550 million for the years
1994, 1995, and 1996, respectively. No significant costs are expected
in connection with the System's generating facilities. Actual
construction costs may vary from these estimates because of a number
of factors, including changes in load growth estimates, changes in
environmental regulations, modifications to nuclear units to meet
regulatory requirements, increasing costs of labor, equipment and
materials, and cost of capital.
Construction expenditures by company (including immaterial
environmental expenditures and AFUDC, but excluding nuclear fuel and
the impact of the ice storm that occurred in February 1994) for the
period 1994-1996 are estimated as follows:
1994 1995 1996 Total
---- ---- ---- -----
(In Millions)
AP&L $181 $172 $175 $528
GSU 134 128 119 381
LP&L 156 143 142 441
MP&L 61 63 63 187
NOPSI 26 26 26 78
System Energy 26 22 23 71
Entergy Power 2 6 2 10
System $586 $560 $550 $1,696
In addition to construction expenditure requirements, the
estimated amounts required during 1994-1996 to meet scheduled long-
term debt and preferred stock maturities and cash sinking fund
requirements are: AP&L - $83 million; GSU - $214 million; LP&L - $158
million; MP&L - $212 million; NOPSI - $80 million; and System Energy -
$615 million. A substantial portion of the above capital and
refinancing requirements is expected to be satisfied from internally
generated funds and cash on hand supplemented by the issuance of debt
and preferred stock. Certain System companies may also continue with
the acquisition or refinancing of all, or a portion of, certain
outstanding series of preferred stock and long-term debt.
In early February 1994, an ice storm left more than 221,000
Entergy customers without electric power across the System's four-
state service area. The storm was the most severe natural disaster
ever to affect the System, causing damage to transmission and
distribution lines, equipment, poles, and facilities in certain areas,
particularly in Mississippi. A substantial portion of the related
costs, which are estimated to be $110 million - $140 million, are
expected to be capitalized. The MPSC acknowledged that there is
precedent in Mississippi for recovery of certain costs associated with
storms and natural disasters and the restoration of service resulting
from such events. MP&L plans to immediately file for rate recovery of
the costs related to the ice storm (see "Rate Matters and Regulation -
Rate Matters - Retail Rate Matters - MP&L," below).
Entergy Corporation's current primary capital requirements are to
periodically invest in, or make loans to, its subsidiaries. Entergy
Corporation has SEC authorization to make additional investments in
Entergy Power, Entergy S.A., Entergy Argentina, S.A., Entergy
Transener, S.A., Entergy SASI, and FPN. Entergy Corporation expects
to meet these requirements in 1994-1996 with internally generated
funds and cash on hand. Entergy receives funds through dividend
payments from its subsidiaries. Certain restrictions may limit the
amount of these distributions. See Entergy Corporation and
Subsidiaries' Notes to Consolidated Financial Statements, Note 2,
"Rate and Regulatory Matters" and Note 8, "Commitments and
Contingencies," incorporated herein by reference, regarding River Bend
rate appeals and pending litigation with Cajun. Substantial write-
offs or charges resulting from adverse rulings in these matters could
adversely affect GSU's ability to continue to pay dividends.
Entergy Corporation continues to consider new opportunities to
expand its electric energy business, including expansion into related
nonregulated businesses. Entergy Corporation expects to invest up to
approximately $150 million per year over the next three years in
nonregulated business opportunities. Entergy Corporation may finance
any such expansion with cash on hand. Further, shareholder and/or
regulatory approvals may be required for such acquisitions to take
place. Also, Entergy Corporation has SEC authorization to repurchase
shares of its outstanding common stock. Market conditions and board
authorization determine the amount of repurchases. Entergy
Corporation has requested SEC authorization for a $300 million bank
line of credit, the proceeds of which are expected to be used for
common stock repurchases and other optional activities.
(For further information on the capital and refinancing
requirements, capital resources, and short-term borrowing arrangements
of AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy, respectively,
refer in each case to AP&L's, GSU's, LP&L's, MP&L's, NOPSI's, and
System Energy's "Management's Financial Discussion and Analysis -
Liquidity and Capital Resources," Note 4 of AP&L's, GSU's, LP&L's,
MP&L's, NOPSI's, and System Energy's Notes to Financial Statements,
"Lines of Credit and Related Borrowings," Note 5 of AP&L's and NOPSI's
Notes to Financial Statements, "Preferred Stock", Note 5 of GSU's
Notes to Financial Statements, "Preferred, Preference and Common
Stock", Note 5 of LP&L's and MP&L's Notes to Financial Statements,
"Preferred and Common Stock," Note 6 of AP&L's, GSU's, LP&L's, MP&L's,
and NOPSI's and Note 5 of System Energy's Notes to Financial
Statements, "Long-Term Debt," and Note 8 of AP&L's, GSU's, LP&L's,
MP&L's, and NOPSI's and Note 7 of System Energy's Notes to Financial
Statements, "Commitments and Contingencies - Capital Requirements and
Financing," each incorporated herein by reference. For further
information concerning Entergy Corporation's capital requirements and
resources, refer to Entergy Corporation and Subsidiaries'
"Management's Financial Discussion and Analysis - Liquidity and
Capital Resources," and Note 4 of Entergy Corporation and
Subsidiaries' Notes to Consolidated Financial Statements, "Lines of
Credit and Related Borrowings," incorporated herein by reference. For
further information on the subsequent event, see Note 12 of AP&L's and
Note 11 of MP&L's Notes to Financial Statements, "Subsequent Event
(Unaudited)," incorporated herein by reference.)
Certain System Financial and Support Agreements
Unit Power Sales Agreement. The Unit Power Sales Agreement
allocates capacity and energy from System Energy's 90% ownership and
leasehold interest in Grand Gulf 1 (and the costs related thereto) to
AP&L (36%), LP&L (14%), MP&L (33%), and NOPSI (17%). AP&L, LP&L,
MP&L, and NOPSI pay rates to System Energy for their respective
entitlements of capacity and energy on a full cost-of-service basis
regardless of the quantity of energy delivered, so long as Grand Gulf
1 remains in commercial operation. Payments under the Unit Power
Sales Agreement are System Energy's only source of operating revenues.
The financial condition of System Energy depends upon the continued
commercial operation of Grand Gulf 1 and upon the receipt of payments
from AP&L, LP&L, MP&L, and NOPSI. (See "Rate Matters and Regulation -
Rate Matters - Wholesale Rate Matters - System Energy," below for
further information with respect to proceedings relating to the Unit
Power Sales Agreement.)
Availability Agreement. The Availability Agreement was entered
into among System Energy and AP&L, LP&L, MP&L, and NOPSI in 1974 in
connection with the financing by System Energy of the Grand Gulf
Station. The agreement provided that System Energy would join in the
agreement among AP&L, LP&L, MP&L, and NOPSI for the sharing of
generating capacity and other capacity and energy resources on or
before the date on which Grand Gulf 1 was placed in commercial
operation. It also provided that System Energy would make available
to AP&L, LP&L, MP&L, and NOPSI all capacity and energy available from
System Energy's share of the Grand Gulf Station. System Energy and
AP&L, LP&L, MP&L, and NOPSI further agreed that if this agreement were
terminated, or if any of the parties thereto withdrew from it, then
System Energy would enter into a separate agreement with all of such
parties or the withdrawing party, as the case may be, with respect to
the purchase of capacity and energy on the same terms as if this
agreement were still controlling.
AP&L, LP&L, MP&L, and NOPSI also agreed severally to pay System
Energy monthly for the right to receive capacity and energy available
from the Grand Gulf Station in amounts that (when added to any amounts
received by System Energy under the Unit Power Sales Agreement, or
otherwise) would be at least equal to System Energy's total operating
expenses for the Grand Gulf Station (including depreciation at a
specified rate) and interest charges.
As amended to date, the Availability Agreement provides that:
- the obligation of AP&L, LP&L, MP&L, and NOPSI for payments for
Grand Gulf 1 became effective upon commercial operation of
Grand Gulf 1 on July 1, 1985;
- the sale of capacity and energy generated by the Grand Gulf
Station may be governed by a separate power purchase agreement
among System Energy and AP&L, LP&L, MP&L, and NOPSI;
- the September 1989 write-off of System Energy's investment in
Grand Gulf 2, amounting to approximately $900 million, will be
amortized for Availability Agreement purposes over 27 years
rather than in the month the write-off was recognized on
System Energy's books; and
- the allocation percentages under the Availability Agreement are
fixed as follows: AP&L - 17.1%; LP&L - 26.9%; MP&L - 31.3%;
and NOPSI - 24.7%.
As noted above, the Unit Power Sales Agreement provides for
different allocation percentages for sales of capacity and energy from
Grand Gulf 1. However, the allocation percentages under the
Availability Agreement remain in effect and would govern payments made
thereunder in the event of a shortfall of funds available to System
Energy from other sources, including payments by AP&L, LP&L, MP&L, and
NOPSI to System Energy under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances
from AP&L, LP&L, MP&L, and NOPSI under the Availability Agreement as
security for its first mortgage bonds and reimbursement obligations to
certain banks providing the letters of credit in connection with the
equity funding of the sale and leaseback transactions described under
"Sale and Leaseback Arrangements - System Energy," below. In these
assignments, AP&L, LP&L, MP&L, and NOPSI further agreed that in the
event they were prohibited by governmental action from making payments
under the Availability Agreement (if, for example, FERC reduced or
disallowed such payments as constituting excessive rates; see the
second succeeding paragraph), they would then make subordinated
advances to System Energy in the same amounts and at the same times as
the prohibited payments. System Energy would not be allowed to repay
these subordinated advances so long as it remained in default under
the related indebtedness or in other similar circumstances.
Each of the assignment agreements relating to the Availability
Agreement provides that AP&L, LP&L, MP&L, and NOPSI shall make
payments directly to System Energy. However, if there is an event of
default, AP&L, LP&L, MP&L, and NOPSI shall make those payments
directly to the holders of indebtedness secured by such assignment
agreements. The payments shall be made pro rata according to the
amount of the respective obligations secured.
The obligations of AP&L, LP&L, MP&L, and NOPSI to make payments
under the Availability Agreement are subject to receipt and continued
effectiveness of all necessary regulatory approvals. Sales of
capacity and energy under the Availability Agreement would require
that the Availability Agreement be submitted to FERC for approval with
respect to the terms of such sale. No filing with FERC has been
required because sales of capacity and energy from the Grand Gulf
Station are being made under the Unit Power Sales Agreement. Other
aspects of the Availability Agreement, including the obligations of
AP&L, LP&L, MP&L, and NOPSI to make subordinated advances, are subject
to the jurisdiction of the SEC under the Holding Company Act, which
approval has been obtained. If, for any reason, sales of capacity and
energy are made in the future pursuant to the Availability Agreement,
the jurisdictional portions of the Availability Agreement would be
submitted to FERC for approval. (Refer to the second preceding
paragraph.)
Amounts that have been received by System Energy under the Unit
Power Sales Agreement have exceeded the amounts payable under the
Availability Agreement. Consequently, no payments under the
Availability Agreement by AP&L, LP&L, MP&L, and NOPSI have ever been
required. If AP&L, LP&L, MP&L, or NOPSI became unable in whole or in
part to continue making payments to System Energy under the Unit Power
Sales Agreement, and System Energy were unable to procure funds from
other sources sufficient to cover any potential shortfall between the
amount owing under the Availability Agreement and the amount of
continuing payments under the Unit Power Sales Agreement plus other
funds then available to System Energy, LP&L and NOPSI could become
subject to claims or demands by System Energy or its creditors for
payments or advances under the Availability Agreement or the
assignments thereof for the difference between their required Unit
Power Sales Agreement payments and their required Availability
Agreement payments. The amount, if any, which these companies would
become liable to pay or advance, over and above amounts they would be
paying under the Unit Power Sales Agreement for capacity and energy
from Grand Gulf 1, would depend on a variety of factors (especially
the degree of any such shortfall and System Energy's access to other
funds). It cannot be predicted whether any such claims or demands, if
made and upheld, could be satisfied. In NOPSI's case, if any such
claims or demands were upheld, the holders of certain of NOPSI's
outstanding general and refunding mortgage bonds could require
redemption of their bonds at par. The ability of AP&L, LP&L, MP&L,
and NOPSI to sustain payments under the Availability Agreement and the
assignments thereof in material amounts without substantially
equivalent recovery from their customers would be limited by their
respective available cash resources and financing capabilities at the
time.
The ability of AP&L, LP&L, MP&L, and NOPSI to recover from their
customers payments made under the Availability Agreement, or under the
assignments thereof, would depend upon the outcome of regulatory
proceedings before the state and local regulatory authorities having
jurisdiction. In view of the controversies that arose over the
allocation of capacity and energy from Grand Gulf 1 pursuant to the
Unit Power Sales Agreement, opposition to recovery would be likely and
the outcome of such proceedings, should they occur, is not
predictable.
Reallocation Agreement. On November 18, 1981, the SEC authorized
LP&L, MP&L, and NOPSI to indemnify AP&L against principally its
responsibilities and obligations with respect to the Grand Gulf
Station contained in the Availability Agreement and the assignments
thereof. The revised percentages of allocated capacity of System
Energy's share of Grand Gulf 1 and Grand Gulf 2 were, respectively:
LP&L - 38.57% and 26.23%; MP&L - 31.63% and 43.97%; and NOPSI - 29.80%
and 29.80%. FERC's decision allocating the capacity and energy of
Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI supersedes the
Reallocation Agreement insofar as it relates to Grand Gulf 1.
However, responsibility for any Grand Gulf 2 amortization amounts (see
"Availability Agreement," above) has been allocated to LP&L - 26.23%,
MP&L - 43.97%, and NOPSI - 29.80% under the terms of the Reallocation
Agreement. The Reallocation Agreement does not affect the obligation
of AP&L to System Energy's lenders under the assignments referred to
in the fifth preceding paragraph, and AP&L would be liable for its
share of such amounts if LP&L, MP&L, and NOPSI were unable to meet
their contractual obligations. No payments of any amortization
amounts will be required as long as amounts paid to System Energy
under the Unit Power Sales Agreement, together with other funds
available to System Energy, exceed amounts required under the
Availability Agreement, which is expected to be the case for the
foreseeable future.
Capital Funds Agreement. System Energy and Entergy Corporation
have entered into the Capital Funds Agreement whereby Entergy
Corporation has agreed to supply to System Energy sufficient capital
to (1) maintain System Energy's equity capital at an amount equal to a
minimum of 35% of its total capitalization (excluding short-term
debt), and (2) permit the continuation of commercial operation of
Grand Gulf 1 and to pay in full all indebtedness for borrowed money of
System Energy when due under any circumstances.
Entergy Corporation has entered into various supplements to the
Capital Funds Agreement, and System Energy has assigned its rights
thereunder as security for its first mortgage bonds and reimbursement
obligations to certain banks providing letters of credit in connection
with the equity funding of the sale and leaseback transactions
described under "Sale and Leaseback Arrangements - System Energy,"
below. Each such supplement provides that permitted indebtedness for
borrowed money incurred by System Energy in connection with the
financing of the Grand Gulf Station may be secured by System Energy's
rights under the Capital Funds Agreement on a pro rata basis (except
for the Specific Payments, as hereinafter defined). In addition, in
the particular supplements to the Capital Funds Agreement relating to
the specific indebtedness being secured, Entergy Corporation has
agreed to make cash capital contributions to System Energy sufficient
to enable System Energy to make payments when due on such indebtedness
(Specific Payments).
Except with respect to the Specific Payments, which have been
approved by the SEC under the Holding Company Act, the performance by
both Entergy Corporation and System Energy of their obligations under
the Capital Funds Agreement, as supplemented, is subject to the
receipt and continued effectiveness of all governmental authorizations
necessary to permit such performance, including approval by the SEC
under the Holding Company Act. Each of the supplemental agreements
provides that Entergy Corporation shall make its payments directly to
System Energy. However, if there is an event of default, Entergy
Corporation shall make those payments directly to the holders of
indebtedness secured by the supplemental agreements. The payments
(other than the Specific Payments) shall be made pro rata according to
the amount of the respective obligations secured by the supplemental
agreements.
Sale and Leaseback Arrangements
LP&L. On September 28, 1989, LP&L entered into arrangements for
the sale and leaseback of an approximate aggregate 9.3% ownership
interest in Waterford 3. LP&L has options to terminate the leases and
to repurchase the sold interests in Waterford 3 at certain intervals
during the basic terms of the leases. Further, at the end of the
terms of the leases, LP&L has options to renew the leases or to
repurchase the interests in Waterford 3. If LP&L does not exercise
its options to repurchase the interests in Waterford 3 on the fifth
anniversary (September 28, 1994) of the closing date of the sale and
leaseback transactions, LP&L will be required to provide collateral to
the owner participants for the equity portion of certain amounts
payable by LP&L under the lease. The required collateral is either a
bank letter or letters of credit or the pledging of new series of
first mortgage bonds issued by LP&L under its first mortgage bond
indenture. (For further information on LP&L's sale and leaseback
arrangements, including the required maintenance by LP&L of specified
capitalization and fixed charge coverage ratios, see Note 9 of LP&L's
Notes to Financial Statements, "Leases - Waterford 3 Lease
Obligations," incorporated herein by reference.)
System Energy. On December 28, 1988, System Energy entered into
arrangements for the sale and leaseback of an 11.5% ownership interest
in Grand Gulf 1. System Energy has options to terminate the leases
and to repurchase the undivided interest in Grand Gulf 1 at certain
intervals during the basic lease term. Further, System Energy has an
option at the end of the basic lease term to renew the leases or to
repurchase the undivided interest in Grand Gulf 1. In connection with
the equity funding of the sale and leaseback arrangements, letters of
credit are required to be maintained by System Energy under the leases
to secure certain amounts payable for the benefit of the equity
investors. The letters of credit currently maintained are effective
until January 15, 1997. Under the provisions of a reimbursement
agreement, dated December 1, 1988, as amended, entered into by System
Energy and various banks in connection with the sale and leaseback
arrangements related to the letters of credit, System Energy has
agreed to a number of covenants relating to, among other things, the
maintenance of certain capitalization and fixed charge ratios. In
connection with an audit of System Energy by FERC, if a decision of
FERC issued on August 4, 1992 (August 4 Order) is ultimately sustained
and implemented, System Energy would need to obtain the consent of
certain banks to waive the capitalization and fixed charge coverage
covenants for a limited period of time in order to avoid violation of
such covenants. System Energy has obtained the consent of the banks
to waive these covenants for the twelve-month period beginning with
the earlier of the write-off or the first refund, if the August 4
Order is implemented prior to December 31, 1994. Absent a waiver,
failure by System Energy to perform these covenants could give rise to
a draw under the letters of credit and/or an early termination of the
letters of credit, and, if such letters of credit were not replaced in
a timely manner, could result in a default under, or other early
termination of, System Energy's leases. (For further information on
the potential effects of the August 4 Order on System Energy's
financial condition, see Note 2 of System Energy's Notes to Financial
Statements, "Rate and Regulatory Matters - FERC Audit," incorporated
herein by reference, and for a further discussion of the provisions of
System Energy's Reimbursement Agreement, see System Energy's Notes to
Financial Statements, Note 6, "Dividend Restrictions" and Note 7,
"Commitments and Contingencies - Reimbursement Agreement,"
incorporated herein by reference.)
RATE MATTERS AND REGULATION
RATE MATTERS
The System operating companies' retail rates are regulated by
their respective state and/or local regulatory authorities, as
described below, and their rates for wholesale sales (including
intrasystem sales pursuant to the System Agreement) and interstate
transmission of electricity are regulated by FERC. Rates for System
Energy's sales of capacity and energy from Grand Gulf 1 to AP&L, LP&L,
MP&L, and NOPSI pursuant to the Unit Power Sales Agreement are also
regulated by FERC.
Wholesale Rate Matters
GSU. For information, see "Retail Rate Matters - GSU," below and
"Regulation - Other Regulation and Litigation - GSU," below.
System Energy. As described above under "Certain System
Financial and Support Agreements," System Energy recovers costs
related to its interest in Grand Gulf 1 through rates charged to AP&L,
LP&L, MP&L, and NOPSI for Grand Gulf 1 capacity and energy under the
Unit Power Sales Agreement. Several proceedings currently pending or
recently concluded at FERC affect these rates.
In connection with an audit report covering a review of System
Energy's books and records for the years 1986-1988, on August 4, 1992,
FERC issued an opinion and order (1) finding that System Energy
overstated its Grand Gulf 1 utility plant by approximately $95 million
for costs included in utility plant that are related to the System's
income tax allocation procedures, and (2) requiring System Energy to
make adjusting accounting entries and refunds, with interest, to AP&L,
LP&L, MP&L, and NOPSI within 90 days from the date of the order.
System Energy requested a rehearing of the order, and on October 5,
1992, FERC issued an order allowing additional time for its
consideration of such request and deferring System Energy's refund
obligation until 30 days following issuance of FERC's order on
rehearing. (For further information on FERC's order and its potential
effect on System Energy's and Entergy's consolidated financial
position, see Note 2 of System Energy's Notes to Financial Statements
and Note 2 of Entergy Corporation and Subsidiaries' Notes to
Consolidated Financial Statements, "Rate and Regulatory Matters - FERC
Audit," incorporated herein by reference.)
In a separate proceeding, on August 24, 1992, FERC instituted an
investigation of the justness and reasonableness of certain of
Entergy's formula wholesale rates, including System Energy's rates
under the Unit Power Sales Agreement. Various regulatory authorities
intervened in the proceeding. On August 2, 1993, Entergy and the
intervenors settled the proceeding and agreed that System Energy's
rate of return on equity would be reduced from 13% to 11%, and such
rate would remain in effect until at least August 1995. Refunds were
payable by System Energy with respect to the period from November 2,
1992, through the effective date of the settlement. FERC approved the
settlement on October 25, 1993, and System Energy credited AP&L, LP&L,
MP&L, and NOPSI with an aggregate of $29.6 million on their October
1993 bills. This matter is now final. (See Note 2 of System Energy's
Notes to Financial Statements, "Rate and Regulatory Matters - FERC
Return on Equity Case," incorporated herein by reference.)
Entergy Power. In 1990, authorizations were obtained from the
SEC, FERC, the APSC, and the Public Service Commission of Missouri for
Entergy Power to purchase AP&L's interests in Independence 2 and
Ritchie 2, and to begin marketing the capacity and energy from the
units in certain wholesale markets. The SEC order approving various
aspects of the transaction was appealed by various intervenors in the
proceeding to the D.C. Circuit, which reversed a portion of the order
and remanded the case to the SEC for consideration of the effect of
the transfers on the System's future costs of replacement generating
capacity and fuel. In response to a June 24, 1993 SEC order setting a
procedural schedule for the filing of further pleadings in the
proceeding, in July 1993, the Entergy parties filed a post-effective
amendment to their application addressing the issues specified in the
SEC order. On September 9, 1993, the City of New Orleans and the LPSC
each requested a hearing. However, on January 5, 1994, the City of
New Orleans withdrew from the proceeding, as agreed in its settlement
with NOPSI of various issues related to the Merger.
System Agreement. AP&L, LP&L, MP&L, and NOPSI engage in the
coordinated planning, construction, and operation of generation and
transmission facilities pursuant to the terms of the System Agreement
(described under "Property - Generating Stations," below). GSU became
a party to the System Agreement upon consummation of the merger of
Entergy's and GSU's electric systems, and GSU now participates in this
System-wide coordination. For further information, see Note 2 of
GSU's Notes to Financial Statements and Note 2 of Entergy Corporation
and Subsidiaries' Notes to Consolidated Financial Statements, "Rate
and Regulatory Matters - Merger-Related Rate Agreements."
In connection with the Merger, FERC approved certain rate
schedule changes to integrate GSU into the System Agreement. Certain
commitments were adopted to provide reasonable assurance that the
ratepayers of the existing Entergy operating companies will not be
allocated higher costs, including, among other things: (1) a tracking
mechanism to protect operating companies from certain unexpected
increases in fuel costs; (2) excluding GSU from the distribution of
profits from power sales contracts entered into prior to the Merger;
(3) a methodology to estimate the cost of capital in future FERC
proceedings; and (4) a stipulation that the operating companies will
be insulated from certain direct effects on capacity equalization
payments should GSU, due to a finding of imprudent GSU management
prior to the Merger, be required to purchase Cajun's 30% share in
River Bend. See "Regulation - Other Regulation and Litigation," for
information on requests for rehearing of FERC's approval.
On August 20, l990, the City of New Orleans filed a complaint
against Entergy Corporation, AP&L, LP&L, MP&L, NOPSI, and System
Energy requesting that FERC investigate AP&L's transfer of its
interest in Independence 2 and Ritchie 2 to Entergy Power (see
"Entergy Power," above) and the effect of the transfer on AP&L, LP&L,
MP&L, and NOPSI and their ratepayers. Various parties, including
certain of the System's state regulators, intervened in the
proceeding. FERC issued an order on March 19, 1991, setting for
investigation (l) the question of whether overall billings under the
System Agreement will increase as a result of the transfer to Entergy
Power, and (2) if so, whether such increased billings reflect
prudently incurred costs that may reasonably be charged under the
System Agreement. In two separate decisions with respect to these
issues, the FERC ALJ assigned to the matter ruled on May 14, l992 and
October 30, 1992, respectively, that there was sufficient evidence to
show that overall billings would increase as a result of the transfer,
but that the transfer was prudent. On December 15, 1993, FERC issued
an opinion declining to address the prudence issue until a future time
when replacement capacity has been added or planned and finding that,
until such time, billings under the System Agreement as affected by
the transfer of the two units are reasonable. The Entergy parties and
the City of New Orleans each filed a request for rehearing of this
order. If FERC's decision were reversed and any refunds were ordered,
they would be retroactive to October 19, 1990.
Open Access Transmission. On August 2, 1991, Entergy Services,
as agent for AP&L, LP&L, MP&L, NOPSI, and Entergy Power, submitted to
FERC (1) proposed tariffs that, subject to certain conditions, would
provide to electric utilities "open access" to the System's integrated
transmission system, and (2) rate schedules providing for sales of
wholesale power at market-based rates. Under FERC policy, sales of
power at market-based rates would be permitted only if FERC found,
among other things, that Entergy did not have market power over
transmission. Permitting "open access" to the System's transmission
system helps support such a finding. Various parties, including the
Council, the APSC, the MPSC, and the LPSC, intervened in the
proceeding. On March 3, 1992, FERC approved the filing, with some
modifications, and on August 7, l992, FERC denied rehearing of its
March 1992 order. On August 24, l992, various parties filed petitions
with the D.C. Circuit for review of FERC's 1992 orders, and these
petitions have been consolidated. The revised tariffs, submitted by
Entergy Services in response to FERC's 1992 orders, were accepted for
filing and made effective, subject to further modifications, by order
dated April 5, l993. Entergy Services made a further compliance
filing on May 5, l993, reflecting these modifications and requesting
reconsideration of certain limited matters, which is subject to
approval by FERC. On December 31, 1993, Entergy Services filed
revisions to the transmission service tariff to recognize GSU's
inclusion in the Entergy System. These matters are pending.
Retail Rate Matters
General. AP&L, LP&L, MP&L, and NOPSI currently have retail rate
structures sufficient to recover their costs, including costs
associated with their allocated shares of capacity and energy from
Grand Gulf 1 under the Unit Power Sales Agreement, and a return on
equity. Certain costs related to Grand Gulf 1 (and in LP&L's case,
Waterford 3 are being phased-into retail rates over a period of time,
in order to avoid the "rate shock" associated with increasing rates to
reflect all of such costs at once. The deferral period in which costs
are incurred but not currently recovered has expired for all of these
programs, and AP&L, LP&L, MP&L, and NOPSI are now recovering those
costs that were previously deferred. Also, AP&L and LP&L have
retained a portion of their shares of Grand Gulf 1 capacity and GSU is
operating under a deregulated asset plan for a portion of its share of
River Bend.
GSU is involved in several rate proceedings involving recovery,
among other things, of costs associated with River Bend. Some rate
relief has been received, but GSU has been unable to obtain
recognition in rates for a substantial portion of its River Bend
investment. Recovery of certain costs has been disallowed, while
other costs are being deferred for future recovery, held in abeyance
pending further regulatory action, or treated as investments in
deregulated assets. There are ongoing rate proceedings and appeals
relating to these issues (see "GSU," below).
The System is committed to taking actions that will stabilize
retail rates and avoid the need for future rate increases. In the
short-term, this involves containing costs to the greatest degree
practicable, thereby avoiding erosion of earnings and delaying for as
long as possible the need for general rate increases. In accordance
with this retail rate policy, the System operating companies have
agreed to retail rate caps and/or rate freezes for specified periods
of time.
In the longer term, as discussed in "Business of Entergy -
Competition - Least Cost Planning" above, and also as discussed
specifically for each applicable company below, the System is pursuing
implementation of least cost planning to minimize the cost of future
sources of energy.
Effective January 1, 1993, the System adopted SFAS No. 106 (SFAS
106), an accounting standard that requires accrual of the costs of
postretirement benefits other than pensions prior to the time these
costs are actually incurred. In 1992, the System operating companies
requested from their retail rate regulators authorization to recognize
in rates the costs associated with implementation of SFAS 106. For
further information, see Note 10 of Entergy Corporation and
Subsidiaries', Note 9 of MP&L's and NOPSI's, and Note 10 of AP&L's,
GSU's, and LP&L's Notes to Financial Statements, "Postretirement and
Postemployment Benefits," incorporated herein by reference.
AP&L
Rate Freeze. In connection with the settlement of various issues
related to the Merger, AP&L agreed that it will not request any
general retail rate increase that would take effect before November 3,
1998, except, among other things, for increases associated with the
Least Cost Plan (discussed below); recovery of certain Grand Gulf 1-
related costs, excess capacity costs, and costs related to the
adoption of SFAS 106 that were previously deferred; recovery of
certain taxes; fuel adjustment recoveries; recovery of nuclear
decommissioning costs; and force majeure (defined to include, among
other things, war, natural catastrophes, and high inflation).
Recovery of Grand Gulf 1 Costs. Under the settlement agreement
entered into with the APSC in 1985 and amended in 1988, AP&L agreed to
retain a portion of its Grand Gulf l-related costs, recover a portion
of such costs currently, and defer a portion of such costs for future
recovery. In 1994 and subsequent years, AP&L will retain 7.92% of
such costs (stated as a percentage of System Energy's 90% share of the
unit) and will recover 28.08% currently. Deferrals ceased in l990,
and AP&L is recovering a portion of the previously deferred costs each
year through l998. As of December 31, l993, the balance of deferred
uncollected costs was $568.0 million. AP&L is permitted to recover on
a current basis the incremental costs of financing the unrecovered
deferrals.
AP&L has the right to sell capacity and energy from its retained
share of Grand Gulf 1 to third parties and to sell such energy to its
retail customers at a price equal to AP&L's avoided energy cost.
Proceeds of sales to third parties of AP&L's retained share of Grand
Gulf l capacity and energy generally accrue to the benefit of AP&L's
stockholder; however, half of the proceeds of such sales to third
parties prior to January 1, 1996, are used to reduce the balance of
uncollected deferrals and thus accrue to the benefit of retail
ratepayers. If AP&L makes sales to third parties prior to that date
in excess of the retained share, the proceeds of such excess are also
split between the stockholder and the ratepayers, except that the
portion of the sale that accrues to the stockholder's benefit cannot
exceed the retained share.
Least Cost Planning. On December 1, 1992 and July 1, 1993, AP&L
filed with the APSC the Least Cost Plan described in "Business of
Entergy - Competition - Least Cost Planning," above. AP&L also
requested authorization to recover development and implementation
costs and costs and incentives related to the DSM aspects of the plan.
On October 13, 1993, the APSC found AP&L's plan to be complete and
directed the APSC staff to conduct a series of public forums in late
1993, including focus groups, town meetings, and collaborative
workshops, before it would establish a procedural schedule that would
include evidentiary hearings and the issuance of a Least Cost Plan
order. Several of these meetings were delayed into 1994, but are
expected to be completed by March 1994. At or before that time, AP&L
expects the APSC to issue a procedural schedule that will allow the
APSC to issue an order before the end of 1994. On January 19, 1994,
AP&L filed a request with the APSC for permission to withdraw the CCLM
portion of the filing and to continue such programs on a pilot basis
at shareholder expense. The APSC has not yet ruled on AP&L's request.
Fuel Adjustment Clause. AP&L's retail rate schedules have a fuel
adjustment clause that provides for recovery of the excess cost of
fuel and purchased power incurred in the second preceding month. The
fuel adjustment clause also contains a nuclear reserve fund designed
to cover the cost of replacement energy during scheduled maintenance
and refueling outages at ANO, and an incentive provision that permits
over- or under-recovery of the excess cost of replacement energy when
ANO is operating or down for reasons other than refueling.
GSU
Rate Cap and Other Merger-Related Rate Agreements. The LPSC and
the PUCT approved separate regulatory proposals that include the
following elements: (1) a five-year rate cap on GSU's retail electric
base rates in the respective states, except for force majeure (defined
to include, among other things, war, natural catastrophes, and high
inflation); (2) a provision for passing through to retail customers in
the respective states the jurisdictional portion of the fuel savings
created by the Merger; and (3) a mechanism for tracking nonfuel
operation and maintenance savings created by the Merger. The LPSC
regulatory plan provides that such nonfuel savings will be shared 60%
by the shareholder and 40% by ratepayers during the eight years
following the Merger. The LPSC plan requires regulatory filings each
year by the end of May through 2001. The PUCT regulatory plan
provides that such savings will be shared equally by the shareholder
and ratepayers, except that the shareholder's portion will be reduced
by $2.6 million per year on a total company basis in years four
through eight. The PUCT plan also requires a series of regulatory
filings, currently anticipated to be in June 1994, and February 1996,
1998, and 2001, to ensure that the ratepayers' share of such savings
be reflected in rates on a timely basis and requires Entergy
Corporation to hold GSU's Texas retail customers harmless from the
effects of the removal by FERC of a 40% cap on the amount of fuel
savings GSU may be required to transfer to other Entergy operating
companies under the FERC tracking mechanism (see "Rate Matters -
Wholesale Rate Matters - System Agreement," above). On January 14,
1994, Entergy Corporation filed a request for rehearing of FERC's
December 15, 1993 order approving the Merger, requesting that FERC
restore the 40% cap provision in the fuel cost protection mechanism
(see "Regulation - Other Litigation and Regulation," below). The
matter is pending.
Recovery of River Bend Costs. GSU deferred approximately $369
million of River Bend operating costs, purchased power costs, and
accrued carrying charges pursuant to a 1986 PUCT accounting order.
Approximately $182 million of these costs are being amortized over a
20-year period, and the remaining $187 million are not being amortized
pending the ultimate outcome of the Rate Appeal (see "Texas
Jurisdiction - River Bend," below). As of December 31, 1993, the
unamortized balance of these costs was $330.3 million. Further, GSU
deferred approximately $400.4 million of similar costs pursuant to a
1986 LPSC accounting order. These costs, of which approximately
$160.4 million are unamortized as of December 31, 1993, are being
amortized over a 10-year period.
In accordance with a phase-in plan approved by the LPSC, GSU
deferred $324.7 million of its River Bend costs related to the period
December 1987 through February 1991. GSU has amortized $86.6 million
through December 31, 1993, and the remainder of $238.1 million will be
recovered over approximately 3.8 years.
Texas Jurisdiction - River Bend. In May 1988, the PUCT granted
GSU a permanent increase in annual revenues of $59.9 million resulting
from the inclusion in rate base of approximately $1.6 billion of
company-wide River Bend plant investment and approximately $182
million of related Texas retail jurisdiction deferred River Bend costs
(Allowed Deferrals). In addition, the PUCT disallowed as imprudent
$63.5 million of company-wide River Bend plant costs and placed in
abeyance, with no finding of prudency, approximately $1.4 billion of
company-wide River Bend plant investment and approximately $157
million of Texas retail jurisdiction deferred River Bend operating and
carrying costs. The PUCT affirmed that the ultimate rate treatment of
such amounts would be subject to future demonstration of the prudency
of such costs. GSU and intervening parties appealed this order (Rate
Appeal) and GSU filed a separate rate case asking that the abeyed
River Bend plant costs be found prudent (Separate Rate Case).
Intervening parties filed suit in district court to prohibit the
Separate Rate Case. The district court's decision was ultimately
appealed to the Texas Supreme Court which ruled in 1990 that the
prudence of the purported abeyed costs could not be relitigated in a
separate rate proceeding. Further, the Texas Supreme Court's decision
stated that all issues relating to the merits of the original order of
the PUCT, including the prudence of all River Bend-related costs,
should be addressed in the Rate Appeal.
In October 1991, the district court in the Rate Appeal issued an
order holding that, while it was clear the PUCT made an error in
assuming it could set aside $1.4 billion of the total costs of River
Bend and consider them in a later proceeding, the PUCT, nevertheless,
found that GSU had not met its burden of proof related to the amounts
placed in abeyance. The court also ruled that the Allowed Deferrals
should not be included in rate base under a 1991 decision regarding El
Paso Electric Company's similar deferred costs (El Paso Case). The
court further stated that the PUCT erred in reducing GSU's deferred
costs by $1.50 for each $1.00 of revenue collected under the interim
rate increases authorized in 1987 and 1988. The court remanded the
case to the PUCT with instructions as to the proper handling of the
Allowed Deferrals. GSU's motion for rehearing was denied, and in
December 1991, GSU filed an appeal of the October 1991 district court
order. The PUCT also appealed the October 1991 district court order,
which served to supersede the district court's judgment, rendering it
unenforceable under Texas law.
In August 1992, the court of appeals in the El Paso Case handed
down its second opinion on rehearing modifying its previous opinion on
deferred accounting. The court's second opinion concluded that the
PUCT may lawfully defer operating and maintenance costs and
subsequently include them in rate base, but that the Public Utility
Regulatory Act prohibits such rate base treatment for deferred
carrying costs. The court stated, however, its opinion would not
preclude the recovery of deferred carrying costs. The August 1992
court of appeals opinion was appealed to the Texas Supreme Court where
arguments were heard in September 1993. The matter is still pending.
In September 1993, the Texas Third District Court of Appeals (the
Third District Court) remanded the October 1991 district court
decision to the PUCT "to reexamine the record evidence to whatever
extent necessary to render a final order supported by substantial
evidence and not inconsistent with our opinion." The Third District
Court specifically addressed the PUCT's treatment of certain costs,
stating that the PUCT's order was not based on substantial evidence.
The Third District Court also applied its most recent ruling in the El
Paso Case to the deferred costs associated with River Bend. However,
the Third District Court cautioned the PUCT to confine its
deliberations to the evidence addressed in the original rate case.
Certain parties to the case have indicated their position that, on
remand, the PUCT may change its original order only with respect to
matters specifically discussed by the Third District Court which, if
allowed, would increase GSU's allowed River Bend investment, net of
accumulated depreciation and related taxes, by approximately $48
million as of December 31, 1993. GSU believes that under the Third
District Court's decision, the PUCT would be free to reconsider any
aspect of its order concerning the abeyed $1.4 billion River Bend
investment. GSU has filed a motion for rehearing asking the Third
District Court to modify its order so as to permit the PUCT to take
additional evidence on remand. The PUCT and other parties have also
moved for rehearing on various grounds. The Third District Court has
not yet ruled on any of these motions.
As of December 31, 1993, the River Bend plant costs disallowed
for retail ratemaking purposes in Texas, and the River Bend plant
costs held in abeyance and the related cost deferrals totaled (net of
taxes) approximately $14 million, $300 million (both net of
depreciation), and $171 million, respectively. Allowed Deferrals were
approximately $95 million, net of taxes and amortization, as of
December 31, 1993. GSU estimates it has collected approximately $139
million of revenues as of December 31, 1993, as a result of the
originally ordered rate treatment of these deferred costs. However,
if the PUCT adopts the most recent decision in the El Paso Case, the
possible refunds approximate $28 million as a result of the inclusion
of deferred carrying costs in rate base for the period July 1988
through December 1990. However, if the PUCT reverses its decision to
reduce GSU's deferred costs by $1.50 for each $1.00 of revenue
collected under the interim rate increases authorized in 1987 and
1988, the potential refund of amounts described above could be reduced
by an amount ranging from $7 million to $19 million.
No assurance can be given as to the timing or outcome of the
remands or appeals described above. Pending further developments in
these cases, GSU has made no write-offs for the River Bend related
costs. Management believes, based on advice from Clark, Thomas &
Winters, a Professional Corporation, legal counsel of record in the
Rate Appeal, that it is reasonably possible that the case will be
remanded to the PUCT, and the PUCT will be allowed to rule on the
prudence of the abeyed River Bend plant costs. Rate caps imposed by
the PUCT's regulatory approval of the Merger could result in GSU being
unable to use the full amount of a favorable decision to immediately
increase rates; however, a favorable decision could permit some
increases and/or limit or prevent decreases during the period the rate
caps are in effect. At this time, management and legal counsel are
unable to predict the amount, if any, of the abeyed and previously
disallowed River Bend plant costs that ultimately may be disallowed by
the PUCT. A net of tax write-off as of December 31, 1993, of up to
$314 million could be required based on the PUCT's ultimate ruling.
In prior proceedings, the PUCT has held that the original cost
of nuclear power plants will be included in rates to the extent those
costs were prudently incurred. Based upon the PUCT's prior decisions,
management believes that its River Bend construction costs were
prudently incurred and that it is reasonably possible that it will
recover in rate base, or otherwise through means such as a deregulated
asset plan, all or substantially all of the abeyed River Bend plant
costs. However, management also recognizes that it is reasonably
possible that not all of the abeyed River Bend plant costs may
ultimately be recovered.
As part of its direct case in the Separate Rate Case, GSU filed a
cost reconciliation study prepared by Sandlin Associates, management
consultants with expertise in the cost analysis of nuclear power
plants, which supports the reasonableness of the River Bend costs held
in abeyance by the PUCT. This reconciliation study determined that
approximately 82% of the River Bend cost increase above the amount
included by the PUCT in rate base was a result of changes in federal
nuclear safety requirements and provided other support for the
remainder of the abeyed amounts.
There have been four other rate proceedings in Texas involving
nuclear power plants. Investment in the plants ultimately disallowed
ranged from 0% to 15%. Each case was unique, and the disallowances in
each were made on a case-by-case basis for different reasons. Appeals
of most, if not all, of these PUCT decisions are currently pending.
The following factors support management's position that a loss
contingency requiring accrual has not occurred, and its belief that
all, or substantially all, of the abeyed plant costs will ultimately
be recovered:
1. The $1.4 billion of abeyed River Bend plant costs have never
been ruled imprudent and disallowed by the PUCT.
2. Sandlin Associates' analysis which supports the prudence of
substantially all of the abeyed construction costs.
3. Historical inclusion by the PUCT of prudent construction costs
in rate base.
4. The analysis of GSU's internal legal staff, which has
considerable experience in Texas rate case litigation.
Additionally, management believes, based on advice from Clark,
Thomas & Winters, a Professional Corporation, legal counsel of record
in the Rate Appeal, that it is probable that the deferred costs will
be allowed. However, assuming the August 1992 court of appeals'
opinion in the El Paso Case is upheld and applied to GSU and the
deferred River Bend costs currently held in abeyance are not allowed
to be recovered in rates as allowable costs, a net-of-tax write-off of
up to $171 million could be required. In addition, future revenues
based upon the deferred costs previously allowed in rate base could
also be lost and no assurance can be given as to whether or not
refunds (up to $28 million as of December 31, 1993) of revenue
received based upon such deferred costs previously recorded will be
required.
See Note 12 of GSU's Notes to Financial Statements, "Entergy
Corporation-GSU Merger," for the accounting treatment of preacquistion
contingencies, including a River Bend write-down.
Texas Jurisdiction - Fuel Reconciliation. In January 1992, GSU
applied with the PUCT for a new fixed fuel factor and requested a
final reconciliation of fuel and purchased power costs incurred
between December 1, 1986 and September 30, 1991. GSU proposed to
recover net underrecoveries and interest (including underrecoveries
related to NISCO, discussed below) over a twelve month period. In
April 1993, the presiding PUCT ALJ issued a report which concluded
that GSU incurred approximately $117 million of nonreimbursable fuel
costs on a company-wide basis (approximately $50 million on a Texas
retail jurisdictional basis) during the reconciliation period.
Included in the nonreimbursable fuel costs were payments above
GSU's avoided cost rate for power purchased from NISCO. The PUCT
ordered in 1986 that the purchased power costs from NISCO in excess of
GSU's avoided costs be disallowed. The PUCT disallowance resulted in
approximately $12 million to $15 million of unrecovered purchased
power costs on an annual basis, which GSU continued to expense as the
costs were incurred. In April 1991, the Texas Supreme Court, in the
appeal of such order, ordered the PUCT to allow GSU to recover
purchased power payments in excess of its avoided cost in future
proceedings, if GSU established to the PUCT's satisfaction that the
payments were reasonable and necessary expenses.
In June 1993, the PUCT, in the fuel reconciliation case,
concluded that the purchased power payments made to NISCO in excess of
GSU's avoided cost were not reasonably incurred. As a result of the
order, GSU recorded additional fuel expenses (including interest) of
$2.8 million for non-NISCO related items. The PUCT's order resulted
in no additional expenses related to the NISCO issue, or for
overcollections related to the fixed fuel factor, as those charges
were expensed by GSU as they were incurred. The PUCT concluded that
GSU had over-collected its fuel costs in Texas and ordered GSU to
refund approximately $33.8 million to its Texas retail customers,
including approximately $7.5 million of interest. The PUCT reduced
GSU's fixed fuel factor in Texas from about 2.1 cents per KWH to
approximately 1.84 cents per KWH. GSU had requested a new fixed fuel
factor of about 2.02 cents per KWH. Based on current sales forecasts,
adoption of the PUCT's recommended fixed fuel factor would reduce
GSU's revenues by approximately $34 million annually. In October
1993, GSU appealed the PUCT's order to the Travis County District
Court. No assurance can be given as to the timing or outcome of the
appeal.
Texas - Cities Rate Settlement. In June 1993, thirteen cities
within GSU's Texas service area instituted an investigation to
determine whether GSU's current rates were justified. In October
1993, the general counsel of the PUCT instituted an inquiry into the
reasonableness of GSU's rates. In November 1993, a settlement
agreement was filed with the PUCT which provides for an initial
reduction in annual retail base revenues in Texas of approximately
$22.5 million effective for electric usage on or after November 1,
1993, and a second reduction of $20 million to be effective September
1994. Further, the settlement provided for GSU to reduce rates with a
$20 million one-time bill credit in December 1993, and to refund
approximately $3 million to Texas retail customers on bills rendered
in December 1993. The cities rate inquiries had been settled earlier
on the same terms.
In November 1993, in association with the settlement of the above-
described rate inquiries, GSU entered into a settlement covering
issues related to a March 1991 non-unanimous settlement in another
proceeding. Under this settlement, a $30 million rate increase
approved by the PUCT in March 1991, became final and the PUCT's
treatment of GSU's federal tax expense was settled, eliminating the
possibility of refunds associated with amounts collected resulting
from the disputed tax calculation.
In December 1993, a large industrial customer of GSU announced
its intention to oppose the settlement of the PUCT rate inquiry. The
customer's opposition does not affect the cities' rate settlement.
The customer's opposition requires the PUCT to conduct a hearing
concerning GSU's rates charged in areas outside the corporate limits
of the cities in its Texas service territory to determine whether the
settlement's rates are just and reasonable. A hearing has been set
for July 8, 1994. GSU believes that the PUCT will ultimately approve
the settlement, but no assurance can be provided in this regard.
Louisiana Jurisdiction - River Bend. Previous rate orders of the
LPSC have been appealed, and pending resolution of various appellate
proceedings, GSU has made no write-off for the disallowance of $30.6
million of deferred revenue requirement that GSU recorded for the
period December 16, 1987 through February 18, 1988.
In January 1992, the LPSC ordered a deregulated asset plan for
$1.4 billion of River Bend plant costs not allowed in rates. The plan
allows GSU to sell the generation from the approximately 22% of River
Bend to Louisiana customers at 4.6 cents per KWH, or off-system at
higher prices. Incremental revenues from off-system sales above 4.6
cents per KWH will be shared 60% by shareholders and 40% by ratepayers
(see GSU's "Management's Financial Discussion and Analysis,"
incorporated herein by reference, for the effects of the plan on GSU's
1993 results of operations).
LPSC - Return on Equity Review. In the June 1993 open session, a
preliminary report was made comparing the authorized and actual earned
rates of return for electric and gas utilities subject to the LPSC's
jurisdiction. The preliminary report indicated that several electric
utilities, including GSU, may be over-earning based on current
estimated costs of equity. The LPSC requested those utilities to file
responses indicating whether they agreed with the preliminary report,
and to provide their reasons if they did not agree. GSU provided the
LPSC with information that GSU believes supports the current rate
level. The LPSC decided at its September 7, 1993 open session to
defer review of GSU's base rates until the first earnings analysis
after the Merger, scheduled for mid-1994.
LPSC Fuel Cost Review. In November 1993, the LPSC ordered a
review of GSU's fuel costs. The LPSC stated that fuel costs for the
period October 1988 through September 1991 would be reviewed based on
the number of outages at River Bend and the findings in the June 1993
PUCT fuel reconciliation case. Hearings are scheduled to begin in
March 1994.
Least Cost Planning. Currently, the PUCT does not have least
cost planning rules in place, and GSU has not filed a Least Cost Plan
with the PUCT. However, the PUCT staff has begun a rulemaking process
for such rules, and GSU is actively participating in this process.
GSU has not yet filed a Least Cost Plan with the LPSC.
Fuel Recovery. In January 1993, the PUCT adopted a new rule for
setting a fixed fuel factor that is intended to recover projected
allowable fuel and purchased power costs not covered by base rates.
To the extent actual costs vary from the fixed factor, the PUCT may
require refunds of overcharges or permit recovery of undercharges.
Under the new rule, fuel factors are to be revised every six months,
and GSU is on a schedule providing for revision each March and
September. The PUCT is required to act within 60 or 90 days,
depending on whether or not a hearing is required, and refunds and
surcharges will be required based upon a materiality threshold of 4%
of Texas retail fuel revenues. Fuel charges will also be subject to
reconciliation proceedings every three years, at which time additional
adjustments may be required (see "Texas Jurisdiction - Fuel
Reconciliation," above). All of GSU's rate schedules in Louisiana
include a fuel adjustment clause to recover the cost of fuel and
purchased power energy costs. The fuel adjustment reflects the
delivered cost of fuel for the second preceding month.
LP&L
LPSC Jurisdiction. In a series of LPSC orders, court decisions,
and agreements from late 1985 to mid-1988, LP&L was granted rate
relief with respect to costs associated with Waterford 3 and LP&L's
share of capacity and energy from Grand Gulf l, subject to certain
terms and conditions. With respect to Waterford 3, LP&L was granted
an increase aggregating $170.9 million over the period 1985-1988, and
LP&L agreed to permanently absorb, and not recover from retail
ratepayers, $284 million of its investment in the unit and to defer
$266 million of its costs related to the years 1985-1988 to be
recovered over approximately 8.6 years beginning in April 1988. As of
December 31, 1993, LP&L's unrecovered deferral balance was $82.5
million. With respect to Grand Gulf l, LP&L agreed to absorb, and not
recover from retail ratepayers, 18% of its 14% share (approximately
2.52%) of the costs of Grand Gulf l capacity and energy. LP&L is
allowed to recover, through the fuel adjustment clause, 4.6 cents per
KWH (currently 2.55 cents per KWH through May 1994) for the energy
related to the permanently absorbed percentage, with LP&L's
permanently absorbed retained percentage to be available for sale to
non-affiliated parties, subject to LPSC approval. (See Note 2 of
LP&L's Notes to Financial Statements, "Rate and Regulatory Matters -
Waterford 3 and Grand Gulf 1," incorporated herein by reference, for
further information on LP&L's Grand Gulf 1 and Waterford 3-related
rates.)
In a subsequent rate proceeding, on March 1, l989, the LPSC
issued an order providing that, in effect, LP&L was entitled to an
approximately $45.9 million annual retail rate increase, but that, in
lieu of a rate increase, LP&L would be permitted to retain $188.6
million of the proceeds of a 1988 settlement of litigation with a gas
supplier, and to amortize such proceeds into revenues over a period of
approximately 5.3 years. The amortization of the proceeds will expire
in mid-1994 and this source of revenue will no longer be available to
LP&L. LP&L believes that the amortization has resulted in
approximately the same amount of additional net income as an annual
rate increase of $45.9 million would have provided over the same
period. In connection with this order, LP&L agreed to a five-year
base rate freeze scheduled to expire in March 1994 at then current
levels subject to certain conditions. (See Note 2 of LP&L's Notes to
Financial Statements, "Rate and Regulatory Matters - March 1989
Order," incorporated herein by reference, for further information on
the terms of this order.)
By letter dated July 27, 1993, the LPSC requested LP&L to explain
its "relatively high cost of debt" compared to other electric
utilities subject to LPSC jurisdiction. LP&L responded to the request
on August 11, 1993. On August 14, 1993, the LPSC's consultants
acknowledged LP&L's rationale for its cost of debt and suggested that
certain aspects of LP&L's cost of debt could be taken up in rate
proceedings after the expiration of LP&L's rate freeze. On October 7,
1993, the LPSC approved a schedule to conduct a review of LP&L's rates
and rate structure upon the expiration of the rate freeze in
March 1994.
Council Jurisdiction. Under the Algiers rate settlement entered
into with the Council in l989, LP&L was granted rate relief with
respect to its Grand Gulf l and Waterford 3-related costs, subject to
certain terms and conditions. LP&L was granted an annual rate
increase of $9.5 million that was phased-in over the two-year period
beginning in July 1989, and was permitted to retain $4.2 million (the
Council's jurisdictional portion) of the proceeds of litigation with a
gas supplier and to amortize such proceeds plus interest into revenues
over the same two-year period. LP&L agreed to absorb and not recover
from Algiers retail ratepayers $17 million of fixed costs associated
with Grand Gulf l and Waterford 3 incurred prior to the date of the
settlement, $5.9 million of its investment in Waterford 3, and 18% of
the Algiers portion of LP&L's Grand Gulf l-related costs incurred
after the settlement. However, LP&L is allowed to recover 4.6 cents
per KWH or the avoided cost, whichever is higher, for the energy
related to the permanently absorbed percentage through the fuel
adjustment clause, with the permanently absorbed percentage to be
available for sale to non-affiliated parties, subject to the Council's
right of first refusal. LP&L also agreed to a rate freeze for Algiers
customers until July 6, l994, except in the case of catastrophic
events, changes in federal tax laws, or changes in LP&L's Grand Gulf l
costs resulting from FERC proceedings.
Least Cost Planning. On December l, l992, and July 1, l993, LP&L
filed with the LPSC and the Council the Least Cost Plan described
under "Business of Entergy - Competition - Least Cost Planning,"
above. LP&L also requested authorization to recover development and
implementation costs and costs and incentives related to the DSM
aspects of the plan. Discovery in the LPSC review of LP&L's Least
Cost Plan filing is continuing, and the current procedural schedule
(which maybe extended) contemplates that, after hearings and
briefings, a report of the LPSC special counsel will be issued on June
14, 1994. The LPSC could render a decision on the basis of this
report. On January 19, 1994, LP&L filed a motion with the LPSC to
dismiss or withdraw without prejudice the CCLM and to proceed with a
pilot CCLM at shareholder expense. The LPSC granted LP&L's motion on
February 2, 1994, subject to LP&L, among other things, keeping the
LPSC timely informed as to LP&L's CCLM activities. (See "NOPSI -
Least Cost Planning," below, for further information on LP&L's and
NOPSI's proceedings pending before the Council.)
Fuel Adjustment Clause. LP&L's rate schedules include a fuel
adjustment clause to reflect the delivered cost of fuel in the second
preceding month and purchased power energy costs. The fuel adjustment
also reflects a surcharge for deferred fuel expense arising from the
monthly reconciliation of actual fuel cost incurred with fuel cost
revenues billed to customers. LP&L defers on its books fuel costs that
will be reflected in customer billings in the future under the fuel
adjustment clause.
MP&L
Rate Freeze. In a stipulation entered into by MP&L in connection
with the settlement of various issues related to the Merger, MP&L
agreed that (1) for a period of five years beginning on November 9,
1993, retail base rates under the FRP (see "Incentive Rate Plan,"
below) would not be increased above the level of rates in effect on
November 1, 1993, and (2) MP&L would not request any general retail
rate increase that would increase retail rates above the level of
MP&L's rates in effect as of November l, 1993, and that would become
effective in such five-year period except, among other things, for
increases associated with the Least Cost Plan (discussed below),
recovery of deferred Grand Gulf 1-related costs, recovery under the
fuel adjustment clause, adjustments for certain taxes, and force
majeure (defined to include, among other things, war, natural
catastrophes, and high inflation).
Recovery of Grand Gulf 1 Costs. The MPSC's Final Order on
Rehearing, issued in 1985, affirmed by the United States Supreme Court
in 1988, and subsequently revised in 1988, granted MP&L an annual base
rate increase of approximately $326.5 million in connection with its
allocated share of Grand Gulf 1 costs. The Final Order on Rehearing
also provided for the deferral of a portion of such costs that were
incurred each year through 1992, and recovery of these deferrals over
a period of six years ending in 1998. As of December 31, 1993, the
uncollected balance of MP&L's deferred costs was approximately $601.4
million. MP&L is permitted to recover the carrying charges on all
deferred amounts on a current basis.
Incentive Rate Plan. In July 1993, the MPSC ordered MP&L to file
a formulary incentive rate plan designed to allow for periodic small
adjustments in rates based upon a comparison of earned to benchmark
returns and upon performance factors incorporated in the plan.
Pursuant to this order, on November 1, 1993, MP&L filed a proposed
formula rate plan. MPSC was also expected to conduct a general review
of MP&L's current rates in the course of approving an incentive rate
plan.
On January 28, 1994, MP&L and the Mississippi Public Utilities
Staff (MPUS) entered into a Joint Stipulation in this proceeding.
Under the Joint Stipulation, MP&L and the MPUS agreed on a number of
accounting adjustments for the test year ending June 30, 1993, (June
30 Test Year) that resulted in a reduction to MP&L's base rate
revenues in the June 30 Test Year of approximately 4.3%, or $28.1
million. This translates into approximately a 3.7% decrease in
overall revenues from sales to retail customers, which include
revenues related to fuel, taxes, and Grand Gulf. MP&L and the MPUS
agreed on a required return on equity of 11% for the June 30 Test
Year.
MP&L and the MPUS also stipulated to a revised Formula Rate Plan
(FRP). The stipulated FRP is essentially the same as the proposed
plan filed by MP&L on November 1, 1993. Certain of the accounting
changes agreed to by the MPUS and MP&L for the June 30 Test Year are
incorporated into the stipulated FRP. Also, the formula in the
stipulated FRP for determining required return on equity would have
produced a required return on equity for MP&L of 11.07% for the June
30 Test Year. The stipulated return on equity formula will be applied
for the first time in the first Evaluation Report under the stipulated
FRP. The first Evaluation Report will be filed in March 1995 for the
Evaluation Period ending December 31, 1994.
On February 10, 1994, MP&L, the Mississippi Industrial Energy
Group (MIEG), and the MPUS entered into and filed with the MPUS, a
Joint Stipulation (MIEG Joint Stipulation) resolving the issues raised
by the MIEG in the docket. On February 16, 1994, MP&L and the
Mississippi Attorney General entered into a Joint Stipulation that
resolved the issues raised by the Mississippi Attorney General in the
docket. Other parties in the case, including two gas utility
intervenors, were not parties to the Joint Stipulations.
In late February 1994, the MPSC conducted a general review of
MP&L's current rates and on March 1, 1994, issued a final order in
which the MPSC approved each of the Joint Stipulations. The MPSC
ordered MP&L to file rates designed to provide a reduction of $28.1
million in operating revenues for the June 30 Test Year on or before
March 18, 1994, to become effective for service rendered on and after
March 25, 1994. The FRP also was approved and will be effective on
March 25, 1994, with any initial adjustment to base rates, if any, in
May 1995. Under the FRP, a formula will be established under which
MP&L's earned rate of return will be calculated automatically every 12
months and compared to a benchmark rate of return calculated under a
separate formula within the FRP. If MP&L's earned rate of return
falls within a bandwidth around the benchmark rate of return, there
will be no adjustment in rates. If MP&L's earnings are above the
bandwidth, the FRP will automatically reduce MP&L's base rates.
Alternatively, if MP&L's earnings are below the bandwidth, the FRP
will automatically increase MP&L's base rates (see "Rate Freeze" above
for information on a cap on base rates at November 1993 levels for a
period of five years). The reduction or increase in base rates will
be an amount representing 50% of the difference between the earned
rate of return and the nearest limit of the bandwidth. In no event
will the annual adjustment in rates exceed the lesser of 2% of MP&L's
aggregate annual retail revenues, or $14.5 million. Under the FRP the
benchmark rate of return, and consequently the bandwidth, will be
adjusted slightly upward or downward based upon MP&L's performance on
three performance factors: customer reliability, customer
satisfaction, and customer price.
In its Final Order, the MPSC also recognized that on February 9
and 10, 1994, a severe ice storm struck northern Mississippi causing
extensive and widespread damage to MP&L's transmission and
distribution facilities in approximately 15 counties. Although the
MPSC made no findings in the final order as to MP&L's costs associated
with the ice storm and restoration of service, the MPSC acknowledged
that there is precedent in Mississippi for recovery of certain costs
associated with storms and natural disasters and restoration of
service. The MPSC stated the recovery of MP&L's ice storm costs
should be addressed in a separate docket. MP&L plans to immediately
file for rate recovery of the costs related to the ice storm.
Least Cost Planning. On December 1, 1992 and July 1, 1993, MP&L
filed with the MPSC the Least Cost Plan described in "Business of
Entergy - Competition - Least Cost Planning," above. MP&L also
requested a finding by the MPSC that the plan's cost recovery
methodology is reasonable and appropriate. MP&L will request approval
of cost recovery mechanisms after the plan has been approved by the
MPSC. On October 6, 1993, the MPSC, on its own motion, stayed all
proceedings in this docket. The MPSC stay order regarding MP&L's
Least Cost Plan filing remains in effect even though MP&L and the MPUS
have stipulated to an FRP (see "Incentive Rate Plan," above). Because
the stay order remains in effect, MP&L has not yet filed a request
that the CCLM portion of the filing be withdrawn and that a pilot CCLM
program be implemented.
Fuel Adjustment Clause. MP&L's rate schedules include a fuel
adjustment clause that permits recovery from customers of changes in
the cost of fuel and purchased power. The monthly fuel adjustment
rate is based on projected sales and costs for the month, adjusted for
differences between actual and estimated costs for the second prior
month.
NOPSI
Electric Retail Rate Reduction. On November 18, 1993, in
connection with the settlement of various issues related to the
Merger, the Council adopted a resolution requiring NOPSI to reduce its
annual electric base rates by $4.8 million on bills rendered on or
after November 1, 1993.
Recovery of Grand Gulf 1 Costs. Under NOPSI's various Rate
Settlements with the Council (which include the 1986 NOPSI Settlement,
the February 4 Resolution relating to prudence issues, and the 1991
NOPSI Settlement of the issues raised in the February 4 Resolution),
NOPSI agreed to absorb and not recover from ratepayers a total of
$186.2 million of its Grand Gulf 1 costs. NOPSI was permitted to
implement annual rate increases in decreasing amounts each year
through 1995, and to defer certain costs, and related carrying
charges, for recovery on a schedule extending from 1991 through 2001.
As of December 31, 1993, the uncollected balance of NOPSI's deferred
costs was $228.8 million. NOPSI also agreed to a base rate freeze
through October 31, 1996, excluding the scheduled increases, certain
changes in tax rates, and increases related to catastrophic events.
(See Note 2 of NOPSI's Notes to Financial Statements, "Rate and
Regulatory Matters - Prudence Settlement and Finalized Phase-In Plan,"
incorporated herein by reference, for further information.)
Gas Rates. In May 1992, NOPSI and the Council settled a pending
application for gas rate increases. The settlement provided for
annual rate increases of approximately $3.8 million in May 1992 and
1993, and the deferral of an additional $3 million for recovery in the
years beginning in May 1993 through May 1996. NOPSI also agreed to a
base rate freeze, except for the scheduled increases and certain other
exceptions, through October 31, 1996.
Least Cost Planning. On December 1, 1992, and July 1, 1993,
NOPSI filed with the Council the Least Cost Plan described under
"Business of Entergy - Competition - Least Cost Planning," above.
NOPSI also requested authorization to recover development and
implementation costs and costs and incentives related to DSM aspects
of the plan. After hearings and briefings, the Council issued, on
November 22, 1993, a resolution that requires NOPSI and LP&L to
provide, within certain time frames, additional information, among
other things, on how the seven full scale DSM programs approved by the
Council in the resolution will be implemented. Such programs are
estimated to cost approximately $13 million over the next three years.
The Council provided in the resolution certain assurances regarding
recovery of costs associated with these programs. Discovery is
proceeding and testimony is being filed, with the second round of
hearings to begin in February 1994. After the hearings are concluded
and briefs have been filed, the Council will address the second round
issues in early April 1994. On February 3, 1994, the Council issued a
resolution and order granting the motions of NOPSI and LP&L to dismiss
without prejudice the CCLM portion of the filing, authorizing NOPSI
and LP&L to proceed with a pilot CCLM (other than the construction of
a fiber optics/coaxial cable network) in New Orleans at shareholder
expense (subject to certain conditions). The Council also opened a new
docket to expeditiously address issues related to the CCLM pilot, and
directing NOPSI and LP&L to obtain Council authorization in the new
docket before constructing such a fiber optics/coaxial cable network.
In connection with the settlement of various issues related to
the Merger, the Council adopted a resolution on November 18, 1993,
that provides that the Council will not disallow the first
$3.5 million of costs incurred by NOPSI through October 31, 1993, in
connection with the Least Cost Plan.
Fuel Adjustment Clause. NOPSI's electric rate schedules include
a fuel adjustment clause to reflect the delivered cost of fuel in the
second preceding month, adjusted by a surcharge for deferred fuel
expense arising from the monthly reconciliation of actual fuel cost
incurred with fuel cost revenues billed to customers. The adjustment
clause, on a monthly basis, also reflects the difference between
nonfuel Grand Gulf 1 costs paid by NOPSI and the estimate of such
costs provided in NOPSI's Grand Gulf 1 Rate Settlements. NOPSI's gas
rate schedules include a gas cost adjustment to reflect gas costs in
excess of those collected in rates, adjusted by a surcharge similar to
that included in the electric adjustment clause. NOPSI defers on its
books fuel and purchased gas costs to be reflected in billings to
customers in the future under the fuel adjustment clause.
REGULATION
Federal Regulation
Holding Company Act. Entergy Corporation is a registered public
utility holding company under the Holding Company Act. As such,
Entergy Corporation and its various direct and indirect subsidiaries
(with the exception of its independent power/EWG subsidiaries) are
subject to the broad regulatory provisions of that Act. Except with
respect to investments in certain EWG projects and foreign utility
company projects (see "Business of Entergy - Competition - General,"
above for a discussion of the Energy Act), Section 11(b)(1) of the
Holding Company Act limits the operations of a registered holding
company system to a single, integrated public utility system, plus
additional systems and businesses as provided by that section.
Federal Power Act. The System operating companies, System
Energy, and Entergy Power are subject to the Federal Power Act as
administered by FERC and the DOE. The Federal Power Act provides for
regulatory jurisdiction over the licensing of certain hydroelectric
projects, the business of, and facilities for, the transmission and
sale at wholesale of electric energy in interstate commerce and
certain other activities of the System operating companies, System
Energy, and Entergy Power as interstate electric utilities, including
accounting policies and practices. Such regulation includes
jurisdiction over the rates charged by System Energy for capacity and
energy provided to AP&L, LP&L, MP&L, and NOPSI, or others, from Grand
Gulf 1.
AP&L holds a license for two hydroelectric projects (70 MW) that
was renewed on July 2, 1980. This license, granted by FERC, will
expire in February 2003.
Regulation of the Nuclear Power Industry
General. Under the Atomic Energy Act of 1954 and Energy
Reorganization Act of 1974, operation of nuclear plants is intensively
regulated by the NRC, which has broad power to impose licensing and
safety-related requirements. In the event of non-compliance, the NRC
has the authority to impose fines or shut down a unit, or both,
depending upon its assessment of the severity of the situation, until
compliance is achieved. AP&L, GSU, LP&L, and System Energy, as owners
of all or a portion of ANO, River Bend, Waterford 3, and Grand Gulf 1,
respectively, and Entergy Operations, as the operator of these units,
are subject to the jurisdiction of the NRC. Revised safety
requirements promulgated by the NRC have, in the past, necessitated
substantial capital expenditures at System nuclear plants and
additional such expenditures could be required in the future.
The nuclear power industry faces uncertainties with respect to
the cost and availability of long-term arrangements for disposal of
spent nuclear fuel and other radioactive waste, nuclear plant
operational issues, the technological and financial aspects of
decommissioning plants at the end of their licensed lives, and the
effect of certain requirements relating to nuclear insurance. These
matters are briefly discussed below.
Spent Fuel and Other High-Level Radioactive Waste. Under the
Nuclear Waste Policy Act of 1982, the DOE is required, for a specified
fee, to construct storage facilities for, and to dispose of, all spent
nuclear fuel and other high-level radioactive waste generated by
domestic nuclear power reactors. The NRC, pursuant to this Act, also
requires operators of nuclear power reactors to enter into spent fuel
disposal contracts with the DOE, and the affected System companies
have entered into such disposal contracts. However, the DOE has not
yet identified a permanent storage repository and, as a result, future
expenditures may be required to increase spent fuel storage capacity
at the plant sites. (For further information concerning spent fuel
disposal contracts with the DOE, schedules for initial shipments of
spent nuclear fuel, current on-site storage capacity, and costs of
providing additional on-site storage capacity, with respect to AP&L,
GSU, LP&L, and System Energy, respectively, see Note 8 of AP&L's,
GSU's, and LP&L's, and Note 7 of System Energy's, Notes to Financial
Statements, "Commitments and Contingencies - Spent Nuclear Fuel and
Decommissioning Costs," incorporated herein by reference.)
Low-Level Radioactive Waste. The availability and cost of
disposal facilities for low-level radioactive waste resulting from
normal operation of nuclear units are subject to a number of
uncertainties. Under the Low-Level Radioactive Waste Policy Act of
1980, as amended, each state is responsible for disposal of its own
waste, and states may join in regional compacts to jointly fulfill
their responsibilities. The States of Arkansas and Louisiana
participate in the Central States Compact, and the State of
Mississippi participates in the Southeast Compact. Two disposal sites
are currently operating in the United States, and one of them, which
is located in Washington, is closed to out-of-region generators. The
second site, the Barnwell Disposal Facility (Barnwell) located in
South Carolina, is operated by the Southeast Compact and the State of
Mississippi is expected to have access to this site through December
1995. Barnwell had been open to out-of-region generators (including
generators in Arkansas and Louisiana) in the past; however, on April
14, 1993, the Southeast Compact voted to deny access to Barnwell to
members of the Central States Compact. Such access was reinstated for
the period from October 1993 through June 1994, at which time
legislative action by the State of South Carolina would be required to
permit further access to out-of-region generators. Beginning in
July 1994, low-level radioactive waste generators in the Central
States Compact, including AP&L, GSU, and LP&L, will be required to
store such waste on-site until a Central States Compact facility
becomes operational or another site becomes accessible.
Both the Central States Compact and the Southeast Compact are
working to establish additional disposal sites. The System, along
with other waste generators, funds the development costs for new
disposal facilities. The System's expenditures to date are
approximately $30 million; and future levels of expenditures cannot be
predicted. Until such facilities are established, the System will
continue to seek access to existing facilities, which may be available
at costs that are higher than those incurred in the past, or which may
be unavailable. If such access is unavailable, the System will store
low-level waste on-site at the affected units. ANO has on-site
storage that is estimated to be sufficient until 1999. Construction
of on-site storage at the other nuclear units is being considered,
along with other alternatives. A coordinated design concept that can
be utilized at both Waterford 3 and River Bend is being evaluated.
Grand Gulf 1 will have continued disposal access through December
1995; therefore, no immediate plans for on-site storage are needed for
Grand Gulf 1. The estimated construction costs for storage sufficient
for approximately five years at Grand Gulf 1, Waterford 3, and River
Bend are in the range of $2.0 million to $5.0 million for each site.
As an alternative to on-site storage, Entergy is working with other
industry groups to influence the continued operation of the Barnwell
disposal facility for out-of-region generators.
Decommissioning. AP&L, GSU, LP&L, and System Energy are
recovering portions of their estimated decommissioning costs for ANO,
River Bend, Waterford 3, and Grand Gulf 1, respectively. These amounts
are being deposited in external trust funds that, together with the
earnings thereon, can only be used for future decommissioning costs.
Estimated decommissioning costs are regularly reviewed and updated to
reflect inflation and changes in regulatory requirements and
technology, and applications will be made to appropriate regulatory
authorities to recover in rates any projected increase in
decommissioning costs above that currently being recovered. (For
additional information with respect to decommissioning costs for ANO,
River Bend, Waterford 3, and Grand Gulf 1, respectively, see Note 8 of
AP&L's, GSU's, and LP&L's and Note 7 of System Energy's Notes to
Financial Statements, "Commitments and Contingencies - Spent Nuclear
Fuel and Decommissioning Costs," incorporated herein by reference.)
Uranium Enrichment Decontamination and Decommissioning Fees. The
Energy Act requires all electric utilities (including AP&L, GSU, LP&L,
and System Energy) that have purchased uranium enrichment services
from the DOE to contribute up to a total of $150 million annually,
adjusted for inflation, up to a total of $2.25 billion over
approximately 15 years, for decommissioning and decontamination of
enrichment facilities. AP&L's, GSU's, LP&L's, and System Energy's
estimated annual contributions to this fund are $3.3 million, $0.6
million, $1.2 million, and $1.3 million, respectively, in 1993 dollars
over approximately 15 years. Contributions to this fund are to be
recovered through rates in the same manner as other fuel costs.
Nuclear Insurance. The Price-Anderson Act provides for a limit
of public liability for a single nuclear incident. As of December 31,
1993, the limit of public liability for such type of incident was
approximately $9.4 billion. AP&L, GSU, LP&L, and System Energy have
protection with respect to this liability through a combination of
private insurance and an industry assessment program, and also have
insurance for property damage, costs of replacement power, and other
risks relating to nuclear generating units. (For a discussion of
insurance applicable to nuclear programs of AP&L, GSU, LP&L, and
System Energy, see Note 7 of System Energy's and Note 8 of AP&L's,
GSU's, and LP&L's Notes to Financial Statements, and Note 8 of Entergy
Corporation and Subsidiaries, Notes to Consolidated Financial
Statements, "Commitments and Contingencies - Nuclear Insurance,"
incorporated herein by reference.)
Nuclear Operations
General. Entergy Operations operates ANO, River Bend, Waterford
3, and Grand Gulf 1, subject to the owner oversight of AP&L, GSU,
LP&L, and System Energy, respectively. AP&L, GSU, LP&L, and System
Energy, and the other Grand Gulf 1, Waterford 3, and River Bend co-
owners, have retained their ownership interests in their respective
nuclear generating units. AP&L, GSU, LP&L, and System Energy have
also retained their associated capacity and energy entitlements, and
pay directly or reimburse Entergy Operations at cost for its operation
of the units.
On June 24, 1992, the NRC issued a bulletin requiring all
utilities using a certain fire barrier material in a nuclear power
plant to take certain actions related to the material. This material
may have been used in as many as 87 nuclear plants in the United
States, including ANO, River Bend, Waterford 3, and Grand Gulf 1 (see
"River Bend," below for additional information).
ANO. In 1990, in response to a special diagnostic evaluation
report by the NRC, AP&L implemented a comprehensive action plan for
ANO designed to correct certain management, organizational, and
technical problems, and to improve the long-term operational
effectiveness and safety of the units. This action plan was largely
completed in 1993.
Leaks in certain steam generator tubes at ANO 2 were discovered
and repaired during an outage in March 1992; and during a refueling
outage in September 1992, a comprehensive inspection of all steam
generator tubing was conducted and necessary repairs were made.
During a mid-cycle outage in May 1993, a scheduled special inspection
of certain steam generator tubing was conducted by Entergy Operations
and additional repairs were made. Entergy Operations proposes to
operate ANO 2 with no further steam generator inspections until the
next refueling outage, which is scheduled for the spring of 1994, and
the NRC has concurred with this proposal. The operations and power
output of the unit have not been adversely affected to date by these
repairs.
River Bend. The Nuclear Information and Resource Service
petitioned the NRC to shut down the River Bend plant in July 1992
because of alleged defects in a fire barrier material. GSU has used
this material in its River Bend plant and is in compliance with the
requirements of the bulletin. On August 19, 1992, the NRC denied the
petitioner's request. In a December 1993 letter, the NRC requested
additional technical information on the use of the material in the
plant, and requested GSU's plans and schedules for resolving technical
issues associated with the use of the material in certain
configurations. GSU has provided the information requested in the NRC
letter.
On January 13, 1993, in connection with the Merger, GSU filed two
applications with the NRC to amend the River Bend operating license.
The applications sought the NRC's consent to the Merger and to a
change in the licensed operator of the facility from GSU to Entergy
Operations. On August 6, 1993, Cajun filed a petition to intervene
and request for a hearing in the proceedings. On January 27, 1994,
the presiding NRC Atomic Safety and Licensing Board (ASLB) issued an
order granting Cajun's petition to intervene and ordered a hearing on
one of Cajun's contentions. On February 15, 1994, GSU filed an appeal
of the ASLB Order with the NRC. On December 16, 1993, prior to this
ASLB ruling, the NRC Staff issued the two license amendments for River
Bend, making them effective immediately upon consummation of the
Merger. On February 16, 1994, Cajun filed with the D.C. Circuit
petitions for review of the two license amendments issued by the NRC.
These two amendments are in full force and effect, but are subject to
the outcome of the two proceedings. A hearing on the proceeding
before the ALSB is not expected to begin prior to the fall of 1994.
In February 1993, GSU and the other affected utilities were
served with a federal grand jury subpoena to produce documents and
other information relating to the fire barrier material used in the
plant. Nothing in the subpoena indicates that GSU or any employee is
a target of the grand jury investigation. GSU is cooperating fully
with the government in its investigation. The requested documentation
and other information were produced in March 1993, and no additional
requests have been received.
On October 25, 1993, the NRC staff began an operational safety
team inspection at River Bend that was concluded by mid-November 1993.
The NRC held the inspection to verify that the plant is being operated
safely and in conformance with regulatory requirements. The team's
findings were discussed at a public meeting in November 1993, and a
written inspection report was issued in January 1994. The inspection
team found apparent violations in two categories: (1) procedure
adequacy, and (2) concerns with the corrective action program. Due to
the nature of these apparent violations, an enforcement conference was
not warranted and no fine was proposed.
State Regulation
General. Each of the System operating companies is subject to
regulation by its respective state and/or local regulatory authorities
with jurisdiction over the service areas in which each company
operates. Such regulation includes authority to set rates for
electric and gas service provided at retail. (See "Rate Matters and
Regulation - Rate Matters - Retail Rate Matters," above)
AP&L is subject to regulation by the APSC and the Tennessee
Public Service Commission (TPSC). APSC regulation includes the
authority to set rates, determine reasonable and adequate service, fix
the value of property used and useful, require proper accounting,
control leasing, control the acquisition or sale of any public utility
plant or property constituting an operating unit or system, set rates
of depreciation, issue certificates of convenience and necessity and
certificates of environmental compatibility and public need, and
control the issuance and sale of securities. Regulation by the TPSC
includes the authority to set standards of service and rates for
service to customers in the state, require proper accounting, control
the issuance and sale of securities, and issue certificates of
convenience and necessity.
GSU is subject to the jurisdiction of the municipal authorities
of incorporated cities in Texas as to retail rates and services within
their boundaries, with appellate jurisdiction over such matters
residing in the PUCT. GSU is also subject to regulation by the PUCT
as to retail rates and services in rural areas, certification of new
generating plants, and extensions of service into new areas. GSU is
subject to regulation by the LPSC as to electric and gas service,
rates and charges, certification of generating facilities and power or
capacity purchase contracts, and other matters.
LP&L is subject to the jurisdiction of the LPSC as to rates and
charges, standards of service, depreciation, accounting, and other
matters, and is subject to the jurisdiction of the Council with
respect to such matters within Algiers.
MP&L is subject to regulation as to service, service areas,
facilities, and retail rates by the MPSC. MP&L is also subject to
regulation by the APSC as to the certificate of environmental
compatibility and public need for the Independence Station.
NOPSI is subject to regulation as to electric and gas service,
rates and charges, standards of service, depreciation, accounting,
issuance of certain securities, and other matters by the Council.
Franchises. AP&L holds franchises to provide electric service in
301 incorporated cities and towns in Arkansas, all of which are
unlimited in duration and terminable by either party.
GSU holds non-exclusive franchises, permits, or certificates of
convenience and necessity to provide electric and gas service in 55
incorporated villages, cities, and towns in Louisiana and 64
incorporated cities and towns in Texas. GSU ordinarily holds 50-year
franchises in Texas towns and 60-year franchises in Louisiana towns.
The present terms of GSU's electric franchises will expire in the
years 2007-2036 in Texas and in the years 2015-2046 in Louisiana. The
natural gas franchise in the City of Baton Rouge will expire in the
year 2015.
LP&L holds franchises to provide electric service in 116
incorporated villages, cities, and towns. Most of these franchises
have 25-year terms expiring during the period 1995-2015. However, six
of these municipalities have granted 60-year franchises, with the last
one expiring in the year 2040. Of these franchises, none has expired
to date, one is scheduled to expire as early as 1995, and 37 are
scheduled to expire by year-end 2000. LP&L also supplies electric
service in 353 unincorporated communities, all of which are located in
parishes (counties) from which LP&L holds franchises to serve the
areas in which the unincorporated communities are located.
MP&L has received from the MPSC certificates of public
convenience and necessity to provide electric service to the areas of
Mississippi that MP&L serves, which include a number of
municipalities. MP&L continues to serve in such municipalities upon
payment of a statutory franchise fee, regardless of whether an
original municipal franchise is still in existence.
NOPSI provides electric and gas service in the City of New
Orleans pursuant to city ordinances, which state, among other things,
that the City has a continuing option to purchase NOPSI's electric and
gas utility properties.
System Energy has no franchises from any municipality or state.
Its business is currently limited to wholesale sales of power.
Environmental Regulation
General. In the areas of air quality, water quality, control of
toxic substances and hazardous and solid wastes, and other
environmental matters, the System operating companies, System Energy,
Entergy Power, and Entergy Operations are subject to regulation by
various federal, state, and local authorities. Each of the Entergy
companies considers itself to be in substantial compliance with those
environmental regulations currently applicable to its business and
operations. Entergy has incurred increased costs of construction and
other increased costs in meeting environmental protection standards.
Because environmental regulations are continually changing, the
ultimate compliance costs to Entergy cannot be precisely estimated at
any one time. However, Entergy currently estimates that its potential
capital expenditures for environmental control purposes, including
those discussed in "Clean Air Legislation," below, will not be
material for the System as a whole.
Clean Air Legislation. The Clean Air Act Amendments of 1990 (the
Act) place limits on emissions of sulfur dioxide and nitrogen oxide
from fossil-fueled generating plants. Entergy has evaluated the Act
to determine the impact on the System's overall cost of emission
control and monitoring equipment. Based upon such evaluation in
connection with existing generating facilities, the System has
determined that no additional control equipment will be required to
control sulfur dioxide. In the area served by GSU, control equipment
will be required for nitrogen oxide reductions due to the ozone
nonattainment status of the Baton Rouge, Louisiana and Beaumont and
Houston, Texas air quality control regions no later than May 1995.
The cost of such control equipment is estimated at $16.0 million. The
remainder of the System may be required to install nitrogen oxide
emission controls on its coal units by the year 2000. The EPA is
currently drafting rules that will determine the levels of nitrogen
oxide emissions that will be allowed by affected units. Under the
latest EPA-proposed regulations on nitrogen oxide, Entergy would not
have to install additional controls. It is not possible to determine
at this time if the final regulations promulgated by EPA would require
the System's coal units to install nitrogen oxide emission controls.
Should additional controls be required, the overall cost would vary
depending on the eventual emission levels that are set.
In addition, the System will be required to install additional
continuous emission monitoring equipment at its coal units to comply
with final EPA regulations. It is estimated that the continuous
emission monitoring systems could cost as much as $1.0 million for all
of the coal units. Final EPA regulations established the acceptable
continuous monitoring methods, as well as alternative monitoring
methods, that make it possible to determine the compliance of the
units with respect to emission levels through fuel sampling and other
estimation methods. Capital expenditures of approximately $11.0
million are estimated for continuous emission monitoring systems at
the other fossil-fueled units.
The authority to impose permit fees has been delegated to the
states by EPA and, depending on the extent of the state program and
the fees imposed by each state regulatory authority, permit fees for
the System could range from $1.6 to $5.0 million annually.
There are several other areas, such as air toxins and visibility,
that will require regulatory study and rule promulgation to determine
whether pollution control equipment is necessary.
Regarding sulfur dioxide emissions, the Act provides "allowances"
to most Entergy units based upon past emission levels and operating
characteristics. Each unit of allowance is an entitlement to emit one
ton of sulfur dioxide per year. Under the Act, utilities will be
required to possess allowances for sulfur dioxide emissions from
affected units. Based on Entergy's past operating history, it is
considered a "clean" utility and as such will receive more allowances
than are currently necessary for normal operations. The System
believes that it will be able to operate its units efficiently without
installing scrubbers or purchasing allowances from outside sources,
and the System may have excess allowances available for sale to other
utilities.
Entergy currently estimates that total capital costs of
approximately $39.4 million could be required to comply with the Act.
These estimated costs for each legal entity are as follows:
Nitrogen Continuous
Company Oxide Emissions
Control Monitors Total
---------------------- -------- ---------- -----
(In Thousands)
AP&L $ 7,275 $ 3,300 $10,575
GSU 16,000 4,900 20,900
LP&L - 2,300 2,300
MP&L 2,500 1,500 4,000
NOPSI - - -
System Energy - - -
Entergy Power 1,575 - 1,575
------- ------- -------
Total Entergy System $27,350 $12,000 $39,350
======= ======= =======
Other Environmental Matters. The provisions of the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as
amended (Superfund), among other things, authorize the EPA and,
indirectly, the states to require the generators and certain
transporters of certain hazardous substances released from or at a
site, and the owners or operators of such site, to clean up the site
or reimburse the costs therefor. This statute has been interpreted to
impose joint and several liability on responsible parties. In
compliance with applicable laws and regulations at the time, the
System operating companies have sent waste materials to various
disposal sites over the years. Also, past operating procedures and
maintenance practices, which were not subject to regulation at that
time, are now regulated by various environmental laws. Some of these
sites have been the subject of governmental action, thereby causing
one or more of the System operating companies to be involved with site
cleanup activities. The System operating companies have participated
to various degrees in accordance with their potential liability with
these site cleanups and have, therefore, developed experience with
cleanup costs. Their experience in these matters, and their judgments
related thereto, are utilized by them in evaluating these sites. In
addition, the System operating companies have established reserves for
environmental clean-up/restoration activities.
AP&L. AP&L has received notices from time to time between 1989
and 1993, from the EPA, the Arkansas Department of Pollution Control
and Ecology (ADPC&E), and others that it (among numerous others,
including various utilities, municipalities and other governmental
units, and major corporations) may be a PRP for cleanup costs
associated with various sites in Arkansas. Most of these sites are
neither owned nor operated by any System company. Contaminants at the
sites include principally polychlorinated biphenyls (PCB's), lead, and
other hazardous wastes. These sites and others are described below.
AP&L received notices from the EPA and ADPC&E in 1990 and 1991,
identifying it as one of 30 PRP's (along with LP&L and GSU) at two
Saline County sites in Arkansas. Both sites are believed to be
contaminated with PCB's and lead. Cleanup costs for both sites are
estimated at $6.0 million, with AP&L's total share of the costs being
estimated at approximately $2.0 million. AP&L to date has expended
approximately $1.0 million for remediation at one of these sites. The
total liability cannot be precisely determined until remediation is
complete at both sites. AP&L believes its potential liability for
these sites will not be material.
Reynolds Metals Company (RMC) and AP&L notified the EPA in 1989,
of possible PCB contamination at two former RMC plant sites in
Arkansas to which AP&L had supplied power. AP&L completed remediation
at the substations serving the plant sites at a cost of $1.7 million.
Additional PCB contamination was found in a portion of a drainage
ditch that flows from the RMC's Patterson facility to the Ouachita
River. RMC has demanded that AP&L participate in the remediation
efforts with respect to the ditch. AP&L and independent contractors
engaged by AP&L conducted an investigation of the ditch contamination
and the potential migration of PCB's from the electrical equipment
that AP&L maintained at the plant. The investigation concluded that
little, if any, of the contamination was caused by AP&L. AP&L's
expenditures thus far on the ditch have been approximately $150,000.
It is AP&L's understanding that RMC has spent approximately $10.0
million to complete remediation of the ditch contamination. AP&L has
not received a notice from the EPA that it may be a PRP with respect
to remediation costs for this site. However, RMC is seeking
reimbursement of $5.0 million (50% of expenditures) from AP&L. AP&L
continues to deny responsibility for any of such remediation costs and
believes that its potential liability, if any, for this site will not
be material.
AP&L entered into a Consent Administrative Order dated February
21, 1991, with the ADPC&E that named AP&L as a PRP for cleanup of
contamination associated with the Utilities Services, Inc. state
Superfund site located near Rison, Arkansas. Such site was found to
have soil contaminated by PCB's and pentachlorophenol (a wood
preservative chemical). Also, containers and drums that contained
PCB's and other hazardous substances were found at the site. AP&L's
share of total remediation costs are estimated to range between $3.0
million and $5.0 million. AP&L is attempting to identify and notify
other PRP's. AP&L has received assurances from the ADPC&E that it
will use its enforcement authority to allocate remediation expenses
among AP&L and any other PRP's that can be identified (approximately
30 - 35 have been identified to date). AP&L has performed the
activities necessary to stabilize the site, which to date has cost
approximately $114,000. AP&L believes that its potential liability
for this site will not be material.
AP&L received Notice of Potential Liability and a Demand for
Payment in November 1992 from the EPA in conjunction with a
contaminated site in Union County, Arkansas. AP&L was identified as
one of eleven PRP's, which also include LP&L. The EPA has already
completed cleanup of the site. An agreement has been negotiated with
the EPA which determined AP&L to be a de minimis party with total
liability of approximately $47,000.
As a result of an internal investigation, AP&L has discovered
soil contamination at two AP&L-owned sites located in Blytheville,
Arkansas and Pine Bluff, Arkansas. The contamination appears to be a
result of past operating procedures that were performed prior to any
applicable environmental regulation. AP&L is still investigating
these sites to determine the full extent of the contamination. Until
the investigations are complete, AP&L cannot estimate the liabilities
associated with these sites. However, AP&L believes its potential
liability for both of the sites should not be material.
For all of these sites and for certain sites in which remediation
has been completed, AP&L has expended approximately $3.2 million for
cleanup costs since 1989.
GSU. GSU has been notified by the EPA that it has been
designated as a PRP for the cleanup of sites on which GSU and others
have, or have been alleged to have, disposed of hazardous materials.
GSU is currently negotiating with the EPA and various state
authorities regarding the cleanup of some of these sites. Several
class action and other suits have been filed seeking relief from GSU
and others for damages caused by the disposal of hazardous waste and
for asbestos-related disease that allegedly occurred from exposure on
GSU premises or on premises on which GSU allegedly disposed of
materials (see "Other Regulation and Litigation - GSU," below). While
the amounts at issue in the cleanup efforts and suits may be very
substantial sums, management believes that its financial condition and
results of operations will not be materially affected by the outcome
of the suits. These environmental liabilities are described below.
In 1971, GSU purchased certain property near its Sabine
generating station for possible cooling water capability expansion.
Although it was not known to GSU at the time of the purchase, the
property was utilized by area industries in the 1950's and 1960's as
an industrial waste dump. GSU sold the property in 1984. In October
1984 the abandoned waste site on the property was included on the
Superfund National Priorities List (NPL) by the EPA. The EPA has
indicated that it believes GSU to be a PRP for cleanup of the site
based on its past ownership. GSU has advised the EPA that it does not
believe that it has such responsibility. GSU has pursued negotiations
with the EPA and is a member of a task force made up of other PRP's
for the voluntary cleanup of the waste site. A Consent Decree has
been signed by all parties. Because additional wastes have been
discovered at the site since the original cleanup costs were
estimated, the total costs for the voluntary cleanup are unknown.
However, it is estimated that cleanup will exceed $15.0 million. GSU
has negotiated a responsible share of 2.26% of the estimated cleanup
cost. Federal and state agencies are presently examining potential
liabilities associated with natural resource damages. This matter is
currently under negotiation with the other PRP's and the agencies.
Remediation of the site is expected to be completed in 1996.
In March 1993, GSU completed its cleanup activities at a site in
Houston, Texas, which is included in the NPL. On September 20, 1993,
GSU received formal notification from the EPA of its acceptance of the
remedial activities conducted at the site. Currently, other parties
are conducting cleanup activities at the site. However, these cleanup
activities are unrelated to GSU's involvement at the site. Through
1993, GSU incurred cleanup costs of approximately $3.3 million.
Pursuant to the Consent Decree, GSU is responsible for oversight costs
incurred by the EPA. GSU has not received a reimbursement request for
outstanding oversight costs, but anticipates these costs may total
between $250,000 and $500,000. GSU is pursuing contribution for the
cleanup costs at the site from other parties believed to be
potentially responsible.
GSU is currently involved in a multi-phased remedial
investigation of an abandoned manufactured gas plant (MGP) site
located in Lake Charles, Louisiana. The property was the site of an
MGP that is believed to have operated during the period from
approximately 1916 to 1931. Coal tar, a by-product of the
distillation process, was apparently routed to a portion of the
property for disposal. Since GSU purchased the property in 1926, the
same area has been filled with soil and used as a landfill for
miscellaneous items including electrical poles, electrical equipment,
and other debris. Under an Order by the Louisiana Department of
Environmental Quality (LDEQ), which is currently stayed, GSU was
required to investigate and, if necessary, take remedial action at the
site. The EPA has notified GSU that it is performing an independent
review and ranking of the site to determine whether the site should be
listed on the NPL. Another PRP has been identified and is believed to
have had a role in the ownership and operation of the MGP.
Negotiations with that company for joint participation and any
remedial action are expected to continue. GSU currently is awaiting
notification from the EPA before initiating additional cleanup
negotiations or actions. While studies to determine the location of
the coal tar have been conducted, the cleanup costs of the site are
unknown. GSU does not presently believe that its ultimate
responsibility with respect to this site will be material.
GSU has also been advised that it has been named as a PRP, along
with a number of other companies (including LP&L), for an abandoned
waste oil recycling plant site in Livingston Parish, Louisiana, which
is included on the NPL. Although significant remediation has been
completed, additional studies are expected to continue in 1994. GSU
and LP&L have been named as defendants in a class action lawsuit
lodged against a group of PRP's associated with the site. (For
information regarding litigation in connection with the Livingston
Parish site, see "Other Regulation and Litigation - GSU," below.) GSU
does not presently believe that its ultimate responsibility with
respect to this site will be material.
GSU received notification in 1992 from the EPA of potential
liability at a site located in Iota, Louisiana. This site accepted a
variety of wastes, including medical and chemical wastes. In addition
to GSU, over 200 parties have been named as PRP's. The EPA is
continuing its investigation of the site and has notified the PRP's of
the possibility of this site being linked to another site. To date,
GSU has not received notification of liability with regard to the
other site. GSU does not presently believe its ultimate
responsibility with respect to this site will be material.
GSU has also been notified by the EPA of potential liability at
two sites located in Saline County, Arkansas. It is believed that
both sites served as a salvaging facility for transformers and
batteries. In addition to GSU, 32 other parties (including AP&L and
LP&L) have been named as PRP's. At this time, GSU's involvement with
the site is unknown. GSU does not presently believe that its ultimate
responsibility with respect to this site will be material.
In November 1993, GSU received informal notification from the
Rhode Island Department of Environmental Management regarding a site
at which electrical capacitors had been located. The State traced
several of these capacitors to GSU. GSU records indicate these
capacitors were returned under warranty to the manufacturer in the
1960's due to defects. GSU does not presently believe it is
responsible for any alleged activities occurring at this site.
As of December 31, 1993, GSU had expended $7.0 million toward the
cleanup of such sites.
In 1990, GSU received an order from the LDEQ to reduce emissions
of nitrogen oxides and reactive hydrocarbons at its Willow Glen and
Louisiana Station plants located near Baton Rouge, Louisiana. GSU has
requested an adjudicatory hearing on the matter, which the LDEQ
secretary has deemed as staying the order. In the interim, GSU has
joined several other Baton Rouge industries to develop and submit to
LDEQ a comprehensive set of short- and long-range reduction plans. In
1993, LDEQ adopted regulations requiring permanent reductions in
nitrogen oxides emissions at Willow Glen and Louisiana Station and is
considering requirements for further reductions. The estimates for
actions necessary to comply with these regulations are included in the
discussion under "Clean Air Legislation," above. GSU believes these
regulations implement the intent of the 1990 order, and actions beyond
those required by the regulations will not be required.
LP&L and NOPSI. LP&L and NOPSI have received notices from time
to time between 1986 and 1993 from the EPA and/or the states of
Louisiana and Mississippi that each or either of the companies may be
a PRP for cleanup costs associated with disposal sites that are
currently in various stages of remediation in Arkansas, Illinois,
Louisiana, Mississippi, and Missouri that are neither owned nor
operated by any System company.
As to one Missouri site, LP&L's and NOPSI's aggregate liability
is currently estimated not to exceed $558,000, and because of the type
and the large number of PRP's (over 700, including many large
utilities and national and international corporations), LP&L and NOPSI
do not expect liabilities in excess of this amount. For the other
Missouri site, LP&L and the other 64 PRP's (including several large,
creditworthy utility companies) have received an EPA demand to pay
approximately $1.2 million expended by the EPA. In June of 1993, LP&L
paid $12,392 in full payment of its share of the cleanup costs. LP&L
considers cleanup at this site to be complete.
As to the two Saline County, Arkansas sites (involving AP&L, GSU,
and LP&L), LP&L has been advised that current estimates for total
cleanup are approximately $6.0 million. LP&L believes that, because
of the number and nature of the PRP's, its exposure for these sites
will not be material. Initial indications are that LP&L was involved
in the Saline sites, but LP&L believes that because of the limited
scope of its involvement and the number and nature of PRP's, its
exposure for these sites will not be material.
LP&L received notice from the EPA in November 1992, that it
(along with AP&L) was involved in the Union County, Arkansas site. An
agreement has been negotiated with the EPA that determined LP&L to be
a de minimis party with a total liability of approximately $47,000
(see "AP&L," above.)
As to the Mississippi site, LP&L (along with System Energy)
understands that EPA has expended approximately $740,000 for this site
(three separate locations being treated administratively as one). The
State of Mississippi has indicated it intends to have PRP's conduct a
cleanup of the site but has not yet taken formal action. LP&L has
expended $22,300 to settle with the EPA for its costs for this site
and, because there are 44 PRP's for this site (including a number of
major oil companies), does not expect its share of future costs to be
material.
For a Livingston Parish, Louisiana site (involving at least 70
PRP's, including GSU and many other large and creditworthy
corporations), LP&L has found in its records no evidence of its
involvement. (For information regarding litigation in connection with
the Livingston Parish site, see "Other Regulation and Litigation -
LP&L," below.) At a second Louisiana site (also included on the NPL
and involving 57 PRP's, including a number of major corporations),
NOPSI believes it has no liability for the site because the material
it sent to the site was not a hazardous substance.
For the Illinois site, NOPSI, upon its review of the site
documentation and of its own records, has asserted to the EPA that it
has no involvement in this site. However, NOPSI is participating with
other PRP's (including many large and creditworthy corporations) as a
prudent means of resolving potential liability, if any.
For all these sites, LP&L has expended approximately $349,000 and
NOPSI has expended approximately $172,000 for cleanup costs
(commencing in 1986) to date.
During 1993, LP&L performed preliminary site assessments at the
locations of two retired power plants previously owned and operated by
two Louisiana municipalities. LP&L had purchased the power plants by
agreement (as part of the municipal electric systems) after operating
them for the last few years of their useful lives. The assessments
indicated some subsurface contamination from fuel oil. LP&L and the
LDEQ are now reviewing site remediation procedures that LP&L estimates
will not exceed $650,000 in the aggregate.
During 1993, the LDEQ issued new rules for solid waste
regulation, including waste water impoundments. LP&L has determined
that certain of its power plant waste water impoundments are affected
by these regulations and has chosen to close them rather than retrofit
and permit them. The aggregate cost of the impoundment closures, to
be completed by 1996, is estimated to be $7.3 million.
System Energy. In February 1990, System Energy received an EPA
notice that it (among numerous other companies) may be a PRP for
cleanup costs associated with the same site in Mississippi in which
LP&L is involved. Potential liability is based on the alleged
shipment of waste oil to the site from 1981 to 1985. System Energy
does not expect its share of the total expenditures to be material
because there are 44 PRP's for this site, including a number of major
oil companies.
Other Regulation and Litigation
Entergy Corporation and GSU. In July and August 1992, Entergy
Corporation and GSU filed applications with FERC, the LPSC, and the
PUCT, and Entergy Corporation, Entergy Operations, and Entergy
Services filed an application with the SEC under the Holding Company
Act, seeking authorization of various aspects of the Merger. In
January 1993, GSU filed two applications with the NRC seeking approval
of the change in ownership of GSU and an amendment to the operating
license for River Bend to reflect its operation by Entergy Operations.
All regulatory approvals were obtained in 1993 and the Merger was
consummated on December 31, 1993 (see "Business of Entergy - Entergy
Corporation-GSU Merger," above, for further information).
Requests for rehearing of certain aspects of the FERC order were
filed on January 14, 1994, by 14 parties, including Entergy
Corporation, the APSC, the Mississippi Attorney General, the LPSC, the
MPSC, the Texas Office of Public Utility Counsel, and the PUCT.
Entergy Corporation, the LPSC, the Texas Office of Public Utility
Counsel, and the PUCT are requesting FERC to restore a 40% cap on the
amount of fuel savings GSU may be required to transfer to other
Entergy operating companies under a tracking mechanism designed to
protect the other companies from certain unexpected increases in fuel
costs. The other parties are seeking to overturn FERC's decision on
various grounds. Requests for rehearing of the SEC order were filed
with the SEC by Houston Industries Incorporated and Houston Lighting &
Power Company on December 28, 1993, and petitions for review seeking
to set aside the SEC order were filed with the D.C. Circuit by these
parties on February 15, 1994 and by Cajun on February 14, 1994.
See "Nuclear Operations - River Bend," above for information on
challenges to the NRC's approval of GSU's applications.
Appeals seeking to set aside the LPSC order related to the Merger
were filed in the 19th Judicial District Court for the Parish of East
Baton Rouge, Louisiana, by Houston Lighting & Power Company on August
13, 1993, and by the Alliance for Affordable Energy, Inc. on August
20, 1993. Subsequently, on February 9, 1994, Houston Lighting & Power
Company filed a motion voluntarily dismissing its appeal.
AP&L. Three lawsuits (which have been consolidated) were filed
in the Arkansas District Court by numerous plaintiffs against AP&L and
Entergy Services in connection with the operation of two dams during a
period of heavy rainfall and flooding in May 1990. The consolidated
lawsuits sought approximately $14.4 million in property losses and
other compensatory damages, and $500 million in punitive damages. In
their responses to these complaints, AP&L and Entergy Services
asserted, among other things, that AP&L owns flowage easements giving
it the permanent right to inundate the lands owned or occupied by the
plaintiffs in connection with the operation of the dams. In June
1991, the Arkansas District Court granted summary judgment to AP&L
with respect to the enforceability of its flowage easements. In
November 1991, the Arkansas District Court ruled that Entergy
Services was entitled to the benefit of AP&L's flowage easements, in
effect, removing from consideration damages in the approximate amount
of $13.5 million alleged to have occurred within the areas covered by
the easements. As a result, over 300 plaintiffs claiming damage
within the easements were dismissed from the consolidated case in
December 1991. Certain plaintiffs appealed these orders to the
Eighth Circuit, which appeal was denied in March 1992. Following the
Eighth Circuit's denial of their interlocutory appeal from the
Arkansas District Court's orders, certain of the plaintiffs, without
prejudice to their right to refile, voluntarily dismissed their claims
which had not been disposed of in the Arkansas District Court's
orders, thus making the orders a final adjudication, and appealed
these orders to the Eighth Circuit. The remaining plaintiffs obtained
a stay and an administrative termination of their claims, pending the
outcome of the appeal. In December 1993, a three-judge panel of the
Eighth Circuit filed its opinion affirming the judgment of the
Arkansas District Court and entered judgment accordingly. The
plaintiffs appealing the Arkansas District Court's orders filed
petitions with the Eighth Circuit for a rehearing by the entire Court
sitting en banc, which petitions were denied. The plaintiffs may
petition the U.S. Supreme Court to issue a writ of certiorari to
permit its review of the Eighth Circuit's decisions. Neither AP&L nor
Entergy Services can predict whether the U.S. Supreme Court will grant
such a petition, if one is filed.
GSU. Between 1986 and 1993, GSU and approximately 70 other
defendants, including many national and international corporations,
including LP&L, have been sued in 17 suits in the Livingston Parish,
Louisiana District Court (State District Court) by a number of
plaintiffs who allegedly suffered damage or injury, or are survivors
of persons who allegedly died, as a result of exposure to "hazardous
toxic waste" that emanated from a site in Livingston Parish. The
plaintiffs alleged that the defendants generated, transported, or
participated in the storage of such wastes at the facility, which was
previously operated as a waste oil recycling facility. These State
District Court suits, which seek damages in total amounts ranging from
$1.0 million to $10.0 billion and are now consolidated in a class
action, and three federal suits in three states other than Louisiana
involving issues arising from the same facility, have been removed and
transferred, respectively, to the U.S. District Court for the Middle
District of Louisiana (Federal District Court). Motions to remand the
class action to the State District Court have been filed, and
procedural issues regarding the federal suits are being considered as
well. It is not known what effect any action taken on these motions
and issues, whenever taken by the Federal District Court, would have
on the April 11, 1994 State District Court trial date that was
established before the suits were removed to Federal District Court;
but it is unlikely such trial date will be met. The matter is
pending.
In October 1989, an amended lawsuit petition was filed on behalf
of 985 plaintiffs in the District Court of Jefferson County, Texas,
60th Judicial District in Beaumont, Texas, naming 55 defendants
including GSU. In February 1990, another amended lawsuit petition was
filed in a different state District Court in Jefferson County, Texas,
on behalf of over 200 plaintiffs (subsequently amended to include a
total of 660) naming 127 defendants including GSU. Possibly 300 to
400 or more of the plaintiffs in Texas may have worked at GSU's
premises. At least five other individual suits have been filed in
Beaumont against GSU and others, seeking damages for alleged asbestos
exposure. All of the plaintiffs in such suits are also suing GSU and
all other defendants on a conspiracy count. There are 25 asbestos-
related law suits filed in the 14th Judicial District Court of
Calcasieu Parish in Lake Charles, Louisiana, on behalf of an aggregate
of 53 plaintiffs naming from 16 to 24 defendants including GSU, and
GSU is aware of as many as 61 additional cases that may be filed. The
suits allege that each plaintiff contracted an asbestos-related
disease from exposure to asbestos insulation products on the premises
of such defendants. Management believes that GSU has meritorious
defenses, but there can be no assurance as to the outcome of these
cases or that additional claims may not be asserted. In asbestos-
related suits against the manufacturers, very substantial recoveries
have been achieved by large groups of claimants. GSU does not
presently believe that the ultimate resolution of these cases will
materially adversely affect the financial position of GSU.
On February 3, 1984, Dow Chemical Company filed a request with
the LPSC for a hearing to consider issues related to the purchase of
cogenerated power by GSU. Other industries subsequently filed similar
requests and the matters were consolidated. In November 1984, the
LPSC completed hearings on rules, policies, and pricing methodologies
applicable to cogeneration. Key issues were whether or not (1) GSU
should be required to pay the industries for avoided capacity costs,
and (2) GSU should be required to wheel power to or from the
industrial plants. While the matter is still pending before the LPSC,
the LPSC did set interim rates, subject to refund by either Dow or
GSU, which exclude capacity costs.
GSU has significant business relationships with Cajun, primarily
co-ownership of River Bend and Big Cajun 2 Unit 3. GSU and Cajun own
70% and 30% of River Bend, respectively, while Big Cajun 2 Unit 3 is
owned 42% and 58% by GSU and Cajun, respectively. GSU operates River
Bend and Cajun operates Big Cajun 2 Unit 3.
GSU was requested by Cajun and Jefferson Davis Electric
Cooperative, Inc., (Jefferson Davis) to provide transmission of power
over GSU's system for delivery to the Industrial Road area near Lake
Charles, Louisiana. GSU provides electric service to industrial and
other customers in such area, and Cajun and Jefferson Davis do not.
On October 10, 1989, Cajun filed a complaint at FERC contending that
GSU wrongfully refused to provide Cajun certain transmission services
so that its member, Jefferson Davis, could provide service to certain
industrial customers, and it requested FERC to order GSU to provide
the service. On October 26, 1989, FERC summarily dismissed Cajun's
complaint, but the D.C. Circuit reversed FERC's summary determination
and remanded the case to FERC for a hearing. On June 24, 1992, after
a hearing, an ALJ issued an Initial Decision, again dismissing Cajun's
complaint. The ALJ found that the parties' contract did not require
GSU to provide the service and that Cajun's member, Jefferson Davis,
had not sought permission from the LPSC to serve the end-use customers
in question. If Jefferson Davis secured permission from the LPSC, the
ALJ believed (but did not decide) that FERC would require GSU to
provide the requested transmission service. Both Cajun and GSU have
filed exceptions to the ALJ's decision, and the matter is pending
before FERC.
Cajun and Jefferson Davis also brought a related action in
federal court in the Western District of Louisiana alleging that GSU
breached its obligations under the parties' contract and violated the
antitrust laws by refusing to provide the transmission service
described above. Cajun and Jefferson Davis seek an injunction
requiring GSU to provide the requested service and unspecified treble
damages for GSU's refusal to provide the service. On November 9,
1989, the district court judge denied Cajun's and Jefferson Davis'
motion for a preliminary injunction. On May 3, 1991, the judge stayed
the proceeding pending final resolution of the matters still pending
before FERC.
GSU and Cajun are parties to FERC proceedings regarding certain
long-standing disputes relating to transmission service charges.
Cajun asserts that GSU has improperly applied the terms of a rate
schedule, Service Schedule CTOC, to its billings to Cajun and it seeks
an order from FERC directing GSU to recompute the bills. GSU asserts
that Cajun underpaid its bills, and it seeks an order directing Cajun
to pay surcharges to make up the underpayments. On April 10, 1992,
FERC issued an order affirming in part and reversing in part an ALJ's
recommendations. Both GSU and Cajun have requested rehearing, and the
requests are still pending. In addition, on August 25, 1993, the
United States Court of Appeals for the Fifth Circuit reversed portions
of FERC's order previously decided adversely to GSU, and remanded the
case to FERC for further proceedings. On January 13, 1994, FERC
rejected GSU's proposal to collect an interim surcharge while FERC
considers the court's remand. GSU interprets FERC's 1992 order and
the Court of Appeals decision to mean that Cajun owes GSU
approximately $85 million through December 31, 1993. If GSU also
prevails on all of the issues raised in its pending request for
rehearing of FERC's earlier orders, then GSU estimates that Cajun
would owe GSU approximately $118 million through December 31, 1993.
If GSU does not prevail on its rehearing request, and Cajun prevails
on its rehearing request, and if FERC rejects the modifications GSU
interprets the court of appeals to have directed, then GSU would owe
Cajun an estimated $76 million through December 31, 1993. Pending
FERC's ruling on the May 1992 motions for rehearing, GSU has continued
to bill Cajun utilizing the historical billing methodology and has
booked underpaid transmission charges, including interest, in the
amount of $140.8 million as of December 31, 1993. This amount is
reflected in long-term receivables and in other deferred credits, with
no effect on net income.
On December 7, 1993, Cajun filed a complaint in the Middle
District of Louisiana alleging that GSU failed to provide Cajun an
opportunity to construct certain facilities that allegedly would have
reduced its rates under Service Schedule CTOC, and Cajun seeks an
order compelling the conveyance of certain facilities and unspecified
damages. GSU has moved to dismiss the complaint on the basis, among
others, that FERC has already addressed the matter in the proceedings
described above.
In May 1990, GSU received a subpoena from the Office of Inspector
General - Investigations, United States Department of Agriculture,
seeking production of documents relating to the construction costs of
River Bend. Such office is authorized to investigate matters relating
to programs of the Department of Agriculture. GSU has been sued by
Cajun with respect to its participation in River Bend with funds made
available through Department programs administered by the REA. GSU
has failed in its efforts to have the REA made a party to the Cajun
litigation. GSU does not know the purpose of such Office's
investigation, but presently assumes that it relates to the Cajun
civil litigation since the production of documents sought by such
Office is similar to that sought by Cajun in its action against GSU.
However, there can be no assurance given by GSU as to the real purpose
of such Office's investigation. Among other areas of responsibility,
such office is authorized to investigate possible violations of law.
GSU believes the subpoena proceeding has been administratively
dismissed without prejudice to the parties.
On December 2, 1991, Cajun filed a complaint seeking declaratory
and injunctive relief from the U. S. District Court for the Middle
District of Louisiana. The complaint concerns GSU's position that
Cajun is in default with respect to paying its share of certain
expenditures to repair corrosion damage in the service water system,
to repair a feedwater nozzle crack, and to repair a turbine rotor.
Cajun alleges that it has no obligation to pay its share of such costs
and seeks a declaration that it may elect not to participate in the
funding of such costs and enjoining GSU from demanding payment
therefor or attempting to implement default provisions in the
Operating Agreement with respect thereto. Cajun alleges that if it is
required to pay its share of such costs it would be forced to default
on other obligations and would be forced to seek relief in bankruptcy.
GSU believes that Cajun is in default under the provisions of the
Operating Agreement. No assurance can be given as to the outcome or
timing of this action brought by Cajun.
On November 25, 1992, Dixie Electric Membership Corporation and
Southwest Louisiana Electric Membership Corporation, both members of
Cajun, filed suit in the U.S. District Court for the Western District
of Louisiana seeking a declaration that the River Bend Joint Ownership
Agreement between GSU and Cajun is void because an allegedly required
approval of the LPSC was not obtained. This suit has been transferred
from the Western District to the Middle District, and is being
processed in conjunction with the suit described in the following
paragraph. GSU believes the suit is without merit.
In June 1989, Cajun filed a civil action against GSU in the U. S.
District Court for the Middle District of Louisiana. Cajun stated in
its complaint that the object of the suit is to annul, rescind,
terminate, and/or dissolve the Joint Ownership Participation and
Operating Agreement entered into on August 28, 1979 (Operating
Agreement), related to River Bend. Cajun alleges fraud and error by
GSU, breach of its fiduciary duties owed to Cajun, and/or GSU's
repudiation, renunciation, abandonment, or dissolution of its core
obligations under the Operating Agreement, as well as the lack or
failure of cause and/or consideration for Cajun's performance under
the Operating Agreement. The suit seeks to recover Cajun's alleged
$1.6 billion investment in the unit as damages, plus attorneys' fees,
interest, and costs. In March 1992, the district court appointed a
mediator to engage in settlement discussions and to schedule
settlement conferences between the parties. Discussions with the
mediator began in July 1992, however, GSU cannot predict what effect,
if any, such discussions will have on the timing or outcome of the
case. A trial without a jury is set for April 12, 1994, on the
portion of the suit by Cajun to rescind the Operating Agreement. GSU
believes the suits are without merit and is contesting them
vigorously. No assurance can be given as to the outcome of this
litigation. If GSU were ultimately unsuccessful in this litigation
and were required to make substantial payments, GSU would probably be
unable to make such payments and would probably have to seek relief
from its creditors under the Bankruptcy Code.
See Note 12 of GSU's Notes to Financial Statements, "Entergy
Corporation-GSU Merger," for the accounting treatment of preacquisition
contingencies, including a charge resulting from an adverse resolution
of the litigation with Cajun related to River Bend.
In July 1992, Cajun notified GSU that it would fund a limited
amount of costs related to the fourth refueling outage at River Bend,
completed in September 1992. Cajun has also not funded its share of
the costs associated with certain additional repairs and improvements
at River Bend completed during the refueling outage. GSU has paid the
costs associated with such repairs and improvements without waiving
any rights against Cajun. GSU believes that Cajun is obligated to pay
its share of such costs under the terms of the applicable contract.
Cajun has filed a suit seeking a declaration that it does not owe such
funds and seeking injunctive relief against GSU. GSU is contesting
such suit and is reviewing its available legal remedies.
In September 1992, GSU received a letter from Cajun alleging that
the operating and maintenance costs for River Bend are "far in excess
of industry averages" and that "it would be imprudent for Cajun to
fund these excessive costs." Cajun further stated that until it is
satisfied it would fund a maximum of $700,000 per week under protest
for the remainder of 1992. In a December 1992 letter, Cajun stated
that it would also withhold costs associated with certain additional
repairs, of which the majority will be incurred during the next
refueling outage, currently scheduled for April 1994. GSU believes
that Cajun's allegations are without merit and is considering its
legal and other remedies available with respect to the underpayments
by Cajun. The total resulting from Cajun's failure to fund repair
projects, Cajun's funding limitation on the fourth refueling outage,
and the weekly funding limitation by Cajun was $33.3 million as of
December 31, 1993, compared with a $28.4 million unfunded balance as
of December 31, 1992.
During 1994, and for the next several years, it is expected that
Cajun's share of River Bend-related costs will be in the range of $60
million to $70 million per year. Cajun's weak financial condition
could have a material adverse effect on GSU, including a possible NRC
action with respect to the operation of River Bend and a need to bear
additional costs associated with the co-owned facilities. If GSU were
required to fund Cajun's share of costs, there can be no assurance
that such payments could be recovered. Cajun's weak financial
condition could also affect the ultimate collectibility of amounts
owed to GSU.
Since 1986, GSU had been in litigation with the Southern Company
regarding unit power and long-term power purchase contracts with the
Southern Company. GSU entered into a settlement agreement dated
December 21, 1990, which was consummated on November 7, 1991, and the
settlement obligations were fully satisfied in 1993.
In 1986, the PUCT and the LPSC disallowed the pass-through by GSU
in its retail rates of the costs of the capacity purchases from the
Southern Company, which were being incurred by GSU. GSU appealed the
actions of the PUCT and the LPSC disallowing pass-through of Southern
Company capacity charges to the appropriate state courts. The appeal
from the LPSC is pending. As part of a settlement of a retail rate
case in Texas during the fourth quarter of 1993, GSU has discontinued
its appeal of the PUCT disallowance.
Following the announcement of the execution of the Reorganization
Agreement, a purported class action complaint was filed on June 9,
1992, in the District Court 60th Judicial District in Jefferson
County, Texas (District Court) against GSU and its directors relating
to the then proposed business combination with Entergy Corporation.
On June 11, 1992, two additional purported class action complaints
were filed against such defendants in the District Court. All three
of the complaints (the Shareholder Actions) were filed by persons
alleged to be shareholders of GSU and seeking declaration of a class
action on behalf of all persons owning common stock of GSU.
GSU has executed a Memorandum of Understanding with counsel for
the plaintiffs in these suits agreeing in principle to settle such
actions subject to execution of an appropriate stipulation of
settlement, approval by the court, and certain other conditions. In
the Memorandum, the defendants have denied any actionable acts or
omissions and state that they have entered into the Memorandum solely
to eliminate the burden and expense of further litigation and to
facilitate the consummation of the business combination. The
Memorandum memorialized certain agreements by GSU and Entergy
Corporation for the benefit of shareholders principally in the event
the business combination were not consummated, including a covenant to
consider reinstitution of dividends on the common stock of GSU in such
event. The business combination was consummated on December 31, 1993.
Incident to the settlement, the defendants agreed not to oppose an
application for attorneys' fees by plaintiffs' counsel that do not
exceed $500,000 or for an award of expenses not to exceed $50,000.
The individual directors named as defendants in these complaints are
entitled to indemnification pursuant to GSU's Restated Articles of
Incorporation, By-laws, and individual indemnity agreements, provided
that the terms and conditions of the indemnities are satisfied.
LP&L. For information regarding litigation in connection with an
abandoned waste oil recycling plant site in Livingston Parish,
Louisiana, in which LP&L and GSU are defendants, see "GSU," above.
LP&L does not believe that it was a generator of any material
delivered to this facility and is defending vigorously against the
claims in these suits.
Since the mid-1980's, LP&L and the tax authorities of St. Charles
Parish, Louisiana (Parish), in which Parish Waterford 3 is located,
have disputed use taxes paid on nuclear fuel ($4.9 million through
1989) under protest by LP&L. LP&L has been successful in a lawsuit in
the Parish with regard to recovering these taxes, plus interest, and
also with regard to Parish lease tax issues pertaining to fuel
financing arrangements. On the grounds of the previous favorable
court decisions, LP&L continues to challenge in the courts additional
use tax assessments that it has paid to the Parish and to seek
additional interest that LP&L claims it is due. Also, in early
procedural stages are (1) suits by LP&L with regard to the state use
tax on nuclear fuel, and (2) LP&L's defense (and indemnification, if
necessary) of nuclear fuel lessors under LP&L's fuel financing
arrangements in the suits filed by the Parish use tax authorities
claiming approximately $64.0 million in lease and use taxes. These
matters are pending.
System Energy. In connection with an IRS audit of Entergy's
1988, 1989, and 1990 consolidated federal income tax returns, the IRS
is proposing that adjustments be made to the Grand Gulf 2 abandonment
loss deduction claimed on Entergy's 1989 consolidated federal income
tax return. If any such adjustments are necessary, the effect on
System Energy's net income should be immaterial. Entergy intends to
contest the proposed adjustments if finalized by the IRS. The outcome
of such proceedings cannot be predicted at this time.
EARNINGS RATIOS OF SYSTEM OPERATING COMPANIES AND SYSTEM ENERGY
The System operating companies and System Energy have calculated
ratios of earnings to fixed charges and ratios of earnings to fixed
charges and preferred dividends pursuant to Item 503 of Regulation S-K
of the SEC as follows:
Years Ended December 31,
---------------------------------------------
1989 1990 1991 1992 1993
---- ---- ---- ---- ----
Ratios of Earnings to
Fixed Charges(a)
AP&L 2.31 2.16 2.25 2.28 3.11(h)
GSU 1.16 .80(i) 1.56 1.72 1.54
LP&L 1.79 2.32 2.40 2.79 3.06
MP&L 1.04(e) 2.42 2.36 2.37 3.79(h)
NOPSI 1.89 2.73 5.66(g) 2.66 4.68(h)
System Energy -(f) 2.10 1.74 2.04 1.87
Years Ended December 31,
---------------------------------------------
1989 1990 1991 1992 1993
---- ---- ---- ---- ----
Ratios of Earnings to
Fixed Charges and
Preferred Dividends(a)(b)(c)
AP&L 1.88 1.81 1.87 1.86 2.54(h)
GSU(d) .66(i) .59(i) 1.19 1.37 1.21
LP&L 1.39 1.87 1.95 2.18 2.39
MP&L 1.00(e) 1.93 1.94 1.97 3.08(h)
NOPSI 1.62 2.36 4.97(g) 2.36 4.12(h)
____________________
(a) "Earnings" as defined by SEC Regulation S-K represent the
aggregate of (1) net income, (2) taxes based on income, (3)
investment tax credit adjustments-net, and (4) fixed charges.
"Fixed Charges" include interest (whether expensed or
capitalized), related amortization, and interest applicable to
rentals charged to operating expenses.
(b) "Preferred Dividends" as defined by SEC Regulation S-K are
computed by dividing the preferred dividend requirement by one
hundred percent (100%) minus the income tax rate.
(c) System Energy's Amended and Restated Articles of Incorporation do
not currently provide for the issuance of preferred stock.
(d) "Preferred Dividends" in the case of GSU also include dividends
on preference stock.
(e) Earnings for the year ended December 31, 1989, include the impact
of the write-off of $60 million of deferred Grand Gulf 1-related
costs pursuant to an agreement between MP&L and the MPSC.
(f) Earnings for the year ended December 31, 1989, were inadequate to
cover fixed charges due to System Energy's cancellation and write-
off of its investment in Grand Gulf 2 in September 1989. The
amount of the coverage deficiency for fixed charges was $745.2
million.
(g) Earnings for the year ended December 31, 1991, include the $90
million effect of the 1991 NOPSI Settlement.
(h) Earnings for the year ended December 31, 1993, include
approximately $81 million, $52 million, and $18 million for AP&L,
MP&L, and NOPSI, respectively, related to the change in
accounting principle to provide for the accrual of estimated
unbilled revenues.
(i) Earnings for the year ended December 31, 1990, for GSU were not
adequate to cover fixed charges by $60.6 million. Earnings for
the years ended December 31, 1990 and 1989, were not adequate to
cover fixed charges and preferred dividends by $165.1 million and
$190.8 million, respectively. Earnings in 1990 include a $205
million charge for the settlement of a purchased power dispute.
INDUSTRY SEGMENTS
NOPSI
Narrative Description of NOPSI Industry Segments
Electric Service. NOPSI supplied electric service to 190,613
customers as of December 31, 1993. During 1993, 36% of electric
operating revenues was derived from residential sales, 40% from
commercial sales, 6% from industrial sales, 15% from sales to
governmental and municipal customers, and 3% from sales to public
utilities and other sources.
Natural Gas Service. NOPSI supplied natural gas service to
154,251 customers as of December 31, 1993. During 1993, 56% of gas
operating revenues was derived from residential sales, 18% from
commercial sales, 9% from industrial sales, and 17% from sales to
governmental and municipal customers. (See "Fuel Supply - Natural Gas
Purchased for Resale," incorporated herein by reference.)
Selected Financial Information Relating to Industry Segments
For selected financial information relating to NOPSI's industry
segments, see NOPSI's financial statements and Note 11 of NOPSI's
Notes to Financial Statements, "Business Segment Information,"
incorporated herein by reference.
Employees by Segment
NOPSI's full-time employees by industry segment as of
December 31, 1993, were as follows:
Electric 568
Natural Gas 148
---
Total 716
(For further information with respect to NOPSI's segments, see
"Property.")
GSU
For the year ended December 31, 1993, 96% of GSU's operating
revenues were derived from the electric utility business. The
remainder of operating revenues were derived 2% from the steam
business and 2% from the natural gas business. Segment information
for GSU is not provided.
PROPERTY
Generating Stations
The total capability of Entergy 's owned and leased generating
stations as of December 31, 1993, by company, is indicated below:
Owned and Leased Capability MW(1)
Gas
Turbine
andl
Fossil Internal
Company Total Fuel Nuclear Combustion Hydro
------- ----- ---- ------- ---------- -----
AP&L 4,367 (2) 2,373 1,694 230 (8) 70
GSU 6,420 (2) 5,693 652 (5) 75 -
LP&L 5,535 (2) 4,441 1,075 (6) 19 -
MP&L 3,046 (2) 3,035 (4) - 11 -
NOPSI 927 (2) 912 - 15 -
System Energy 1,028 - 1,028 (7) - -
Total System 21,323 (3) 16,454 (3)(4) 4,449 350 70
_______________________
(1) "Owned and Leased Capability" is the dependable load carrying
capability of the stations, as demonstrated under actual
operating conditions based on the primary fuel (assuming no
curtailments) that each station was designed to utilize.
(2) Excludes the capacity of fossil-fueled generating stations placed
on extended reserve as follows: AP&L - 506 MW; GSU - 405 MW; LP&L
- 19 MW; MP&L - 73 MW; and NOPSI - 143 MW. Generating stations
that are not expected to be utilized in the near-term to meet
load requirements are placed in extended reserve shutdown in
order to minimize operating expenses.
(3) Excludes net capability of Entergy Power, which owns 809 MW of
fossil-fueled capacity (see "Rate Matters and Regulation - Rate
Matters - Wholesale Rate Matters - Entergy Power," above).
(4) Independence 2, a coal unit operated by AP&L and jointly
owned 25% by MP&L (210 MW), 31.5% by Entergy Power (265 MW), and
the balance by various municipalities and a cooperative. The
unit was out of service, due to an explosion from August 11, 1993
to February 18, 1994.
(5) GSU's nuclear capability represents its 70% ownership interest in
River Bend; Cajun owns the remaining 30% undivided interest.
(6) LP&L's nuclear capability represents its 90.7% ownership interest
and 9.3% leasehold interest in Waterford 3.
(7) System Energy's capability represents its 90% interest in Grand
Gulf 1 (78.5% ownership interest and 11.5% leasehold interest).
South Mississippi Electric Power Association has the remaining
10% undivided ownership interest in Grand Gulf 1. Entitlement to
System Energy's capacity has been allocated to AP&L, LP&L, MP&L,
and NOPSI pursuant to the Unit Power Sales Agreement.
(8) Includes 188 MW of capacity leased by AP&L through 1999.
Representatives of the System regularly review load and capacity
projections in order to coordinate and recommend the location and time
of installation of additional generating capacity and of
interconnections in light of the availability of power, the location
of new loads, and maximum economy to the System. Based on load and
capability projections, the System has no need to install additional
generating capacity until 1999. To delay the need for new capacity,
the System is engaging in conservation and DSM programs, as discussed
in "Business of Entergy - Competition - Least Cost Planning," above.
When new generation resources are needed, the System plans to meet
this need with a variety of sources other than construction of new
base load generating capacity. In the meantime, the System will meet
capacity needs by, among other things, removing generating stations
from extended reserve shutdown. Generating stations brought out of
extended reserve shutdown during 1993 added 248 MW to meet operating
requirements.
Under the terms of the System Agreement, some of the generating
capacity and other power resources are shared among the System
operating companies. Among other things, the System Agreement
provides that parties having generating capacity greater than their
load requirements sell such capacity to those parties having
deficiencies in generating capacity and that the purchasers pay to the
sellers a charge sufficient to cover certain of the sellers' ownership
costs, including operating expenses, fixed charges on debt, dividend
requirements on preferred and preference stock, and a fair rate of
return on common equity investment. Under the System Agreement, these
charges are based on costs associated with the sellers' steam electric
generating units fueled by oil or gas. In addition, for all energy to
be exchanged among the System operating companies under the System
Agreement, the purchasers are required to pay the cost of fuel
consumed in generating such energy plus a charge to cover other
associated costs (see "Rate Matters and Regulation - Rate Matters -
Wholesale Rate Matters - System Agreement," above, for a discussion of
FERC proceedings relating to the System Agreement).
The System's business is subject to seasonal fluctuations with
the peak period occurring in the summer months. Excluding GSU,
Entergy 's 1993 peak demand of 12,858 MW occurred on August 19, 1993.
The net System capability at the time of peak was 14,029 MW, which
reflects a reduction of the System's total 14,765 MW of owned and
leased capability by net off-system firm sales of 736 MW. The
capacity margin at the time of the peak was approximately 8.4%, not
including units placed on extended reserve and capacity owned by
Entergy Power.
GSU's 1993 peak demand of 5,612 MW occurred on August 18, 1993.
The net GSU capability at the time of peak was 6,704 MW, which
reflects an increase of GSU's total 6,420 MW of owned and leased
capability by net off-system purchases of 284 MW. The capacity margin
at the time of the peak was approximately 18.2%, not including units
placed on extended reserve.
Interconnections
The electric power supply facilities of Entergy consist
principally of steam-electric production facilities strategically
located with reference to availability of fuel, protection of local
loads, and other controlling economic factors. These are
interconnected by a transmission system operating at various voltages
up to 500 KV. Generally, with the exception of Grand Gulf 1, Entergy
Power's capacity and a small portion of MP&L's capacity, operating
facilities or interests therein are owned by the System operating
company serving the area in which the facilities are located.
However, all of the System's generating facilities are centrally
dispatched and operated with a view to realizing the greatest economy.
This operation seeks, among other things, the lowest cost sources of
energy from hour to hour. The minimum of investment and the most
efficient use of plant are sought to be achieved, in part, through the
coordinated scheduling of maintenance, inspection, and overhaul.
The System operating companies have direct interconnections with
neighboring utilities including, in individual cases, Mississippi
Power Company, Southwestern Electric Power Company, Southwest Power
Administration, Central Louisiana Electric Company, Inc., Oklahoma Gas
and Electric Company, The Empire District Electric Company, Union
Electric Company, Arkansas Electric Cooperative Corporation, Tennessee
Valley Authority, Cajun, Sam Rayburn Dam Electric Cooperative, Inc.,
SRG&T, SRMPA, Associated Electric Cooperative, Inc., Municipal Energy
Agency of Mississippi, Louisiana Energy and Power Authority, Farmers
Electric Cooperative, South Mississippi Electric Power Authority, and
the cities of Lafayette, Plaquemine, and New Roads, Louisiana. GSU
also has an interconnection agreement with Houston Lighting and Power
Company providing a minor amount of emergency service only. The System
operating companies also have interchange agreements with Alabama
Electric Cooperative, Big Rivers Electric Cooperative, Northeast Texas
Electric Cooperative, Inc., Sam Rayburn G&T Electric Cooperative,
Inc., Florida Power Corporation, Florida Power & Light Company,
Jacksonville Electric Authority, Oglethorpe Power Cooperative, the
City of Lafayette, Louisiana, the City of Springfield, Missouri, and
East Kentucky Electric Cooperative.
The System operating companies are members of the Southwest Power
Pool, the primary purpose of which is to ensure the reliability and
adequacy of the electric bulk power supply in the southwest region of
the United States. The Southwest Power Pool is a member of the North
American Electric Reliability Council. AP&L, LP&L, MP&L, and NOPSI
are also members of the Western Systems Power Pool.
Gas Property
As of December 31, 1993, NOPSI distributed and transported
natural gas for distribution solely within the limits of the City of
New Orleans through a total of 1,422 miles of gas distribution mains
and 32 miles of gas transmission lines. NOPSI receives deliveries of
natural gas for distribution purposes at 14 separate locations,
including deliveries from United Gas Pipe Line Company (United) at six
of these locations. Of the remaining delivery points, two are
principally served by interstate suppliers and the remaining are
served by intrastate suppliers.
As of December 31, 1993, the gas property of GSU was not material
to GSU.
Titles
The System's generating stations are generally located on lands
owned in fee simple. The greater portion of the transmission and
distribution lines of the System operating companies has been
constructed over lands of private owners pursuant to easements or on
public highways and streets pursuant to appropriate permits. The
rights of each company in the realty on which its properties are
located are considered by it to be adequate for its use in the conduct
of its business. Minor defects and irregularities customarily found
in properties of like size and character exist, but such defects and
irregularities do not materially impair the use of the properties
affected thereby. The System operating companies generally have the
right of eminent domain whereby they may, if necessary, perfect or
secure titles to, or easements or servitudes on, privately-held lands
used or to be used in their utility operations.
Substantially all the physical properties owned by each System
operating company and System Energy are subject to the lien of the
mortgage and deed of trust securing the first mortgage bonds of such
company. The Lewis Creek generating station is owned by GSG&T, Inc.,
and is not subject to the lien of the GSU mortgage securing the first
mortgage bonds of GSU, but is leased and operated by GSU. In the case
of LP&L, certain properties are subject to the liens of second
mortgages securing other obligations of LP&L. In the case of MP&L and
NOPSI, substantially all of their properties and assets are subject to
the second mortgage lien of their respective general and refunding
mortgage bond indentures.
FUEL SUPPLY
The following tabulation shows the percentages of natural gas,
fuel oil, nuclear fuel, and coal used in generation, excluding that of
Entergy Power, during the past three years. It also shows the average
fuel cost per KWH generated by each type of fuel during that period.
The balance of generation, which was immaterial, was provided by
hydroelectric power.
ENTERGY EXCLUDING GSU
Natural Gas Fuel Oil Nuclear Fuel Coal
----------------- ----------------- ----------------- -----------------
% Cents % Cents % Cents % Cents
of Per of Per of Per of Per
Year Gen KWH Gen KWH Gen KWH Gen KWH
- ---- --- ----- --- ----- --- ----- --- -----
1993 27 2.70 7 2.10 51 .58 15 1.91
1992 32 1.99 - - 49 .67 18 1.90
1991 31 1.64 - - 50 .79 18 1.76
GSU
Natural Gas Fuel Oil Nuclear Fuel Coal
---------------- ----------------- ----------------- -----------------
% Cents % Cents % Cents % Cents
of Per of Per of Per of Per
Year Gen KWH Gen KWH Gen KWH Gen KWH
- ---- --- ----- --- ----- --- ----- --- -----
1993 69 2.44 - - 14 1.19 17 1.77
1992 76 2.01 - - 8 1.64 16 1.68
1991 66 1.79 - - 19 1.24 15 2.08
The following tabulation shows the percentages of generation by
fuel type used in generation, excluding that of Entergy Power, for
1993 (actual) and 1994 (projected).
Natural Gas Fuel Oil Nuclear Coal
---------------- ---------------- ---------------- ----------------
1993 1994 1993 1994 1993 1994 1993 1994
---- ---- ---- ---- ---- ---- ---- ----
System(a) 27% 36% 7% 3% 51% 38% 15% 23%
AP&L 7 1 - - 60 48 33 51
GSU 69 59 - - 14 21 17 20
LP&L 52 62 1 - 47 38 - -
MP&L 24 39 52 27 - - 24 34
NOPSI 92 100 8 - - - - -
System Energy - - - - 100(b) 100(b) - -
_______________________
(a) The System's 1993 actual generation by fuel type excludes GSU;
1994 estimated generation by fuel type includes GSU.
(b) Capacity and energy from System Energy's interest in Grand Gulf 1
is allocated as follows: AP&L - 36%; LP&L - 14%; MP&L - 33%; and
NOPSI - 17%.
Natural Gas
The System operating companies have various long-term gas
contracts that will satisfy a significant percentage of each operating
company's needs; however, such contracts typically require the
operating companies to purchase less than half of their annual gas
requirements under such contracts. Additional gas requirements are
satisfied under less expensive short-term contracts and spot-market
purchases. In November 1992, GSU entered into a transportation
service agreement with a gas supplier that obligates such supplier to
provide GSU with flexible natural gas swing service to certain
generating stations by using such supplier's pipeline and salt dome
gas storage facility.
Many factors influence the availability and price of natural gas
supplies for power plants including wellhead deliverability, storage
and pipeline capacity, and the demand requirements of the end users.
This demand is closely tied to the severity of the weather conditions
in the region. Furthermore, pricing relative to other energy sources
(i.e. fuel oil, coal, purchased power, etc.) will affect the demand
for natural gas for power plants. Supplies of natural gas are
expected to be adequate in 1994.
Pursuant to FERC and state regulations, gas supplies may be
interrupted to power plants during periods of shortage. To the extent
natural gas supplies may be disrupted, the System operating companies
will use alternate sources of energy such as fuel oil.
Coal
AP&L has long-term contracts for the supply of low-sulfur coal
for the White Bluff Steam Electric Generating Station and the
Independence Steam Electric Station (which is owned 25% by MP&L).
Coal for the White Bluff Station is supplied under a contract from a
mine in the State of Wyoming. The coal contract provides for the
delivery of sufficient coal to operate the White Bluff Station through
approximately 2002. Coal for the Independence Station is also
supplied under a contract from a mine in the State of Wyoming. Coal
supplied under this contract is expected to meet the requirements of
the Independence Station through at least 2014. GSU has a contract
for a supply of low-sulfur Wyoming coal for Nelson Unit 6, which
should be sufficient to satisfy the fuel requirements at Nelson Unit 6
through 2004. Cajun has advised GSU that it has contracts that should
provide an adequate supply of coal until 1997 for the operation of Big
Cajun 2, Unit 3 (which is operated by Cajun and of which GSU owns
42%).
Nuclear Fuel
Generally, the supply of fuel for nuclear generating units
involves the mining and milling of uranium ore to produce a
concentrate, the conversion of uranium concentrate to uranium
hexafluoride gas, enrichment of that gas, fabrication of the nuclear
fuel assemblies, and disposal of the spent fuel.
System Fuels is responsible for contracts to acquire nuclear fuel
to be used in AP&L's, LP&L's, and System Energy's nuclear units and
for maintaining inventories of such materials during the various
stages of processing. Each of these companies is currently
responsible for contracting for the fabrication of its own nuclear
fuel and for purchasing the required enriched uranium hexafluoride
from System Fuels. Currently, the requirements for GSU's River Bend
plant are covered by contracts made by GSU.
On October 3, 1989, System Fuels entered into a revolving credit
agreement with banks permitting it to borrow up to $45 million to
finance its nuclear materials and services inventory. AP&L, LP&L, and
System Energy agreed to purchase from System Fuels the nuclear
materials and services financed under the agreement if System Fuels
should default in its obligations thereunder. Such purchases would be
allocated based on percentages agreed upon among the parties. In the
absence of such agreement, AP&L, LP&L, and System Energy would each be
obligated to purchase one-third of the nuclear materials and services.
Based upon the planned fuel cycles for the System's nuclear
units, the following tabulation shows the years through which existing
contracts and inventory will provide materials and services:
Acquisition
of or
Conversion Spent
Uranium to Uranium Enrich- Fabri- Fuel
Concentrate Hexafluoride ment(3) cation Disposal
----------- ------------ ------- ------ --------
ANO 1 (1) (1) 1995 1997 (4)
ANO 2 (1) (1) 1995 1994 (4)
River Bend (2) (2) 2000 1995 (4)
Waterford 3 (1) (1) 1995 1999 (4)
Grand Gulf 1 (1) (1) 1995 1995 (4)
__________________________
(1) Current contracts will provide these materials and services
through termination dates ranging from 1994-1997. Additional
materials and services required beyond these dates are estimated
to be available for the foreseeable future.
(2) Current GSU contracts will provide a significant percentage of
these materials and services for River Bend through 1995.
(3) Enrichment services for ANO 1, ANO 2, Waterford 3, and Grand Gulf
1 are provided by a System Fuels contract with the United States
Enrichment Corporation (USEC). The contract has been terminated
after 1995 to permit flexibility on future pricing and terms that
could be obtained. Enrichment services for River Bend are
provided by a GSU contract with USEC that may be partially
terminated after 1998 and fully terminated after 2000. (See
"Rate Matters and Regulation - Regulation - Regulation of the
Nuclear Power Industry - Decommissioning," above for information
on annual contributions to a federal decontamination and
decommissioning fund required by the Energy Act to be made by
AP&L, GSU, LP&L, and System Energy as a result of their
enrichment contracts with DOE.)
(4) The Nuclear Waste Policy Act of 1982 provides for the disposal of
spent nuclear fuel or high level waste by the DOE. Under this
Act, the DOE was to begin accepting spent fuel in 1998 and to
continue until the disposal of all spent fuel from reactor sites
has been accomplished. In November 1989, the DOE indicated that
the repository program will be delayed. Current on-site spent
fuel storage capacity at ANO, River Bend, Waterford 3, and Grand
Gulf 1 is estimated to be sufficient to store fuel from normal
operations until 1995, 2003, 2000, and 2004, respectively. It is
expected that any additional storage capacity required, due to
delay of the DOE repository program, will have to be provided by
the affected companies (see "Rate Matters and Regulation -
Regulation - Regulation of the Nuclear Power Industry - Spent
Fuel and Other High-Level Radioactive Waste," above).
The System will require additional arrangements for segments of
the nuclear fuel cycle beyond the dates shown above. Except as noted
above, Entergy cannot predict the ultimate availability or cost of
such arrangements at this time.
AP&L, GSU, LP&L, and System Energy currently have nuclear fuel
leasing arrangements that provide that AP&L, GSU, LP&L, and System
Energy may lease up to $125 million, $105 million, $95 million, and
$105 million of nuclear fuel, respectively. As of December 31, 1993,
the unrecovered cost base of AP&L's, GSU's, LP&L's, and System
Energy's nuclear fuel leases amounted to approximately $93.6 million,
$96.5 million, $61.3 million, and $79.7 million, respectively. Each
lessor finances its acquisition and ownership of nuclear fuel under a
credit agreement and through the issuance of intermediate-term notes.
The credit agreements, which were entered into by AP&L in 1988, by
LP&L and System Energy in 1989, and GSU in 1993, had initial terms of
five years, with the exception of GSU, which has an initial term of
three years. These agreements are subject to annual renewal with, in
LP&L's and GSU's case, the consent of the lenders. The credit
agreements for AP&L, LP&L, and System Energy have all been extended
and now have termination dates of December 1996, January 1997, and
February 1997, respectively. The credit agreement for GSU was entered
into in December 1993 and has a termination date of December 1996.
The intermediate-term notes have varying maturities through January
31, 1999. It is expected that the credit agreements will be extended,
or alternative financing will be secured by each lessor, based on the
particular lessee's nuclear fuel requirements. If extensions or
alternative financing cannot be arranged, the particular lessee must
purchase sufficient nuclear fuel to allow the lessor to retire such
borrowings.
Natural Gas Purchased for Resale
NOPSI has several suppliers of natural gas for resale. Its
system is interconnected with three interstate and three intrastate
pipelines. Presently, NOPSI's primary suppliers of natural gas for
resale are United, an interstate pipeline, and Bridgeline and
Pontchartrain, intrastate pipelines. NOPSI has a firm gas purchase
contract with United and receives this service subject to FERC-
approved rates pursuant to a certificate granted by FERC. NOPSI also
has firm contracts with its two intrastate suppliers and also makes
interruptible spot market purchases when economically attractive. In
recent years, natural gas deliveries have been subject primarily to
weather-related curtailments. However, NOPSI has experienced no such
curtailments.
In April 1992, FERC issued Order No. 636, which mandated
interstate pipeline restructuring. The order requires interstate
pipelines to cease selling gas to local distribution customers at the
city-gate interconnection although transportation service can be
provided in lieu of the former sale. As a result, in the future,
NOPSI must substitute sources upstream of the United system for its
current gas supply from United. NOPSI is considering purchases from
independent intrastate or interstate supply aggregators and/or from
intrastate pipeline sources in a manner consistent with its economic
and supply reliability objectives.
Prior to the effectiveness of Order No. 636, discussed above, in
the event of a natural gas shortage on the United system, NOPSI would
have received a portion of the available gas supply from United and
its other suppliers. After Order No. 636 mandated restructuring
(October 31, 1993), curtailments of supply could occur if NOPSI's
suppliers failed to perform their obligations to deliver gas under
their supply agreements with NOPSI. United could curtail
transportation capacity only in the event of pipeline system
constraints. Based on the current supply of natural gas, and absent
extreme weather related curtailments, NOPSI does not anticipate that
there will be any interruptions in natural gas deliveries to its
customers.
GSU purchases natural gas for resale from a single interstate
supplier. Abandonment of service by the present supplier would be
subject to abandonment proceedings by FERC.
Research
AP&L, GSU, LP&L, MP&L, and NOPSI are members of the Electric
Power Research Institute (EPRI). EPRI conducts a broad range of
research in major technical fields related to the electric utility
industry. Entergy participates in various EPRI projects, based on its
needs and available resources. During 1991, 1992, and 1993, the
System, including GSU, contributed approximately $12 million,
$16 million, and $17 million, respectively, for the various research
programs in which Entergy was involved.
Item 2. Properties
Refer to Item 1. "Business - Property," incorporated herein by
reference, for information regarding the properties of the
registrants.
Item 3. Legal Proceedings
Refer to Item 1. "Business - Rate Matters and Regulation,"
incorporated herein by reference, for details of the registrants'
material rate proceedings and other regulatory proceedings and
litigation that are pending or that terminated in the fourth quarter
of 1993.
Item 4. Submission of Matters to a Vote of Security Holders
A consent in lieu of a special meeting of common stockholders of
Entergy-GSU Holdings, Inc. (Holdings) was executed on December 30,
1993, pursuant to a Delaware statute that permits such a procedure.
The consent was signed on behalf of Entergy Corporation and GSU, which
at that time owned all of the outstanding common stock of Holdings.
The common stockholders acted to: (1) increase the number of directors
from 2 to 18 upon the occurrence of the combination of Entergy
Corporation and GSU, such expanded board to consist of Edwin Lupberger
and Joseph Donnelly, who continued as directors, and the following new
directors: W. Frank Blount; John A. Cooper, Jr.; Brooke H. Duncan;
Lucie J. Fjeldstad; Kaneaster Hodges, Jr.; Robert v.d. Luft; Adm.
Kinnaird R. McKee; Paul W. Murrill; James R. Nichols; Eugene H. Owen;
John N. Palmer, Sr.; Robert D. Pugh; H. Duke Shackelford; Wm. Clifford
Smith; Bismark A. Steinhagen; and Dr. Walter Washington; (2) approve
the terms and provisions of certain agreements related to such
combination; (3) approve the actions of the officers in connection
with those agreements and the transactions contemplated thereby; (4)
approve the assumption and adoption by Holdings of certain benefit
plans of Entergy Corporation; and (5) approve the taking of actions to
issue stock with respect to such plans, including the listing of
Holdings' common stock on the New York, Pacific, and Midwest Stock
Exchanges and the filing of registration statements with the
Securities and Exchange Commission. After the consummation of the
transactions involved in the combination, the name of Holdings was
changed to Entergy Corporation. On January 22, 1994, Mr. Donnelly
resigned from the position of director of Entergy Corporation.
PART II
Item 5. Market for Registrants' Common Equity and Related
Stockholder Matters
Entergy Corporation. The shares of Entergy Corporation's common
stock are listed on the New York, Midwest, and Pacific Stock
Exchanges.
The high and low prices for each quarterly period in 1993 and
1992, were as follows:
1993 1992
--------------- ----------------
High Low High Low
------ ------ ------ ------
(In Dollars)
First 36 1/2 32 1/2 29 5/8 27 1/8
Second 38 1/4 33 1/4 28 1/2 26 1/8
Third 39 7/8 36 1/4 31 7/8 28 1/4
Fourth 39 1/4 35 1/8 33 5/8 30 1/2
Four consecutive quarterly cash dividends on common stock were
paid to stockholders of Entergy Corporation in each of 1993 and 1992.
In 1993, dividends of 40 cents per share were paid in each of the
first three quarters and dividends of 45 cents per share were paid in
the last quarter. Dividends of 35 cents per share were paid in each
of the first three quarters of 1992, and dividends of 40 cents per
share were paid in the last quarter of 1992.
As of February 24, 1994, there were 63,779 stockholders of record
of Entergy Corporation.
For information with respect to Entergy Corporation's future
ability to pay dividends, refer to Note 7 of Entergy Corporation and
Subsidiaries' Notes to Consolidated Financial Statements, "Dividend
Restrictions," incorporated herein by reference. In addition to the
restrictions described in Note 7, the Holding Company Act provides
that, without approval of the SEC, the unrestricted, undistributed
retained earnings of any Entergy Corporation subsidiary are not
available for distribution to Entergy Corporation's common
stockholders until such earnings are made available to Entergy
Corporation through the declaration of dividends by such subsidiaries.
AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy. There is no
market for the common stock of System Energy and the System operating
companies, all of which is owned by Entergy Corporation. Prior to
December 31, 1993, GSU's common stock was publicly held. Effective
with the Merger, all shares of GSU common stock were acquired by
Entergy Corporation. No cash dividends on common stock were paid by
GSU to its stockholders in 1992-1993. Cash dividends on common stock
paid by AP&L, LP&L, MP&L, NOPSI, and System Energy to Entergy
Corporation during 1993 and 1992, were as follows:
1993 1992
------ ------
(In Millions)
AP&L $156.3 $ 75.0
LP&L 167.6 174.6
MP&L 85.8 68.4
NOPSI 43.9 32.2
System Energy 233.1 137.7
For information with respect to restrictions that limit the
ability of System Energy and the System operating companies to pay
dividends, and for information with respect to dividends paid to
Entergy Corporation by its subsidiaries subsequent to December 31,
1993, refer respectively, to Note 6 of System Energy's and Note 7 of
AP&L's, GSU's, LP&L's, MP&L's, and NOPSI's Notes to Financial
Statements, "Dividend Restrictions," incorporated herein by reference.
Item 6. Selected Financial Data
Entergy Corporation. Refer to information under the heading
"Entergy Corporation and Subsidiaries Selected Financial Data - Five-
Year Comparison," which information is incorporated herein by
reference.
AP&L. Refer to information under the heading "Arkansas Power &
Light Company Selected Financial Data - Five-Year Comparison," which
information is incorporated herein by reference.
GSU. Refer to information under the heading "Gulf States
Utilities Company Selected Financial Data - Five-Year Comparison,"
which information is incorporated herein by reference.
LP&L. Refer to information under the heading "Louisiana Power &
Light Company Selected Financial Data - Five-Year Comparison," which
information is incorporated herein by reference.
MP&L. Refer to information under the heading "Mississippi Power
& Light Company Selected Financial Data - Five-Year Comparison," which
information is incorporated herein by reference.
NOPSI. Refer to information under the heading "New Orleans
Public Service Inc. Selected Financial Data - Five-Year Comparison,"
which information is incorporated herein by reference.
System Energy. Refer to information under the heading "System
Energy Resources, Inc. Selected Financial Data - Five-Year
Comparison," which information is incorporated herein by reference.
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Entergy Corporation. Refer to information under the heading
"ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL
DISCUSSION AND ANALYSIS," which information is incorporated herein by
reference.
AP&L. Refer to information under the heading "ARKANSAS POWER &
LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS," which
information is incorporated herein by reference.
GSU. Refer to information under the heading "GULF STATES
UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS,"
which information is incorporated herein by reference.
LP&L. Refer to information under the heading "LOUISIANA POWER &
LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS," which
information is incorporated herein by reference.
MP&L. Refer to information under the heading "MISSISSIPPI POWER
& LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS," which
information is incorporated herein by reference.
NOPSI. Refer to information under the heading "NEW ORLEANS
PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS,"
which information is incorporated herein by reference.
System Energy. Refer to information under the heading "SYSTEM
ENERGY RESOURCES, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND
ANALYSIS," which information is incorporated herein by reference.
Item 8. Financial Statements and Supplementary Data.
INDEX TO FINANCIAL STATEMENTS
Entergy Corporation and Subsidiaries:
Definitions
Report of Management
Audit Committee Chairman's Letter
Independent Auditors' Report
Consolidated Balance Sheets, December 31, 1993 and 1992
Statements of Consolidated Cash Flows For the Years Ended December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis
Statements of Consolidated Income For the Years Ended December 31, 1993, 1992 and 1991
Statements of Consolidated Retained Earnings and Paid-In Capital for the Years Ended
December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis (continued)
Notes to Consolidated Financial Statements
Selected Financial Data - Five-Year Comparison
AP&L:
Definitions
Report of Management
Audit Committee Chairman's Letter
Independent Auditors' Report
Balance Sheets, December 31, 1993 and 1992
Statements of Cash Flows For the Years Ended December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis
Statements of Income For the Years Ended December 31, 1993, 1992 and 1991
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis (continued)
Notes to Financial Statements
Selected Financial Data - Five-Year Comparison
GSU:
Definitions
Report of Management
Audit Committee Chairman's Letter
Independent Auditors' Report
Balance Sheets, December 31, 1993 and 1992
Statements of Cash Flows For the Years Ended December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis
Statements of Income For the Years Ended December 31, 1993, 1992 and 1991
Statements of Retained Earnings and Paid-In Capital for the Years Ended December 31, 1993, 1992
and 1991
Management's Financial Discussion and Analysis (continued)
Notes to Financial Statements
Selected Financial Data - Five-Year Comparison
LP&L:
Definitions
Report of Management
Audit Committee Chairman's Letter
Independent Auditors' Report
Balance Sheets, December 31, 1993 and 1992
Statements of Cash Flows For the Years Ended December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis
Statements of Income For the Years Ended December 31, 1993, 1992 and 1991
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis (continued)
Notes to Financial Statements
Selected Financial Data - Five-Year Comparison
MP&L:
Definitions
Report of Management
Audit Committee Chairman's Letter
Independent Auditors' Report
Balance Sheets, December 31, 1993 and 1992
Statements of Cash Flows For the Years Ended December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis
Statements of Income For the Years Ended December 31, 1993, 1992 and 1991
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis (continued)
Notes to Financial Statements
Selected Financial Data - Five-Year Comparison
NOPSI:
Definitions
Report of Management
Audit Committee Chairman's Letter
Independent Auditors' Report
Balance Sheets, December 31, 1993 and 1992
Statements of Cash Flows For the Years Ended December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis
Statements of Income For the Years Ended December 31, 1993, 1992 and 1991
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis (continued)
Notes to Financial Statements
Selected Financial Data - Five-Year Comparison
System Energy:
Definitions
Report of Management
Audit Committee Chairman's Letter
Independent Auditors' Report
Balance Sheets, December 31, 1993 and 1992
Statements of Cash Flows For the Years Ended December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis
Statements of Income For the Years Ended December 31, 1993, 1992 and 1991
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991
Management's Financial Discussion and Analysis (continued)
Notes to Financial Statements
Selected Financial Data - Five-Year Comparison
Entergy Corporation and Subsidiaries
1993 Financial Statements
ENTERGY CORPORATION AND SUBSIDIARIES
DEFINITIONS
Certain abbreviations or acronyms used in the Financial Statements, Notes
to Financial Statements, and Management's Financial Discussion and Analysis are
defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During
Construction
ANO Arkansas Nuclear One Steam Electric
Generating Station
ANO 2 Unit No. 2 of ANO
AP&L Arkansas Power & Light Company
APSC Arkansas Public Service Commission
Council Council of the City of New Orleans,
Louisiana
Entergy or System Entergy Corporation and its various direct
and indirect subsidiaries
Entergy Enterprises Entergy Enterprises, Inc. (formerly
Electec, Inc.)
Entergy Operations Entergy Operations, Inc., a subsidiary of
Entergy Corporation that has operating responsibility
for Grand Gulf 1, Waterford 3, ANO, and River Bend
Entergy Power Entergy Power, Inc., a subsidiary of
Entergy Corporation that markets capacity and energy
for resale from certain generating facilities to other
parties, principally non-affiliates
FERC Federal Energy Regulatory Commission
G&R Bonds General and Refunding Mortgage Bonds issued
and issuable by MP&L and NOPSI
Grand Gulf 1 Unit No. 1 of the Grand Gulf Steam Electric
Generating Station
Grand Gulf 2 Unit No. 2 of the Grand Gulf Steam Electric
Generating Station
GSU Gulf States Utilities Company (including
wholly owned subsidiaries - Varibus Corporation, GSG&T,
Inc., Prudential Oil and Gas, Inc., and Southern Gulf
Railway Company)
KWH Kilowatt-Hour(s)
LP&L Louisiana Power & Light Company
LPSC Louisiana Public Service Commission
Merger The combination transaction, consummated on
December 31, 1993, by which GSU became a subsidiary of
Entergy Corporation and Entergy Corporation became a
Delaware corporation
MP&L Mississippi Power & Light Company
MPSC Mississippi Public Service Commission
1991 NOPSI Settlement Agreement, retroactive to October 4, 1991,
among NOPSI, the Council, the Alliance for Affordable
Energy, Inc., and others that settled certain Grand
Gulf 1 prudence issues and pending litigation related
to the resolution (including the Determinations and
Order referred to therein) adopted by the Council on
February 4, 1988, disallowing NOPSI's recovery of $135
million of previously deferred Grand Gulf 1-related
costs
NOPSI New Orleans Public Service Inc.
PUCT Public Utility Commission of Texas
Rate Cap The level of GSU's retail electric base
rates in effect at December 31, 1993, for the Louisiana
retail jurisdiction, and the level in effect prior to
the Texas Cities Rate Settlement for the Texas retail
jurisdiction, that may not be exceeded for the five
years following December 31, 1993
River Bend River Bend Steam Electric Generating
Station (nuclear), owned 70% by GSU
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
promulgated by the Financial Accounting Standards Board
SFAS 106 SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions"
SFAS 109 SFAS No. 109, "Accounting for Income Taxes"
System Agreement Agreement, effective January 1, 1983, as
amended, among the System operating companies relating
to the sharing of generating capacity and other power
resources
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI,
collectively
System or Entergy Entergy Corporation and its various direct
and indirect subsidiaries
Waterford 3 Unit No. 3 of the Waterford Steam Electric
Generating Station
ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENT
The management of Entergy Corporation has prepared and is responsible for
the financial statements and related financial information included herein. The
financial statements are based on generally accepted accounting principles.
Financial information included elsewhere in this report is consistent with the
financial statements.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting controls that
is designed to provide reasonable assurance, on a cost-effective basis, as to
the integrity, objectivity, and reliability of the financial records, and as to
the protection of assets. This system includes communication through written
policies and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and the
training of personnel. This system is also tested by a comprehensive internal
audit program.
The independent public accountants provide an objective assessment of the
degree to which management meets its responsibility for fairness of financial
reporting. They regularly evaluate the system of internal accounting controls
and perform such tests and other procedures as they deem necessary to reach and
express an opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide reasonable
assurance that its operations are carried out with a high standard of business
conduct.
/S/ EDWIN LUPBERGER /S/ GERALD D. MCINVALE
EDWIN LUPBERGER GERALD D. MCINVALE
Chairman and Chief Executive Officer Senior Vice President and
Chief Financial Officer
ENTERGY CORPORATION AND SUBSIDIARIES
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Entergy Corporation Board of Directors' Audit Committee is comprised of
five directors, who are not officers of Entergy Corporation: H. Duke Shackelford
(Chairman), Brooke H. Duncan, Kaneaster Hodges, Jr., John N. Palmer, Sr., and
Bismark A. Steinhagen (as of December 31, 1993). The committee held four
meetings during 1993.
The Audit Committee oversees Entergy Corporation's financial reporting
process on behalf of Entergy Corporation's Board of Directors. In fulfilling
its responsibility, the committee recommended to the board, subject to
stockholder approval, the selection of Entergy Corporation's independent public
accountants (Deloitte & Touche). Also, the committee oversees and coordinates
the activities and policies of the subsidiary companies' audit committees.
The Audit Committee discussed with Entergy's internal auditors and the
independent public accountants the overall scope and specific plans for their
respective audits, as well as Entergy Corporation's consolidated financial
statements and the adequacy of Entergy Corporation's internal controls. The
committee met, together and separately, with Entergy's internal auditors and
independent public accountants, without management present, to discuss the
results of their audits, their evaluation of Entergy Corporation's internal
controls, and the overall quality of Entergy Corporation's financial reporting.
The meetings also were designed to facilitate and encourage any private
communication between the committee and the internal auditors or independent
public accountants.
/S/ H. DUKE SHACKELFORD
H. DUKE SHACKELFORD
Chairman, Audit Committee
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of
Entergy Corporation
We have audited the accompanying consolidated balance sheets of Entergy
Corporation and subsidiaries as of December 31, 1993 and 1992, and the related
statements of consolidated income, retained earnings and paid-in capital, and
cash flows for each of the three years in the period ended December 31, 1993.
These financial statements are the responsibility of the Corporation's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. We did not audit the financial statements of
Gulf States Utilities Company (a consolidated subsidiary acquired on December
31, 1993), which statements reflect total assets constituting 31% of
consolidated total assets at December 31, 1993. Those statements were audited
by other auditors whose report (which included explanatory paragraphs regarding
the uncertainties discussed in the fourth and fifth paragraphs below) has been
furnished to us, and our opinion, insofar as it relates to the amounts included
for Gulf States Utilities Company, is based solely on the report of such other
auditors.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits and the report of the other auditors provide a
reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors,
such consolidated financial statements present fairly, in all material respects,
the financial position of Entergy Corporation and subsidiaries at December 31,
1993 and 1992, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1993 in conformity with
generally accepted accounting principles.
The Corporation acquired a 70% interest in River Bend Unit I Nuclear
Generating Plant (River Bend) through its acquisition of Gulf States Utilities
Company on December 31, 1993. As discussed in Note 2 to the consolidated
financial statements, the net amount of capitalized costs for River Bend exceed
those costs currently being recovered through rates. At December 31, 1993,
approximately $747 million is not currently being recovered through rates. If
current regulatory and court orders are not modified, a write-off of all or a
portion of such costs may be required. Additionally, as discussed in Note 2 to
the consolidated financial statements, other rate-related contingencies exist
which may result in a refund of revenues previously collected. The extent of
such write-off of capitalized River Bend costs or refund of revenues previously
collected, if any, will not be determined until appropriate rate proceedings and
court appeals have been concluded. Accordingly, the accompanying consolidated
financial statements do not include any adjustments that might result from the
outcome of these uncertainties.
As discussed in Note 8 to the consolidated financial statements, civil
actions have been initiated against Gulf States Utilities Company to, among
other things, recover the co-owner's investment in River Bend and to annul the
related joint ownership participation and operating agreement. The ultimate
outcome of these proceedings, including their impact on Gulf States Utilities
Company, cannot presently be determined. Accordingly, the accompanying
consolidated financial statements do not include any adjustments that might
result from the outcome of this uncertainty.
As discussed in Note 1 to the consolidated financial statements, certain of
the Corporation's subsidiaries changed their method of accounting for revenues
in 1993 and, as discussed in Notes 3 and 10 to the consolidated financial
statements, in 1993 the Corporation changed its methods of accounting for income
taxes and postretirement benefits other than pensions, respectively.
/S/ DELOITTE & TOUCHE
DELOITTE & TOUCHE
New Orleans, Louisiana
February 11, 1994
ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
-----------------------------
1993 1992
----------- -----------
(In Thousands)
Utility Plant (Note 1):
Electric $20,848,844 $13,765,029
Plant acquisition adjustment - GSU (Note 11) 380,117 -
Electric plant under leases (Note 9) 663,024 662,400
Property under capital leases - electric 175,276 100,945
Natural gas 156,452 110,399
Steam products 75,689 -
Construction work in progress 533,112 309,552
Nuclear fuel under capital leases (Note 9) 329,433 233,616
Nuclear fuel 17,760 20,683
----------- -----------
Total 23,179,707 15,202,624
Less - accumulated depreciation and amortization 7,157,981 4,462,693
----------- -----------
Utility plant - net 16,021,726 10,739,931
----------- -----------
Other Property and Investments:
Decommissioning trust funds 172,960 127,323
Other 183,597 76,558
----------- -----------
Total 356,557 203,881
----------- -----------
Current Assets:
Cash and cash equivalents (Note 1):
Cash 27,345 6,975
Temporary cash investments - at cost, which
approximates market 536,404 372,817
----------- -----------
Total cash and cash equivalents 563,749 379,792
Other temporary investments - at cost, which
approximates market - 17,012
Special deposits 36,612 18,739
Notes receivable 17,710 19,778
Accounts receivable:
Customer (less allowance for doubtful accounts of
$8.8 million in 1993 and $6.2 million in 1992) 315,796 194,980
Other 81,931 43,006
Accrued unbilled revenues (Note 1) 257,321 57,716
Fuel inventory - at average cost and LIFO 110,204 85,595
Materials and supplies - at average cost 360,353 287,407
Rate deferrals (Note 2) 333,311 186,391
Prepayments and other 98,144 74,168
----------- -----------
Total 2,175,131 1,364,584
----------- -----------
Deferred Debits and Other Assets:
Rate deferrals (Note 2) 1,876,051 1,485,598
SFAS 109 regulatory asset - net (Note 3) 1,385,824 -
Long-term receivables 228,030 15,739
Unamortized loss on reacquired debt 210,698 91,825
Other 622,680 337,979
----------- -----------
Total 4,323,283 1,931,141
----------- -----------
TOTAL $22,876,697 $14,239,537
=========== ===========
See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
----------------------------
1993 1992
---------- -----------
(In Thousands)
Capitalization:
Common stock, $.01 par value in 1993 and $5 par value
in 1992: authorized 500,000,000 shares; issued and
outstanding 231,219,737 shares in 1993; issued
175,137,392 shares in 1992 (Note 5) $2,312 $875,687
Paid-in capital 4,223,682 1,327,589
Retained earnings (Note 7) 2,310,082 2,062,188
Less - treasury stock (1,943 shares in 1992) (Note 5) - 54
----------- -----------
Total common shareholders' equity 6,536,076 4,265,410
Subsidiary's preference stock (Note 5) 150,000 -
Subsidiaries' preferred stock (Note 5):
Without sinking fund 550,955 414,511
With sinking fund 349,053 304,049
Long-term debt (Notes 6 and 9) 7,355,962 5,149,344
----------- -----------
Total 14,942,046 10,133,314
----------- -----------
Other Noncurrent Liabilities:
Obligations under capital leases (Note 9) 322,867 177,112
Other (Note 8) 270,318 140,292
----------- -----------
Total 593,185 317,404
----------- -----------
Current Liabilities:
Currently maturing long-term debt (Note 6) 322,010 133,805
Notes payable (Note 4) 43,667 667
Accounts payable 413,727 313,054
Customer deposits 127,524 100,496
Taxes accrued 118,267 128,172
Accumulated deferred income taxes (Note 3) 44,637 43,265
Interest accrued 210,894 152,136
Dividends declared 13,404 15,172
Gas contract settlements - liability to customers - 55,998
Deferred revenue - gas supplier judgment proceeds 14,632 42,256
Deferred fuel cost 4,528 16,128
Obligations under capital leases (Note 9) 194,015 157,448
Other 240,471 90,149
----------- -----------
Total 1,747,776 1,248,746
----------- -----------
Deferred Credits:
Accumulated deferred income taxes (Note 3) 3,858,337 1,612,947
Accumulated deferred investment tax credits (Note 3) 793,375 553,506
Deferred revenue - gas supplier judgment proceeds - 14,846
Other 941,978 358,774
----------- -----------
Total 5,593,690 2,540,073
----------- -----------
Commitments and Contingencies (Notes 2, 8, and 9)
TOTAL $22,876,697 $14,239,537
=========== ===========
See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
For the Years Ended December 31,
--------------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Operating Activities:
Net income $551,930 $437,637 $482,032
Noncash items included in net income:
Cumulative effect of a change in accounting
principle (93,841) - -
Change in rate deferrals/excess capacity - net 200,532 109,153 (7,342)
Depreciation and decommissioning 443,550 424,958 398,864
Deferred income taxes and investment tax credits 17,669 118,562 194,830
Allowance for equity funds used during
construction (8,049) (7,355) (7,921)
Amortization of deferred revenues (42,470) (38,646) (36,310)
Provision for estimated losses and reserves 20,832 (24,911) 21,576
Gain on sale of property - net - (19,612) -
Changes in working capital:
Receivables (40,682) (19,150) 5,655
Fuel inventory (1,161) 20,008 (37,917)
Accounts payable (9,167) (54,559) 1,302
Taxes accrued (32,761) 28,561 41,085
Interest accrued (758) (10,845) (19,830)
Other working capital accounts 51,100 (12,428) 18,821
Refunds to customers - gas contract settlement (56,027) (56,066) (56,098)
Decommissioning trust contributions (20,402) (20,896) (23,193)
Other 94,092 (43,185) (13,619)
---------- -------- --------
Net cash flow provided by operating activities 1,074,387 831,226 961,935
---------- -------- --------
Investing Activities:
Merger with GSU - cash paid (250,000) - -
Merger with GSU - cash acquired 261,349 - -
Construction/capital expenditures (512,235) (438,845) (439,087)
Allowance for equity funds used during construction 8,049 7,355 7,921
Proceeds received from sale of property - 67,985 -
Nuclear fuel purchases (118,216) (60,359) (66,068)
Proceeds from sale/leaseback of nuclear fuel 121,526 62,332 47,452
Investment in nonregulated/nonutility properties (76,870) (35,189) (10,878)
Decrease in other temporary investments 17,012 114,651 150,580
---------- -------- --------
Net cash flow used in investing activities (549,385) (282,070) (310,080)
---------- -------- --------
Financing Activities:
Proceeds from the issuance of:
First mortgage bonds 605,000 637,114 -
General and refunding mortgage bonds 350,000 65,000 -
Preferred stock - 120,999 133,175
Bank notes and other long-term debt 106,070 48,067 68,514
Retirement of:
First mortgage bonds (911,692) (1,009,320) (665,384)
General and refunding mortgage bonds (99,400) - -
Bank notes and other long-term debt (69,982) (17,412) (7,442)
Common stock (20,558) (105,673) (161,640)
Redemption of preferred stock (56,000) (109,369) (85,500)
Common stock dividends paid (287,483) (256,117) (228,816)
Changes in short-term borrowings 43,000 - -
---------- -------- --------
Net cash flow used in financing activities (341,045) (626,711) (947,093)
---------- -------- --------
Net increase (decrease) in cash and cash equivalents 183,957 (77,555) (295,238)
Cash and cash equivalents at beginning of period 379,792 457,347 752,585
---------- -------- --------
Cash and cash equivalents at end of period $563,749 $379,792 $457,347
========== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $485,876 $570,199 $646,872
Income taxes $159,659 $125,079 $68,278
Noncash investing and financing activities:
Capital lease obligations incurred $126,812 $75,040 $46,073
Merger with GSU - common stock issued $2,031,101 - -
See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is important to Entergy due to the capital intensive nature of
our business, which requires large investments in long-lived assets. However,
large capital expenditures for the construction of new generating capacity are
not currently planned. The System requires significant capital resources for
the periodic maturity of certain series of debt and preferred stock. Net cash
flow from operations totaled $1,074 million, $831 million, and $962 million in
1993, 1992, and 1991, respectively. In recent years, this cash flow,
supplemented by cash on hand, has been sufficient to meet substantially all
investing and financing requirements, including capital expenditures, dividends,
and debt/preferred stock maturities. Entergy's ability to fund these capital
requirements with cash from operations results, in part, from our continued
efforts to streamline operations and reduce costs as well as collections under
our Grand Gulf 1 rate phase-in plans, which exceed the current cash requirements
for Grand Gulf 1-related costs. (In the income statement, these revenue
collections are offset by the amortization of previously deferred costs,
therefore, there is no effect on net income.) Further, Entergy Corporation's
subsidiaries have the ability to meet future capital requirements through future
debt or preferred stock issuances, as discussed below. See Note 8, incorporated
herein by reference, for additional information on the System's capital and
refinancing requirements in 1994 - 1996. Also, in order to take advantage of
lower interest and dividend rates, Entergy Corporation's subsidiaries may
continue to refinance high-cost debt and preferred stock prior to maturity.
Productive investment of excess funds is necessary to enhance the long-term
value of our common stock. In 1993, Entergy Corporation made approximately $77
million in investments in an electric distribution company and a high-voltage
transmission system in Argentina. In 1992, Entergy Corporation invested $11
million in a generating facility in Argentina, $12.5 million in an independent
power plant in Virginia, $5.5 million in a lighting efficiency services company,
and $6.2 million in a company that develops energy management and other
technology applications. Entergy Corporation expects to invest approximately
$150 million per year in nonregulated and nonutility businesses. See
"Significant Factors and Known Trends - Nonregulated Investments" for additional
information.
Certain agreements and restrictions limit the amount of mortgage bonds and
preferred stock that can be issued by the System operating companies and System
Energy. Based on the most restrictive applicable tests as of December 31, 1993
(which in certain instances, are impacted by the inclusion of the cumulative
effect of the change in accounting principle for accruing unbilled revenues
discussed in Note 1), and an assumed annual interest or dividend rate of 8%, the
System operating companies could have issued bonds or preferred stock in the
following amounts, respectively: AP&L - $226 million and $1,075 million; GSU -
$425 million and $0 million; LP&L - $92 million and $686 million; MP&L -
$219 million and $548 million; and NOPSI - $40 million and $306 million. System
Energy could also have issued $290 million of bonds, but its charter does not
presently provide for the issuance of preferred stock. In addition, the System
operating companies and System Energy have the conditional ability to issue
bonds against the retirement of bonds, in some cases without meeting an earnings
coverage test. AP&L may also issue preferred stock to refund outstanding
preferred stock without meeting an earnings coverage test. GSU has no
limitations on the issuance of preference stock. See Note 4, incorporated
herein by reference, for information on the System's short-term borrowings.
Entergy Corporation's current primary capital requirements are to
periodically invest in, or make loans to, its subsidiaries. Entergy Corporation
expects to meet these requirements in 1994 - 1996 with internally generated
funds and cash on hand. Further, Entergy Corporation paid $287.5 million of
dividends on its common stock in 1993. Entergy Corporation receives funds
through dividend payments from its subsidiaries. During 1993, these common
stock dividend payments totaled $686.7 million. Certain restrictions may limit
the amount of these distributions. See Note 7, incorporated herein by
reference, for additional information. See Notes 2 and 8, incorporated herein
by reference, regarding River Bend rate appeals and pending litigation with
Cajun Electric Power Cooperative, Inc. (Cajun). Substantial write-offs or
charges resulting from adverse rulings in these matters could adversely affect
GSU's ability to continue to pay dividends.
Entergy Corporation has SEC authorization to repurchase shares of its
outstanding common stock. Market conditions and board authorization determine
the amount of repurchases. Entergy Corporation has requested SEC authorization
for a $300 million bank line of credit, the proceeds of which are expected to be
used for common stock repurchases and other optional activities. See Notes 4
and 5, incorporated herein by reference, for additional information.
ENTERGY CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
For the Years Ended December 31,
-----------------------------------------
1993 1992 1991
---------- ---------- ----------
(In Thousands, Except Share Data)
Operating Revenues:
Electric $4,394,346 $4,043,555 $3,974,478
Natural gas 90,991 72,944 76,951
---------- ---------- ----------
Total 4,485,337 4,116,499 4,051,429
---------- ---------- ----------
Operating Expenses:
Operation:
Fuel for electric generation and fuel-related expenses 859,641 759,470 735,986
Purchased power 278,070 228,679 205,131
Gas purchased for resale 52,592 43,212 49,986
Other 813,555 806,943 823,817
Maintenance 306,666 301,836 282,821
Depreciation and decommissioning 443,550 424,958 398,864
Taxes other than income taxes 199,151 197,895 184,247
Income taxes (Note 3) 251,163 210,081 243,760
Rate deferrals (Note 2):
Rate deferrals (1,651) (24,176) (56,681)
Amortization of rate deferrals 289,259 209,015 206,468
Deferral of previously incurred Grand Gulf 1-related
costs - - (90,000)
---------- ---------- ----------
Total 3,491,996 3,157,913 2,984,399
---------- ---------- ----------
Operating Income 993,341 958,586 1,067,030
---------- ---------- ----------
Other Income:
Allowance for equity funds used during construction 8,049 7,355 7,921
Miscellaneous - net 60,068 135,475 122,697
Income taxes (Note 3) (33,640) (46,382) (33,391)
---------- ---------- ----------
Total 34,477 96,448 97,227
---------- ---------- ----------
Interest and Other Charges:
Interest on long-term debt 488,799 529,668 599,797
Other interest - net 29,849 29,686 27,245
Allowance for borrowed funds used during construction (5,478) (5,094) (7,392)
Preferred dividend requirements of subsidiaries 56,559 63,137 62,575
---------- ---------- ----------
Total 569,729 617,397 682,225
---------- ---------- ----------
Income before Cumulative Effect of a Change in
Accounting Principle 458,089 437,637 482,032
Cumulative Effect to January 1, 1993, of Accruing Unbilled
Revenues (net of income taxes of $57,188) (Note 1) 93,841 - -
---------- ---------- ----------
Net Income $551,930 $437,637 $482,032
========== ========== ==========
Earnings per average common share before cumulative
effect of a change in accounting principle $2.62 $2.48 $2.64
Earnings per average common share $3.16 $2.48 $2.64
Dividends declared per common share (Note 7) $1.65 $1.45 $1.25
Average number of common shares outstanding (Note 5) 174,887,556 176,573,778 182,665,303
See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED RETAINED EARNINGS AND PAID-IN CAPITAL
For the Years Ended December 31,
--------------------------------------
1993 1992 1991
---------- ---------- ----------
(In Thousands)
Retained Earnings, January 1 $2,062,188 $1,943,298 $1,775,000
Add - Net income 551,930 437,637 482,032
---------- ---------- ----------
Total 2,614,118 2,380,935 2,257,032
---------- ---------- ----------
Deduct:
Dividends declared on common stock 288,342 255,479 228,555
Common stock retirements (Note 5) 13,906 59,187 80,009
Capital stock and other expenses 1,788 4,081 5,170
---------- ---------- ----------
Total 304,036 318,747 313,734
---------- ---------- ----------
Retained Earnings, December 31 (Note 7) $2,310,082 $2,062,188 $1,943,298
========== ========== ==========
Paid-in Capital, January 1 $1,327,589 $1,357,883 $1,408,640
Add:
Gain (loss) on reacquisition of
subsidiaries' preferred stock (20) (1,323) 35
Issuance of 56,667,726 shares of common
stock in the merger with GSU (Note 11) 2,027,325 - -
Issuance of 174,552,011 shares of common
stock at $.01 par value net of the
retirement of 174,552,011 shares of
common stock at $5.00 par value (Note 5) 871,015 - -
---------- ---------- ----------
Total 4,225,909 1,356,560 1,408,675
---------- ---------- ----------
Deduct:
Common stock retirements (Note 5) 4,389 28,127 49,391
Capital stock discounts and other expenses (2,162) 844 1,401
---------- ---------- ----------
Total 2,227 28,971 50,792
---------- ---------- ----------
Paid-in Capital, December 31 $4,223,682 $1,327,589 $1,357,883
========== ========== ==========
See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Consolidated net income increased in 1993 due primarily to the one-time
recording of the cumulative effect of the change in accounting principle for
unbilled revenues (see Note 1, incorporated herein by reference) and its ongoing
effects. Effective January 1, 1993, AP&L, MP&L, and NOPSI began accruing as
revenues the charges for energy delivered to customers but not yet billed.
Electric and gas revenues were previously recorded on a cycle-billing basis.
This increase was partially offset by the effects of implementing SFAS 109 and
SFAS 106 (see Notes 3 and 10, respectively, incorporated herein by reference),
and the impact in March 1992 of an after-tax gain from the sale of AP&L's
Missouri properties. Excluding these items, net income for 1993 would have been
$475.9 million and net income for 1992 would have been $418.0 million. This
$57.9 million increase is due to increased retail energy sales, improved gas
revenues, and decreased interest expense, partially offset by decreased
miscellaneous income and by the impact of an August 1993 rate settlement
involving System Energy's return on equity (see Note 2, incorporated herein by
reference).
Consolidated net income decreased in 1992 due primarily to reduced retail
energy sales resulting from mild summer and winter temperatures. This decrease
was partially offset by lower nonfuel operation and maintenance expenses
(excluding nuclear refueling outage expenses of $87.9 million in 1992 and $61.8
million in 1991) and lower interest expense. In addition, 1992 net income
includes $19.6 million from the gain on the sale of AP&L's retail properties in
Missouri.
Significant factors affecting the results of operations and causing
variances between the years 1993 and 1992, and 1992 and 1991, are discussed
under "Revenues and Sales," "Expenses," and "Other" below.
Revenues and Sales
See "Selected Financial Data - Five-Year Comparison," incorporated herein
by reference, following the notes, for information on electric operating
revenues by source and KWH sales.
Electric operating revenues were higher in 1993 due primarily to increased
residential and commercial energy sales resulting from a return to more normal
weather as compared to milder weather in 1992, increased industrial sales
primarily in the petrochemical, lumber, and plywood industries, and increased
fuel adjustment revenues and collections of previously deferred Grand Gulf 1-
related costs, neither of which affects net income. These increases were
partially offset by the impact of a System Energy rate settlement.
Electric operating revenues were higher in 1992 due primarily to an
increase in fuel adjustment revenues and collections of previously deferred
Grand Gulf 1 costs, neither of which affects net income. The increase in fuel
adjustment revenues was due to increased gas generation resulting from scheduled
nuclear refueling outages. Partially offsetting these higher revenues were
decreased retail sales resulting from mild temperatures.
Gas operating revenues increased in 1993 due primarily to an increase in
gas rates and increased fuel adjustment revenues resulting from higher average
per unit cost for gas purchased for resale.
Expenses
Fuel for electric generation and fuel-related expenses increased in 1993
due primarily to an increase in generation requirements resulting from increased
energy sales as discussed in "Revenues and Sales" above and higher per unit
costs for gas used for generation. Purchased power increased in 1993 due
primarily to increased power purchased from nonassociated utilities due to
changes in generation requirements for AP&L, LP&L, MP&L, and NOPSI, resulting
primarily from changes in fuel-related costs and increased energy sales. Fuel
expense and purchased power increased in 1992 as a result of the nuclear
refueling outages. In addition to the increased fossil generation discussed in
"Revenues and Sales" above, additional power was purchased from outside
utilities in 1992. Gas purchased for resale increased in 1993 due to a higher
average per unit cost for gas purchased while it declined in 1992 due primarily
to a lower average per unit cost.
Rate deferrals decreased in 1993 and 1992 due to the fact that as of
October 1992, Grand Gulf 1-related costs are no longer being deferred. The
amortization of rate deferrals increased in 1993 due primarily to the collection
of more Grand Gulf 1-related costs from customers in 1993 as compared to 1992.
Total income taxes increased in 1993 due primarily to higher pretax income,
an increase in the federal income tax rate as a result of the Omnibus Budget
Reconciliation Act of 1993, and the implementation of SFAS 109, partially
offset by the impact of the March 1992 sale of AP&L's Missouri properties.
Other
Miscellaneous other income - net decreased in 1993 and increased in 1992
due primarily to the 1992 pretax gain of approximately $33.7 million from the
sale of AP&L's retail properties in Missouri. Additionally, decreased interest
income contributed to the 1993 decrease. Interest on long-term debt decreased
in 1993 and 1992 due primarily to the continued refinancing of high-cost debt
and debt reduction activities.
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Entergy Corporation-GSU Merger
On December 31, 1993, Entergy completed the Merger and became one of the
nation's largest electric utilities. With GSU as its fifth retail operating
company, Entergy gains size, expanded market area, economies of scale, an
additional nuclear unit (River Bend), and a more price-competitive fuel mix.
Entergy estimates $850 million in fuel cost savings and $670 million in
operation and maintenance expense savings over the next decade. It is possible
that common shareholders may experience some dilution in earnings in the short
term as a result of the Merger. However, Entergy Corporation believes that the
Merger will be beneficial to common shareholders over the longer term, both in
terms of the strategic benefits and the economies and efficiencies expected to
be produced. For further information, see Notes 2 and 11, incorporated herein
by reference.
Competition
Entergy welcomes competition in the electric energy business and believes
that a more competitive environment should benefit our shareholders, customers,
and employees. We also recognize that competition presents us with many
challenges, and we have identified the following as our major competitive
challenges.
Retail and Wholesale Rate Issues
Increasing competition in the utility industry brings an increased need to
stabilize or reduce retail rates. The retail regulatory environment is shifting
from traditional rate-base regulation to incentive rate regulation. Incentive
rate and performance-based plans encourage efficiencies and productivity while
permitting utilities to share in the results. The MPSC has approved a formula
rate plan for MP&L, and GSU is implementing shared-savings plans as part of the
Merger.
In February 1994, the MPSC conducted a general review of MP&L's current
rates and in March 1994, the MPSC issued a final order adopting a formula rate
plan for MP&L that will allow for periodic small adjustments in rates based on a
comparison of earned to benchmark returns and upon certain performance factors.
The order also adopted previously agreed-upon stipulations of 1) a required
return on equity of 11% and 2) certain accounting adjustments that result in a
4.3% ($28.1 million) reduction in MP&L's June 30, 1993, test-year operating
revenues. The MPSC's order requires MP&L to file rates designed to provide for
this reduction in operating revenues for the test year on or before March 18,
1994, to become effective for service rendered on or after March 25, 1994. See
Note 2, incorporated herein by reference, for further information.
In connection with the Merger, AP&L and MP&L agreed with their respective
regulators not to request any general retail rate increases that would take
effect before November 1998, with certain exceptions. NOPSI agreed with the
Council to reduce its annual electric base rates by $4.8 million effective for
bills rendered on or after November 1, 1993, and is operating under electric and
gas base rate freezes through October 31, 1996. GSU agreed with the LPSC and
PUCT to a five-year Rate Cap on retail electric rates, and to pass through to
retail customers the fuel savings and a certain percentage of the nonfuel
savings created by the Merger. See Note 2, incorporated herein by reference,
for further information on Merger-related agreements.
GSU's base rates will be reviewed by the LPSC during the first post-Merger
earnings analysis, scheduled for mid-1994, for reasonableness of its return on
equity. The PUCT will also review GSU's base rates in accordance with its
Merger approval plan in mid-1994. Further, LP&L is scheduled for a review of
its rates and rate structure by the LPSC upon expiration of LP&L's current rate
freeze in March 1994. Under the same LPSC order, an approximate $46 million per
year increase in LP&L's retail rates will also expire in March 1994. See Note
2, incorporated herein by reference, for additional information.
Retail wheeling, a major industry issue which may require utilities to
"wheel" or move power from third parties to their own retail customers, is
evolving gradually. As a result, the retail market could become more
competitive. In the wholesale rate area, FERC approved in 1992, with certain
modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power to
sell wholesale power at market-based rates and to provide to electric utilities
"open access" to the System's transmission system (subject to certain
requirements). GSU was later added to this filing. Various intervenors in the
proceeding filed petitions for review with the United States Court of Appeals
for the District of Columbia Circuit. FERC's order, once it takes effect, will
increase marketing opportunities for the System, but will also expose the System
to the risk of loss of load or reduced revenues due to competition with
alternative suppliers.
In light of the rate issues discussed above, Entergy is aggressively
reducing costs to avoid potential earnings erosions that might result as well as
to successfully compete by becoming a low-cost producer. To help minimize
future costs, Entergy remains committed to least cost planning. In December
1992, AP&L, LP&L, MP&L, and NOPSI each filed a Least Cost Integrated Resource
Plan (Least Cost Plan) with their respective retail regulators, and GSU is
currently working with the PUCT regarding integrated resource planning.
Integrated resource or least cost planning includes demand-side measures such as
customer energy conservation and supply-side measures such as more efficient
power plants. These measures are designed to delay the building of new power
plants for the next 20 years. The System operating companies plan to
periodically file Least Cost Plans.
The Energy Policy Act of 1992
The Energy Policy Act of 1992 (Energy Act) is changing the transmission and
distribution of electricity. This act encourages competition and affords us the
opportunities, and the risks, associated with an open and more competitive
market environment. The Energy Act increases competition in the wholesale
energy market through the creation of exempt wholesale generators (EWGs). We
are competing in this market through our independent power subsidiary, Entergy
Power Development Corporation. The Energy Act also gives FERC the authority to
order investor-owned utilities to provide transmission access to or for other
utilities, including EWGs. In addition, the Energy Act allows utilities to own
and operate foreign generation, transmission, and distribution facilities. See
"Nonregulated Investments" below for further information.
Litigation and Regulatory Proceedings
See Note 2, incorporated herein by reference, for information on the
possibility of material adverse effects on GSU's financial condition as a result
of substantial write-offs and/or refunds in connection with outstanding appeals
and remands regarding approximately $1.4 billion of abeyed company-wide River
Bend plant costs and approximately $187 million of Texas retail jurisdiction
deferred River Bend operating and carrying costs. See Note 2, incorporated
herein by reference, for information with respect to possible write-offs and
refunds by System Energy which may result from a decision issued by FERC.
See Note 8, incorporated herein by reference, for information on pending
litigation with Cajun concerning Cajun's ownership interest in River Bend and
the possible material adverse effects on GSU's financial condition in the event
that GSU is ultimately unsuccessful in this litigation.
Nonregulated Investments
Entergy continues to seek new opportunities to expand its electric energy
business, including expansion into related nonutility businesses. These
opportunities include new domestic ventures such as our subsidiary, Entergy
Systems and Service, Inc. (Entergy SASI), the region's only full-service
provider of energy-efficient lighting and related services; established ventures
in Argentina; and planned investments in South America and China. These
nonregulated businesses reduced consolidated net income by approximately $24
million in 1993. Entergy Corporation expects to invest approximately $150
million per year in nonregulated business opportunities. Entergy may finance
any such expansion with cash on hand. Further, shareholder and/or regulatory
approvals may be required for such acquisitions to take place. For information
on Entergy Corporation's investments in Argentina, see "Management's Financial
Discussion and Analysis - Liquidity and Capital Resources," incorporated herein
by reference.
ANO Matters
Leaks in certain steam generator tubes at ANO 2 were discovered and
repaired during outages in March and September 1992. During a mid-cycle outage
in May 1993, a scheduled special inspection of certain steam generator tubing
was conducted by Entergy Operations and additional repairs were made. The
operations and power output of ANO 2 have not been adversely affected by these
repairs and AP&L's budgeted maintenance expenditures were adequate to cover the
cost of such repairs. Entergy Operations is taking steps at ANO 2 to reduce the
number and severity of future tube cracks. Entergy Operations met with the
Nuclear Regulatory Commission (NRC) in August 1993 to discuss such steps along
with recent inspection findings and intervals between future inspections. The
NRC concurred with Entergy Operations' proposal to operate ANO 2 with no further
steam generator inspections until the next refueling outage, which is scheduled
for the spring of 1994.
ENTERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying consolidated financial statements include the accounts of
Entergy Corporation and its direct and indirect subsidiaries: AP&L, GSU, LP&L,
MP&L, NOPSI, System Energy, Entergy Operations, Entergy Power, Entergy Power
Development Corporation, Entergy Richmond Power Corporation, Entergy Services,
Inc., System Fuels, Entergy Enterprises, Entergy SASI, Entergy S.A., Entergy
Argentina S.A., and Entergy Transener S.A. Because the acquisition of GSU was
consummated on December 31, 1993, under the purchase method of accounting, GSU
is included only in the December 31, 1993, consolidated balance sheet amounts.
All references made to Entergy or System as of, and subsequent to, the Merger
closing date include amounts and information pertaining to GSU as an Entergy
company. All significant intercompany transactions have been eliminated.
Entergy Corporation's utility subsidiaries maintain accounts in accordance with
FERC and other regulatory guidelines. Certain previously reported amounts have
been reclassified to conform to current classifications.
Revenues and Fuel Costs
The System operating companies accrue estimated revenues for energy
delivered since the latest billings. However, prior to January 1, 1993, AP&L,
GSU, MP&L, and NOPSI recognized electric and gas revenues when billed. To
provide a better matching of revenues and expenses, effective January 1, 1993,
AP&L, GSU, MP&L, and NOPSI adopted a change in accounting principle to provide
for accrual of estimated unbilled revenues. The cumulative effect of this
accounting change as of January 1, 1993 (excluding GSU), increased net income by
$93.8 million, or $0.54 per share. Had this new accounting method been in
effect during prior years, net income before the cumulative effect would not
have been materially different from that shown in the accompanying financial
statements. In accordance with an LPSC rate order, GSU recorded a deferred
credit for $16.6 million for the January 1, 1993, amount of unbilled revenues.
The System operating companies' rate schedules (except GSU's Texas rate
schedules) include fuel adjustment clauses that allow either current recovery or
deferrals of fuel costs until such costs are reflected in the related revenues.
GSU's Texas retail rate schedules include a fixed fuel factor approved by the
PUCT, which remains the same until changed as part of a general rate case or
fuel reconciliation, or until the PUCT orders a reconciliation for any over or
under collections of fuel cost.
Utility Plant
Utility plant is stated at original cost. The original cost of utility
plant retired or removed, plus the applicable removal costs, less salvage, is
charged to accumulated depreciation. Maintenance, repairs, and minor
replacement costs are charged to operating expenses. Substantially all of the
utility plant is subject to liens of the subsidiaries' mortgage bond indentures.
AFUDC represents the approximate net composite interest cost of borrowed
funds and a reasonable return on the equity funds used for construction.
Although AFUDC increases utility plant and increases earnings, it is only
realized in cash through depreciation provisions included in rates. The System
operating companies' effective composite rates for AFUDC were 10.6% for 1993 and
10.8% for 1992 and 1991.
Utility plant includes the portions of Grand Gulf 1 and Waterford 3 that
were sold and are currently under lease. For financial reporting purposes,
these sale and leaseback transactions are reflected as financing transactions.
Depreciation is computed on the straight-line basis at rates based on the
estimated service lives and costs of removal of the various classes of property.
Depreciation provisions on average depreciable property approximated 3.0% in
1993, 1992, and 1991.
Jointly-Owned Generating Stations
Certain Entergy Corporation subsidiaries own undivided interests in several
jointly-owned electric generating facilities and record the investments and
expenses associated with these stations to the extent of their respective
ownership percentages. As of December 31, 1993, the System's investment and
accumulated depreciation in each of these generating stations were as follows:
Total
Megawatt Accumulated
Generating Stations Fuel Type Capability Ownership Investment Depreciation
------------------- --------- ---------- --------- ---------- ------------
(In Thousands)
Grand Gulf Nuclear 1,143 90.00%* $3,449,068 $669,666
River Bend Unit 1 Nuclear 931 70.00% $3,056,464 $545,740
Independence Units 1 and 2 Coal 1,680 56.50% $ 543,659 $156,645
White Bluff Units 1 and 2 Coal 1,660 57.00% $ 398,644 $140,731
Roy S. Nelson Unit 6 Coal 550 70.00% $ 389,915 $134,877
Big Cajun 2 Unit 3 Coal 540 42.00% $ 219,911 $ 68,150
* Includes System Energy's ownership and leasehold interests in Grand Gulf 1
Income Taxes
Entergy Corporation and its subsidiaries file a consolidated federal income
tax return (excluding GSU prior to 1994). Income taxes are allocated to the
System companies in proportion to their contribution to consolidated taxable
income. SEC regulations require that no System company pay more taxes than it
would have had a separate income tax return been filed. Deferred taxes are
recorded for all temporary differences between book and taxable income.
Investment tax credits are deferred and amortized based upon the average useful
life of the related property in accordance with rate treatment. As discussed in
Note 3, effective January 1, 1993, Entergy changed its accounting for income
taxes to conform with SFAS 109.
Reacquired Debt
The premiums and costs associated with reacquired debt are being amortized
over the life of the related new issuances, in accordance with ratemaking
treatment.
Cash and Cash Equivalents
Entergy considers all unrestricted highly liquid debt instruments purchased
with an original maturity of three months or less to be cash equivalents.
SFAS 101
SFAS 101 specifies how an enterprise that ceases to meet the criteria for
application of SFAS No. 71, "Accounting for Certain Types of Regulation," to all
or part of its operations should report that event in its financial statements.
GSU discontinued regulatory accounting principles for the wholesale jurisdiction
and steam department, and the Louisiana deregulated portion of River Bend,
during 1989 and 1991, respectively.
Fair Value Disclosures
The estimated fair value amounts of financial instruments have been
determined by Entergy, using available market information and appropriate
valuation methodologies. However, considerable judgment is required in
developing the estimates of fair value. Therefore, estimates are not
necessarily indicative of the amounts that Entergy could realize in a current
market exchange. In addition, gains or losses realized on financial instruments
may be reflected in future rates and not accrue to the benefit of stockholders.
Entergy considers the carrying amounts of financial instruments classified
as current assets and liabilities to be a reasonable estimate of their fair
value because of the short maturity of these instruments. In addition, Entergy
does not presently expect that performance of its obligations will be required
in connection with certain off-balance sheet commitments and guarantees
considered financial instruments. Due to this factor, and because of the
related party nature of these commitments and guarantees, determination of fair
value is not considered practicable. See Notes 5, 6, and 8 for additional fair
value disclosure.
NOTE 2. RATE AND REGULATORY MATTERS
River Bend
In May 1988, the PUCT granted GSU a permanent increase in annual revenues
of $59.9 million resulting from the inclusion in rate base of approximately $1.6
billion of company-wide River Bend plant investment and approximately $182
million of related Texas retail jurisdiction deferred River Bend costs (Allowed
Deferrals). In addition, the PUCT disallowed as imprudent $63.5 million of
company-wide River Bend plant costs and placed in abeyance, with no finding of
prudency, approximately $1.4 billion of company-wide River Bend plant investment
and approximately $157 million of Texas retail jurisdiction deferred River Bend
operating and carrying costs. The PUCT affirmed that the ultimate rate
treatment of such amounts would be subject to future demonstration of the
prudency of such costs. GSU and intervening parties appealed this order (Rate
Appeal) and GSU filed a separate rate case asking that the abeyed River Bend
plant costs be found prudent (Separate Rate Case). Intervening parties filed
suit in district court to prohibit the Separate Rate Case. The district court's
decision was ultimately appealed to the Texas Supreme Court which ruled in 1990
that the prudence of the purported abeyed costs could not be relitigated in a
separate rate proceeding. Further, the Texas Supreme Court's decision stated
that all issues relating to the merits of the original order of the PUCT,
including the prudence of all River Bend-related costs, should be addressed in
the Rate Appeal.
In October 1991, the district court in the Rate Appeal issued an order
holding that, while it was clear the PUCT made an error in assuming it could set
aside $1.4 billion of the total costs of River Bend and consider them in a later
proceeding, the PUCT, nevertheless, found that GSU had not met its burden of
proof related to the amounts placed in abeyance. The court also ruled the
Allowed Deferrals should not be included in rate base under a 1991 decision
regarding El Paso Electric Company's similar deferred costs (El Paso Case). The
court further stated that the PUCT erred in reducing GSU's deferred costs by
$1.50 for each $1.00 of revenue collected under the interim rate increases
authorized in 1987 and 1988. The court remanded the case to the PUCT with
instructions as to the proper handling of the Allowed Deferrals. GSU's motion
for rehearing was denied, and in December 1991, GSU filed an appeal of the
October 1991 district court order. The PUCT also appealed the October 1991
district court order, which served to supersede the district court's judgment,
rendering it unenforceable under Texas law.
In August 1992, the court of appeals in the El Paso Case handed down its
second opinion on rehearing modifying its previous opinion on deferred
accounting. The court's second opinion concluded that the PUCT may lawfully
defer operating and maintenance costs and subsequently include them in rate
base, but that the Public Utility Regulatory Act prohibits such rate base
treatment for deferred carrying costs. The court stated, however, its opinion
would not preclude the recovery of deferred carrying costs. The August 1992
court of appeals opinion was appealed to the Texas Supreme Court where arguments
were heard in September 1993. The matter is pending.
In September 1993, the Texas Third District Court of Appeals (the Third
District Court) remanded the October 1991 district court decision to the PUCT
"to reexamine the record evidence to whatever extent necessary to render a final
order supported by substantial evidence and not inconsistent with our opinion."
The Third District Court specifically addressed the PUCT's treatment of certain
costs, stating that the PUCT's order was not based on substantial evidence. The
Third District Court also applied its most recent ruling in the El Paso Case to
the deferred costs associated with River Bend. However, the Third District
Court cautioned the PUCT to confine its deliberations to the evidence addressed
in the original rate case. Certain parties to the case have indicated their
position that, on remand, the PUCT may change its original order only with
respect to matters specifically discussed by the Third District Court which, if
allowed, would increase GSU's allowed River Bend investment, net of accumulated
depreciation and related taxes, by approximately $48 million as of December 31,
1993. GSU believes that under the Third District Court's decision, the PUCT
would be free to reconsider any aspect of its order concerning the abeyed $1.4
billion River Bend investment. GSU has filed a motion for rehearing asking the
Third District Court to modify its order so as to permit the PUCT to take
additional evidence on remand. The PUCT and other parties have also moved for
rehearing on various grounds. The Third District Court has not yet ruled on any
of these motions.
As of December 31, 1993, the River Bend plant costs disallowed for retail
ratemaking purposes in Texas, and the River Bend plant costs held in abeyance
and the related cost deferrals totaled (net of taxes) approximately $14 million,
$300 million (both net of depreciation), and $171 million, respectively.
Allowed Deferrals were approximately $95 million, net of taxes and amortization,
as of December 31, 1993. GSU estimates it has collected approximately $139
million of revenues as of December 31, 1993, as a result of the originally
ordered rate treatment of these deferred costs. However, if the PUCT adopts the
most recent decision in the El Paso Case, the possible refunds approximate $28
million as a result of the inclusion of deferred carrying costs in rate base for
the period July 1988 through December 1990. However, if the PUCT reverses its
decision to reduce GSU's deferred costs by $1.50 for each $1.00 of revenue
collected under the interim rate increases authorized in 1987 and 1988, the
potential refund of amounts described above could be reduced by an amount
ranging from $7 million to $19 million.
No assurance can be given as to the timing or outcome of the remands or
appeals described above. Pending further developments in these cases, GSU has
made no write-offs for the River Bend-related costs. Management believes, based
on advice from Clark, Thomas & Winters, a Professional Corporation, legal
counsel of record in the Rate Appeal, that it is reasonably possible that the
case will be remanded to the PUCT, and the PUCT will be allowed to rule on the
prudence of the abeyed River Bend plant costs. Rate Caps imposed by the PUCT's
regulatory approval of the Merger could result in GSU being unable to use the
full amount of a favorable decision to immediately increase rates; however, a
favorable decision could permit some increases and/or limit or prevent decreases
during the period the Rate Caps are in effect. At this time, management and
legal counsel are unable to predict the amount, if any, of the abeyed and
previously disallowed River Bend plant costs that ultimately may be disallowed
by the PUCT. A net of tax write-off as of December 31, 1993, of up to $314
million could be required based on the PUCT's ultimate ruling.
In prior proceedings, the PUCT has held that the original cost of nuclear
power plants will be included in rates to the extent those costs were prudently
incurred. Based upon the PUCT's prior decisions, management believes that its
River Bend construction costs were prudently incurred and that it is reasonably
possible that it will recover in rate base, or otherwise through means such as a
deregulated asset plan, all or substantially all of the abeyed River Bend plant
costs. However, management also recognizes that it is reasonably possible that
not all of the abeyed River Bend plant costs may ultimately be recovered.
As part of its direct case in the Separate Rate Case, GSU filed a cost
reconciliation study prepared by Sandlin Associates, management consultants with
expertise in the cost analysis of nuclear power plants, which supports the
reasonableness of the River Bend costs held in abeyance by the PUCT. This
reconciliation study determined that approximately 82% of the River Bend cost
increase above the amount included by the PUCT in rate base was a result of
changes in federal nuclear safety requirements and provided other support for
the remainder of the abeyed amounts.
There have been four other rate proceedings in Texas involving nuclear
power plants. Investment in the plants ultimately disallowed ranged from 0% to
15%. Each case was unique, and the disallowances in each were made on a
case-by-case basis for different reasons. Appeals of most, if not all, of
these PUCT decisions are currently pending.
The following factors support management's position that a loss contingency
requiring accrual has not occurred, and its belief that all, or substantially
all, of the abeyed plant costs will ultimately be recovered:
1. The $1.4 billion of abeyed River Bend plant costs have never been ruled
imprudent and disallowed by the PUCT.
2. Sandlin Associates' analysis which supports the prudence of
substantially all of the abeyed construction costs.
3. Historical inclusion by the PUCT of prudent construction costs in rate
base.
4. The analysis of GSU's internal legal staff, which has considerable
experience in Texas rate case litigation.
Additionally, management believes, based on advice from Clark, Thomas &
Winters, a Professional Corporation, legal counsel of record in the Rate Appeal,
that it is probable that the deferred costs will be allowed. However, assuming
the August 1992 court of appeals' opinion in the El Paso Case is upheld and
applied to GSU and the deferred River Bend costs currently held in abeyance are
not allowed to be recovered in rates as allowable costs, a net of tax write-off
of up to $171 million could be required. In addition, future revenues based
upon the deferred costs previously allowed in rate base could also be lost and
no assurance can be given as to whether or not refunds (up to $28 million as of
December 31, 1993) of revenue received based upon such deferred costs previously
recorded will be required.
See Note 11 for the accounting treatment of preacquisition contingencies,
including a River Bend write-down.
Merger-Related Rate Agreements
In November 1993, Entergy Corporation, AP&L, MP&L, and NOPSI entered into
separate settlement agreements whereby the APSC, MPSC, and Council agreed to
withdraw from the SEC proceeding related to the Merger. In return, among other
things, AP&L, MP&L, and NOPSI agreed that their retail ratepayers would be
protected from (1) increases in the cost of capital resulting from risks
associated with the Merger, (2) recovery of any portion of the acquisition
premium or transactional costs associated with the Merger, (3) certain direct
allocations of costs associated with GSU's River Bend nuclear unit, and (4) any
losses of GSU resulting from resolution of litigation in connection with its
ownership of River Bend. AP&L and MP&L agreed not to request any general retail
rate increase that would take effect before November 1998, except, among other
things, for increases associated with the Least Cost Plan, recovery of certain
Grand Gulf 1-related costs, recovery of certain taxes, and force majeure
(defined to include, among other things, war, natural catastrophes, and high
inflation), and in the case of AP&L, excess capacity costs and costs related to
the adoption of SFAS 106 that were previously deferred. MP&L also agreed that
retail base rates under its proposed formula rate plan would not be increased
above November 1, 1993, levels for a period of five years beginning November 9,
1993, (described below). NOPSI was required to reduce its annual electric base
rates by $4.8 million effective for bills rendered on or after November 1, 1993,
and to expense its SFAS 106 costs. Further, NOPSI's SFAS 106 expenses through
October 31, 1996, will be allowed by the Council for purposes of evaluating the
appropriateness of NOPSI's rates. The Council also agreed not to seek to
disallow the first $3.5 million of costs incurred through October 31, 1993, in
connection with the Least Cost Plan.
The LPSC and the PUCT approved separate regulatory proposals that include
the following elements: (1) a five-year Rate Cap on GSU's retail electric base
rates in the respective states, except for force majeure (defined to include,
among other things, war, natural catastrophes, and high inflation); (2) a
provision for passing through to retail customers in the respective states the
jurisdictional portion of the fuel savings created by the Merger; and (3) a
mechanism for tracking nonfuel operation and maintenance savings created by the
Merger. The LPSC regulatory plan provides that such nonfuel savings will be
shared 60% by the shareholder and 40% by ratepayers during the eight years
following the Merger. The LPSC plan requires regulatory filings each year by
the end of May through 2001. The PUCT regulatory plan provides that such
savings will be shared equally by the shareholder and ratepayers, except that
the shareholder's portion will be reduced by $2.6 million per year on a total
company basis in years four through eight. The PUCT plan also requires a series
of regulatory filings, currently anticipated to be in June 1994, and February
1996, 1998, and 2001, to ensure that ratepayers' share of such savings be
reflected in rates on a timely basis and requires Entergy Corporation to hold
GSU's Texas retail customers harmless from the effects of the removal by FERC of
a 40% cap on the amount of fuel savings GSU may be required to transfer to other
Entergy operating companies under the FERC tracking mechanism (see below). On
January 14, 1994, Entergy Corporation filed a request for rehearing of FERC's
December 15, 1993, order approving the Merger requesting that FERC restore the
40% cap provision in the fuel cost protection mechanism. The matter is pending.
FERC approved certain rate schedule changes to integrate GSU into the
System Agreement. Certain commitments were adopted to provide reasonable
assurance that the ratepayers of AP&L, LP&L, MP&L, and NOPSI will not be
allocated higher costs, including, among other things, (1) a tracking mechanism
to protect AP&L, LP&L, MP&L, and NOPSI from certain unexpected increases in fuel
costs, (2) the distribution of profits from power sales contracts entered into
prior to the Merger, (3) a methodology to estimate the cost of capital in future
FERC proceedings, and (4) a stipulation that AP&L, LP&L, MP&L, and NOPSI will be
insulated from certain direct effects on capacity equalization payments should
GSU, due to a finding of imprudent GSU management prior to the Merger, be
required to purchase Cajun's 30% share in River Bend (see Note 8).
Incentive Rate Plan
In July 1993, the MPSC ordered MP&L to file a formulary incentive rate plan
designed to allow for periodic small adjustments in rates based upon a
comparison of earned to benchmark returns and upon performance factors
incorporated in the plan. In November 1993, MP&L filed a formula rate plan
(Proposed Plan) with the MPSC to become effective on March 1, 1994, with any
initial adjustment to base rates in June 1994. Under the Proposed Plan, a
formula would be established under which MP&L's earned rate of return would be
calculated automatically every 12 months and compared to a benchmark rate of
return, which would be calculated under a separate formula within the Proposed
Plan. If MP&L's earned rate of return falls within a bandwidth around the
benchmark rate of return, there would be no adjustment in rates. If MP&L's
earnings are above the bandwidth, the Proposed Plan would automatically reduce
MP&L's base rates. Alternatively, if MP&L's earnings are below the bandwidth,
the Proposed Plan would automatically increase MP&L's base rates (subject to the
five-year cap described above under "Merger-Related Rate Agreements"). The
reduction or increase in base rates would be an amount representing 50% of the
difference between the earned rate of return and the nearest limit of the
bandwidth. In no event would the annual adjustment in rates exceed the lesser
of 2% of MP&L's aggregate retail revenues, or $14.5 million. Under the Proposed
Plan, the benchmark rate of return, and consequently the bandwidth, would be
adjusted slightly upward or downward based upon MP&L's performance on three
performance factors: customer reliability, customer satisfaction, and customer
price.
Subsequently, the MPSC conducted a general review of MP&L's current rates
and later issued a final order adopting the Proposed Plan and previously agreed-
upon stipulations of 1) a required return on equity of 11% and 2) certain
accounting adjustments that result in a 4.3% ($28.1 million) reduction in MP&L's
June 30, 1993, test-year base revenues. The MPSC's order requires MP&L to file
rates designed to provide for this reduction in operating revenues for the test
year on or before March 18, 1994, to become effective for service rendered on or
after March 25, 1994.
LPSC Investigation
In response to a preliminary report of the LPSC indicating that the rates
of return on equity of several electric utilities subject to the LPSC's
jurisdiction may be too high, GSU provided the LPSC with information GSU
believes supports the current rate level. In September 1993, the LPSC deferred
review of GSU's base rates until the first post-Merger earnings analysis is
filed in accordance with the LPSC Merger approval (scheduled for mid-1994).
Recognizing that LP&L is subject to a rate freeze until March 1994, the
LPSC requested LP&L to explain its "relatively high cost of debt" compared to
other electric utilities subject to LPSC jurisdiction. LP&L responded to this
request, and in an August 1993 report to the LPSC, the LPSC's legal consultants
acknowledged LP&L's rationale for its cost of debt in comparison to two other
utilities subject to the LPSC's jurisdiction. Further, the legal consultants
suggested that certain aspects of the LP&L cost of debt could be taken up in any
rate proceeding after the expiration of LP&L's rate freeze in March 1994. In
October 1993, the LPSC approved a schedule to conduct a review of LP&L's rates
and rate structure upon the expiration of LP&L's current rate freeze.
FERC Audit
In December 1990, FERC Division of Audits issued a report for System Energy
for the years 1986 through 1988. The report recommended that System Energy (1)
write off, and not recover in rates, approximately $95 million of Grand Gulf 1
costs included in utility plant related to certain System income tax allocation
procedures alleged to be inconsistent with FERC's accounting requirements, and
(2) compute refunds for the years 1987 to date to correct for resulting
overcollections from AP&L, LP&L, MP&L, and NOPSI.
In August 1992, FERC issued an opinion and order (August 4 Order) which
found that System Energy overstated its Grand Gulf 1 utility plant account by
approximately $95 million as indicated in FERC's report. The order required
System Energy to make adjusting accounting entries and refunds, with interest,
to AP&L, LP&L, MP&L, and NOPSI within 90 days from the date of the order.
System Energy filed a request for rehearing, and in October 1992, FERC issued an
order allowing additional time for its consideration of the request. In
addition, it deferred System Energy's refund obligation until 30 days after FERC
issues an order on rehearing.
Assuming AP&L, LP&L, MP&L, and NOPSI are required to refund or credit to
their customers all of the System Energy refund (except for those portions
attributable to AP&L's and LP&L's retained share of Grand Gulf 1 costs),
implementation of the August 4 Order would result in a reduction in Entergy's
consolidated net income of approximately $146.4 million as of December 31, 1993.
However, this reduction could be partially offset by: (1) the write-off by AP&L,
LP&L, MP&L, and NOPSI of unamortized balances of corresponding deferred credits
(approximately $66.7 million as of December 31, 1993), and (2) any recovery from
ratepayers of deferred credits that have been previously amortized and passed on
to ratepayers (approximately $24.4 million as of December 31, 1993). The amount
of such recovery would depend on the associated retail rate treatment. System
Energy believes that its consolidated income tax accounting procedures and
related rate treatment are in compliance with SEC and FERC requirements and is
vigorously contesting this issue. The ultimate resolution of this matter cannot
be predicted.
If the August 4 Order is implemented, System Energy needs the consent of
certain banks to temporarily waive the fixed charge coverage and equity ratio
covenants in the letters of credit and reimbursement agreement related to the
Grand Gulf 1 sale and leaseback transaction (see Notes 6 and 9). System Energy
has obtained the consent of the banks to waive these covenants, for the 12-month
period beginning with the earlier of the write-off or the first refund, if the
August 4 Order is implemented prior to December 31, 1994. The waiver is
conditioned upon System Energy not paying any common stock dividends to Entergy
Corporation until the equity ratio covenant is once again met. Absent a waiver,
System Energy's failure to perform these covenants could cause a draw under the
letters of credit and/or early termination of the letters of credit. If the
letters of credit were not replaced in a timely manner, a default or early
termination of System Energy's leases could result.
Texas Cities Rate Settlement
In June 1993, 13 cities within GSU's Texas service area instituted an
investigation to determine whether GSU's current rates were justified. In
October 1993, the general counsel of the PUCT instituted an inquiry into the
reasonableness of GSU's rates. In November 1993, a settlement agreement was
filed with the PUCT which provides for an initial reduction in GSU's annual
retail base revenues in Texas of approximately $22.5 million effective for
electric usage on or after November 1, 1993, and a second reduction of $20
million to be effective September 1994. Further, the settlement provided for
GSU to reduce rates with a $20 million one-time bill credit in December 1993,
and to refund approximately $3 million to Texas retail customers on bills
rendered in December 1993. The cities' rate inquiries had been settled earlier
on the same terms.
In November 1993, in association with the settlement of the above-described
rates inquiries, GSU entered into a settlement covering issues related to a
March 1991 non-unanimous settlement in another proceeding. Under this
settlement, a $30 million rate increase approved by the PUCT in March 1991
became final, and the PUCT's treatment of GSU's federal tax expense was settled,
eliminating the possibility of refunds associated with amounts collected
resulting from the disputed tax calculation.
In December 1993, a large industrial customer of GSU announced its
intention to oppose the settlement of the PUCT rate inquiry. The customer's
opposition does not affect the cities' rate settlement. The customer's
opposition requires the PUCT to conduct a hearing concerning GSU's rates charged
in areas outside the corporate limits of the cities in its Texas service
territory to determine whether the settlement's rates are just and reasonable.
A hearing has been set for July 8, 1994. GSU believes that the PUCT will
ultimately approve the settlement, but no assurance can be provided in this
regard.
Rate Deferrals
The System operating companies have various rate moderation or phase-in
plans that reduced the immediate effect of Grand Gulf 1, River Bend, and
Waterford 3 costs on ratepayers. Under these plans, certain costs are either
retained permanently (and not recovered from ratepayers), deferred in early
years and collected in later years, or recovered currently from customers.
These plans vary in the proportions of costs each company retains, defers, or
recovers and in the length of the deferral/recovery periods. Only those costs
retained permanently and not recovered through rates or through sales to third
parties result in a reduction of net income. The carrying charges associated
with unamortized deferrals are either deferred or recovered currently from
customers.
The 1991 NOPSI Settlement provided for a finalized phase-in plan for the
increased recovery of NOPSI's Grand Gulf 1-related costs over a 10-year period
and for a five-year base rate freeze (subject to certain exceptions) with
respect to non-Grand Gulf 1 electric rates. In 1991, NOPSI recorded on its
balance sheet a $90 million deferred asset of previously incurred but
unrecovered Grand Gulf 1-related costs, with a corresponding pretax gain on the
income statement. This gain increased 1991 consolidated net income by $48.6
million after taxes.
GSU deferred approximately $369 million of River Bend operating costs,
purchased power costs, and accrued carrying charges pursuant to a 1986 PUCT
accounting order. Approximately $182 million of these costs are being amortized
over a 20-year period and the remaining $187 million are not being amortized
pending the ultimate outcome of the Rate Appeal. As of December 31, 1993, the
unamortized balance of these costs was $330.3 million. Further, GSU deferred
approximately $400 million of similar costs pursuant to a 1986 LPSC accounting
order. These costs, of which approximately $160.4 million are unamortized as of
December 31, 1993, are being amortized over a 10-year period.
Previous rate orders of the LPSC have been appealed, and pending resolution
of various appellate proceedings, GSU has made no write-off for the disallowance
of $30.6 million of deferred revenue requirement, related to GSU's Louisiana
phase-in plan, recorded for the period December 1987 through February 1988.
AP&L's permanently retained share of Grand Gulf 1 costs (stated as a
percentage of System Energy's 90% owned and leased share of Grand Gulf 1) ranges
from 5.67% in 1989 to 7.92% in 1994 and all succeeding years of the unit's
commercial operation. In the event AP&L is not able to sell its retained share
to third parties, it may sell such energy to its retail customers at a price
equal to its avoided energy cost, which is currently less than AP&L's cost of
such energy. LP&L permanently absorbs 18% of its 14% (approximately 2.52%)
FERC-allocated share of Grand Gulf 1-related costs. LP&L is able to recover
through the fuel adjustment clause 4.6 cents per KWH (currently 2.55 cents per
KWH through May 1994) for the energy related to its retained portion of these
costs. Alternatively, LP&L may sell such energy to nonaffiliated parties at
prices above the fuel adjustment clause recovery amount, subject to LPSC
approval. For the year ended December 31, 1993, System Energy's billings for
Grand Gulf 1-related costs totaled approximately $650 million. A deregulated
asset plan representing an unregulated portion (approximately 22%) of River Bend
(plant costs, generation, revenues, and expenses) was established pursuant to a
January 1992 LPSC order. The plan allows GSU to sell such generation to
Louisiana retail customers at 4.6 cents per KWH or off-system at higher prices
with certain sharing provisions for such incremental revenue.
FERC Settlements
In September 1991, FERC approved a settlement among AP&L, LP&L, MP&L, and
NOPSI and various state and local regulatory authorities which (1) required
credits from System Energy to AP&L, LP&L, MP&L, and NOPSI of approximately
$48 million, (2) increased System Energy's decommissioning collections, and (3)
reduced the allowed rate of return on common equity under the System Agreement
and for System Energy from 14% to 13%. As a result of the settlement, 1991
consolidated net income was reduced by approximately $30 million. Pursuant to a
subsequent settlement in another proceeding, the allowed rate of return was
further reduced to 11% effective November 3, 1992. Refunds from this settlement
reduced 1993 consolidated revenues and net income by approximately $27.2 million
and $16.8 million, respectively.
NOTE 3. INCOME TAXES
Effective January 1, 1993, the System adopted SFAS 109 (excluding GSU which
recorded the adoption effective January 1, 1990). This new standard requires
that deferred income taxes be recorded for all temporary differences and
carryforwards, and that deferred tax balances be based on enacted tax laws at
tax rates that are expected to be in effect when the temporary differences
reverse. SFAS 109 requires that regulated enterprises recognize adjustments
resulting from implementation as regulatory assets or liabilities if it is
probable that such amounts will be recovered from or returned to customers in
future rates. A substantial majority of the adjustments required by SFAS 109
was recorded to deferred tax balance sheet accounts with offsetting adjustments
to regulatory assets and liabilities. The cumulative effect of the adoption of
SFAS 109 is included in income tax expense charged to operations. As a result
of the adoption of SFAS 109, 1993 net income and earnings per share were
decreased by $13.2 million and $0.08 per share, respectively, and assets and
liabilities were increased by $822.7 million and $835.9 million, respectively.
Income tax expense consisted of the following:
For the Years Ended December 31,
--------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Current:
Federal $236,513 $ 99,898 $ 64,111
State 30,618 23,596 13,158
-------- -------- --------
Total 267,131 123,494 77,269
-------- -------- --------
Deferred - net:
Reclassification due to net operating (17,131) 35,969 (22,516)
loss carryforward
Rate deferrals - net (88,651) (54,079) (3,248)
Gas contract settlement 9,513 15,180 15,342
Liberalized depreciation 116,513 107,976 116,266
Unbilled revenue 56,315 (18,902) 6,633
Alternative minimum tax (10,270) 6,577 16,019
Bond reacquisition cost 17,958 11,496 (1,256)
Nuclear refueling and maintenance (7,929) 9,740 484
Decontamination and decommissioning 27,303 - -
fund
Other 15,035 (1,595) (6,465)
-------- -------- --------
Total 118,656 112,362 121,259
-------- -------- --------
Investment tax credit adjustments - net (43,796) 20,607 78,623
-------- -------- --------
Recorded income tax expense $341,991 $256,463 $277,151
======== ======== ========
Charged to operations $251,163 $210,081 $243,760
Charged to other income 33,640 46,382 33,391
Charged to cumulative effect 57,188 - -
-------- -------- --------
Recorded income tax expense 341,991 256,463 277,151
Income taxes applied against the debt - 696 886
component of AFUDC
-------- -------- --------
Total income taxes $341,991 $257,159 $278,037
======== ======== ========
Total income taxes differ from the amounts computed by applying the
statutory federal income tax rate to income before taxes. The reasons for the
differences were:
For the Years Ended December 31
------------------------------------------------------
1993 1992 1991
--------------- ------------------ ---------------
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
-------- ------ -------- ------- -------- -------
(Dollars in Thousands)
Computed at statutory rate $332,555 35.0 $257,461 34.0 $279,395 34.0
Increases (reductions) in tax resulting from:
Amortization of excess deferred income taxes (7,063) (0.7) (6,537) (0.9) (7,318) (0.9)
State income taxes net of federal income
tax effect 30,160 3.2 26,057 3.5 23,741 2.9
Amortization of investment tax credits (25,911) (2.7) (26,885) (3.6) (22,470) (2.7)
Depreciation 5,925 0.6 4,527 0.6 5,693 0.7
SFAS 109 adjustment 9,547 1.0 - - - -
Other - net (3,222) (0.4) 1,840 0.3 (1,890) (0.2)
-------- ----- -------- ----- -------- -----
Recorded income tax expense 341,991 36.0 256,463 33.9 277,151 33.8
Income taxes applied against debt component
of AFUDC - - 696 0.1 886 0.1
-------- ----- -------- ----- -------- -----
Total income taxes $341,991 36.0 $257,159 34.0 $278,037 33.9
======== ===== ======== ===== ======== =====
Significant components of net deferred tax liabilities as of December 31,
1993, were (in thousands):
Deferred tax liabilities:
Net regulatory assets $(1,676,161)
Plant related basis differences (2,945,933)
Rate deferrals (767,124)
Other (167,478)
-----------
Total $(5,556,696)
===========
Deferred tax assets:
Sale and leaseback $ 241,391
Accumulated deferred investment tax credit 330,852
Alternative minimum tax credit 138,063
Removal cost 92,618
Standard coal plant 30,165
NOL carryforwards 307,737
Pension related items 24,879
Unbilled revenues 23,587
Investment tax credit carryforwards 314,862
Other 149,568
-----------
Total $ 1,653,722
===========
Net deferred tax liabilities $(3,902,974)
===========
As of December 31, 1993, Entergy had federal net operating loss (NOL)
carryforwards of $790.3 million and state NOL carryforwards of $561.4 million
related to GSU operations. Investment tax credit (ITC) and other credit
carryforwards as of December 31, 1993, amounted to $357.4 million. The ITC
carryforwards include the 35% reduction required by the Tax Reform Act of 1986
and may be applied against federal income tax liabilities and, if not utilized,
will expire in 1995 through 2005. It is currently anticipated that
approximately $15.2 million will expire unutilized. A valuation allowance has
been provided for that amount.
Entergy's consolidated tax allocation reflects ITC carryforwards as of
December 31, 1993. The allocation does not reflect any NOL carryforwards for
the System. However, due to the current method of allocating taxes between
subsidiaries, some companies have the tax effect of NOL carryforwards recorded
on their separate company books. The alternative minimum tax (AMT) credit
carryforwards as of December 31, 1993, were $138.1 million. This AMT credit can
be carried forward indefinitely and will reduce the System's federal income tax
liability in the future.
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized AP&L, LP&L, MP&L, NOPSI, and System Energy to effect
short-term borrowings up to an aggregate of $518 million, subject to increase to
as much as $865 million (subject to individual authorizations for each company)
after further SEC approval. These authorizations are effective through
November 30, 1994. Short-term borrowings by MP&L and NOPSI are also limited by
the terms of their respective G&R Bond indentures to amounts not exceeding the
greater of 10% of capitalization or 50% of Grand Gulf 1 rate deferrals available
to support the issuance of G&R Bonds.
As of December 31, 1993, AP&L, GSU, LP&L, and MP&L had unused lines of
credit for short-term borrowings of $197.6 million from banks within their
service territories. Included in this amount for GSU was a $100 million bank
credit agreement which expired on March 2, 1994. In addition, AP&L, LP&L, MP&L,
NOPSI, System Energy, Entergy Operations, Entergy Services, Inc., and System
Fuels can borrow from each other and from Entergy Corporation through the System
money pool, an intra-System borrowing arrangement designed to reduce the
System's dependence on external short-term borrowings (Money Pool). A filing
was made with the SEC on January 4, 1994, requesting authorization for GSU to
participate in the Money Pool and enter into new bank lines of credit and
commercial paper arrangements. The filing requested a borrowing authorization
of $125 million, subject to increase to a maximum amount of $455 million after
further SEC approval.
Entergy Corporation has a short-term line of credit, expiring September 17,
1994, for $43 million (all of which was outstanding as of December 31, 1993).
Entergy Corporation has requested SEC approval for a $300 million three-year
bank line of credit. System Fuels has financing agreements totaling $65 million
(none of which was outstanding as of December 31, 1993). These are restricted
as to use, and are secured by fuel inventories and certain accounts receivable
from the sales of these inventories.
NOTE 5. PREFERRED, PREFERENCE, AND COMMON STOCK
The number of shares and dollar value of the System operating companies'
(excluding GSU in 1992) preferred and preference stock was:
As of December 31,
--------------------------------------------
Shares Call Price Per
Authorized and Total Share as of
Outstanding Dollar Value December 31,
1993 1992 1993 1992 1993
--------- -------- -------- -------- ---------------
(Dollars in Thousands)
Preferred Stock
Without sinking fund:
Cumulative, $100 par value
4.16% - 5.56% Series 1,201,715 1,070,106 $120,172 $107,011 $102.50 to $108.00
6.08% - 8.56% Series 2,262,829 1,380,000 226,283 138,000 $101.80 to $103.78
9.16% - 11.48% Series 425,000 75,000 42,500 7,500 $104.06 to $104.64
Cumulative, $25 par value
8.00% - 9.68% Series 3,880,000 3,880,000 97,000 97,000 $26.56
Cumulative, $0.01 par value
$2.40 Series (1)(2) 2,000,000 2,000,000 50,000 50,000 -
$1.96 Series (1)(2) 600,000 600,000 15,000 15,000 -
---------- ---------- -------- --------
Total without sinking fund 10,369,544 9,005,106 $550,955 $414,511
========== ========== ======== ========
With sinking fund:
Cumulative, $100 par value
7.00% - 9.76% Series 2,126,539 1,835,000 $212,654 $183,500 $100.00 to $106.75
10.60% - 12.92% Series 67,700 137,700 6,770 13,770 $104.09 to $106.00
15.44% - 16.16% Series 49,495 79,495 4,950 7,950 $107.72
Adjustable, 7.10% - 7.15%
as of December 31, 1993 553,500 - 55,350 - $100.00 to $103.00
Cumulative, $25 par value
9.92% - 12.64% Series 2,311,666 2,931,666 57,791 73,291 $26.34 to $27.37
13.12% - 15.20% Series 461,537 1,021,537 11,538 25,538 $26.64 to $28.22
---------- ---------- -------- --------
Total with sinking fund 5,570,437 6,005,398 $349,053 $304,049
========== ========== ======== ========
Preference Stock
Cumulative, without par value
7% Series (1)(2) 6,000,000 - $150,000 $ - -
========== ========== ======== ========
(1) The total dollar value represents the involuntary liquidation value of $25
per share.
(2) These series are not redeemable as of December 31, 1993.
The fair value of the System operating companies' (excluding GSU in 1992)
preferred and preference stock with sinking fund was estimated to be
approximately $526.2 million and $333.6 million as of December 31, 1993 and
1992, respectively. The fair value was determined using quoted market prices or
estimates from nationally recognized investment banking firms. See Note 1 for
additional information on disclosure of fair value of financial instruments.
As of December 31, 1993, the System operating companies had 8,292,023,
13,798,915, and 12,400,000 shares of cumulative, $100, $25, and $0.01 par value
preferred stock, respectively, and 14,000,000 shares of preference stock without
par value, that were authorized but unissued. On February 4, 1994, MP&L amended
its charter to authorize 1,500,000 additional shares of $100 par value preferred
stock.
Changes in the preferred stock of AP&L, LP&L, MP&L, and NOPSI, with and
without sinking fund, during the last three years were:
Number of Shares
--------------------------------------
1993 1992 1991
----------- ---------- ------------
Preferred Stock Issuances:
$100 par value - 700,000 350,000
$25 par value - 1,480,000 2,000,000
$0.01 par value - 600,000 2,000,000
Preferred Stock Retirements:
$100 par value (265,000) (589,940) (530,060)
$25 par value (1,180,000) (1,895,160) (1,300,000)
Cash sinking fund requirements for the next five years for preferred stock
outstanding as of December 31, 1993, are (in millions): 1994 - $37.6, 1995 -
$36.1, 1996 - $28.1, 1997 - $25.9, and 1998 - $15.6.
On December 31, 1993, Entergy Corporation issued 56,667,726 shares of
common stock in connection with the Merger. In addition, Entergy Corporation
redeemed 174,552,011 shares of $5.00 par value common stock and reissued
174,552,011 shares of $0.01 par value common stock resulting in an increase in
paid-in capital of $871 million.
Entergy Corporation has SEC authorization to repurchase, through
December 31, 1994, up to 27.1 million shares of its outstanding common stock,
either on the open market or through negotiated purchases or tender offers.
Stock repurchases are made from time to time depending upon market conditions
and authorization of the Entergy Corporation board. Under this program, Entergy
Corporation repurchased and retired (returned to authorized but unissued status)
3,671,900 shares and 6,447,900 shares, at a cost of $161.6 million and $105.7
million during 1992 and 1991, respectively. In addition, 1,943 shares of
treasury stock were purchased during 1992 at a cost of $54,263. During 1993,
627,000 shares of treasury stock were purchased at a cost of $20.6 million. A
portion of these treasury shares were subsequently reissued and in connection
with the Merger on December 31, 1993, all of the existing balance of 579,274
shares of treasury shares was canceled.
Entergy Corporation has SEC authorization to acquire, through December 31,
1994, up to 3,000,000 shares of its common stock to be held as treasury shares,
and to be reissued to meet the requirements of the Stock Plan for Outside
Directors (Directors Plan), the Equity Ownership Plan of Entergy Corporation and
Subsidiaries (Equity Plan), and certain other stock benefit plans. The
Directors Plan awards nonemployee directors a portion of their compensation in
the form of a fixed number of shares of Entergy Corporation common stock.
Shares awarded under the Directors Plan were 12,550, 14,904, and 7,000 during
1993, 1992, and 1991, respectively. The Equity Plan grants stock options,
restricted shares, and equity awards to key employees of the System companies.
The costs of awards are charged to income over the period of the grant or
restricted period, as appropriate. Amounts charged to compensation expense in
1993 were immaterial. Stock options, which comprise 50% of the shares targeted
for distribution under the Equity Plan, are granted at exercise prices not less
than market value on the date of grant. The options are generally exercisable
no less than six months or more than 10 years after the date of grant.
Nonstatutory stock options transactions are summarized as follows:
Option Price Number of Options
------------ -----------------
Options granted during 1992 29.625 50,000
Options exercised during 1992 29.625 (5,000)
Options granted during 1993 34.75 62,500
39.75* 6,107
Options exercised during 1993 29.625 (8,198)
-------
Options remaining as of December 31, 1993 105,409
=======
* Options are not currently exercisable at December 31, 1993.
During 1993, Entergy Corporation received SEC approval for the Employee
Stock Investment Plan (ESIP) which will become effective in March 1994. Entergy
Corporation received SEC authorization to issue new shares or acquire, through
March 31, 1997, up to 2,000,000 shares of its common stock to be held as
treasury shares, and to be reissued to meet the requirements of the ESIP. Under
the ESIP, employees may be granted the opportunity to purchase (up to 10% of
regular pay) common stock at 85% of the market value on the first or last
business day of the plan year, whichever is lower. The 1994 plan year will run
from April 1, 1994, to March 31, 1995.
NOTE 6. LONG -TERM DEBT
The long-term debt of Entergy Corporation's subsidiaries (excluding GSU in
1992) as of December 31, 1993 and 1992, was:
Maturities Interest Rates
From To From To 1993 1992
---- ---- ----- ---- ---------- ----------
(In Thousands)
First Mortgage Bonds
1993 1998 4-5/8% 14%* $1,354,810 $ 990,410
1999 2003 6% 11% 1,143,520 861,220
2004 2008 6.65% 10% 635,000 282,767
2014 2018 9-5/8% 11-3/8% 90,319 160,319
2019 2024 7% 10-3/8% 1,083,818 588,550
G&R Bonds
1993 1998 5.95% 14.95%** 284,200 383,600
1999 2023 6-5/8% 8.65% 350,000 -
Governmental Obligations ***
1992 2008 6.125% 10% 139,009 115,383
2009 2023 5.95% 12.5% 1,481,678 963,382
Debentures - Due 1998, 9.72% 200,000 -
Long-Term DOE Obligation (Note 8) 101,029 97,959
Waterford 3 Lease Obligation, 8.76% (Note 9) 353,600 353,600
Grand Gulf Lease Obligation, 7.02% (Note 9) 500,000 500,000
Other Long-Term Debt 6,879 21,737
Unamortized Premium and Discount - Net (45,890) (35,778)
---------- ----------
Total Long-Term Debt 7,677,972 5,283,149
Less Amount Due Within One Year 322,010 133,805
---------- ----------
Long-Term Debt Excluding Amount Due Within One Year $7,355,962 $5,149,344
========== ==========
* The 14% series of $200 million is due 11/15/94. All other series are
at interest rates within the range of 4-5/8% - 11.375%.
** The 14.95% series of $20 million is due 2/1/95. All other series are at
interest rates within the range of 5.95% - 11.2%.
*** Consists of pollution control bonds and municipal revenue bonds,
certain series of which are secured by non-interest bearing first mortgage
bonds.
The fair value of Entergy Corporation's long-term debt (excluding GSU in
1992), excluding lease obligations and long-term DOE obligations, as of
December 31, 1993 and 1992, was estimated to be $7,207.3 million and $4,662.3
million, respectively. The fair values were determined using bid prices
reported by dealer markets and by nationally recognized investment banking
firms.
For the years 1994, 1995, 1996, 1997, and 1998, Entergy Corporation's
subsidiaries have long-term debt maturities (excluding lease obligations) and
cash sinking fund requirements in the aggregate of (in millions) $321.4, $378.4,
$558.4, $361.9, and $315.9, respectively. In addition, other sinking fund
requirements will be satisfied by cash or by certification of property additions
at the rate of 167% of such requirements. The amounts associated with this
provision total approximately $11.2 million for each of the years 1994 through
1998.
NOTE 7. DIVIDEND RESTRICTIONS
Various agreements relating to the long-term debt and preferred stock of
Entergy Corporation's subsidiaries restrict the payment of cash dividends or
other distributions on their common stock. In addition to these restrictions,
the Public Utility Holding Company Act of 1935 prohibits Entergy Corporation's
subsidiaries from making loans or advances to Entergy Corporation. As of
December 31, 1993, Entergy Corporation's subsidiaries had restricted common
equity of approximately $5,165.4 million, including $1,167.8 million of
restricted retained earnings, which were unavailable for distribution to Entergy
Corporation. In February 1994, Entergy Corporation received common stock
dividend payments totaling $198.2 million, including $100 million from GSU.
Prior to this, GSU had not paid a common stock dividend since June 1986.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Cajun - River Bend
GSU has significant business relationships with Cajun, primarily co-
ownership of River Bend and Big Cajun 2 Unit 3. GSU and Cajun own 70% and 30%
of River Bend, respectively, while Big Cajun 2 Unit 3 is owned 42% and 58% by
GSU and Cajun, respectively. GSU operates River Bend and Cajun operates Big
Cajun 2 Unit 3.
In June 1989, Cajun filed a civil action against GSU in the U. S. District
Court for the Middle District of Louisiana. Cajun stated in its complaint that
the object of the suit is to annul, rescind, terminate, and/or dissolve the
Joint Ownership Participation and Operating Agreement entered into on August 28,
1979 (Operating Agreement), related to River Bend. Cajun alleges fraud and
error by GSU, breach of its fiduciary duties owed to Cajun, and/or GSU's
repudiation, renunciation, abandonment, or dissolution of its core obligations
under the Operating Agreement, as well as the lack or failure of cause and/or
consideration for Cajun's performance under the Operating Agreement. The suit
seeks to recover Cajun's alleged $1.6 billion investment in the unit as damages,
plus attorneys' fees, interest, and costs.
In March 1992, the district court appointed a mediator to engage in
settlement discussions and to schedule settlement conferences between the
parties. Discussions with the mediator began in July 1992, however, GSU cannot
predict what effect, if any, such discussions will have on the timing or outcome
of the case. A trial without a jury is set for April 12, 1994, on the portion
of the suit by Cajun to rescind the Operating Agreement. Two member
cooperatives of Cajun have brought an independent action to declare the River
Bend Operating Agreement void, based upon failure to get prior LPSC approval
alleged to be necessary. GSU believes the suits are without merit and is
contesting them vigorously. No assurance can be given as to the outcome of this
litigation. If GSU were ultimately unsuccessful in this litigation and were
required to make substantial payments, GSU would probably be unable to make such
payments and would probably have to seek relief from its creditors under the
Bankruptcy Code.
See Note 11 for the accounting treatment of preacquisition contingencies,
including a charge resulting from an adverse resolution in the Cajun - River
Bend litigation.
In July 1992, Cajun notified GSU that it would fund a limited amount of
costs related to the fourth refueling outage at River Bend, completed in
September 1992. Cajun has also not funded its share of the costs associated
with certain additional repairs and improvements at River Bend completed during
the refueling outage. GSU has paid the costs associated with such repairs and
improvements without waiving any rights against Cajun. GSU believes that Cajun
is obligated to pay its share of such costs under the terms of the applicable
contract. Cajun has filed a suit seeking a declaration that it does not owe
such funds and seeking injunctive relief against GSU. GSU is contesting such
suit and is reviewing its available legal remedies.
In September 1992, GSU received a letter from Cajun alleging that the
operating and maintenance costs for River Bend are "far in excess of industry
averages" and that "it would be imprudent for Cajun to fund these excessive
costs." Cajun further stated that until it is satisfied it would fund a maximum
of $700,000 per week under protest for the remainder of 1992. In a December
1992 letter, Cajun stated that it would also withhold costs associated with
certain additional repairs, of which the majority will be incurred during the
next refueling outage, currently scheduled for April 1994. GSU believes that
Cajun's allegations are without merit and is considering its legal and other
remedies available with respect to the underpayments by Cajun. The total
resulting from Cajun's failure to fund repair projects, Cajun's funding
limitation on the fourth refueling outage, and the weekly funding limitation by
Cajun was $33.3 million as of December 31, 1993, compared with a $28.4 million
unfunded balance as of December 31, 1992. These amounts are reflected in long-
term receivables.
During 1994, and for the next several years, it is expected that Cajun's
share of River Bend-related costs will be in the range of $60 million to $70
million per year. Cajun's weak financial condition could have a material
adverse effect on GSU, including a possible NRC action with respect to the
operation of River Bend and a need to bear additional costs associated with the
co-owned facilities. If GSU were required to fund Cajun's share of costs, there
can be no assurance that such payments could be recovered. Cajun's weak
financial condition could also affect the ultimate collectibility of amounts
owed to GSU.
Cajun - Transmission Service
GSU and Cajun are parties to FERC proceedings related to transmission
service charge disputes. In April 1992, FERC issued a final order and in May
1992 GSU and Cajun filed motions for rehearings which are pending consideration
by FERC. In June 1992, GSU filed a petition for review in the United States
Court of Appeals regarding certain of the issues decided by FERC. In August
1993, the United States Court of Appeals rendered an opinion reversing the FERC
order regarding the portion of such disputes relating to the calculations of
certain credits and equalization charges under GSU's service schedules with
Cajun. The opinion remanded the issues to FERC for further proceedings
consistent with its opinion. In January 1994, FERC denied GSU's request to
collect a surcharge while FERC considers the court's remand.
GSU interprets the FERC order and the court of appeals' decision to mean
that Cajun would owe GSU approximately $85 million as of December 31, 1993. GSU
further estimates that if it prevails in its May 1992 motion for rehearing,
Cajun would owe GSU approximately $118 million as of December 31, 1993. If
Cajun were to prevail in its May 1992 motion for rehearing to FERC, and if GSU
were not to prevail in its May 1992 motion for rehearing to FERC, and if FERC
does not implement the court's remand as GSU contends is required, GSU estimates
it would owe Cajun approximately $76 million as of December 31, 1993. The above
amounts are exclusive of a $7.3 million payment by Cajun on December 31, 1990,
which the parties agreed to apply to the disputed transmission service charges.
GSU and Cajun further agreed that their positions at FERC would remain
unaffected by the $7.3 million. Pending FERC's ruling on the May 1992 motions
for rehearing, GSU has continued to bill Cajun utilizing the historical billing
methodology and has booked underpaid transmission charges, including interest,
in the amount of $140.8 million as of December 31, 1993. This amount is
reflected in long-term receivables and in other deferred credits, with no effect
on net income.
Capital Requirements and Financing
Construction expenditures (excluding nuclear fuel) for the years 1994,
1995, and 1996 are estimated to total $586 million, $560 million, and
$550 million, respectively. The System will also require $1,362 million during
the period 1994-1996 to meet long-term debt and preferred stock maturities and
cash sinking fund requirements. The System plans to meet the above requirements
primarily with internally generated funds and cash on hand, supplemented by the
issuance of debt and preferred stock. Certain System companies may also
continue with the acquisition or refinancing of all or a portion of certain
outstanding series of preferred stock and long-term debt. See Note 12 for
information on additional capital requirements related to a February 1994 ice
storm.
Capital Funds and Availability Agreements
Entergy Corporation has agreed to arrange for or supply to System Energy
sufficient amounts of capital to (1) maintain System Energy's equity capital at
not less than 35% of System Energy's total capitalization (excluding short-term
debt), and (2) continue commercial operation of Grand Gulf 1 and enable System
Energy to pay its borrowings. In addition, under supplements to the Capital
Funds Agreement assigning System Energy's rights as security for specific debt
of System Energy, Entergy Corporation has agreed to make cash capital
contributions to enable System Energy to make payments on such debt when due.
System Energy has entered into various agreements with AP&L, LP&L, MP&L,
and NOPSI, whereby AP&L, LP&L, MP&L, and NOPSI are obligated to purchase their
respective entitlements of capacity and energy from System Energy's 90%
ownership and leasehold interest in Grand Gulf 1, and to make payments that,
together with other available funds, are adequate to cover System Energy's
operating expenses. System Energy would have to secure funds from other
sources, including Entergy Corporation's obligations under the Capital Funds
Agreement, to cover any shortfalls from payments received from AP&L, LP&L, MP&L,
and NOPSI under these agreements.
Long-Term Contracts
The System has several long-term contracts to purchase natural gas and
low-sulfur coal for use at its generating units. LP&L has a long-term agreement
through the year 2031 to purchase energy generated by a hydroelectric facility.
If the maximum percentage (94%) of the energy is made available to LP&L, current
production projections would require estimated payments of approximately
$47 million per year through 1996, $54 million in 1997, and a total of $3.5
billion for the years 1998 through 2031. LP&L recovers the cost of purchased
energy through its fuel adjustment clause.
In 1988, GSU entered into a joint venture with a primary term of 20 years
with Conoco, Inc., Citgo Petroleum Corporation, and Vista Chemical Company
(Industrial Participants) whereby GSU's Nelson Units 1 and 2 were sold to a
partnership (NISCO) consisting of the Industrial Participants and GSU. The
Industrial Participants are supplying the fuel for the units, while GSU operates
the units at the discretion of the Industrial Participants and purchases the
electricity produced by the units. GSU is continuing to sell electricity to the
Industrial Participants. For the years ended December 31, 1993, 1992, and 1991,
the purchases of electricity from the joint venture totaled $62.6 million, $37.8
million, and $61.3 million, respectively.
Nuclear Insurance
The Price-Anderson Act limits public liability for a single nuclear
incident to approximately $9.4 billion as of December 31, 1993. The System has
protection for this liability through a combination of private insurance
(currently $200 million) and an industry assessment program. Under the
assessment program, the maximum amount the System would be required to pay for
each nuclear incident would be $79.28 million per reactor, payable at a rate of
$10 million per licensed reactor per incident per year. As a co-licensee of
Grand Gulf 1 with System Energy, South Mississippi Electric Power Association
(SMEPA) would share 10% of this obligation. With respect to River Bend, any
assessments pertaining to this program are subject to the 70/30% ownership
interest between GSU and Cajun. The System has five licensed reactors. In
addition, the System participates in a private insurance program which provides
coverage for worker tort claims filed for bodily injury caused by radiation
exposure. The program provides for a maximum assessment of approximately
$15.5 million for the System's five nuclear units, in the event losses exceed
accumulated reserve funds.
AP&L, GSU, LP&L, and System Energy are also members of certain insurance
programs that provide coverage for property damage, including decontamination
and premature decommissioning expense, to members' nuclear generating plants.
As of December 31, 1993, AP&L, GSU, LP&L, and System Energy each were insured
against such losses up to $2.7 billion, with $250 million of this amount
designated to cover any shortfall in the NRC required decommissioning trust
funding. In addition, AP&L, GSU, LP&L, MP&L, and NOPSI are members of an
insurance program that covers certain replacement power and business
interruption costs incurred due to prolonged nuclear unit outages. Under the
property damage and replacement power/business interruption insurance programs,
these System companies could be subject to assessments if losses exceed the
accumulated funds available to the insurers. As of December 31, 1993, the
maximum amounts of such possible assessments were: AP&L - $28.14 million; GSU -
$15.9 million; LP&L - $24.34 million; MP&L - $0.63 million; NOPSI -
$0.34 million, and System Energy - $21.89 million. Under its agreement with
System Energy, SMEPA would share in System Energy's obligation. Cajun shares
approximately $4.02 million of GSU's obligation.
The amount of property insurance carried by the System exceeds the NRC's
minimum requirement for nuclear power plant licensees of $1.06 billion per site.
NRC regulations provide that the proceeds of this insurance must be used, first,
to place and maintain the reactor in a safe and stable condition and, second, to
complete decontamination operations. Only after proceeds are dedicated for such
use and regulatory approval is secured, would any remaining proceeds be made
available for the benefit of plant owners or their creditors.
Spent Nuclear Fuel and Decommissioning Costs
AP&L, GSU, LP&L, and System Energy provide for estimated future disposal
costs for spent nuclear fuel in accordance with the Nuclear Waste Policy Act of
1982. The affected System companies entered into contracts with the Department
of Energy (DOE), whereby the DOE will furnish disposal service at a cost of one
mill per net KWH generated and sold after April 7, 1983, plus a one-time fee for
generation prior to that date. AP&L, the only System company that generated
electricity with nuclear fuel prior to that date, elected to pay the one-time
fee, plus accrued interest, no earlier than 1998, and has recorded a liability
as of December 31, 1993, of approximately $101.0 million. The fees payable to
the DOE may be adjusted in the future to assure full recovery. The System
considers all costs incurred or to be incurred, except accrued interest, for the
disposal of spent nuclear fuel to be proper components of nuclear fuel expense,
and provisions to recover such costs have been or will be made in applications
to regulatory authorities.
Due to delays of the DOE repository program for the acceptance of spent
nuclear fuel, it is uncertain when shipments of spent fuel from the System's
nuclear units will commence. In the meantime, the affected companies are
responsible for spent fuel storage. Current on-site spent fuel storage capacity
at ANO, River Bend, Waterford 3, and Grand Gulf 1 is estimated to be sufficient
until 1995, 2003, 2000, and 2004, respectively. Thereafter, the affected
companies will provide additional storage. The initial cost of providing the
additional on-site spent fuel storage capability required at ANO, River Bend,
Waterford 3, and Grand Gulf 1 is approximately $5 million to $10 million per
unit. In addition, approximately $3 million to $5 million per unit will be
required every two to three years subsequent to 1995 for ANO and every four to
five years subsequent to 2003, 2000, and 2004 for River Bend, Waterford 3, and
Grand Gulf 1, respectively, until the DOE's repository begins accepting such
units' spent fuel.
Decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf 1
were estimated to be approximately $606.8 million (based on a 1992 update to the
original cost study), $141.0 million (based on a 1985 cost study), $203.0
million (based on a 1988 update to the original cost study), and $248.7 million
(based on a 1989 cost study), respectively. AP&L and GSU are authorized to
recover through rates amounts that, when added to estimated investment income,
should be sufficient to meet the above estimated decommissioning costs for ANO
and River Bend. However, GSU did a 1991 update to the cost study which
indicated decommissioning costs for River Bend may be approximately $279.8
million. The results of the 1991 update have not yet been added into GSU's
rates and used as a basis for funding. During the first quarter of 1994, AP&L
expects to prepare and file with the APSC an interim update of the ANO cost
study, which will likely reflect significant increases in costs of low-level
radioactive waste disposal. The LPSC authorized LP&L to recover $4.0 million
annually through 1993, based on the 1988 study update. LP&L will begin funding
$4.8 million in 1994 in anticipation of a 1994 study update and a related LPSC
review and determination of appropriate funding levels. System Energy is
currently recovering in rates amounts sufficient to fund $198.0 million (in 1989
dollars) of its decommissioning costs, and an updated cost study is scheduled to
be completed by mid-1994. AP&L, GSU, LP&L, and System Energy regularly review
and update estimated decommissioning costs, and applications will be made to the
appropriate regulatory authorities to reflect in rates any future change in
projected decommissioning costs. The amounts recovered in rates are deposited
in external trust funds which have a market value of $193.1 million and $138.5
million (excluding GSU in 1992) as of December 31, 1993 and 1992, respectively.
The accumulated decommissioning liability has been recorded in accumulated
depreciation for AP&L, GSU, and LP&L, and in other deferred credits for System
Energy, in the amounts of $119.2 million, $18.1 million, $22.1 million, and
$24.8 million, respectively, as of December 31, 1993. Decommissioning expense
amounting to $19.9 million was recorded in 1993. The actual decommissioning
costs may vary from the above estimates because of regulatory requirements,
changes in technology, and increased costs of labor, materials, and equipment,
and management believes that actual decommissioning costs are likely to be
higher than the amounts presented above.
The Energy Act has a provision that assesses domestic nuclear utilities
with fees for the decontamination and decommissioning of the DOE's past uranium
enrichment operations. The decontamination and decommissioning assessments will
be used to set up a fund into which contributions from utilities and the federal
government will be placed. AP&L's, GSU's, LP&L's, and System Energy's annual
assessments, which will be adjusted annually for inflation, are approximately
$3.3 million, $0.6 million, $1.2 million, and $1.3 million (in 1993 dollars),
respectively, for approximately 15 years. FERC requires that utilities treat
these assessments as costs of fuel as they are amortized. The cumulative
liability of $87.4 million as of December 31, 1993, is recorded in other current
liabilities and other noncurrent liabilities and is offset in the consolidated
financial statements by a regulatory asset, recorded as a deferred debit.
NOTE 9. LEASES
General
As of December 31, 1993, the System had capital leases and noncancelable
operating leases (excluding nuclear fuel leases and the sale and leaseback
transactions discussed below) with minimum lease payments as follows:
Capital Operating
Year Leases Leases
---- -------- ---------
(In Thousands)
1994 $ 33,780 $ 43,337
1995 33,880 42,527
1996 29,490 39,235
1997 24,654 20,820
1998 24,654 22,532
Years thereafter 160,903 180,651
-------- --------
Minimum lease payments 307,361 $349,102
Less: Amount representing interest 121,708 ========
--------
Present value of net minimum lease payments $185,653
========
Rental expense for capital and operating leases (excluding nuclear fuel
leases and the sale and leaseback transactions) amounted to approximately $62.7
million, $75.5 million, and $73.8 million in 1993, 1992, and 1991, respectively.
Nuclear Fuel Leases
AP&L, GSU, LP&L, and System Energy have arrangements to lease nuclear fuel
in an aggregate amount up to $455 million as of December 31, 1993. The lessors
finance their acquisitions of nuclear fuel through credit agreements and the
issuance of notes. If a lessor cannot arrange financing upon maturity of its
borrowings, the lessee must purchase nuclear fuel in an amount sufficient to
enable the lessor to retire such borrowings.
Lease payments are based on nuclear fuel use. Nuclear fuel lease expense
for AP&L, LP&L, and System Energy of $145.8 million, $158.4 million, and $185.6
million (including interest of $20.5 million, $25.6 million, and $32.7 million)
was charged to operations in 1993, 1992, and 1991, respectively.
Sale and Leaseback Transactions
In 1988 and 1989, System Energy and LP&L, respectively, sold and leased
back portions of their ownership interests in Grand Gulf 1 and Waterford 3, for
26- and 28-year lease terms, respectively. Both companies have options to
terminate the leases, to repurchase the sold interests, or to renew the leases
at the end of their terms.
Under System Energy's sale and leaseback arrangements, letters of credit
are required to be maintained to secure certain amounts payable, for the benefit
of equity investors, by System Energy under the leases. The letters of credit
currently maintained are effective until January 1997. It is expected that the
letters of credit will either be renewed, extended, or replaced prior to
expiration. On January 11, 1994, System Energy refinanced the debt portion of
the sale and leaseback arrangements. The new secured lease obligation bonds of
$356 million, 7.43% series due 2011 and $79 million, 8.2% series due 2014 will
be indirectly secured by liens on, and a security interest in, certain ownership
interests and the respective leases relating to Grand Gulf 1.
If LP&L does not exercise its option to repurchase the lease interests in
Waterford 3 in September 1994, LP&L will be required to provide collateral to
secure the equity portion of certain of its obligations under the lease. This
collateral would be either a letter of credit or a new series of first mortgage
bonds issued by LP&L.
As of December 31, 1993, System Energy and LP&L had future minimum lease
payments (reflecting implicit rates of 7.02% after the above refinancing and
8.76%, respectively) as follows:
System
Energy LP&L
---------- --------
(In Thousands)
1994 $ 17,423* $ 32,568
1995 42,464 32,569
1996 42,753 35,165
1997 42,753 39,805
1998 42,753 41,447
Years thereafter 845,573 726,744
---------- --------
Total $1,033,719 $908,298
========== ========
* An additional $24 million payment was made in January 1994 prior to the
refinancing of the debt portion of the sale/leaseback arrangements.
NOTE 10. POSTRETIREMENT BENEFITS
Pension Plans
The System companies have various postretirement benefit plans covering
substantially all of their employees. The pension plans are noncontributory and
provide pension benefits that are based on employees' credited service and
compensation during the final years before retirement. Entergy Corporation and
its subsidiaries fund pension costs in accordance with contribution guidelines
established by the Employee Retirement Income Security Act of 1974, as amended,
and the Internal Revenue Code of 1986, as amended. The assets of the plans
include common and preferred stocks, fixed income securities, interest in a
money market fund, and insurance contracts.
Total 1993, 1992, and 1991 pension cost of Entergy Corporation and its
subsidiaries, including amounts capitalized, included the following components:
<CAPTION
For the Years Ended December 31,
----------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Service cost - benefits earned during the period $ 21,760 $ 18,784 $ 16,393
Interest cost on projected benefit obligation 53,371 50,225 44,367
Actual return on plan assets (81,708) (43,772) (120,705)
Net amortization and deferral 27,261 (8,243) 70,760
Other - - 2,888
-------- -------- ---------
Net pension cost $ 20,684 $ 16,994 $ 13,703
======== ======== =========
The funded status of Entergy's various pension plans as of December 31,
1993 and 1992 (excluding GSU in 1992), was:
1993 1992
---------- --------
(In Thousands)
Actuarial present value of accumulated pension plan obligation:
Vested $ 821,292 $552,437
Nonvested 17,867 2,999
---------- --------
Accumulated benefit obligation $ 839,159 $555,436
========== ========
Plan assets at fair value $1,059,715 $647,120
Projected benefit obligation 1,041,104 666,626
---------- --------
Plan assets in excess of (less than) projected benefit obligation 18,611 (19,506)
Unrecognized prior service cost 20,288 21,723
Unrecognized transition asset (61,561) (68,914)
Unrecognized net loss (gain) 32,634 (13,473)
---------- --------
Accrued pension asset (liability) $ 9,972 $(80,170)
========== ========
The significant actuarial assumptions used in computing the information
above for 1993, 1992, and 1991 (only 1993 with respect to GSU's plan), were as
follows: weighted average discount rate, 7.5% for 1993 and 8.25% for 1992 and
1991 (7.5% for GSU); weighted average rate of increase in future compensation
levels, 5.6% (5.0% for GSU); and expected long-term rate of return on plan
assets, 8.5% (8.5% for GSU). Transition assets of the System are being
amortized over the greater of the remaining service period of active
participants or 15 years.
Other Postretirement Benefits
The System companies also provide certain health care and life insurance
benefits for retired employees. Substantially all employees may become eligible
for these benefits if they reach retirement age while still working for the
System companies. The cost of providing these benefits, recorded on a cash
basis, to retirees in 1992 was approximately $13 million. Prior to 1992, the
cost of providing these benefits for retirees was not separable from the cost of
providing benefits for active employees. Based on the ratio of the number of
retired employees to the total number of active and retired employees in 1991,
the cost of providing these benefits, recorded on a cash basis, for retirees was
approximately $11.8 million.
Effective January 1, 1993, Entergy adopted SFAS 106. The new standard
requires a change from a cash method to an accrual method of accounting for
postretirement benefits other than pensions. The System operating companies
continue to fund these benefits on a pay-as-you-go basis. At January 1, 1993,
the actuarially determined accumulated postretirement benefit obligation (APBO)
earned by retirees and active employees was estimated to be approximately
$241.4 million and $128.0 million for Entergy and for GSU, respectively. Such
obligations are being amortized over a 20-year period beginning in 1993.
The System operating companies have sought approval, in their respective
regulatory jurisdictions, to implement the appropriate accounting requirements
related to SFAS 106 for ratemaking purposes. AP&L has received an order
permitting deferral, as a regulatory asset, of these costs. MP&L is expensing
its SFAS 106 costs, which will be reflected in rates pursuant to an order from
the MPSC in connection with MP&L's formulary incentive rate plan (see Note 2).
The LPSC ordered GSU and LP&L to use the pay-as-you-go method for ratemaking
purposes for postretirement benefits other than pensions but the LPSC retains
the flexibility to examine individual companies' accounting for postretirement
benefits to determine if special exceptions to this order are warranted. NOPSI
is expensing its SFAS 106 costs. Pursuant to resolutions adopted in November
1993 by the Council related to the Merger, NOPSI's SFAS 106 expenses through
October 31, 1996, will be allowed by the Council for purposes of evaluating the
appropriateness of NOPSI's rates. Pursuant to a ruling by the PUCT applicable
to all Texas utilities, including GSU, amounts recorded in compliance with SFAS
106 and included in a rate filing test period, will be recoverable in rates (at
the time of the next general rate case), and postretirement benefits amounts
allowed in rates must then be funded by the utility. The System's net income in
1993 (excluding GSU) was decreased by approximately $9 million as a result of
adopting SFAS 106.
Total 1993 postretirement benefit cost of Entergy Corporation and its
subsidiaries (excluding GSU), including amounts capitalized and deferred,
included the following components (in thousands):
Service cost - benefits earned during the period $ 7,751
Interest cost on APBO 19,394
Return on plan assets (71)
Amortization of transition obligation 12,071
-------
Net periodic postretirement benefit cost $39,145
=======
The funded status of Entergy's postretirement plans as of December 31,
1993, was (in thousands):
Accumulated postretirement benefit obligation:
Retirees $ 221,562
Other fully eligible participants 68,283
Other active participants 95,854
---------
385,699
Plan assets at fair value 354
---------
Plan assets less than APBO (385,345)
Unrecognized transition obligation 229,346
Unrecognized net loss 28,529
---------
Accrued postretirement benefit liability $(127,470)
=========
The assumed health care cost trend rate used in measuring the APBO of the
System companies, excluding GSU, was 9.9% for 1994 (10% for GSU), gradually
decreasing each successive year until it reaches 5.6% in 2020 (5% for GSU in
2002). A one percentage-point increase in the assumed health care cost trend
rate for each year would have increased the APBO of the System companies,
excluding GSU, as of December 31, 1993, by 8.9%, (13.6% for GSU) and the sum of
the service cost and interest cost by approximately 11.4% (22.7% for GSU). The
assumed discount rate and rate of increase in future compensation used in
determining the APBO were 7.5% (7.5% for GSU) and 5.5% (5% for GSU),
respectively.
NOTE 11. ENTERGY CORPORATION-GSU MERGER
On December 31, 1993, GSU became a wholly-owned subsidiary of Entergy
Corporation and continues to operate as a public utility under the regulation of
the PUCT and the LPSC. As consideration to GSU's shareholders, Entergy
Corporation paid $250 million and issued 56,667,726 shares of its common stock
at a price of $35.8417 per share. In addition, $33.5 million of transaction
costs were capitalized in connection with the Merger. The Merger was accounted
for under the purchase method of accounting. Various parties have requested
rehearings and/or are appealing the approval orders or plans of the SEC, NRC,
LPSC, and FERC.
The Consolidated Balance Sheet of Entergy Corporation as of December 31,
1993, includes the accounts of GSU and, therefore, is not directly comparable to
the Consolidated Balance Sheet presented as of December 31, 1992. Entergy
Corporation recorded an acquisition adjustment in utility plant in the amount of
$380 million representing the excess of the purchase price over the net assets
acquired of GSU. The acquisition adjustment will be amortized on a straight-
line basis over a 31-year period, which approximates the remaining average book
life of the plant being acquired.
The allocation of the purchase price has been based on preliminary
estimates which may be revised at a later date. The possibility of an adverse
result in the litigation relating to Cajun (see Note 8) and the possibility of a
write-off relating to Texas River Bend ratemaking issues (see Note 2) represent
preacquisition contingencies. There may be other contingencies associated with
GSU which could also constitute preacquisition contingencies but which have not
yet been specifically identified as such by Entergy Corporation. During the
allocation period (which will not exceed one year after consummation of the
transaction), Entergy Corporation will complete its analyses with respect to
these contingencies. Upon completion, should Entergy Corporation no longer
believe GSU has a reasonable possibility of attaining a favorable ruling in such
preacquisition contingencies, any resulting write-offs and/or losses would cause
the reduction of the affected noncurrent assets and an increase of an equal
amount in the acquisition adjustment in Entergy Corporation's consolidated
financial statements, in accordance with the purchase method of accounting for
business combinations.
In accordance with the purchase method of accounting, the 12-month results
of operations for Entergy Corporation reported in its Statements of Consolidated
Income, Cash Flows, and Retained Earnings do not reflect GSU's results of
operations for any period as a result of the December 31, 1993, closing date of
the Merger. The pro forma combined revenues, net income, earnings per common
share before extraordinary items and cumulative effect of accounting changes,
and earnings per common share of Entergy Corporation presented below give effect
to the Merger as if it had occurred at January 1, 1992. This pro forma
information is not necessarily indicative of the results of operation that would
have occurred had the Merger been consummated for the period for which it is
being given effect, nor is it necessarily indicative of future operating
results.
Year Ended December 31,
-----------------------
1993 1992
---------- ----------
(In Thousands, Except Per Share Amounts)
Revenues $6,286,999 $5,850,973
Net income $ 595,211 $ 521,783
Earnings per average common share
before extraordinary items and
cumulative effect of accounting $ 2.10 $ 2.26
changes
Earnings per average common share $ 2.57 $ 2.24
NOTE 12. SUBSEQUENT EVENT (UNAUDITED)
In early February 1994, an ice storm left more than 221,000 Entergy
customers without electric power across the System's four-state service area.
The storm was the most severe natural disaster ever to affect the System,
causing damage to transmission and distribution lines, equipment, poles, and
facilities in certain areas, primarily in Mississippi. A substantial portion of
the related costs, which are estimated to be $110 million to $140 million, are
expected to be capitalized. The MPSC acknowledged that there is precedent in
Mississippi for recovery of certain costs associated with storms and natural
disasters and the restoration of service resulting from such events. MP&L plans
to immediately file for rate recovery of the costs related to the ice storm.
Estimated construction expenditures (see Note 8) have not yet been updated to
reflect the above amounts.
NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED)
The business of the System is subject to seasonal fluctuations with the
peak period occurring during the third quarter. Consolidated operating results
for the four quarters of 1993 and 1992 were:
Operating Operating Net Earnings
Revenues Income Income per Share
----------- ---------- -------- ---------
(In Thousands, Except Per Share Amounts)
1993:
First Quarter (1) $ 926,412 $192,743 $151,154 $0.86
Second Quarter $1,070,102 $260,574 $130,860 $0.75
Third Quarter $1,410,951 $359,938 $233,430 $1.34
Fourth Quarter $1,077,872 $180,086 $ 36,486 $0.21
1992:
First Quarter (2) $ 916,467 $211,679 $ 95,277 $0.54
Second Quarter $ 958,121 $220,141 $ 82,102 $0.46
Third Quarter $1,237,894 $340,361 $204,578 $1.16
Fourth Quarter $1,004,017 $186,405 $ 55,680 $0.32
(1) The first quarter of 1993 reflects a nonrecurring increase in net income of
$93.8 million, net of taxes of $57.2 million, and a $0.54 increase in
earnings per share, due to the recording of the cumulative effect of the
change in accounting principle for unbilled revenues (see Note 1).
Beginning with the second quarter, the remaining quarters are not generally
comparable to prior year quarters because of the ongoing effects of the
accounting change.
(2) The first quarter of 1992 reflects a nonrecurring increase in net income of
$19.6 million, net of tax, and a $0.11 increase in earnings per share, due
to the AP&L sale of retail properties in Missouri.
ENTERGY CORPORATION AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1993 1992 1991 1990 1989
----------- ----------- ----------- ----------- -----------
(In Thousands, Except Per Share Amounts)
Operating revenues $ 4,485,337 $ 4,116,499 $ 4,051,429 $ 3,982,062 $ 3,724,004
Income (loss) before cumulative
effect of a change in
accounting principle $ 458,089 $ 437,637 $ 482,032 $ 478,318 $ (472,585)
Earnings (loss) per share before
cumulative effect of a change
in accounting principle $ 2.62 $ 2.48 $ 2.64 $ 2.44 $ (2.31)
Dividends declared per share $ 1.65 $ 1.45 $ 1.25 $ 1.05 $ 0.90
Book value per share, year-end (2) $ 28.27 $ 24.35 $ 23.46 $ 22.18 $ 20.62
Total assets (2) $22,876,697 $14,239,537 $14,383,102 $14,831,394 $14,715,241
Long-term obligations (1)(2) $ 8,177,882 $ 5,630,505 $ 5,801,364 $ 6,395,951 $ 6,711,509
(1) Includes long-term debt (excluding currently maturing debt), preferred and
preference stock with sinking fund, and noncurrent capital lease
obligations.
(2) 1993 amounts include the effects of the Merger in accordance with the
purchase method of accounting for combinations (see Note 11).
See Notes 1, 3, and 10 for the effect of the accounting changes in 1993.
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
(Dollars in Thousands)
Electric Operating Revenues:
Residential $1,596,480 $1,440,360 $1,463,281 $1,449,768 $1,331,154
Commercial 1,072,583 1,007,420 996,619 988,409 930,345
Industrial 1,199,172 1,097,023 1,068,802 1,051,796 1,021,456
Governmental 136,649 127,753 128,762 124,597 121,912
---------- ---------- ---------- ---------- ----------
Total retail 4,004,884 3,672,556 3,657,464 3,614,570 3,404,867
Sales for resale 293,894 252,288 220,347 212,504 177,014
Other 95,568 118,711 96,667 67,045 51,756
---------- ---------- ---------- ---------- ----------
Total $4,394,346 $4,043,555 $3,974,478 $3,894,119 $3,633,637
========== ========== ========== ========== ==========
Billed Electric Energy
Sales (Millions of KWH):
Residential 18,946 17,549 18,329 18,174 17,245
Commercial 13,420 12,928 13,164 12,977 12,533
Industrial 24,889 23,610 23,466 22,795 22,396
Governmental 1,887 1,839 1,903 1,831 1,833
---------- ---------- ---------- ---------- ----------
Total retail 59,142 55,926 56,862 55,777 54,007
Sales for resale 8,291 7,979 7,346 6,292 4,857
---------- ---------- ---------- ---------- ----------
Total 67,433 63,905 64,208 62,069 58,864
========== ========== ========== ========== ==========
ARKANSAS POWER & LIGHT COMPANY
1993 FINANCIAL STATEMENTS
ARKANSAS POWER & LIGHT COMPANY
DEFINITIONS
Certain abbreviations or acronyms used in AP&L's Financial Statements,
Notes to Financial Statements, and Management's Financial Discussion and
Analysis are defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
ANO Arkansas Nuclear One Steam Electric Generating Station
ANO 1 Unit No. 1 of ANO
ANO 2 Unit No. 2 of ANO
AP&L Arkansas Power & Light Company
APSC Arkansas Public Service Commission
DOE United States Department of Energy
Entergy or System Entergy Corporation and its various direct and indirect
subsidiaries
Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy
Corporation that has operating responsibility for Grand
Gulf 1, Waterford 3, ANO, and River Bend
Entergy Power Entergy Power, Inc., a subsidiary of Entergy
Corporation that markets capacity and energy for resale
from certain generating facilities to other parties,
principally non-affiliates
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Grand Gulf Station Grand Gulf Steam Electric Generating Station
Grand Gulf 1 Unit No. 1 of the Grand Gulf Station
Grand Gulf 2 Unit No. 2 of the Grand Gulf Station
GSU Gulf States Utilities Company (including wholly owned
subsidiaries - Varibus Corporation, GSG&T, Inc.,
Prudential Oil and Gas, Inc., and Southern Gulf Railway
Company)
Independence Station Independence Steam Electric Generating Station
Independence 2 Unit No. 2 of the Independence Station
KWH Kilowatt-Hour(s)
LP&L Louisiana Power & Light Company
Merger The combination transaction, consummated on December
31, 1993, by which GSU became a subsidiary of Entergy
Corporation and Entergy Corporation became a Delaware
Corporation
Money Pool Entergy Money Pool, which allows certain System
companies to borrow from, or lend to, certain other
System companies
MP&L Mississippi Power & Light Company
NOPSI New Orleans Public Service Inc.
NRC Nuclear Regulatory Commission
OBRA Omnibus Budget Reconciliation Act of 1993
Revised Settlement
Agreement Arkansas Settlement Agreement, as modified by the APSC
order issued October 6, 1988, to bring the Grand Gulf
1-related phase-in plan into compliance with the
requirements of SFAS No. 92, "Regulated Enterprises -
Accounting for Phase-in Plans"
Ritchie 2 Unit No. 2 of the Ritchie Steam Electric Generating
Station
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards promulgated
by the FASB
SFAS 106 SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions"
SFAS 109 SFAS No. 109, "Accounting for Income Taxes"
System or Entergy Entergy Corporation and its various direct and indirect
subsidiaries
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively
Union Electric Union Electric Company of St. Louis, Missouri
White Bluff Station White Bluff Steam Electric Generating Station
ARKANSAS POWER & LIGHT COMPANY
REPORT OF MANAGEMENT
The management of Arkansas Power & Light Company has prepared and is
responsible for the financial statements and related financial information
included herein. The financial statements are based on generally accepted
accounting principles. Financial information included elsewhere in this report
is consistent with the financial statements.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting controls that
is designed to provide reasonable assurance, on a cost-effective basis, as to
the integrity, objectivity, and reliability of the financial records, and as to
the protection of assets. This system includes communication through written
policies and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and the
training of personnel. This system is also tested by a comprehensive internal
audit program.
The independent public accountants provide an objective assessment of the
degree to which management meets its responsibility for fairness of financial
reporting. They regularly evaluate the system of internal accounting controls
and perform such tests and other procedures as they deem necessary to reach and
express an opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide reasonable
assurance that its operations are carried out with a high standard of business
conduct.
/S/ EDWIN LUPBERGER /S/ GERALD D. MCINVALE
EDWIN LUPBERGER GERALD D. MCINVALE
Chairman and Chief Executive Officer Senior Vice President and
Chief Financial Officer
ARKANSAS POWER & LIGHT COMPANY
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Arkansas Power & Light Company Audit Committee of the Board of
Directors is comprised of four directors, who are not officers of AP&L:
Kaneaster Hodges, Jr. (Chairman), Richard P. Herget, Jr., Dr. Raymond P.
Miller, Sr., and Gus B. Walton, Jr. The committee held four meetings during
1993.
The Audit Committee oversees AP&L's financial reporting process on behalf
of the Board of Directors and provides reasonable assurance to the Board that
sufficient operating, accounting, and financial controls are in existence and
are adequately reviewed by programs of internal and external audits.
The Audit Committee discussed with Entergy's internal auditors and the
independent public accountants (Deloitte & Touche) the overall scope and
specific plans for their respective audits, as well as AP&L's financial
statements and the adequacy of AP&L' s internal controls. The committee met,
together and separately, with Entergy's internal auditors and independent public
accountants, without management present, to discuss the results of their audits,
their evaluation of AP&L's internal controls, and the overall quality of AP&L's
financial reporting. The meetings also were designed to facilitate and
encourage any private communication between the committee and the internal
auditors or independent public accountants.
/S/ KANEASTER HODGES, JR.
KANEASTER HODGES, JR.
Chairman, Audit Committee
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of
Arkansas Power & Light Company
We have audited the accompanying balance sheets of Arkansas Power & Light
Company (AP&L) as of December 31, 1993 and 1992, and the related statements of
income, retained earnings, and cash flows for each of the three years in the
period ended December 31, 1993. These financial statements are the
responsibility of AP&L's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of AP&L at December 31, 1993 and 1992, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1993 in conformity with generally accepted accounting
principles.
As discussed in Note 1 to the financial statements, AP&L changed its method
of accounting for revenues in 1993 and, as discussed in Notes 3 and 10 to the
financial statements, in 1993 AP&L changed its methods of accounting for income
taxes and postretirement benefits other than pensions, respectively.
/S/ DELOITTE & TOUCHE
DELOITTE & TOUCHE
New Orleans, Louisiana
February 11, 1994
ARKANSAS POWER & LIGHT COMPANY
BALANCE SHEETS
ASSETS
December 31,
-----------------------
1993 1992
---------- ----------
(In Thousands)
Utility Plant (Notes 1 and 2):
Electric $4,098,355 $4,002,350
Property under capital leases (Note 9) 62,139 67,840
Construction work in progress 197,005 174,909
Nuclear fuel under capital lease (Note 9) 93,606 102,435
---------- ----------
Total 4,451,105 4,347,534
Less - accumulated depreciation and amortization 1,604,318 1,512,919
---------- ----------
Utility plant - net 2,846,787 2,834,615
---------- ----------
Other Property and Investments:
Investment in subsidiary companies - at equity (Note 8) 11,232 11,232
Decommissioning trust fund (Note 8) 108,192 91,075
Other - at cost (less accumulated depreciation) 4,257 3,498
---------- ----------
Total 123,681 105,805
---------- ----------
Current Assets:
Cash 1,825 -
Accounts receivable:
Customer (less allowance for doubtful accounts of
$2.1 million in 1993 and $1.6 million in 1992) 65,641 75,087
Associated companies (Note 11) 18,312 32,238
Other 20,817 6,881
Accrued unbilled revenues (Note 1) 83,378 -
Fuel inventory - at average cost 51,920 52,093
Materials and supplies - at average cost 81,398 91,000
Rate deferrals (Note 2) 92,592 69,536
Deferred excess capacity (Note 2) 9,115 8,395
Prepayments and other 28,303 35,918
---------- ----------
Total 453,301 371,148
---------- ----------
Deferred Debits:
Rate deferrals (Note 2) 475,387 574,040
Deferred excess capacity (Note 2) 28,465 38,300
SFAS 109 regulatory asset - net (Note 3) 234,015 -
Unamortized loss on reaquired debt 60,169 23,262
Other (Note 8) 112,300 91,641
---------- ----------
Total 910,336 727,243
---------- ----------
TOTAL $4,334,105 $4,038,811
========== ==========
See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
-----------------------
1993 1992
---------- ----------
(In Thousands)
Capitalization:
Common stock, $0.01 par value, authorized 325,000,000
shares; issued and outstanding 46,980,196 shares in
1993 and 1992 $470 $470
Paid-in capital 590,844 590,838
Retained earnings (Note 7) 448,811 420,691
---------- ----------
Total common shareholder's equity 1,040,125 1,011,999
Preferred stock (Note 5):
Without sinking fund 176,350 176,350
With sinking fund 70,027 85,527
Long-term debt (Note 6) 1,313,315 1,260,947
---------- ----------
Total 2,599,817 2,534,823
---------- ----------
Other Noncurrent Liabilities:
Obligations under capital leases (Note 9) 94,861 107,114
Other (Note 8) 59,750 86,020
---------- ----------
Total 154,611 193,134
---------- ----------
Current Liabilities:
Currently maturing long-term debt (Note 6) 3,020 17,900
Notes payable:
Associated companies (Note 4) 21,395 4,000
Other 667 667
Accounts payable:
Associated companies (Note 11) 45,177 36,757
Other 93,611 81,423
Customer deposits 15,241 14,926
Taxes accrued 43,013 64,996
Accumulated deferred income taxes (Note 3) 32,367 20,904
Interest accrued 31,410 31,209
Dividends declared 5,049 5,534
Nuclear refueling reserve 3,070 3,050
Co-owner advances (Note 1) 39,435 31,005
Deferred fuel cost (Note 1) 16,130 19,553
Obligations under capital leases (Note 9) 60,883 63,162
Other 29,789 25,842
---------- ----------
Total 440,257 420,928
---------- ----------
Deferred Credits:
Accumulated deferred income taxes (Note 3) 876,618 618,416
Accumulated deferred investment tax credits (Note 3) 154,723 165,296
Other 108,079 106,214
---------- ----------
Total 1,139,420 889,926
---------- ----------
Commitments and Contingencies (Notes 2, 8, and 9)
TOTAL $4,334,105 $4,038,811
========== ==========
See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
----------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Operating Activities:
Net income $205,297 $130,529 $143,451
Noncash items included in net income:
Cumulative effect of a change in accounting principle (50,187) - -
Change in rate deferrals/excess capacity - net (Note 2) 84,712 60,344 16,936
Depreciation and decommissioning 135,530 132,459 128,410
Deferred income taxes and investment tax credits (6,965) (820) 9,448
Allowance for equity funds used during construction (3,627) (4,173) (4,508)
Provision for estimated losses and reserves 1,963 (21,670) 7,786
Gain on sale of property - net - (19,612) -
Changes in working capital:
Receivables 7,385 (22,281) 10,948
Fuel inventory 173 17,039 (37,142)
Accounts payable 20,608 (5,393) (4,528)
Taxes accrued (21,983) (23,492) 2,514
Interest accrued 201 (8,041) (154)
Other working capital accounts 26,486 5,249 2,506
Decommissioning trust contributions (11,491) (13,255) (13,765)
Other (41,826) (2,736) (284)
-------- -------- --------
Net cash flow provided by operating activities 346,276 224,147 261,618
-------- -------- --------
Investing Activities:
Construction expenditures (176,540) (179,320) (156,734)
Proceeds received from sale of property (Note 2) - 67,985 -
Allowance for equity funds used during construction 3,627 4,173 4,508
Nuclear fuel purchases (29,156) (34,238) (32,900)
Proceeds from sale/leaseback of nuclear fuel 29,156 34,238 33,058
-------- -------- --------
Net cash flow used in investing activities (172,913) (107,162) (152,068)
-------- -------- --------
Financing Activities:
Proceeds from issuance of:
First mortgage bonds 445,000 148,114 -
Preferred stock - 14,222 48,175
Other long-term debt 48,070 3,973 18,607
Retirement of:
First mortgage bonds (441,141) (329,019) (35,598)
Other long-term debt (47,700) (1,225) (1,140)
Redemption of preferred stock (15,500) (34,388) (14,000)
Changes in short-term borrowings 17,395 4,000 -
Dividends paid:
Common stock (156,300) (75,000) (39,900)
Preferred stock (21,362) (23,730) (22,071)
-------- -------- --------
Net cash flow used in financing activities (171,538) (293,053) (45,927)
-------- -------- --------
Net increase (decrease) in cash and cash equivalents 1,825 (176,068) 63,623
Cash and cash equivalents at beginning of period - 176,068 112,445
-------- -------- --------
Cash and cash equivalents at end of period $1,825 - $176,068
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $103,826 $114,791 $124,220
Income taxes $66,366 $60,987 $36,396
Noncash investing and financing activities:
Capital lease obligations incurred $48,513 $37,351 $36,619
See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is important to AP&L due to the capital intensive nature of our
business, which requires large investments in long-lived assets. However, large
capital expenditures for the construction of new generating capacity are not
currently planned. AP&L requires significant capital resources for the periodic
maturity of certain series of debt and preferred stock. Net cash flow from
operations totaled $346 million, $224 million, and $262 million in 1993, 1992,
and 1991, respectively. The increase in AP&L's 1993 cash flow from operations
resulted primarily from increased electricity sales and increased collections
under the phase-in plan, as discussed below. In recent years, this cash flow,
supplemented by issuances of debt and proceeds from the sale of retail
properties in Missouri, has been sufficient to meet substantially all investing
and financing requirements, including capital expenditures, dividends, and
debt/preferred stock maturities. AP&L's ability to fund these capital
requirements results, in part, from our continued efforts to streamline
operations and reduce costs, as well as collections under our Grand Gulf 1 rate
phase-in plan which exceed the current cash requirements for Grand Gulf 1-
related costs. (In the income statement, these revenue collections are offset
by the amortization of previously deferred costs, therefore, there is no effect
on net income.) See Note 2, incorporated herein by reference, for additional
information on AP&L's rate phase-in plan. See Note 8, incorporated herein by
reference, for additional information on AP&L's capital and refinancing
requirements in 1994 - 1996. Further, in order to take advantage of lower
interest and dividend rates, AP&L may continue to refinance high-cost debt and
preferred stock prior to maturity.
Earnings coverage tests (which are impacted by the inclusion of the
cumulative effect of the change in accounting principle for accruing unbilled
revenues discussed in Note 1) and bondable property additions limit the amount
of first mortgage bonds and preferred stock that AP&L can issue. Based on the
most restrictive applicable tests as of December 31, 1993, and an assumed annual
interest or dividend rate of 8%, AP&L could have issued $226 million of
additional first mortgage bonds or $1,075 million of additional preferred stock.
AP&L has the conditional ability to issue first mortgage bonds and preferred
stock against the retirement of first mortgage bonds and preferred stock,
respectively, in some cases, without satisfying an earnings coverage test.
See Notes 5 and 6, incorporated herein by reference, for information on
AP&L's financing activities and Note 4, incorporated herein by reference, for
information on AP&L's short-term borrowings and lines of credit.
ARKANSAS POWER & LIGHT COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31,
-----------------------------------------
1993 1992 1991
---------- ---------- ----------
(In Thousands)
Operating Revenues (Notes 1, 2, and 11): $1,591,568 $1,521,129 $1,528,270
---------- ---------- ----------
Operating Expenses:
Operation (Note 11):
Fuel for electric generation and fuel-related
expenses 257,983 242,040 268,699
Purchased power 349,718 417,099 378,069
Other 294,103 285,740 298,584
Maintenance (Note 11) 109,724 118,540 108,398
Depreciation and decommissioning 135,530 132,459 128,410
Taxes other than income taxes 28,626 26,709 23,068
Income taxes (Note 3) 18,746 4,058 22,958
Amortization of rate deferrals (Note 2) 160,916 114,711 80,666
---------- ---------- ----------
Total 1,355,346 1,341,356 1,308,852
---------- ---------- ----------
Operating Income 236,222 179,773 219,418
---------- ---------- ----------
Other Income:
Allowance for equity funds used during
construction 3,627 4,173 4,508
Miscellaneous - net (Note 2) 64,884 113,842 82,733
Income taxes (Note 3) (32,451) (46,531) (30,908)
---------- ---------- ----------
Total 36,060 71,484 56,333
---------- ---------- ----------
Interest Charges:
Interest on long-term debt 107,771 120,318 133,854
Other interest - net 11,819 3,666 2,415
Allowance for borrowed funds used during
construction (2,418) (3,256) (3,969)
---------- ---------- ----------
Total 117,172 120,728 132,300
---------- ---------- ----------
Income before Cumulative Effect of a Change
in Accounting Principle 155,110 130,529 143,451
Cumulative Effect to January 1, 1993, of Accruing
Unbilled Revenues (net of income taxes of
$31,140) (Note 1) 50,187 - -
---------- ---------- ----------
Net Income 205,297 130,529 143,451
Preferred Stock Dividend Requirements 20,877 23,202 22,870
---------- ---------- ----------
Earnings Applicable to Common Stock $184,420 $107,327 $120,581
========== ========== ==========
See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
------------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Retained Earnings, January 1 $420,691 $388,364 $307,683
Add:
Net income 205,297 130,529 143,451
-------- -------- --------
Total 625,988 518,893 451,134
-------- -------- --------
Deduct:
Dividends declared:
Preferred stock 20,877 23,202 22,870
Common stock 156,300 75,000 39,900
-------- -------- --------
Total 177,177 98,202 62,770
-------- -------- --------
Retained Earnings, December 31 (Note 7) $448,811 $420,691 $388,364
======== ======== ========
See Notes to Financial Statements.
ARKANSAS POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income increased in 1993 due primarily to the one-time recording of the
cumulative effect of the change in accounting principle for unbilled revenues
(see Note 1, incorporated herein by reference) and its ongoing effects,
partially offset by the effect of implementing SFAS 109 (see Note 3,
incorporated herein by reference) and by the impact in March 1992 of an after-
tax gain from the sale of AP&L's retail properties in Missouri. Effective
January 1, 1993, AP&L began accruing as revenues the charges for energy
delivered to customers but not yet billed. Electric revenues were previously
recorded on a cycle-billing basis. Excluding the above mentioned items, net
income for 1993 would have been $157.7 million and net income for 1992 would
have been $110.9 million. This increase of $46.8 million is due primarily to
increased retail energy sales.
Net income decreased in 1992 due primarily to decreased operating revenues
and slight increases in maintenance expense, taxes other than income taxes,
depreciation and decommissioning expense, and the retained share of Grand Gulf
1-related costs. These decreases in net income were partially offset by the
$19.6 million after-tax gain from the sale of AP&L's retail properties in
Missouri in March 1992 and a decrease in interest expense.
Significant factors affecting the results of operations and causing
variances between the years 1993 and 1992, and 1992 and 1991, are discussed
under "Revenues and Sales", "Expenses", and "Other" below.
Revenues and Sales
See "Selected Financial Data - Five-Year Comparison," incorporated herein
by reference, following the notes, for information on operating revenues by
source and KWH sales.
Electric operating revenues were higher in 1993 due to an increase in
residential and commercial energy sales resulting from a return to more normal
weather as compared to milder weather in 1992. Industrial sales increased
primarily in the lumber/plywood and petroleum/natural gas pipeline industries.
Additionally, electric revenues increased as a result of increased collections
of previously deferred Grand Gulf 1-related costs, which does not impact net
income.
Electric operating revenues were lower in 1992 due primarily to decreased
retail revenues resulting from milder temperatures and the loss of the Missouri
retail customers. This decrease was partially offset by increased revenues from
sales for resale due to the addition of Union Electric as a wholesale customer
resulting from the Missouri property sale. Total energy sales were lower in
1992 due primarily to decreased retail sales as discussed above and decreased
sales for resale to associated companies resulting from changes in generation
availability and requirements among AP&L, LP&L, MP&L, and NOPSI.
Expenses
Fuel for electric generation and fuel-related expenses increased in 1993
due primarily to an increase in generation requirements resulting primarily from
increased retail energy sales and increased fuel costs as discussed in "Revenues
and Sales" above. Purchased power decreased in 1993 due primarily to energy
demands being met by increased nuclear generation.
Scheduled refueling outages at both ANO 1 and ANO 2 during 1992, and an
unscheduled outage at ANO 2 from March 1992 to May 1992, contributed to the
decrease in fuel for electric generation and fuel-related expenses and the
corresponding increase in purchased power in 1992. Lower energy sales in 1992
also contributed to decreased fuel expenses.
The amortization of rate deferrals increased in 1993 and 1992 due to
increased amortization of previously deferred Grand Gulf 1-related costs
pursuant to the step-up provisions of AP&L's phase-in plan.
Total income taxes increased in 1993 due primarily to higher pretax income,
an increase in the federal income tax rate as a result of OBRA, and the effect
of implementing SFAS 109.
Other
Miscellaneous other income - net decreased in 1993 and increased in 1992
due primarily to the impact of the pretax gain on the 1992 sale of AP&L's retail
properties in Missouri.
Interest on long-term debt decreased in 1993 due primarily to the continued
refinancing of high-cost debt. Other interest - net was higher in 1993 as AP&L
began recording decommissioning interest expense on its decommissioning trust
fund. This expense has no effect on net income, as decommissioning trust fund
earnings are recorded in miscellaneous other income - net.
ARKANSAS POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Competition
AP&L welcomes competition in the electric energy business and believes that
a more competitive environment should benefit our customers, employees, and
shareholders of Entergy Corporation. We also recognize that competition
presents us with many challenges, and we have identified the following as our
major competitive challenges:
Retail and Wholesale Rate Issues
Increasing competition in the utility industry brings an increased need to
stabilize or reduce retail rates In connection with the Merger, AP&L agreed
with its retail regulator not to request any general rate increases that would
take effect before November 1998, with certain exceptions. See Note 2,
incorporated herein by reference, for further information.
Retail wheeling, a major industry issue which may require utilities to
"wheel" or move power from third parties to their own retail customers, is
evolving gradually. As a result, the retail market could become more
competitive.
In the wholesale rate area, FERC approved in 1992, with certain
modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power to
sell wholesale power at market-based rates and to provide to electric utilities
"open access" to the System's transmission system (subject to certain
requirements). GSU was later added to this filing. Various intervenors in the
proceeding filed petitions for review with the United States Court of Appeals
for the District of Columbia Circuit. FERC's order, once it takes effect, will
increase marketing opportunities for AP&L, but will also expose AP&L to the risk
of loss of load or reduced revenues due to competition with alternative
suppliers.
In light of the rate issues discussed above, AP&L is aggressively reducing
costs to avoid potential earnings erosions that might result as well as to
successfully compete by becoming a low-cost producer. To help minimize future
costs, AP&L remains committed to least cost planning. In December 1992, AP&L
filed a Least Cost Integrated Resource Plan (Least Cost Plan) with its retail
regulator. Least cost planning includes demand-side measures such as customer
energy conservation and supply-side measures such as more efficient power
plants. These measures are designed to delay the building of new power plants
for the next 20 years. AP&L plans to periodically file revised Least Cost
Plans.
The Energy Policy Act of 1992
The Energy Policy Act of 1992 (Energy Act) is changing the transmission and
distribution of electricity. This act encourages competition and affords us the
opportunities, and the risks, associated with an open and more competitive
market environment. The Energy Act increases competition in the wholesale
energy market through the creation of exempt wholesale generators (EWGs). The
Energy Act also gives FERC the authority to order investor-owned utilities to
provide transmission access to or for other utilities, including EWGs.
ANO Matters
Leaks in certain steam generator tubes at ANO 2 were discovered and
repaired during outages in March and September 1992. During a mid-cycle outage
in May 1993, a scheduled special inspection of certain steam generator tubing
was conducted by Entergy Operations and additional repairs were made. The
operations and power output of ANO 2 have not been adversely affected by these
repairs and AP&L's budgeted maintenance expenditures were adequate to cover the
cost of such repairs. Entergy Operations is taking steps at ANO 2 to reduce the
number and severity of future tube cracks. Entergy Operations met with the NRC
in August 1993 to discuss such steps along with recent inspection findings and
intervals between future inspections. The NRC concurred with Entergy
Operations' proposal to operate ANO 2 with no further steam generator
inspections until the next refueling outage, which is scheduled for the spring
of 1994.
ARKANSAS POWER & LIGHT COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
AP&L maintains accounts in accordance with FERC and other regulatory
guidelines. Certain previously reported amounts have been reclassified to
conform to current classifications.
Revenues and Fuel Costs
Prior to January 1, 1993, AP&L recorded revenues when billed to its
customers with no accrual for energy delivered but not yet billed. To provide a
better matching of revenues and expenses, effective January 1, 1993, AP&L
adopted a change in accounting principle to provide for accrual of estimated
unbilled revenues. The cumulative effect of this accounting change as of
January 1, 1993, increased net income by $50.2 million. Had this new accounting
method been in effect during prior years, net income before the cumulative
effect would not have been materially different from that shown in the
accompanying financial statements.
Substantially all of AP&L's rate schedules include fuel adjustment clauses
that allow either current recovery or deferrals of fuel costs until such costs
are reflected in the related revenues. The fuel adjustment clause provides, as
an incentive with respect to ANO, for over or under-recovery of the cost of
replacement energy in excess of the cost of equal amounts of nuclear energy when
the units are not down for refueling.
Utility Plant
Utility plant is stated at original cost. The original cost of utility
plant retired or removed, plus the applicable removal costs, less salvage, is
charged to accumulated depreciation. Maintenance, repairs, and minor
replacement costs are charged to operating expenses. Substantially all of
AP&L's utility plant is subject to the lien of its mortgage and deed of trust.
AFUDC represents the approximate net composite interest cost of borrowed
funds and a reasonable return on the equity funds used for construction.
Although AFUDC increases utility plant and increases earnings, it is only
realized in cash through depreciation provisions included in rates. AP&L's
effective composite rates for AFUDC were 10.3%, 10.5%, and 10.7% for 1993, 1992,
and 1991, respectively.
Depreciation is computed on the straight-line basis at rates based on the
estimated service lives and costs of removal of the various classes of property.
Depreciation provisions on average depreciable property approximated 3.4% in
1993, 1992, and 1991.
Jointly-Owned Generating Stations
AP&L is a co-owner in two coal-fueled, two-unit generating stations, the
White Bluff Station and the Independence Station. AP&L is the agent for the
respective co-owners and operates the stations. AP&L records its investment and
expenses associated with these generating stations to the extent of its
ownership interests. As of December 31, 1993, AP&L's investment and accumulated
depreciation in these generating stations were as follows:
Total
Megawatt Accumulated
Generating Stations Capability Ownership Investment Depreciation
- ------------------- ---------- --------- ---------- ------------
(In Thousands)
White Bluff: Units 1 and 2 946 57.00% $398,644 $140,731
Independence: Unit 1 263 31.50% $116,511 $ 35,797
Common Facilities 15.75% $ 29,163 $ 8,043
Income Taxes
AP&L, its parent, and affiliates (excluding GSU prior to 1994) file a
consolidated federal income tax return. Income taxes are allocated to AP&L in
proportion to its contribution to consolidated taxable income. SEC regulations
require that no System company pay more taxes than it would have had a separate
income tax return been filed. Deferred taxes are recorded for all temporary
differences between book and taxable income. Investment tax credits are
deferred and amortized based upon the average useful life of the related
property in accordance with rate treatment. As discussed in Note 3, effective
January 1, 1993, AP&L changed its accounting for income taxes to conform with
SFAS 109.
Reacquired Debt
The premiums and costs associated with reacquired debt are being amortized
over the life of the related new issuances, in accordance with ratemaking
treatment.
Cash and Cash Equivalents
AP&L considers all unrestricted highly liquid debt instruments purchased
with an original maturity of three months or less to be cash equivalents.
Fair Value Disclosure
The estimated fair value amounts of financial instruments have been
determined by AP&L, using available market information and appropriate valuation
methodologies. However, considerable judgment is required in developing the
estimates of fair value. Therefore, estimates are not necessarily indicative of
the amounts that AP&L could realize in a current market exchange. In addition,
gains or losses realized on financial instruments may be reflected in future
rates and not accrue to the benefit of stockholders.
AP&L considers the carrying amounts of financial instruments classified as
current assets and liabilities to be a reasonable estimate of their fair value
because of the short maturity of these instruments. In addition, AP&L does not
presently expect that performance of its obligations will be required in
connection with certain off-balance sheet commitments and guarantees considered
financial instruments. Due to this factor, and because of the related party
nature of these commitments and guarantees, determination of fair value is not
considered practicable. See Notes 5, 6, and 8 for additional fair value
disclosure.
NOTE 2. RATE AND REGULATORY MATTERS
Rate Agreement
In November 1993, AP&L and the APSC entered into a settlement agreement
whereby the APSC agreed to withdraw its request for hearing and its objections
in the SEC proceeding related to the Merger. In return, AP&L agreed, among
other things, (a) that it will not request any general retail rate increase that
would take effect before November 3, 1998, except, among other things, for
increases associated with the Least Cost Plan, recovery of certain Grand Gulf 1-
related costs, excess capacity costs and costs related to the adoption of SFAS
106 that were previously deferred, recovery of certain taxes, and force majeure
(defined to include, among other things, war, natural catastrophes, and high
inflation); and (b) that its retail ratepayers would be protected from (1)
increases in its cost of capital resulting from risks associated with the
Merger, (2) recovery of any portion of the acquisition premium or transactional
costs associated with the Merger, (3) certain direct allocations of costs
associated with GSU's River Bend nuclear unit, and (4) any losses of GSU
resulting from resolution of litigation in connection with its ownership of
River Bend.
Arkansas - Revised Settlement Agreement
Pursuant to the terms of the Revised Settlement Agreement, AP&L (1)
permanently retains a portion of its Grand Gulf 1-related costs (Retained
Share), ranging from 5.67% (stated as a percentage of System Energy's share of
Grand Gulf 1) in 1989 to 7.92% in 1994 and all succeeding years of commercial
operation of the unit; (2) recovers currently a portion of such costs, ranging
from 17.86% in 1989 to 28.08% in 1994 and thereafter; and (3) deferred a portion
of such costs for future recovery (Deferred Balance). AP&L is permitted to
currently recover carrying charges on the unrecovered portion of the Deferred
Balance. For the year ended December 31, 1993, $234 million was billed to AP&L
by System Energy.
AP&L has the right under the Revised Settlement Agreement to sell capacity
and energy available from its Retained Share to third parties, which shall not
include AP&L's wholesale customers. In the event AP&L is not able to sell such
capacity and energy to such third parties, it has the right to sell the energy
available from such capacity, and to date a significant portion has been sold,
to its retail customers at a price equal to AP&L's avoided energy cost, which is
currently less than AP&L's cost of such energy. The Revised Settlement
Agreement requires that a portion of the proceeds from sales of Retained Share
capacity and energy to third parties through 1995 be applied to reduce the
Deferred Balance.
Arkansas - Rate Riders
In conjunction with the Revised Settlement Agreement, AP&L was permitted to
implement annual updates to the Grand Gulf 1 rate rider, increasing Arkansas
retail rates by approximately 3.1% and 2.6% for the years 1992 and 1991,
respectively. These increases reflect scheduled phase-in plan increases
adjusted for any prior year over or under-collection. Beginning in 1993 and
continuing for a five year period, rates will remain at the 1992 level, unless
adjustments are made for an over or under-collection of Grand Gulf 1-related
costs in excess of $10 million. Although it was not required under the terms of
the Grand Gulf 1 rate rider, in 1993 AP&L opted to implement a 0.7% rate refund
in 1994 for a cumulative over-recovery amount of $7.3 million.
Various other rate riders, which modify non-Grand Gulf 1 rates under the
Revised Settlement Agreement, have been implemented with respect to tax
adjustments, depreciation, decommissioning costs, and deferred return on excess
capacity (which is being recovered over a 10-year period ending in 1998).
Missouri Retail Operations
In March 1992, AP&L sold its retail properties in Missouri for
approximately $68 million. AP&L's retail properties in Missouri constituted
less than 2% of its total property. The cash received from the sale, which also
included Missouri accounts receivable and material and supplies inventory, was
approximately $72 million, which was in excess of book value. The gain on the
sale, classified as "Other Income-Miscellaneous" in the 1992 Statement of
Income, was approximately $33.7 million, which resulted in a $19.6 million
increase in net income after taxes. Under the terms of the contract, AP&L's
28,000 Missouri retail customers became Union Electric customers and AP&L's
employees in Missouri became Union Electric employees. The proceeds from this
sale were used to redeem all or a portion of certain series of AP&L's
outstanding first mortgage bonds at special redemption prices, pursuant to the
applicable provisions of AP&L's mortgage and deed of trust. In addition, AP&L
has agreed to sell to Union Electric 120 megawatts of capacity and associated
energy for an initial period of 10 years, and beginning on January 1, 1995,
Union Electric shall also purchase 40 megawatts of peaking capacity from AP&L.
NOTE 3. INCOME TAXES
Effective January 1, 1993, AP&L adopted SFAS 109. This new standard
requires that deferred income taxes be recorded for all temporary differences
and carryforwards, and that deferred tax balances be based on enacted tax laws
at tax rates that are expected to be in effect when the temporary differences
reverse. SFAS 109 requires that regulated enterprises recognize adjustments
resulting from implementation as regulatory assets or liabilities if it is
probable that such amounts will be recovered from or returned to customers in
future rates. A substantial majority of the adjustments required by SFAS 109
was recorded to deferred tax balance sheet accounts with offsetting adjustments
to regulatory assets and liabilities. The cumulative effect of the adoption of
SFAS 109 is included in income tax expense charged to operations. As a result
of the adoption of SFAS 109, 1993 net income was reduced by $2.6 million, assets
were increased by $168.2 million, and liabilities were increased by $170.8
million.
Income tax expense consisted of the following:
For the Years Ended December 31,
----------------------------------
1993 1992 1991
------- ------- -------
(In Thousands)
Current:
Federal $47,326 $45,932 $34,648
State 10,836 11,156 9,770
------- ------- -------
Total 58,162 57,088 44,418
------- ------- -------
Deferred - net:
Liberalized depreciation 7,074 4,929 5,885
Alternative minimum tax (2,227) 6,577 6,249
Nuclear refueling and maintenance (2,161) 7,751 (5,001)
Deferred purchased power costs (35,896) (14,375) (1,868)
Deferred excess capacity costs (4,044) (3,190) (1,609)
Unbilled revenue 26,847 (2,474) 3,424
Bond reacquisition costs 14,706 5,184 765
Intangible plant 410 1,941 4,514
Decontamination and decommissioning fund 16,429 - -
Other 13,610 (2,853) (1,311)
------- ------- -------
Total 34,748 3,490 11,048
------- ------- -------
Investment tax credit adjustments - net (10,573) (9,989) (1,600)
------- ------- -------
Recorded income tax expense $82,337 $50,589 $53,866
======= ======= =======
Charged to operations $18,746 $ 4,058 $22,958
Charged to other income 32,451 46,531 30,908
Charged to cumulative effect 31,140 - -
------- ------- -------
Recorded income tax expense 82,337 50,589 53,866
Income taxes applied against the debt - 1 94
component of AFUDC
------- ------- -------
Total income taxes $82,337 $50,590 $53,960
======= ======= =======
Total income taxes differ from the amounts computed by applying the
statutory federal income tax rate to income before taxes. The reasons for the
differences were:
For the Years Ended December 31
-----------------------------------------------------------
1993 1992 1991
------------------ ----------------- ---------------
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
-------- ------ ------- ------ ------- ------
(Dollars in Thousands)
Computed at statutory rate $100,673 35.0 $61,580 34.0 $67,088 34.0
Increases (reductions) in tax resulting from:
State income taxes net of federal income
tax effect 12,119 4.2 7,963 4.4 7,409 3.7
Amortization of investment tax credits (11,702) (4.1) (13,285) (7.4) (11,064) (5.6)
Depreciation (3,156) (1.1) (6,755) (3.7) (6,122) (3.1)
Reversal of tax contingency (3,771) (1.3) - - - -
Flow-through/permanent differences (7,669) (2.7) (1,407) (0.8) (76) -
Other - net (4,157) (1.4) 2,493 1.4 (3,369) (1.7)
-------- ----- ------- ----- ------- -----
Recorded income tax expense 82,337 28.6 50,589 27.9 53,866 27.3
Income taxes applied against debt component
of AFUDC - - 1 - 94 -
-------- ----- ------- ----- ------- -----
Total income taxes $ 82,337 28.6 $50,590 27.9 $53,960 27.3
======== ===== ======= ===== ======= =====
Significant components of AP&L's net deferred tax liabilities as of
December 31, 1993, were (in thousands):
Deferred tax liabilities:
Net regulatory assets $ (294,713)
Plant related basis differences (458,023)
Rate deferrals (229,714)
Bond reacquisition (23,604)
Decontamination and decommissioning fund (16,429)
Other (21,414)
-----------
Total $(1,043,897)
===========
Deferred tax assets:
Alternative minimum tax credit $ 34,137
Nuclear refueling and maintenance 12,035
Accumulated deferred investment tax credit 60,698
Standard coal plant 9,552
Other 18,490
-----------
Total $ 134,912
===========
Net deferred tax liabilities $ (908,985)
===========
The alternative minimum tax (AMT) credit as of December 31, 1993, was
$34.1 million. This AMT credit can be carried forward indefinitely and will
reduce AP&L's federal income tax liability in future years.
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized AP&L to effect short-term borrowings up to
$125 million, subject to increase to as much as $255 million after further SEC
approval. These authorizations are effective through November 30, 1994. As of
December 31, 1993, AP&L had unused lines of credit for short-term borrowings of
$34 million from banks within its service territory. In addition, AP&L can
borrow from the Money Pool, subject to its maximum authorized level of
short-term borrowings and the availability of funds. AP&L had $21.4 million in
outstanding borrowings under the Money Pool arrangement as of December 31, 1993.
NOTE 5. PREFERRED STOCK
The number of shares and dollar value of AP&L's preferred stock was:
As of December 31,
-------------------------------------------
Shares Call Price Per
Authorized and Total Share as of
Outstanding Dollar Value December 31,
1993 1992 1993 1992 1993
------ ------- -------- -------- --------------
(Dollars in Thousands)
Without sinking fund:
Cumulative, $100 par value:
4.32% Series 70,000 70,000 $ 7,000 $ 7,000 $103.647
4.72% Series 93,500 93,500 9,350 9,350 $107.000
4.56% Series 75,000 75,000 7,500 7,500 $102.830
4.56% 1965 Series 75,000 75,000 7,500 7,500 $102.500
6.08% Series 100,000 100,000 10,000 10,000 $102.830
7.32% Series 100,000 100,000 10,000 10,000 $103.170
7.80% Series 150,000 150,000 15,000 15,000 $103.250
7.40% Series 200,000 200,000 20,000 20,000 $102.800
7.88% Series 150,000 150,000 15,000 15,000 $103.000
Cumulative, $25 par value:
8.84% Series 400,000 400,000 10,000 10,000 $26.560
Cumulative, $0.01 par value:
$2.40 Series(1)(2) 2,000,000 2,000,000 50,000 50,000 -
$1.96 Series(1)(2) 600,000 600,000 15,000 15,000 -
--------- --------- -------- --------
Total without sinking fund 4,013,500 4,013,500 $176,350 $176,350
========= ========= ======== ========
With sinking fund:
Cumulative, $100 par value:
10.60% Series 20,000 40,000 $ 2,000 $ 4,000 $104.090
11.04% Series - 40,000 - 4,000 -
8.52% Series 400,000 425,000 40,000 42,500 $106.390
Cumulative, $25 par value:
9.92% Series 721,085 801,085 18,027 20,027 $26.940
13.28% Series 400,000 600,000 10,000 15,000 $28.220
--------- --------- -------- --------
Total with sinking fund 1,541,085 1,906,085 $ 70,027 $ 85,527
========= ========= ======== ========
(1) The total dollar value represents the involuntary liquidation value of $25
per share.
(2) These series are not redeemable as of December 31, 1993.
The fair value of AP&L's preferred stock with sinking fund was estimated to
be approximately $74.7 million and $89.3 million as of December 31, 1993 and
1992, respectively. The fair value was determined using quoted market prices or
estimates from nationally recognized investment banking firms. See Note 1 for
additional information on disclosure of fair value of financial instruments.
As of December 31, 1993, AP&L had 2,296,500, 7,478,915, and 12,400,000
shares of cumulative, $100, $25, and $0.01 par value preferred stock,
respectively, that were authorized but unissued.
Changes in the preferred stock, with and without sinking fund, during the
last three years were:
Number of Shares
----------------------------------
1993 1992 1991
--------- -------- ---------
Preferred stock issuances:
$0.01 par value - 600,000 2,000,000
Preferred stock retirements:
$100 par value (85,000) (109,940) (70,060)
$25 par value (280,000) (880,000) (280,000)
Cash sinking fund requirements for the next five years for preferred stock
outstanding as of December 31, 1993 are (in millions): 1994 - $8.0; 1995 - $8.0;
1996 - $7.0; 1997 - $7.0; and 1998 - $4.5. AP&L has the annual non-cumulative
option to redeem, at par, additional amounts of certain series of its
outstanding preferred stock. Additionally, AP&L has SEC authorization for the
acquisition, through December 31, 1995, of up to $150 million of preferred
stock.
NOTE 6. LONG-TERM DEBT
The long-term debt of AP&L as of December 31, 1993 and 1992 was:
Maturities Interest Rates
From To From To 1993 1992
---- ---- ----- ------ ---------- ----------
(In Thousands)
First Mortgage Bonds
1993 1998 4-5/8% 8-3/4% $ 100,560 $ 116,160
1999 2003 6% 9-3/4% 182,000 217,200
2004 2008 6.65% 7-1/2% 215,000 175,000
2019 2023 7% 10-3/8% 448,818 403,550
Governmental Obligations*
1995 2008 6.125% 10% 83,290 81,708
2009 2021 6-1/8% 11% 202,193 202,193
Long-Term DOE Obligation (Note 8) 101,029 97,959
Unamortized Premium and Discount - Net (16,555) (14,923)
---------- ----------
Total Long-Term Debt 1,316,335 1,278,847
Less Amount Due Within One Year 3,020 17,900
---------- ----------
Long-Term Debt Excluding Amount Due Within $1,313,315 $1,260,947
One Year ========== ==========
* Consists of pollution control bonds, certain series of which are secured by
non-interest bearing first mortgage bonds.
The fair value of AP&L's long-term debt, excluding long-term DOE
obligation, as of December 31, 1993 and 1992 was estimated to be $1,250.8
million and $1,286.6 million, respectively. The fair value was determined using
quoted market prices or estimates from nationally recognized investment banking
firms. See Note 1 for additional information on disclosure of fair value of
financial instruments.
For the years 1994, 1995, 1996, 1997 and 1998, AP&L has long-term debt
maturities and cash sinking fund requirements (in millions) of $2.2, $27.4,
$28.2, $33.5, and $19.4, respectively. In addition, other sinking fund
requirements of approximately $.9 million annually may be satisfied by cash or
by certification of property additions at the rate of 167% of such requirements.
AP&L has regulatory authorization for the issuance and sale through
December 31, 1995, of up to $600 million of additional first mortgage bonds (of
which $270 million remained available as of December 31, 1993). In addition,
AP&L has SEC authorization for the acquisition of not more than $350 million of
first mortgage bonds (of which $199 million remained available as of
December 31, 1993) and $175 million of pollution control revenue bonds and/or
solid waste disposal revenue bonds, issued for the benefit of AP&L through
December 31, 1995.
NOTE 7. DIVIDEND RESTRICTIONS
The indenture relating to AP&L's long-term debt and provisions of the
Amended and Restated Articles of Incorporation, as amended, relating to AP&L's
preferred stock provide for restrictions on the payment of cash dividends or
other distributions on common stock. As of December 31, 1993, $291.3 million of
AP&L's retained earnings were restricted against the payment of cash dividends
or other distributions on common stock. On February 1, 1994, AP&L paid Entergy
Corporation a $17.9 million cash dividend on common stock.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Capital Requirements and Financing
Construction expenditures (excluding nuclear fuel) for the years 1994,
1995, and 1996 are estimated to total $181 million, $172 million, and
$175 million, respectively. AP&L will also require $83 million during the
period 1994-1996 to meet long-term debt and preferred stock maturities and
sinking fund requirements. AP&L plans to meet the above requirements with
internally generated funds and cash on hand, supplemented by the issuance of
debt and preferred stock. See Notes 5 and 6 regarding the possible refunding,
redemption, purchase or other acquisition of certain outstanding series of
preferred stock and long-term debt. See Note 12 for information on additional
capital requirements related to a February 1994 ice storm.
Unit Power Sales Agreement
System Energy has agreed to sell all of its 90% owned and leased share of
capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in
accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI
17%) as ordered by FERC. Charges under this agreement are paid in consideration
for AP&L's respective entitlement to receive capacity and energy, and are
payable irrespective of the quantity of energy delivered so long as the unit
remains in commercial operation. The agreement will remain in effect until
terminated by the parties and approved by FERC, most likely upon Grand Gulf 1's
retirement from service. AP&L's monthly obligation for payments under the
agreement is approximately $19 million.
Availability Agreement
AP&L, LP&L, MP&L, and NOPSI are individually obligated to make payments or
subordinated advances to System Energy in accordance with stated percentages
(AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 24.7%) in amounts that when added
to amounts received under the Unit Power Sales Agreement or otherwise, are
adequate to cover all of System Energy's operating expenses. System Energy has
assigned its rights to payments and advances to certain creditors as security
for certain obligations. Payments or advances under the Availability Agreement
are only required if funds available to System Energy from all sources are less
than the amount required under the Availability Agreement. Since commercial
operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have
exceeded the amounts payable under the Availability Agreement. Accordingly, no
payments have ever been required. In 1989, the Availability Agreement was
amended to provide that the write-off of $900 million of Grand Gulf 2 costs
would be amortized for Availability Agreement purposes over a period of 27
years, in order to avoid the need for payments by AP&L, LP&L, MP&L, and NOPSI.
Reallocation Agreement
System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation
Agreement relating to the sale of capacity and energy from the Grand Gulf
Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume
all of AP&L's responsibilities and obligations with respect to the Grand Gulf
Station under the Availability Agreement. FERC's decision allocating a portion
of Grand Gulf 1 capacity and energy to AP&L supersedes the Reallocation
Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2
amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%,
and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the
Reallocation Agreement does not affect AP&L's obligation to System Energy's
lenders under the assignments referred to in the preceding paragraph. AP&L
would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were
unable to meet their contractual obligations. No payments of any amortization
amounts will be required as long as amounts paid to System Energy under the Unit
Power Sales Agreement, including other funds available to System Energy, exceed
amounts required under the Availability Agreement, which is expected to be the
case for the foreseeable future.
System Fuels
AP&L has a 35% interest in System Fuels, a jointly owned subsidiary of
AP&L, LP&L, MP&L, and NOPSI. The parent companies of System Fuels, including
AP&L, agreed to make loans to System Fuels to finance its fuel procurement,
delivery, and storage activities. As of December 31, 1993, AP&L had
approximately $11 million of loans outstanding to System Fuels which mature in
2008.
In addition, System Fuels entered into a revolving credit agreement with a
bank that provides $45 million in borrowings to finance System Fuels' nuclear
materials and services inventory. Should System Fuels default on its
obligations under its credit agreement, AP&L, LP&L, and System Energy have
agreed to purchase nuclear materials and services financed under the agreement.
On April 30, 1993, AP&L assumed System Fuels' rights and obligations in
connection with System Fuels' coal car leases. The other parent companies of
System Fuels have been released from their obligations with respect to the coal
car leases.
Coal
AP&L is a party to a contract with a joint venture for supply of coal from
a mine in Wyoming which, based on estimated reserves, is expected to provide the
projected requirements of the Independence Station through at least 2014. AP&L
has also agreed to purchase, over an approximate 20-year period beginning in
1980, 100 million tons of coal for use at the White Bluff Station, of which
approximately 60 million have been purchased as of December 31, 1993.
Nuclear Insurance
The Price-Anderson Act limits public liability for a single nuclear
incident to approximately $9.4 billion as of December 31, 1993. AP&L has
protection for this liability through a combination of private insurance
(currently $200 million) and an industry assessment program. Under the
assessment program, the maximum amount that would be required for each nuclear
incident would be $79.28 million per reactor, payable at a rate of $10 million
per licensed reactor per incident per year. AP&L has two licensed reactors. In
addition, the System participates in a private insurance program which provides
coverage for worker tort claims filed for bodily injury caused by radiation
exposure. AP&L's maximum assessment under the program is an aggregate of
approximately $6.2 million in the event losses exceed accumulated reserve funds.
AP&L is a member of certain insurance programs that provide coverage for
property damage, including decontamination and premature decommissioning
expense, to members' nuclear generating plants. As of December 31, 1993, AP&L
was insured against such losses up to $2.7 billion, with $250 million of this
amount designated to cover any shortfall in the NRC required decommissioning
trust funding. In addition, AP&L is a member of an insurance program that
covers certain replacement power and business interruption costs incurred due to
prolonged nuclear unit outages. Under the property damage and replacement
power/business interruption insurance programs, AP&L could be subject to
assessments if losses exceed the accumulated funds available to the insurers.
As of December 31, 1993, the maximum amount of such possible assessments to AP&L
was $28.14 million.
The amount of property insurance presently carried by AP&L exceeds the
NRC's minimum requirement for nuclear power plant licensees of $1.06 billion per
site. NRC regulations provide that the proceeds of this insurance must be used,
first, to place and maintain the reactor in a safe and stable condition and,
second, to complete decontamination operations. Only after proceeds are
dedicated for such use and regulatory approval is secured, would any remaining
proceeds be made available for the benefit of plant owners or their creditors.
Spent Nuclear Fuel and Decommissioning Costs
AP&L provides for estimated future disposal costs for spent nuclear fuel in
accordance with the Nuclear Waste Policy Act of 1982. AP&L entered into a
contract with the DOE, whereby the DOE will furnish disposal service at a cost
of one mill per net KWH generated and sold after April 7, 1983, plus a one-time
fee for generation prior to that date. AP&L elected to pay the one-time fee,
plus accrued interest, and has recorded a liability as of December 31, 1993, of
approximately $101 million. The fees payable to the DOE may be adjusted in the
future to assure full recovery. AP&L considers all costs incurred or to be
incurred, except accrued interest, for the disposal of spent nuclear fuel to be
proper components of nuclear fuel expense and provisions to recover such costs
have been or will be made in applications to regulatory authorities.
Due to delays of the DOE's repository program for the acceptance of spent
nuclear fuel, it is uncertain when shipments of spent fuel from AP&L's nuclear
units will commence. In the meantime, AP&L is responsible for spent fuel
storage. Current on-site spent fuel storage capacity at ANO is estimated to be
sufficient until 1995. Thereafter, AP&L will provide additional storage
capacity at an estimated initial cost of $5 million to $10 million per unit. In
addition, approximately $3 million to $5 million per unit will be required every
two to three years subsequent to 1995 until the DOE's repository program begins
accepting ANO's spent fuel.
AP&L is recovering in rates amounts sufficient to fund decommissioning
costs for ANO, based on a 1992 update to the original decommissioning cost
study, of approximately $606.8 million (in 1992 dollars). These amounts are
deposited in external trust funds which have a market value of approximately
$124.3 million and $101.3 million as of December 31, 1993 and 1992,
respectively. The accumulated decommissioning liability of $119.2 million as of
December 31, 1993, has been recorded in accumulated depreciation..
Decommissioning expense in the amount of $11.0 million was recorded in 1993.
During the first quarter of 1994, AP&L expects to file with the APSC an interim
update of the ANO cost study which will likely reflect significant increases in
costs of low-level radioactive waste disposal. AP&L regularly reviews and
updates its estimates for decommissioning costs and applications will be made to
the APSC to reflect in rates future changes in projected decommissioning costs.
The actual decommissioning costs may vary from the above estimates because of
regulatory requirements, changes in technology, and increased costs of labor,
materials, and equipment, and management believes that actual decommissioning
costs are likely to be higher than the amounts presented above.
The Energy Act has a provision that assesses domestic nuclear utilities
with fees for the decontamination and decommissioning of the DOE's past uranium
enrichment operations. The decontamination and decommissioning assessments will
be used to set up a fund into which contributions from utilities and the federal
government will be placed. AP&L's annual assessment, which will be adjusted
annually for inflation, is approximately $3.3 million (in 1993 dollars) for
approximately 15 years. FERC requires that utilities treat these assessments as
costs of fuel as they are amortized. The liability of $45.7 million as of
December 31, 1993 is recorded in other current liabilities and other noncurrent
liabilities and is offset in the financial statements by a regulatory asset,
recorded as a deferred debit.
NOTE 9. LEASES
As of December 31, 1993, AP&L had capital leases and noncancelable
operating leases (excluding the nuclear fuel lease) with minimum lease payments
as follows:
Capital Operating
Leases Leases
-------- ---------
(In Thousands)
1994 $ 13,189 $17,284
1995 13,544 17,229
1996 11,127 16,068
1997 8,293 10,548
1998 8,293 10,514
Years thereafter 56,989 21,908
-------- -------
Minimum lease payments 111,435 $93,551
Less: Amount representing interest (47,674) =======
-------
Present value of net minimum lease payments $63,761
=======
Rental expense for capital and operating leases (excluding the nuclear fuel
lease) amounted to approximately $23.2 million, $27.4 million, and $26.2 million
in 1993, 1992, and 1991, respectively.
Nuclear Fuel Lease
AP&L has an arrangement to lease nuclear fuel in an amount of up to $125
million.. The lessor finances its acquisition of nuclear fuel through a credit
agreement and the issuance of notes. The credit agreement, which was entered
into in 1988, has been extended to December 1996 and the notes have varying
remaining maturities of up to 4 years. It is expected that these arrangements
will be extended or alternative financing will be secured by the lessor upon the
maturity of the current arrangements, based on AP&L's nuclear fuel requirements.
If the lessor cannot arrange financing upon maturity of its borrowings, AP&L
must purchase nuclear fuel in an amount sufficient to enable the lessor to
retire such borrowings.
Lease payments are based on nuclear fuel use. Nuclear fuel lease expense
of $69.7 million, $65.5 million, and $76.9 million (including interest of $10.6
million, $11.6 million, and $14.0 million) was charged to operations in 1993,
1992, and 1991, respectively.
NOTE 10. POSTRETIREMENT BENEFITS
Pension Plan
AP&L has a defined benefit pension plan covering substantially all of its
employees. The pension plan is noncontributory and provides pension benefits
that are based on employees' credited service and average compensation, during
the last ten years of employment. AP&L funds pension costs in accordance with
contribution guidelines established by the Employee Retirement Income Security
Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The
assets of the plan consist primarily of common and preferred stocks, fixed
income securities, interest in a money market fund, and insurance contracts.
Effective June 6, 1990, AP&L's nuclear operations employees became
employees of Entergy Operations. However, the employees still remain under
AP&L's plan and no transfers of related pension liabilities and assets have been
made.
AP&L's 1993, 1992, and 1991 pension cost, including amounts capitalized,
included the following components:
For the Years Ended December 31,
--------------------------------
1993 1992 1991
------- ------- -------
(In Thousands)
Service cost - benefits earned during the period $ 7,940 $ 6,906 $ 6,210
Interest cost on projected benefit obligation 21,744 20,512 18,505
Actual return on plan assets (31,984) (16,765) (47,707)
Net amortization and deferral 10,531 (3,531) 28,377
Other - - 915
------- ------- -------
Net pension cost $ 8,231 $ 7,122 $ 6,300
======= ======= =======
The funded status of AP&L's pension plan as of December 31, 1993 and 1992,
was:
1993 1992
-------- --------
(In Thousands)
Actuarial present value of accumulated pension plan benefits:
Vested $255,955 $228,237
Nonvested 1,724 1,231
-------- --------
Accumulated benefit obligation $257,679 $229,468
======== ========
Plan assets at fair value $288,418 $255,956
Projected benefit obligation 316,255 272,148
-------- --------
Plan assets less than projected benefit obligation (27,837) (16,192)
Unrecognized prior service cost 5,841 6,168
Unrecognized transition asset (18,686) (21,022)
Unrecognized net loss (gain) 13,242 (5,806)
-------- --------
Accrued pension liability $(27,440) $(36,852)
======== ========
The significant actuarial assumptions used in computing the information
above for 1993, 1992, and 1991 were as follows: weighted average discount rate,
7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in
future compensation levels, 5.6%; and expected long-term rate of return on plan
assets, 8.5%. Transition assets are being amortized over 15 years.
Other Postretirement Benefits
AP&L also provides certain health care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits if they reach retirement age while still working for AP&L. The cost of
providing these benefits, recorded on a cash basis, to retirees in 1992 was
approximately $3.5 million. Prior to 1992, the cost of providing these benefits
for retired employees was not separable from the cost of providing benefits for
active employees. Based on the ratio of the number of retired employees to the
total number of active and retired employees in 1991, the cost of providing
these benefits in 1991, recorded on a cash basis, for retirees was approximately
$4.1 million.
Effective January 1, 1993, AP&L adopted SFAS 106. The new standard
requires a change from a cash method to an accrual method of accounting for
postretirement benefits other than pensions. AP&L continues to fund these
benefits on a pay-as-you-go basis. As of January 1, 1993, the actuarially
determined accumulated postretirement benefit obligation (APBO) earned by
retirees and active employees was estimated to be approximately $80.5 million.
This obligation is being amortized over a 20-year period beginning in 1993.
AP&L has received an order from the APSC permitting deferral, as a regulatory
asset, of the increased annual expense associated with these benefits.
AP&L's 1993 postretirement benefit cost, including amounts capitalized and
deferred, included the following components (in thousands):
Service cost - benefits earned during the period $ 2,366
Interest cost on APBO 6,427
Actual return on plan assets (71)
Amortization of transition obligation 3,954
-------
Net periodic postretirement benefit cost $12,676
=======
The funded status of AP&L's postretirement plan as of December 31, 1993,
was (in thousands):
Accumulated postretirement benefit obligation:
Retirees $59,906
Other fully eligible participants 8,366
Other active participants 25,038
-------
93,310
Plan assets at fair value 354
-------
Plan assets less than APBO (92,956)
Unrecognized transition obligation 75,114
Unrecognized net loss 8,360
-------
Accrued postretirement benefit liability $(9,482)
=======
The assumed health care cost trend rate used in measuring the APBO was 9.9%
for 1994, gradually decreasing each successive year until it reaches 5.6% in
2020. A one percentage-point increase in the assumed health care cost trend
rate for each year would have increased the APBO as of December 31, 1993, by 8.7
% and the sum of the service cost and interest cost by approximately 11.2%. The
assumed discount rate and rate of increase in future compensation used in
determining the APBO were 7.5% and 5.5%, respectively.
NOTE 11. TRANSACTIONS WITH AFFILIATES
AP&L buys electricity from and/or sells electricity to LP&L, MP&L, NOPSI,
System Energy, and Entergy Power under rate schedules filed with FERC. In
addition, AP&L purchases fuel from System Fuels, receives technical and advisory
services from Entergy Services, Inc. and receives management and operating
services from Entergy Operations.
Operating revenues include revenues from sales to affiliates amounting to
$181.8 million in 1993, $211.4 million in 1992, and $212.6 million in 1991.
Operating expenses include charges from affiliates for fuel costs, purchased
power and related charges, management services, and technical and advisory
services totaling $323.2 million in 1993, $573.4 million in 1992, and
$510.1 million in 1991. Operating expenses also include $16.8 million in 1993,
$47.4 million in 1992, and $33.4 million in 1991 for power purchased from
Entergy Power. AP&L pays directly or reimburses Entergy Operations for the
costs associated with operating ANO (excluding nuclear fuel), which were
approximately $226.3 million in 1993, $292.3 million in 1992, and $248.6 million
in 1991.
NOTE 12. SUBSEQUENT EVENT (UNAUDITED)
In early February 1994, an ice storm left more than 97,000 AP&L customers
without electric power in its service area. The storm was the most severe
natural disaster ever to affect AP&L, causing damage to transmission and
distribution lines, equipment, poles, and facilities in certain areas. A
substantial portion of the related costs, which are estimated to be $25 million
to $35 million, are expected to be capitalized. Estimated construction
expenditures (see Note 8) have not yet been updated to reflect the above
amounts.
NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED)
AP&L's business is subject to seasonal fluctuations with the peak period
occurring during the third quarter. Operating results for the four quarters of
1993 and 1992 were:
Operating Operating Net
Revenues Income Income
--------- --------- --------
(In Thousands)
1993:
First Quarter (1) $346,740 $ 36,961 $66,081
Second Quarter $383,651 $ 53,332 $34,572
Third Quarter $519,822 $101,484 $81,677
Fourth Quarter $341,355 $ 44,445 $22,967
1992:
First Quarter (2) $338,996 $ 39,402 $41,725
Second Quarter $347,224 $ 31,239 $14,052
Third Quarter $465,130 $ 79,006 $62,059
Fourth Quarter $369,779 $ 30,126 $12,693
(1) The first quarter of 1993 reflects a nonrecurring increase in net
income of $50.2 million, net of taxes of $31.1 million, due to the
recording of the cumulative effect of the change in accounting principle
for unbilled revenues (see Note 1). Beginning with the second quarter, the
remaining quarters are not generally comparable to prior year quarters
because of the ongoing effects of the accounting change.
(2) The first quarter of 1992 reflects a nonrecurring increase in net income of
$19.6 million, net of tax, due to the sale of retail properties in Missouri
(see Note 2).
ARKANSAS POWER & LIGHT COMPANY
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
(In Thousands)
Operating revenues $1,591,568 $1,521,129 $1,528,270 $1,481,408 $1,381,871
Income before cumulative
effect of a change in
accounting principle $ 155,110 $ 130,529 $ 143,451 $ 129,765 $ 131,979
Total assets $4,334,105 $4,038,811 $4,192,020 $4,137,938 $4,059,596
Long-term obligations (1) $1,478,203 $1,453,588 $1,670,678 $1,731,212 $1,584,749
(1) Includes long-term debt (excluding currently maturing debt), preferred
stock with sinking fund, and noncurrent capital lease obligations.
See Notes 1, 3, and 10 for the effect of accounting changes in 1993.
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
(Dollars in Thousands)
Operating Revenues:
Residential $ 528,734 $ 476,090 $ 494,375 $ 484,359 $ 425,568
Commercial 306,742 291,367 289,291 283,971 254,636
Industrial 336,856 325,569 324,632 331,929 307,853
Governmental 16,670 17,700 19,731 19,599 20,990
---------- ---------- ---------- ---------- ----------
Total retail 1,189,002 1,110,726 1,128,029 1,119,858 1,009,047
Sales for resale 379,480 385,028 373,735 339,366 345,377
Other 23,086 25,375 26,506 22,184 27,447
---------- ---------- ---------- ---------- ----------
Total $1,591,568 $1,521,129 $1,528,270 $1,481,408 $1,381,871
========== ========== ========== ========== ==========
Billed Electric Energy
Sales (Millions of KWH):
Residential 5,680 5,102 5,564 5,401 5,098
Commercial 4,067 3,841 3,967 3,821 3,644
Industrial 5,690 5,509 5,565 5,532 5,513
Governmental 230 248 290 285 320
---------- ---------- ---------- ---------- ----------
Total retail 15,667 14,700 15,386 15,039 14,575
Sales for resale 13,950 15,413 16,087 13,618 12,128
---------- ---------- ---------- ---------- ----------
Total 29,617 30,113 31,473 28,657 26,703
========== ========== ========== ========== ==========
Gulf States Utilities Company
1993 Financial Statements
GULF STATES UTILITIES COMPANY
DEFINITIONS
Certain abbreviations or acronyms used in GSU's Financial Statements, Notes
to Financial Statements, and Management's Financial Discussion and Analysis are
defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
AP&L Arkansas Power & Light Company
Cajun Cajun Electric Power Cooperative, Inc.
DOE United States Department of Energy
Entergy or System Entergy Corporation and its various direct and indirect
subsidiaries
Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy that
has operating responsibility for Grand Gulf 1, River
Bend, Waterford 3, and Arkansas Nuclear One Steam
Electric Generating Station
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
GSU Gulf States Utilities Company (including wholly owned
subsidiaries - Varibus Corporation, GSG&T, Inc.,
Prudential Oil and Gas, Inc., and Southern Gulf Railway
Company)
KWH Kilowatt-Hour(s)
LP&L Louisiana Power & Light Company
LPSC Louisiana Public Service Commission
Money Pool Entergy Money Pool, which allows certain System
companies to borrow from, or lend to, certain other
System companies
MP&L Mississippi Power & Light Company
Merger The combination transaction consummated on
December 31, 1993, by which GSU became a subsidiary of
Entergy Corporation and Entergy Corporation became a
Delaware corporation
NOPSI New Orleans Public Service Inc.
PUCT Public Utility Commission of Texas
Rate Cap The level of retail electric base rates in effect at
December 31, 1993, for the Louisiana retail
jurisdiction, and the level in effect prior to the
Texas Cities Rate Settlement for the Texas retail
jurisdiction, that may not be exceeded for the five
years following December 31, 1993
River Bend River Bend Steam Electric Generating Station (nuclear),
owned 70% by GSU
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards promulgated
by the FASB
SFAS 106 SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions"
SFAS 109 SFAS No. 109, "Accounting for Income Taxes"
System or Entergy Entergy Corporation and its various direct and indirect
subsidiaries
System Agreement Agreement, effective January 1, 1983, as
amended among the System operating companies relating
to the sharing of generating capacity and other power
resources
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively
GULF STATES UTILITIES COMPANY
REPORT OF MANAGEMENT
The management of Gulf States Utilities Company has prepared and is
responsible for the financial statements and related financial information
included herein. The financial statements are based on generally accepted
accounting principles. Financial information included elsewhere in this report
is consistent with the financial statements.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting controls that
is designed to provide reasonable assurance, on a cost-effective basis, as to
the integrity, objectivity, and reliability of the financial records, and as to
the protection of assets. This system includes communication through written
policies and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and the
training of personnel. This system is also tested by a comprehensive internal
audit program.
The independent public accountants provide an objective assessment of the
degree to which management meets its responsibility for fairness of financial
reporting. They regularly evaluate the system of internal accounting controls
and perform such tests and other procedures as they deem necessary to reach and
express an opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide reasonable
assurance that its operations are carried out with a high standard of business
conduct.
/S/ EDWIN LUPBERGER /S/ GERALD D. MCINVALE
EDWIN LUPBERGER GERALD D. MCINVALE
Chairman and Chief Executive Officer Senior Vice President and
Chief Financial Officer
GULF STATES UTILITIES COMPANY
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Gulf States Utilities Company Audit Committee of the Board of Directors
is comprised of four directors, who are not officers of GSU: Bismark A.
Steinhagen (Chairman-effective January 2, 1994), Frank W. Harrison, Jr., M.
Bookman Peters, and James E. Taussig, II. The committee held two meetings
during 1993.
The Audit Committee oversees GSU's financial reporting process on behalf of
the Board of Directors and provides reasonable assurance to the Board that
sufficient operating, accounting, and financial controls are in existence and
are adequately reviewed by programs of internal and external audits.
The Audit Committee discussed with GSU's internal auditors and the
independent public accountants (Coopers & Lybrand) the overall scope and
specific plans for their respective audits, as well as GSU's financial
statements and the adequacy of GSU's internal controls. The committee met,
together and separately, with GSU's internal auditors and independent public
accountants, without management present, to discuss the results of their audits,
their evaluation of GSU's internal controls, and the overall quality of GSU's
financial reporting. The meetings also were designed to facilitate and
encourage any private communication between the committee and the internal
auditors or independent public accountants.
/S/ BISMARK A. STEINHAGEN
BISMARK A. STEINHAGEN
Chairman, Audit Committee
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of
Gulf States Utilities Company
We have audited the accompanying balance sheets of Gulf States Utilities
Company as of December 31, 1993 and 1992 and the related statements of income,
retained earnings and paid in capital and cash flows for each of the three years
in the period ended December 31, 1993. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 12 to the financial statements, the common stock of
the Company was acquired on December 31, 1993.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Gulf States Utilities
Company as of December 31, 1993 and 1992, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
1993 in conformity with generally accepted accounting principles.
As discussed in Note 2 to the financial statements, the net amount of
capitalized costs for the Company's River Bend Unit I Nuclear Generating Plant
(River Bend) exceed those costs currently being recovered through rates. At
December 31, 1993, approximately $747 million is not currently being recovered
through rates. If current regulatory and court orders are not modified, a
write-off of all or a portion of such costs may be required. Additionally,
as discussed in Note 2 to the financial statements, other rate-related
contingencies exist which may result in a refund of revenues previously
collected. The extent of such write-off of River Bend costs or refund of
revenues previously collected, if any, will not be determined until appropriate
rate proceedings and court appeals have been concluded. Accordingly, no
provision for write-off or refund has been recorded in the accompanying
financial statements.
As discussed in Note 8 to the financial statements, civil actions have been
initiated against the Company to, among other things, recover the co-owner's
investment in River Bend and to annul the River Bend Joint Ownership
Participation and Operating Agreement. The ultimate outcome of these
proceedings cannot presently be determined. Accordingly, no provision for any
liability that may result from the ultimate resolution of these proceedings has
been recorded in the accompanying financial statements.
As discussed in Note 3 to the financial statements, in 1993, the Company
adopted Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes", and elected to restate the 1991 and 1992 financial statements
for its effects. As discussed in Note 10 to the financial statements, the
Company adopted Statement of Financial Accounting Standards No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions",
as of January 1, 1993. As discussed in Note 1 to the financial statements,
as of January 1, 1993, the Company began accruing revenues for energy
delivered to customers but not yet billed. As discussed in Note 1 to the
financial statements, the Company changed its accounting for power
plant materials and supplies as of January 1, 1992.
/S/ COOPERS & LYBRAND
COOPERS & LYBRAND
Houston, Texas
February 11, 1994
GULF STATES UTILITIES COMPANY
BALANCE SHEETS
ASSETS
December 31,
-----------------------------
1993 1992
---------- ----------
(In Thousands)
Utility Plant (Notes 1 and 2):
Electric $6,825,989 $6,770,017
Natural gas 42,786 41,160
Steam products 75,689 72,292
Property under capital leases (Note 9) 86,039 87,214
Construction work in progress 50,080 32,305
Nuclear fuel under capital leases (Note 9) 94,828 106,565
---------- ----------
Total 7,175,411 7,109,553
Less - accumulated depreciation and amortization 2,323,804 2,172,719
---------- ----------
Utility plant - net 4,851,607 4,936,834
---------- ----------
Other Property and Investments:
Decommissioning trust fund (Note 8) 17,873 14,102
Other - at cost (less accumulated depreciation) 29,360 36,225
---------- ----------
Total 47,233 50,327
---------- ----------
Current Assets:
Cash and cash equivalents (Note 1):
Cash 3,012 720
Temporary cash investments - at cost,
which approximates market 258,337 197,021
---------- ----------
Total cash and cash equivalents 261,349 197,741
Accounts receivable:
Customer (less allowance for doubtful accounts of
$2.4 million in 1993 and $3.0 million in 1992) 117,369 124,214
Other 18,371 18,405
Accrued unbilled revenues (Note 1) 32,572 -
Deferred fuel costs (Note 1) 5,883 -
Fuel inventory (Note 1) 23,448 21,159
Materials and supplies - at average cost 86,831 86,972
Rate deferrals (Note 2) 90,775 85,473
Accumulated deferred income taxes (Note 3) 28,425 91,731
Prepayments and other 48,948 38,314
---------- ----------
Total 713,971 664,009
---------- ----------
Deferred Debits and Other Assets:
Rate deferrals (Note 2) 638,015 728,790
SFAS 109 regulatory asset - net (Note 3) 432,411 357,253
Long-term receivables 218,079 191,269
Unamortized loss on reacquired debt 70,970 67,074
Other 193,490 168,891
---------- ----------
Total 1,552,965 1,513,277
---------- ----------
TOTAL $7,165,776 $7,164,447
========== ==========
See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
-----------------------------
1993 1992
---------- -----------
(In Thousands)
Capitalization:
Common stock, no par value, authorized 200,000,000
shares; issued and outstanding 100 shares at
December 31, 1993 (Notes 5 and 12) $114,055 $1,200,923
Paid-in capital 1,152,304 67,316
Retained earnings (Notes 3 and 7) 666,401 631,462
---------- ----------
Total common shareholder's equity 1,932,760 1,899,701
Preference stock (Note 5) 150,000 -
Preferred stock (Note 5):
Without sinking fund 136,444 136,444
With sinking fund 101,004 269,387
Long-term debt (Note 6) 2,368,639 2,374,458
---------- ----------
Total 4,688,847 4,679,990
---------- ----------
Other Noncurrent Liabilities:
Obligations under capital leases (Note 9) 152,359 154,923
Other (Note 8) 47,107 18,865
---------- ----------
Total 199,466 173,788
---------- ----------
Current Liabilities:
Currently maturing long-term debt 425 160,425
Accounts payable:
Associated companies (Note 11) 2,745 -
Other 109,840 101,513
Customer deposits 21,958 21,152
Taxes accrued 22,856 19,092
Interest accrued 59,516 62,013
Nuclear refueling reserve 22,356 10,083
Deferred fuel cost (Note 1) - 36,954
Obligations under capital leases (Note 9) 41,713 51,688
Other 97,203 66,534
---------- ----------
Total 378,612 529,454
---------- ----------
Deferred Credits:
Accumulated deferred income taxes (Note 3) 1,252,295 1,192,182
Accumulated deferred investment tax credits (Note 3) 94,455 94,690
Deferred River Bend finance charges 106,765 131,123
Other 445,336 363,220
---------- ----------
Total 1,898,851 1,781,215
---------- ----------
Commitments and Contingencies (Notes 2, 8, and 9)
TOTAL $7,165,776 $7,164,447
========== ==========
See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
------------------------------------------
1993 1992 1991
-------- ---------- --------
(In Thousands)
Operating Activities:
Net income $78,862 $133,848 $112,030
Noncash items included in net income:
Extraordinary items 1,259 9,597 361
Cumulative effect of accounting changes (10,660) (4,032) -
Change in rate deferrals 61,115 52,946 38,236
Depreciation and decommissioning 190,405 188,393 187,936
Deferred income taxes and investment tax credits 41,302 50,238 43,504
Allowance for equity funds used during construction (726) (1,226) (608)
Changes in working capital:
Receivables 6,879 4,373 (12,503)
Fuel inventory (2,289) (4,152) 10,422
Accounts payable 11,072 (1,171) (6,912)
Taxes accrued 3,764 (2,634) 753
Interest accrued (2,497) (15,276) 3,211
Other working capital accounts (9,582) (13,675) 12,602
Decommissioning trust contributions 2,710 5,912 2,315
Purchased power settlement (169,300) (20,797) 12,565
Other 53,121 (34,816) 29,833
-------- ---------- --------
Net cash flow provided by operating activities 255,435 347,528 433,745
-------- ---------- --------
Investing
Construction expenditures (115,481) (97,377) (87,470)
Proceeds received from sale of property - 12,460 -
Allowance for equity funds used during construction 726 1,226 608
Nuclear fuel purchases (2,118) - -
Proceeds from sale/leaseback of nuclear fuel 2,118 - -
Other property, investments and escrow account 5,921 13,091 10,070
-------- ---------- --------
Net cash flow used in investing activities (108,834) (70,600) (76,792)
-------- ---------- --------
Financing Activities:
Proceeds from issuance of:
First mortgage bonds 338,379 1,185,260 -
Preference stock 146,625 - -
Other long-term debt 21,440 48,965 200,000
Retirement of:
First mortgage bonds (360,199) (1,067,717) (87,320)
Other long-term debt (18,398) (127,161) (245,762)
Redemption of preferred and preference stock (174,841) (174,226) -
Dividends paid:
Preferred and preference stock (35,999) (237,369) (127,398)
-------- ---------- --------
Net cash flow used in financing activities (82,993) (372,248) (260,480)
-------- ---------- --------
Net increase (decrease) in cash and cash equivalents 63,608 (95,320) 96,473
Cash and cash equivalents at beginning of period 197,741 293,061 196,588
-------- ----------
Cash and cash equivalents at end of period $261,349 $197,741 $293,061
======== ========== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $197,058 $239,607 $227,306
Income taxes $15,600 $8,000 $5,700
Noncash investing and financing activities:
Capital lease obligations incurred $17,143 $87,022 $13,958
See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is important to GSU due to the capital intensive nature of our
business, which requires large investments in long-lived assets. However, large
capital expenditures for the construction of new generating capacity are not
currently planned. GSU requires significant capital resources for the periodic
maturity of certain series of debt, preferred stock, and preference stock. Net
cash flow from operations totaled $255 million, $348 million, and $434 million
in 1993, 1992, and 1991, respectively. Cash flow from operations in 1993
includes nonrecurring items related to the payment of $169.3 million as a result
of the settlement of a purchased power dispute. In recent years, this cash
flow, supplemented by cash on hand, has been sufficient to meet substantially
all investing and financing requirements, including capital expenditures,
preferred and preference dividends, and debt/preferred stock maturities. GSU's
ability to fund these capital requirements with cash from operations, results in
part from our continued efforts to reduce costs as well as collections under our
River Bend rate phase-in plan of previously deferred amounts. (In the income
statement, these revenue collections are offset by the amortization of
previously deferred costs, therefore, there is no effect on net income.) See
Note 2, incorporated herein by reference, for additional information on GSU's
rate phase-in plan. Further, GSU has the ability to meet future capital
requirements through future debt and preference stock issuances, as discussed
below. See Note 8, incorporated herein by reference, for additional information
on GSU's capital and refinancing requirements in 1994 through 1996. Further,
in order to take advantage of lower interest and dividend rates, GSU continues
to refinance high-cost debt and preferred stock prior to maturity.
In February 1994, GSU paid to Entergy Corporation a $100 million cash
dividend on common stock. Prior to the February 1994 dividend payment, GSU had
not paid a common dividend since June 1986.
Earnings coverage tests (which are impacted by the inclusion of the
cumulative effect of the change in accounting principle for accruing unbilled
revenues discussed in Note 1) and bondable property additions limit the amount
of first mortgage bonds and preferred stock that GSU can issue. Based on the
most restrictive applicable tests as of December 31, 1993, and an assumed annual
interest rate of 8%, GSU could have issued $425 million of additional first
mortgage bonds. As of December 31, 1993, GSU was unable to issue any additional
preferred stock. There are no limitations on the issuance of preference stock.
GSU has the conditional ability to issue first mortgage bonds against the
retirement of first mortgage bonds without satisfying an earnings coverage test.
See Notes 5 and 6, incorporated herein by reference, for information on
GSU's financing activities and Note 4, incorporated herein by reference, for
information on GSU's short-term borrowings and lines of credit.
See Notes 2 and 8 regarding River Bend rate appeals and litigation with
Cajun. Substantial write-offs or charges resulting from adverse rulings in
these matters could adversely affect GSU's ability to continue to pay dividends
and obtain financing, which could in turn affect GSU's liquidity.
GULF STATES UTILITIES COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31,
-----------------------------------------
1993 1992 1991
---------- ---------- ----------
(In Thousands)
Operating Revenues (Notes 1 and 2):
Electric $1,747,961 $1,694,536 $1,623,959
Natural gas 32,466 28,523 31,858
Steam products 47,193 50,315 46,418
---------- ---------- ----------
Total 1,827,620 1,773,374 1,702,235
---------- ---------- ----------
Operating Expenses:
Operation:
Fuel for electric generation and fuel-related
expenses 538,887 471,873 446,543
Purchased power 134,936 136,716 161,374
Gas purchased for resale 20,529 16,563 19,290
Other 324,617 277,385 248,302
Maintenance 144,766 161,080 142,098
Depreciation and decommissioning 190,405 188,393 187,936
Taxes other than income taxes 95,742 91,740 88,402
Income taxes (Note 3) 46,007 38,058 35,084
Amortization of rate deferrals (Note 2) 61,115 52,946 38,236
---------- ---------- ----------
Total 1,557,004 1,434,754 1,367,265
---------- ---------- ----------
Operating Income 270,616 338,620 334,970
---------- ---------- ----------
Other Income:
Allowance for equity funds used during
construction 726 1,226 608
Miscellaneous - net 19,996 64,837 49,947
Income taxes (Note 3) (12,009) (17,801) (13,166)
---------- ---------- ----------
Total 8,713 48,262 37,389
Interest Charges:
Interest on long-term debt 202,235 239,341 234,418
Other interest - net 8,364 9,075 26,038
Allowance for borrowed funds used during
construction (731) (947) (488)
---------- ---------- ----------
Total 209,868 247,469 259,968
---------- ---------- ----------
Income before Extraordinary Items and the
Cumulative Effect of Accounting Changes 69,461 139,413 112,391
Extraordinary Items (net of income taxes)
(Note 1) (1,259) (9,597) (361)
Cumulative Effect of Accounting Changes
(net of income taxes) (Note 1) 10,660 4,032 -
---------- ---------- ----------
Net Income 78,862 133,848 112,030
Preferred and Preference Stock Dividend
Requirements 35,581 49,702 63,070
---------- ---------- ----------
Earnings Applicable to Common Stock $43,281 $84,146 $48,960
========== ========== ==========
See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY
STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL
For the Years Ended December 31,
----------------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Retained Earnings, January 1 (Note 3) $631,462 $667,893 $622,026
Add - Net income 78,862 133,848 112,030
Total 710,324 801,741 734,056
Deduct:
Dividends declared:
Preferred and preference stock 35,581 158,547 66,163
Common stock - - -
Preferred and preference stock redemption 8,342 11,732 -
-------- -------- --------
Total 43,923 170,279 66,163
-------- -------- --------
Retained Earnings, December 31 (Note 7) $666,401 $631,462 $667,893
======== ======== ========
Paid-in Capital, January 1 $67,316 $73,993 $22,237
Issuance of 100 shares of no par common
stock with a stated value of $114,055
net of the retirement of 114,055,065 shares
of no par common stock (Notes 5 and 12) 1,086,868 - -
Issuance of 6,000,000 shares of common
stock in the settlement of purchased
power dispute - - 51,775
Loss on reacquisition of
preferred and preference stock (1,880) (6,677) (19)
---------- -------- --------
Paid-in Capital, December 31 $1,152,304 $67,316 $73,993
========== ======== ========
See Notes to Financial Statements.
GULF STATES UTILITIES COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income decreased in 1993 due primarily to Merger-related charges
recorded at year-end. Also contributing to the decrease was a rate refund and
one-time credit resulting from a November 1993 rate settlement (see Note 2,
incorporated herein by reference), the effect of implementing SFAS 106 (see Note
10, incorporated herein by reference), and the impact in 1992 of reducing a
purchased power settlement liability. The decrease in net income was partially
offset by the one-time recording of the cumulative effect of the change in
accounting principle for unbilled revenues (see Note 1, incorporated herein by
reference) and its ongoing effects. Effective January 1, 1993, GSU began
accruing as revenues the charges for energy delivered to customers but not yet
billed. Electric and gas revenues were previously recorded on a cycle-billing
basis. Excluding the above mentioned items, net income for 1993 would have been
$139.2 million and net income for 1992 would have been $109.6 million. This
increase of $29.6 million is due primarily to increased retail energy sales and
decreased interest expense.
Net income increased in 1992 due primarily to increased revenues, reduced
interest charges, and reductions to a previously recorded purchased power
settlement liability.
Significant factors affecting the results of operations and causing
variances between the years 1993 and 1992, and 1992 and 1991 are discussed under
"Revenues and Sales," "Expenses," and "Other" below.
Revenues and Sales
Operating revenues were higher in 1993 due primarily to increased
residential and commercial energy sales resulting primarily from a return to
more normal weather as compared to milder weather in 1992, and increased fuel
adjustment revenues and collections of previously deferred River Bend costs,
neither of which affects net income. These increases were partially offset by a
refund and one-time credit to Texas retail customers resulting from a rate
settlement.
Operating revenues were higher in 1992 due primarily to increased fuel
adjustment revenues and increased collections of previously deferred River Bend
costs and, to a lesser extent, to increased energy sales, primarily industrial.
Also contributing to the 1992 increase was the fact that revenues were lower in
1991 due in part to a $24.1 million refund provision ordered by the LPSC.
See "Selected Financial Data - Five-Year Comparison," incorporated herein
by reference, following the notes, for information on operating revenues by
source and KWH sales.
Expenses
Fuel for electric generation and fuel-related expenses increased in 1993
due primarily to a higher average per unit cost for gas resulting from increased
gas prices in 1993 and increased generation, primarily River Bend. Fuel expense
in 1992 increased due to higher average fuel cost, offset partially by reduced
generation resulting from a scheduled refueling outage at River Bend in the
first half of 1992. Purchased power expense decreased in 1992, despite
increased purchases, due to the conclusion in June 1991 of capacity costs
associated with the buyback of a portion of Cajun's share of River Bend
generation.
Other operating expenses increased in 1993 due primarily to $52.3 million
of Merger-related charges for financial investment advisor fees and early
retirement and other severance plan provisions. Charges for other
postemployment benefits increased resulting from the adoption of SFAS 106.
Other operating and maintenance expenses increased in 1992 due to costs in
excess of the normal eighteen month outage accrual resulting from an extended
refueling outage at River Bend from March to September. Further, amortization
of rate deferrals increased in 1993 and 1992 due to increased amortization of
amounts in accordance with the River Bend phase-in plan.
Other
Other miscellaneous income decreased in 1993 and increased in 1992 due
primarily to the 1992 effect of reducing a liability relating to a purchased
power settlement. In accordance with the settlement, the liability was based
upon the price of GSU common stock as of the November 1991 settlement and was
subsequently reduced as the price of GSU common stock increased. Interest
expense declined in 1993 and 1992 as a result of the continued refinancing of
high-cost debt during 1993, 1992, and 1991.
GULF STATES UTILITIES COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Entergy Corporation-GSU Merger
On December 31, 1993, Entergy Corporation completed the Merger with GSU.
For further information, see Note 12, incorporated herein by reference.
Competition
GSU welcomes competition in the electric energy business and believes that
a more competitive environment should benefit our customers, employees, and
shareholders of Entergy Corporation. We also recognize that competition
presents us with many challenges, and we have identified the following as our
major competitive challenges:
Retail and Wholesale Rate Issues
Increasing competition in the utility industry brings an increased need to
stabilize or reduce rates. In connection with the Merger, GSU agreed with the
LPSC and PUCT to a five-year Rate Cap on retail electric rates, and to pass
through to retail customers the fuel savings and a certain percentage of the
nonfuel savings created by the Merger. GSU's base rates will be reviewed by the
LPSC during the first post-Merger earnings analysis, scheduled for mid-1994, for
reasonableness of its return on equity. The PUCT will review GSU's base rates
in accordance with its Merger approval plan in mid-1994 also. For further
information on Merger-related rate agreements, see Note 2, incorporated herein
by reference.
Cogeneration projects developed or considered by certain industrial
customers over the last several years have resulted in GSU developing and
securing approval of rates lower than the rates previously approved by the PUCT
and LPSC for such industrial customers. Such rates are designed to retain such
customers, and to compete for and develop new loads, and do not presently
recover GSU's full cost of service. The pricing agreements at non-full cost of
service based rates fully recover all related costs but provide only a minimal
return. Substantially all of such pricing agreements expire no later than 1997.
During 1993, KWH sales to industrial customers at less than full cost of
service, which make up approximately 26% of the total industrial class,
increased 8%. Sales to the remaining industrial customers decreased 3%.
Retail wheeling, a major industry issue which may require utilities to
"wheel" or move power from third parties to their own retail customers, is
evolving gradually. As a result, the retail market could become more
competitive.
In the wholesale rate area, FERC approved in 1992, with certain
modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power, Inc.
to sell wholesale power at market-based rates and to provide to electric
utilities "open access" to the System's transmission system (subject to certain
requirements). GSU was later added to this filing. Various intervenors in the
proceeding filed petitions for review with the United States Court of Appeals
for the District of Columbia Circuit. FERC's order, once it takes effect, will
increase marketing opportunities for GSU, but will also expose GSU to the risk
of loss of load or reduced revenues due to competition with alternative
suppliers.
In light of these rate issues, GSU is aggressively reducing costs to avoid
potential earnings erosions that might result as well as to successfully compete
by becoming a low-cost producer. To minimize future costs, GSU is currently
working with the PUCT regarding integrated resource planning. Integrated
resource planning, or least cost planning, includes demand-side measures such as
customer energy conservation and supply-side measures such as more efficient
power plants. These measures are designed to delay the building of new power
plants for the next 20 years.
The Energy Policy Act of 1992
The Energy Policy Act of 1992 (Energy Act) is changing the transmission and
distribution of electricity. This act encourages competition and affords us the
opportunities, and the risks, associated with an open and more competitive
market environment. The Energy Act increases competition in the wholesale
energy market through the creation of exempt wholesale generators (EWGs). The
Energy Act also gives FERC the authority to order investor-owned utilities to
provide transmission access to or for other utilities, including EWGs.
Deregulated Portion of River Bend
As of December 31, 1993, GSU has not recovered a significant amount of its
investment or received any return associated with the portion of River Bend
included in the deregulated asset plan in Louisiana and the portion of River
Bend placed in abeyance as part of the Texas rate order which went into effect
in July 1988. See Note 2, incorporated herein by reference, for further
information. Future earnings will continue to be limited as long as the limited
recovery of the investment and lack of return continues.
For the year ended December 31, 1993, GSU recorded revenues resulting from
the sale of electricity from the deregulated asset plan of approximately $35.3
million. Operations and maintenance expenses, including fuel, were
approximately $33.3 million, and depreciation expense associated with the
deregulated asset plan investment was approximately $16.8 million for the year
ended December 31, 1993. For the year ended December 31, 1993, GSU recorded
nonfuel revenue of $31.5 million (included in the $35.3 million of total
deregulated asset plan revenue discussed above) which, absent the deregulated
asset plan, would not have been realized. The operations and maintenance
expenses and depreciation expense allocated to the deregulated asset plan as
detailed above, however, would have been incurred at River Bend with or without
the deregulated asset plan. Future impact of the deregulated asset plan on
GSU's results of operations and financial position will depend on River Bend's
future operating costs, the unit's efficiency and availability, and the future
market for energy over the remaining life of the unit. GSU anticipates based on
current estimates of the factors discussed above, that future revenues from the
deregulated asset plan will fully recover all related costs.
Litigation and Regulatory Proceedings
See Note 2, incorporated herein by reference, for information on the
possibility of material adverse effects on GSU's financial condition resulting
from substantial write-offs and/or refunds in connection with outstanding
appeals and remands regarding approximately $1.4 billion of abeyed River Bend
plant costs and approximately $187 million of Texas retail jurisdiction deferred
River Bend operating and carrying costs.
See Note 8, incorporated herein by reference, for information regarding
litigation with Cajun concerning Cajun's ownership interest in River Bend and
the possible material adverse effects on GSU's financial condition in the event
that GSU is ultimately unsuccessful in this litigation, including a possible
filing under the bankruptcy laws.
GULF STATES UTILITIES COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GSU maintains accounts in accordance with FERC and other regulatory
guidelines. Certain previously reported amounts have been reclassified to
conform to current classifications.
Revenues and Fuel Costs
Prior to January 1, 1993, GSU recognized electric and gas revenues when
billed. To provide a better matching of revenues and expenses, effective
January 1, 1993, GSU adopted a change in accounting principle to provide for
accrual of the nonfuel portion of estimated unbilled revenues. The cumulative
effect of this accounting change as of January 1, 1993 for the Texas retail
jurisdiction, wholesale jurisdiction, and gas department increased 1993 net
income by $10.7 million, net of related income taxes of $6.9 million. Had this
new accounting method been in effect during prior years, net income before the
cumulative effect would not have been materially different from that shown in
the accompanying financial statements.
In the Louisiana retail jurisdiction, the LPSC issued a rate order,
effective March 1, 1991, which required GSU to defer the initial effect when and
if GSU changed its accounting for unbilled revenue. The amount of unbilled
revenues in the Louisiana jurisdiction was $16.6 million at January 1, 1993.
Because of the LPSC rate order, GSU recorded a deferred credit of $16.6 million.
There was no cumulative effect of the change recorded in operations. If the
LPSC order were to be revised, the net income effect would be $10.1 million, net
of related income taxes of $6.5 million. Changes in unbilled revenues in the
Louisiana retail jurisdiction subsequent to January 1, 1993 have been recorded
in operations.
GSU's wholesale and Louisiana retail rate schedules include fuel adjustment
clauses that allow deferral of fuel costs until such costs are reflected in the
related revenues. GSU's Texas retail rate schedules include a fixed fuel factor
approved by the PUCT, which remains the same until changed as part of a general
rate case or fuel reconciliation, or until the PUCT orders a reconciliation for
any over or under collections of fuel costs. Reconcilable fuel and purchased
power costs in excess of those included in base rates or recovered through fuel
adjustment clauses are deferred (or accrued) until such costs are billed (or
credited) to customers.
Utility Plant
Utility plant is stated at original cost. The original cost of utility
plant retired or removed, plus the applicable removal costs, less salvage, is
charged to accumulated depreciation. Maintenance, repairs, and minor
replacement costs are charged to operating expenses. Substantially all of
GSU's utility plant is subject to the lien of its mortgage indenture.
AFUDC represents the approximate net composite interest cost of borrowed
funds and a reasonable return on the equity funds used for construction.
Although AFUDC increases utility plant and earnings, only recovery of prudently
incurred costs are realized in cash through depreciation provisions included in
rates allowed by regulators. GSU's AFUDC rates were as follows:
January 1, 1991 - March 31, 1991 11.50%
April 1, 1991 - March 31, 1992 11.75%
April 1, 1992 - March 31, 1993 10.75%
April 1, 1993 - December 31, 1993 10.50%
Depreciation is computed on the straight-line basis at rates based on the
estimated service lives and cost of removal of the various classes of property.
Depreciation provisions on average depreciable property approximated 2.7% in
1993, 1992, and 1991.
Jointly-Owned Facilities
As of December 31, 1993, GSU owned undivided interests in three jointly-
owned electric generating facilities as detailed below:
Total
Fuel Megawatt Accumulated
Generating Stations Type Capability Ownership Investment Depreciation
------------------- ------ ---------- --------- ---------- ------------
(In Thousands)
River Bend Unit 1 Nuclear 931 70% $3,056,464 $545,740
Roy S. Nelson Unit 6 Coal 550 70% $ 389,915 $134,877
Big Cajun 2 Unit 3 Coal 540 42% $ 219,911 $ 68,150
GSU's share of operations and maintenance expense related to the jointly-
owned units is included in operating expenses. See Note 8 for information
regarding unpaid amounts by Cajun for their share of River Bend costs.
Income Taxes
GSU and its subsidiaries file a consolidated federal income tax return.
Income taxes are allocated to GSU in proportion to its contribution to the
consolidated taxable income subject to the limitations for recognition of net
operating loss carryforwards and investment tax credits. Deferred taxes are
recorded for all temporary differences between book and taxable income.
Investment tax credits are deferred and amortized based upon the average
useful life of the related property in accordance with rate treatment.
Inventories
GSU's fuel inventories are comprised of fuel oil and natural gas, valued at
weighted average cost, and coal, valued at last-in, first-out cost.
Accounting for Power Plant Materials and Supplies
During the first quarter of 1992, accounting procedures were changed to
include in inventory, power plant materials and supplies previously expensed or
capitalized as plant in service. GSU believed this change provided a better
matching of costs with related revenues. The change resulted from
recommendations during audits by FERC and the LPSC, in addition to a general
change in industry practice. The pro forma effect of retroactive application on
any period prior to 1992 was not determinable as, prior to this change, GSU did
not perform the physical inventory counts necessary to determine inventory
balances in prior periods. The effect of the change was to increase materials
and supplies by $76.6 million, of which $41.1 million associated with GSU's
Texas and Louisiana retail jurisdictions was deferred, and to decrease amounts
previously capitalized, primarily plant in service, by $29 million. Amounts
deferred for the Louisiana retail jurisdiction are currently being amortized to
income over approximately seven years, through February 1998, while amounts
deferred for the Texas retail jurisdiction will be amortized to income in future
years. The cumulative effect of this accounting change as of January 1, 1992,
which relates to the operations on which GSU has discontinued regulatory
accounting principles, amounted to $6.5 million before the related income tax
effect of $2.5 million.
Reacquired Debt
The premiums and costs associated with reacquired debt are amortized over
the life of the related new issuances for the portions of the business accounted
for in accordance with generally accepted accounting principles for regulated
enterprises.
During 1992, GSU extinguished over $1 billion of long-term debt through
refinancings. A loss of $81.8 million was recorded associated with the
extinguished debt of which $67.2 million of the loss was deferred, representing
the portion of GSU's operations allocable to the Texas and Louisiana retail
jurisdictions, and began to amortize that amount over the life of the new debt
sold to retire the existing debt. A loss of $9.6 million, net of related income
taxes of $5.0 million, was charged to income in 1992 as an extraordinary item.
Further, refinancings of long-term debt during 1993 resulted in an extraordinary
loss of $1.3 million, net of $.7 million of related taxes.
Cash and Cash Equivalents
GSU considers all unrestricted highly liquid debt instruments purchased
with an original maturity of three months or less to be cash equivalents.
SFAS 101
SFAS No. 101, "Regulated Enterprises - Accounting for the Discontinuation
of Application of FASB Statement No. 71," specifies how an enterprise that
ceases to meet the criteria for application of SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation," to all or part of its operations should
report that event in its financial statements. GSU discontinued regulatory
accounting principles for the wholesale jurisdiction and steam department, and
the Louisiana deregulated portion of River Bend, during 1989 and 1991,
respectively.
Fair Value Disclosure
The estimated fair value of GSU's significant financial instruments have
been determined using available market information and appropriate valuation
methodologies. However, considerable judgment is required in developing the
estimates of fair value. Therefore, estimates are not necessarily
indicative of the amounts that GSU could realize in a current market exchange.
In addition, gains or losses realized on financial instruments may be reflected
in future rates and not accrue to the benefit of stockholders.
GSU considers the carrying amounts of financial instruments classified as
current assets and liabilities to be a reasonable estimate of their fair value
because of the short maturity of these instruments. See Notes 5, 6, and 8 for
additional fair value disclosure.
NOTE 2. RATE AND REGULATORY MATTERS
River Bend
In May 1988, the PUCT granted GSU a permanent increase in annual revenues
of $59.9 million resulting from the inclusion in rate base of approximately $1.6
billion of company-wide River Bend plant investment and approximately $182
million of related Texas retail jurisdiction deferred River Bend costs (Allowed
Deferrals). In addition, the PUCT disallowed as imprudent $63.5 million of
company-wide River Bend plant costs and placed in abeyance, with no finding of
prudency, approximately $1.4 billion of company-wide River Bend plant investment
and approximately $157 million of Texas retail jurisdiction deferred River Bend
operating and carrying costs. The PUCT affirmed that the ultimate rate
treatment of such amounts would be subject to future demonstration of the
prudency of such costs. GSU and intervening parties appealed this order (Rate
Appeal) and GSU filed a separate rate case asking that the abeyed River Bend
plant costs be found prudent (Separate Rate Case). Intervening parties filed
suit in district court to prohibit the Separate Rate Case. The district court's
decision was ultimately appealed to the Texas Supreme Court which ruled in 1990
that the prudence of the purported abeyed costs could not be relitigated in a
separate rate proceeding. Further, the Texas Supreme Court's decision stated
that all issues relating to the merits of the original order of the PUCT,
including the prudence of all River Bend-related costs, should be addressed in
the Rate Appeal.
In October 1991, the district court in the Rate Appeal issued an order
holding that, while it was clear the PUCT made an error in assuming it could set
aside $1.4 billion of the total costs of River Bend and consider them in a later
proceeding, the PUCT, nevertheless, found that GSU had not met its burden of
proof related to the amounts placed in abeyance. The court also ruled that the
Allowed Deferrals should not be included in rate base under a 1991 decision
regarding El Paso Electric Company's similar deferred costs (El Paso Case). The
court further stated that the PUCT erred in reducing GSU's deferred costs by
$1.50 for each $1.00 of revenue collected under the interim rate increases
authorized in 1987 and 1988. The court remanded the case to the PUCT with
instructions as to the proper handling of the Allowed Deferrals. GSU's motion
for rehearing was denied, and in December 1991, GSU filed an appeal of the
October 1991 district court order. The PUCT also appealed the October 1991
district court order, which served to supersede the district court's judgment,
rendering it unenforceable under Texas law.
In August 1992, the court of appeals in the El Paso Case handed down its
second opinion on rehearing modifying its previous opinion on deferred
accounting. The court's second opinion concluded that the PUCT may lawfully
defer operating and maintenance costs and subsequently include them in rate
base, but that the Public Utility Regulatory Act prohibits such rate base
treatment for deferred carrying costs. The court stated, however, its opinion
would not preclude the recovery of deferred carrying costs. The August 1992
court of appeals opinion was appealed to the Texas Supreme Court where arguments
were heard in September 1993. The matter is pending.
In September 1993, the Texas Third District Court of Appeals (the Third
District Court) remanded the October 1991 district court decision to the PUCT
"to reexamine the record evidence to whatever extent necessary to render a final
order supported by substantial evidence and not inconsistent with our opinion."
The Third District Court specifically addressed the PUCT's treatment of certain
costs, stating that the PUCT's order was not based on substantial evidence. The
Third District Court also applied its most recent ruling in the El Paso Case to
the deferred costs associated with River Bend. However, the Third District
Court cautioned the PUCT to confine its deliberations to the evidence addressed
in the original rate case. Certain parties to the case have indicated their
position that, on remand, the PUCT may change its original order only with
respect to matters specifically discussed by the Third District Court which, if
allowed, would increase GSU's allowed River Bend investment, net of accumulated
depreciation and related taxes, by approximately $48 million as of December 31,
1993. GSU believes that under the Third District Court's decision, the PUCT
would be free to reconsider any aspect of its order concerning the abeyed $1.4
billion River Bend investment. GSU has filed a motion for rehearing asking the
Third District Court to modify its order so as to permit the PUCT to take
additional evidence on remand. The PUCT and other parties have also moved for
rehearing on various grounds. The Third District Court has not yet ruled on any
of these motions.
As of December 31, 1993, the River Bend plant costs disallowed for retail
ratemaking purposes in Texas, and the River Bend plant costs held in abeyance
and the related cost deferrals totaled (net of taxes) approximately $14 million,
$300 million (both net of depreciation), and $171 million, respectively.
Allowed Deferrals were approximately $95 million, net of taxes and amortization,
as of December 31, 1993. GSU estimates it has collected approximately $139
million of revenues as of December 31, 1993, as a result of the originally
ordered rate treatment of these deferred costs. However, if the PUCT adopts the
most recent decision in the El Paso Case, the possible refunds approximate $28
million as a result of the inclusion of deferred carrying costs in rate base for
the period July 1988 through December 1990. However, if the PUCT reverses its
decision to reduce GSU's deferred costs by $1.50 for each $1.00 of revenue
collected under the interim rate increases authorized in 1987 and 1988, the
potential refund of amounts described above could be reduced by an amount
ranging from $7 million to $19 million.
No assurance can be given as to the timing or outcome of the remands or
appeals described above. Pending further developments in these cases, GSU has
made no write-offs for the River Bend-related costs. Management believes, based
on advice from Clark, Thomas & Winters, a Professional Corporation, legal
counsel of record in the Rate Appeal, that it is reasonably possible that the
case will be remanded to the PUCT, and the PUCT will be allowed to rule on the
prudence of the abeyed River Bend plant costs. Rate Caps imposed by the PUCT's
regulatory approval of the Merger could result in GSU being unable to use the
full amount of a favorable decision to immediately increase rates; however, a
favorable decision could permit some increases and/or limit or prevent decreases
during the period the Rate Caps are in effect. At this time, management and
legal counsel are unable to predict the amount, if any, of the abeyed and
previously disallowed River Bend plant costs that ultimately may be disallowed
by the PUCT. A net of tax write-off as of December 31, 1993, of up to $314
million could be required based on the PUCT's ultimate ruling.
In prior proceedings, the PUCT has held that the original cost of nuclear
power plants will be included in rates to the extent those costs were prudently
incurred. Based upon the PUCT's prior decisions, management believes that its
River Bend construction costs were prudently incurred and that it is reasonably
possible that it will recover in rate base, or otherwise through means such as a
deregulated asset plan, all or substantially all of the abeyed River Bend plant
costs. However, management also recognizes that it is reasonably possible that
not all of the abeyed River Bend plant costs may ultimately be recovered.
As part of its direct case in the Separate Rate Case, GSU filed a cost
reconciliation study prepared by Sandlin Associates, management consultants with
expertise in the cost analysis of nuclear power plants, which supports the
reasonableness of the River Bend costs held in abeyance by the PUCT. This
reconciliation study determined that approximately 82% of the River Bend cost
increase above the amount included by the PUCT in rate base was a result of
changes in federal nuclear safety requirements and provided other support for
the remainder of the abeyed amounts.
There have been four other rate proceedings in Texas involving nuclear
power plants. Investment in the plants ultimately disallowed ranged from 0% to
15%. Each case was unique, and the disallowances in each were made on a
case-by-case basis for different reasons. Appeals of most, if not all, of
these PUCT decisions are currently pending.
The following factors support management's position that a loss contingency
requiring accrual has not occurred, and its belief that all, or substantially
all, of the abeyed plant costs will ultimately be recovered:
1. The $1.4 billion of abeyed River Bend plant costs have never been ruled
imprudent and disallowed by the PUCT.
2. Sandlin Associates' analysis which supports the prudence of
substantially all of the abeyed construction costs.
3. Historical inclusion by the PUCT of prudent construction costs in rate
base.
4. The analysis of GSU's internal legal staff, which has considerable
experience in Texas rate case litigation.
Additionally, management believes, based on advice from Clark, Thomas &
Winters, a Professional Corporation, legal counsel of record in the Rate Appeal,
that it is probable that the deferred costs will be allowed. However, assuming
the August 1992 court of appeals' opinion in the El Paso Case is upheld and
applied to GSU and the deferred River Bend costs currently held in abeyance are
not allowed to be recovered in rates as allowable costs, a net of tax write-off
of up to $171 million could be required. In addition, future revenues based
upon the deferred costs previously allowed in rate base could also be lost and
no assurance can be given as to whether or not refunds (up to $28 million as of
December 31, 1993) of revenue received based upon such deferred costs previously
recorded will be required.
See Note 12 for the accounting treatment of preacquisition contingencies,
including a River Bend write-down.
Merger-Related Rate Agreements
The LPSC and the PUCT approved separate regulatory proposals that include
the following elements: (1) a five-year Rate Cap on GSU's retail electric base
rates in the respective states, except for force majeure (defined to include,
among other things, war, natural catastrophes, and high inflation); (2) a
provision for passing through to retail customers in the respective states the
jurisdictional portion of the fuel savings created by the Merger; and (3) a
mechanism for tracking nonfuel operation and maintenance savings created by the
Merger. The LPSC regulatory plan provides that such nonfuel savings will be
shared 60% by the shareholder and 40% by ratepayers during the eight years
following the Merger. The LPSC plan requires regulatory filings each year by
the end of May through 2001. The PUCT regulatory plan provides that such
savings will be shared equally by the shareholder and ratepayers, except that
the shareholder's portion will be reduced by $2.6 million per year on a total
company basis in years four through eight. The PUCT plan also requires a series
of regulatory filings currently anticipated to be in June 1994, and February
1996, 1998, and 2001, to ensure that ratepayers' share of such savings be
reflected in rates on a timely basis and requires Entergy Corporation to hold
GSU's Texas retail customers harmless from the effects of the removal by FERC of
a 40 % cap on the amount of fuel savings GSU may be required to transfer to
other Entergy operating companies under the FERC tracking mechanism (see below).
On January 14, 1994, Entergy Corporation filed a request for rehearing of FERC's
December 15, 1993, order approving the Merger requesting that FERC restore the
40 % cap provision in the fuel cost protection mechanism. The matter is
pending.
FERC approved certain rate schedule changes to integrate GSU into the
System Agreement. Certain commitments were adopted to provide reasonable
assurance that the ratepayers of AP&L, LP&L, MP&L, and NOPSI will not be
allocated higher costs, including, among other things: (1) a tracking mechanism
to protect AP&L, LP&L, MP&L, and NOPSI from certain unexpected increases in fuel
costs; (2) the distribution of profits from power sales contracts entered into
prior to the Merger; (3) a methodology to estimate the cost of capital in future
FERC proceedings; and (4) a stipulation that AP&L, LP&L, MP&L, and NOPSI will be
insulated from certain direct effects on capacity equalization payments should
GSU, due to a finding of imprudent GSU management prior to the Merger, be
required to purchase Cajun's 30% share in River Bend (see Note 8).
Texas - Fuel Reconciliation
In January 1992, GSU applied with the PUCT for a new fixed fuel factor and
requested a final reconciliation of fuel and purchased power costs incurred
between December 1, 1986 and September 30, 1991. GSU proposed to recover net
underrecoveries and interest (including underrecoveries related to Nelson
Industrial Steam Company (NISCO), discussed below) over a twelve month period.
In April 1993, the presiding PUCT administrative law judge (ALJ) issued a report
which concluded that GSU incurred approximately $117 million of nonreimbursable
fuel costs on a company-wide basis (approximately $50 million on a Texas retail
jurisdictional basis) during the reconciliation period.
Included in the nonreimbursable fuel costs were payments above GSU's
avoided cost rate for power purchased from NISCO. The PUCT ordered in 1986 that
the purchased power costs from NISCO in excess of GSU's avoided costs be disal
lowed. The PUCT disallowance resulted in approximately $12 million to $15
million of unrecovered purchased power costs on an annual basis, which GSU
continued to expense as the costs were incurred. In April 1991, the Texas
Supreme Court, in the appeal of such order, ordered the PUCT to allow GSU to
recover purchased power payments in excess of its avoided cost in future
proceedings, if GSU established to the PUCT's satisfaction that the payments
were reasonable and necessary expenses.
In June 1993, the PUCT, in the fuel reconciliation case, concluded that the
purchased power payments made to NISCO in excess of GSU's avoided cost were not
reasonably incurred. As a result of the order, GSU recorded additional fuel
expenses (including interest) of $2.8 million for non-NISCO related items. The
PUCT's order resulted in no additional expenses related to the NISCO issue, or
for overcollections related to the fixed fuel factor, as those charges were
expensed by GSU as they were incurred. The PUCT concluded that GSU had over-
collected its fuel costs in Texas and ordered GSU to refund approximately $33.8
million to its Texas retail customers, including approximately $7.5 million of
interest. The PUCT reduced GSU's fixed fuel factor in Texas from about 2.1
cents per KWH to approximately 1.84 cents per KWH. GSU had requested a new
fixed fuel factor of about 2.02 cents per KWH. Based on current sales
forecasts, adoption of the PUCT's recommended fixed fuel factor would reduce
GSU's revenues by approximately $34 million annually. In October 1993, GSU
appealed the PUCT's order to the Travis County District Court. No assurance can
be given as to the timing or outcome of the appeal.
Texas Cities Rate Settlement
In the state of Texas, incorporated cities have original jurisdiction over
GSU's rates and services within their boundaries, while the PUCT has appellate
jurisdiction over intramunicipal rates and original jurisdiction over
unincorporated areas.
In June 1993, 13 cities within GSU's Texas service area instituted an
investigation to determine whether GSU's current rates were justified. In
October 1993, the general counsel of the PUCT instituted an inquiry into the
reasonableness of GSU's rates. In November 1993, a settlement agreement was
filed with the PUCT which provides for an initial reduction in annual retail
base revenues in Texas of approximately $22.5 million effective for electric
usage on or after November 1, 1993, and a second reduction of $20 million to be
effective September 1994. Further, the settlement provided for GSU to reduce
rates with a $20 million one-time bill credit in December 1993, and to refund
approximately $3 million to Texas retail customers on bills rendered in December
1993. The cities rate inquiries had been settled earlier on the same terms.
In November 1993, in association with the settlement of the above-described
rate inquiries, GSU entered into a settlement covering issues related to a March
1991 non-unanimous settlement in another proceeding. Under this settlement, a
$30 million rate increase approved by the PUCT in March 1991, became final and
the PUCT's treatment of GSU's federal tax expense was settled, eliminating the
possibility of refunds associated with amounts collected resulting from the
disputed tax calculation.
In December 1993, a large industrial customer of GSU announced its
intention to oppose the settlement of the PUCT rate inquiry. The customer's
opposition does not affect the cities' rate settlement. The customer's
opposition requires the PUCT to conduct a hearing concerning GSU's rates charged
in areas outside the corporate limits of the cities in its Texas service
territory to determine whether the settlement's rates are just and reasonable.
A hearing has been set for July 8, 1994. GSU believes that the PUCT will
ultimately approve the settlement, but no assurance can be provided in this
regard.
Louisiana
Previous rate orders of the LPSC have been appealed, and pending resolution
of various appellate proceedings, GSU has made no write-off for the disallowance
of $30.6 million of deferred revenue requirement that GSU recorded for the
period December 16, 1987 through February 18, 1988.
Deregulated Asset Plan
A deregulated asset plan representing an unregulated portion (approximately
22%) of River Bend (plant costs, generation, revenues, and expenses) was
established pursuant to a January 1992 LPSC order. The plan allows GSU to sell
such generation to Louisiana retail customers at 4.6 cents per KWH or off-system
at higher prices with certain sharing provisions for such incremental revenue.
LPSC Return on Equity Review
In the June 1993 open session, a preliminary report was made comparing the
authorized and actual earned rates of return for electric and gas utilities
subject to the LPSC's jurisdiction. The preliminary report indicated that
several electric utilities, including GSU, may be over-earning based on current
estimated costs of equity. The LPSC requested those utilities to file responses
indicating whether they agreed with the preliminary report, and to provide their
reasons if they did not agree. GSU provided the LPSC with information that GSU
believes supports the current rate level. The LPSC decided at its September 7,
1993 open session to defer review of GSU's base rates until the first post-
Merger earnings analysis, scheduled for mid-1994.
LPSC Fuel Cost Review
In November 1993, the LPSC ordered a review of GSU's fuel costs. The LPSC
stated that fuel costs for the period October 1988 through September 1991 would
be reviewed based on the number of outages at River Bend and the findings in the
June 1993 PUCT fuel reconciliation case. Hearings are scheduled to begin in
March 1994.
River Bend Cost Deferrals
GSU deferred approximately $369 million of River Bend operating costs,
purchased power costs, and accrued carrying charges pursuant to a 1986 PUCT
accounting order. Approximately $182 million of these costs are being amortized
over a 20-year period, and the remaining $187 million are not being amortized
pending the ultimate outcome of the Rate Appeal. As of December 31, 1993, the
unamortized balance of these costs was $330.3 million. Further, GSU deferred
approximately $400.4 million of similar costs pursuant to a 1986 LPSC accounting
order. These costs, of which approximately $160.4 million are unamortized as of
December 31, 1993, are being amortized over a 10-year period.
In accordance with a phase-in plan approved by the LPSC, GSU deferred
$324.7 million of its River Bend costs related to the period December 1987
through February 1991. GSU has amortized $86.6 million through December 31,
1993, and the remainder of $238.1 million will be recovered over approximately
3.8 years.
NOTE 3. INCOME TAXES
Effective January 1, 1993, GSU adopted SFAS 109. This new standard
requires that deferred income taxes be recorded for all temporary differences
and carryforwards, and that deferred tax balances be based on enacted tax laws
at tax rates that are expected to be in effect when the temporary differences
reverse. SFAS 109 requires that regulated enterprises recognize adjustments
resulting from its implementation as regulatory assets or liabilities if it is
probable that such amounts will be recovered from or returned to customers in
future rates. A substantial majority of the adjustments required by SFAS 109
were recorded to deferred tax balance sheet accounts with offsetting adjustments
to regulatory assets and liabilities. GSU recorded the adoption of SFAS 109 by
restating 1990, 1991, and 1992 financial statements and including a charge of
$96.5 million for the cumulative effect of the adoption of SFAS 109 in 1990
primarily for that portion of the operations on which GSU has discontinued
regulatory accounting principles. Detailed below are the effects on GSU's 1992
and 1991 results of operations and financial position as of December 31, 1992,
resulting from such restatement (in thousands):
1991 As SFAS 1991
Previously No. 109 As
Reported Effect Restated
---------- --------- --------
Income before extraordinary items and the cumulative effect
of accounting change $122,449 $(10,058) $112,391
Net income $102,283 $ 9,747 $112,030
Income applicable to common stock $ 39,213 $ 9,747 $ 48,960
1992 As SFAS 1992
Previously No. 109 As
Reported Effect Restated
---------- ------- --------
Income before extraordinary items and the cumulative effect
of accounting change $133,787 $5,626 $139,413
Net income $128,157 $5,691 $133,848
Income applicable to common stock $ 78,455 $5,691 $ 84,146
Balance at Balance at
December 31, December 31,
1992 As SFAS 1992
Previously No. 109 As
Reported Effect Restated
------------ -------- ------------
Total assets $6,858,494 $305,953 $7,164,447
Total capitalization and liabilities (excluding retained earnings) $6,153,859 $379,126 $6,532,985
Retained earnings $ 704,635 $(73,173) $ 631,462
Income taxes differ from the amounts computed by applying the statutory
federal income tax rate to income before taxes. The reasons for these
differences were (1992 and 1991 restated for the effects of SFAS 109):
For the Years Ended December 31,
-----------------------------------------------------
1993 1992 1991
---------------- ---------------- ---------------
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
------- ------ ------- ------ ------- ------
(Dollars in Thousands)
Computed at statutory rate $50,101 35.0 $63,662 34.0 $54,415 34.0
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect 1,332 0.9 3,573 1.9 3,444 2.2
Rate deferrals - net 6,193 4.3 5,439 2.9 5,481 3.4
Depreciation (11,343) (7.9) (15,479) (8.3) (12,302) (7.7)
Impact of change in tax rate 5,179 3.6 - - - -
Book expenses not deducted for tax 15,134 10.6 142 0.1 187 0.1
Amortization of investment tax credits (4,435) (3.1) (4,356) (2.3) (4,308) (2.7)
Other - net 2,123 1.5 413 0.2 1,098 0.7
------- ----- ------- ----- ------- -----
Total income taxes $64,284 44.9 $53,394 28.5 $48,015 30.0
======= ===== ======= ===== ======= =====
Income tax expense (1992 and 1991 restated for the effects of SFAS 109)
consisted of the following:
For the Years Ended December 31,
--------------------------------
1993 1992 1991
------- ------- ------
(In Thousands)
Current
Federal $16,714 $ 5,621 $4,746
State - - -
------- ------- ------
Total 16,714 5,621 4,746
------- ------- ------
Deferred - net
Liberalized depreciation 37,951 24,287 26,041
Nuclear unit cancellation costs, net of amortization (2,930) (3,107) (2,954)
Fuel and purchased power costs (accrued) 7,689 (669) (4,652)
Expenses deferred for tax purposes (12,387) 3,449 (5,216)
Tax net operating loss carryforward (8,357) 12,349 60,333
Rate deferrals - net (24,458) (21,238) (15,347)
Unbilled revenues 4,999 2,889 813
Income deferred for book purposes (2,102) 2,328 (14,614)
Louisiana provision for rate refund 3,793 4,416 (8,209)
Alternative minimum tax credit (22,183) (8,197) (5,595)
Loss on debt extinguishment, net of amortization 1,398 22,314 -
State tax refund deferred for financial reporting - - 6,478
Purchased power settlement 66,753 6,562 8,088
Other (3,689) 4,590 2,411
------- ------- -------
Total 46,477 49,973 47,577
------- ------- -------
Investment tax credit adjustments - net 1,093 (2,200) (4,308)
------- ------- -------
Recorded income tax expense $64,284 $53,394 $48,015
======= ======= =======
Charged to operations $46,007 $38,058 $35,084
Charged to other income 12,009 17,801 13,166
Charged to extraordinary items (671) (4,943) (235)
Charged to cumulative effect of accounting changes 6,939 2,478 -
------- ------- -------
Total income taxes $64,284 $53,394 $48,015
======= ======= =======
Significant components of net deferred tax liabilities, as restated for the
effects of SFAS 109, as of December 31, 1993 and 1992, were (in thousands):
1993 1992
------------ ------------
Deferred tax liabilities:
Net regulatory assets $ (529,706) $ (453,064)
Plant related basis differences (1,023,446) (981,915)
Rate deferrals - net (169,689) (194,147)
Debt reacquisition loss (24,140) (22,805)
Other (25,871) (29,799)
----------- -----------
Total $(1,772,852) $(1,681,730)
=========== ===========
Deferred tax assets:
Net operating loss carryforwards $ 307,737 $ 294,100
Investment tax credit carryforward 176,032 181,560
Valuation allowance-investment tax credit carryforward (15,213) -
Unbilled revenue 12,243 17,242
Southern Company settlement - 66,753
Plant related basis differences 25,007 22,868
Alternative minimum tax credit 39,860 17,453
Other 164,135 162,863
----------- -----------
709,801 762,839
Investment tax credit carryforwards reserved (160,819) (181,560)
----------- -----------
Total $ 548,982 $ 581,279
=========== ===========
Net deferred tax liability $(1,223,870) $(1,100,451)
=========== ===========
As of December 31, 1993, for tax purposes, GSU had federal tax loss
carryforwards of approximately $790 million, state tax loss carryforwards of
approximately $561 million, and investment tax (ITC) and other credit
carryforwards of approximately $179 million which will be used to reduce income
tax payments in future years and, if not used, will expire through the year
2008. It is currently anticipated that approximately $15.2 million of ITC
carryforwards will expire unutilized as a result of limitations arising from the
Merger. A valuation allowance has been provided for that amount. The
alternative minimum tax credit, which can be carried forward indefinitely to
reduce GSU's future federal income tax liability, was $40 million as of December
31, 1993.
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
As of December 31, 1993, GSU had agreements with banks and banking
institutions which provided for short-term lines of credit totaling $113.4
million. Included in the total short-term lines of credit was a $100 million
bank credit agreement which expired on March 2, 1994. GSU had no outstanding
borrowings under these arrangements as of December 31, 1993.
A filing has been made with the SEC requesting authorization for GSU to
participate in the Money Pool, an intra-system borrowing arrangement designed to
reduce the System's dependence on external short-term borrowings, and to enter
into new bank lines of credit and commercial paper arrangements. The filing
requested a borrowing authorization of $125 million with reservation of
jurisdiction over additional amounts up to a maximum of $455 million.
NOTE 5. PREFERRED, PREFERENCE, AND COMMON STOCK
The number of shares and dollar value of GSU's preferred and preference stock
was:
Call Price
As of December 31 Per Share as
Shares Outstanding Total Dollar Value of December
1993 1992 1993 1992 31, 1993
--------- ------- -------- --------- -----------
(Dollars in Thousands)
Preference Stock
Authorized 20,000,000 shares, without
par value, cumulative
7% Series (2) 6,000,000 - $150,000 $ - (1)
========= ======= ======== ========
Preferred Stock
Authorized 6,000,000 shares, $100 par value, cumulative
Without sinking fund:
4.40% Series 51,173 51,173 $5,117 $5,117 $108.00
4.50% Series 5,830 5,830 583 583 $105.00
4.40% - 1949 Series 1,655 1,655 166 166 $103.00
4.20% Series 9,745 9,745 975 975 $102.82
4.44% Series 14,804 14,804 1,480 1,480 $103.75
5.00% Series 10,993 10,993 1,099 1,099 $104.25
5.08% Series 26,845 26,845 2,685 2,685 $104.63
4.52% Series 10,564 10,564 1,056 1,056 $103.57
6.08% Series 32,829 32,829 3,283 3,283 $103.34
7.56% Series 350,000 350,000 35,000 35,000 $101.80
8.52% Series 500,000 500,000 50,000 50,000 $102.43
9.96% Series 350,000 350,000 35,000 35,000 $104.64
--------- --------- -------- --------
Total without sinking fund 1,364,438 1,364,438 $136,444 $136,444
========= ========= ======== ========
With sinking fund:
8.80% Series 237,963 260,275 $23,796 $26,027 $100.00
9.75% Series 22,576 24,598 2,258 2,460 $100.00
8.64% Series 196,000 224,000 19,600 22,400 $103.00
11.48% Series - 340,000 - 34,000 -
12.92% Series - 510,000 - 51,000 -
11.50% Series - 712,500 - 71,250 -
Adjustable Rate Series A, 7.10% (3) 216,000 240,000 21,600 24,000 $100.00
Adjustable Rate Series B, 7.15% (3) 337,500 382,500 33,750 38,250 $103.00
--------- --------- -------- --------
Total with sinking fund 1,010,039 2,693,873 $101,004 $269,387
========= ========= ======== ========
(1) This series is not redeemable as of December 31, 1993.
(2) The total dollar value represents the involuntary liquidation value of
$25 dollars per share.
(3) Rates are as of December 31, 1993.
The fair value of GSU's preferred and preference stock with sinking fund
was estimated to be approximately $255 million and $279.5 million as of December
31, 1993 and 1992, respectively. The fair value was determined using quoted
market prices or estimates from nationally recognized investment banking firms.
See Note 1 for additional information on disclosure of fair value of financial
instruments.
Changes in the common stock, preference stock, and preferred stock during the
last three years were:
Number of Shares
--------------------------------------
1993 1992 1991
------------ ---------- ----------
Common stock issuances 100 - 6,000,000
Common stock retirements with Merger closing (114,055,065) - -
Preference stock issuances 6,000,000 - -
Preference stock retirements - (4,000,000) -
Preferred stock with sinking fund retirements (1,683,834) (559,257) -
Minimum cash sinking fund requirements for preferred stock with sinking funds
are $6.1 million for each of the years 1994-1998. Limitations based on the
ratio of after-tax earnings to fixed charges and preferred dividends are imposed
by the Articles of Incorporation (Articles) upon the issuance of additional
preferred stock. Based upon the results of operations for the year ended
December 31, 1993, GSU is unable to issue any additional preferred stock.
NOTE 6. LONG-TERM DEBT
GSU's long-term debt as of December 31, 1993 and 1992, was as follows:
Maturities Interest Rates December 31
From To From To 1993 1992
---- ---- ---- ---- ---------- ----------
(In Thousands)
First Mortgage Bonds
1996 1998 5% 7.35% $ 345,000 $ 345,000
1999 2003 6.41% 8-1/2% 470,000 420,000
2004 2008 6.77% 8-7/8% 420,000 480,000
2022 2024 8.70% 8.94% 450,000 450,000
Governmental and Industrial Development Bonds
2006 2016 5.9% 12% 482,885 483,310
Debentures - Due 1998, 9.72% 200,000 200,000
Notes payable - 160,000
Other long-term debt 6,879 2,718
Unamortized premium and discount - net (5,700) (6,145)
---------- ----------
Total long-term debt 2,369,064 2,534,883
Less amount due within one year 425 160,425
---------- ----------
Long-term debt excluding amount due within one year $2,368,639 $2,374,458
========== ==========
The fair value of GSU's long-term debt as of December 31, 1993 and 1992 was
estimated to be $2,548.1 million and $2,623 million, respectively. Fair values
were determined using bid prices reported by dealer markets and by nationally
recognized investment banking firms. See Note 1 for additional information on
disclosure of fair value of financial instruments.
For the years 1994, 1995, 1996, 1997, and 1998, GSU has long-term debt
maturities and cash sinking fund requirements of (in millions) $.4, $50.4,
$145.4, $160.9, and $190.9, respectively. In addition, other sinking fund
requirements for the years 1994, 1995, 1996, 1997, and 1998 of (in millions)
$16.7, $16.7, $15.6, $14.3, and $12.6, respectively, may be satisfied by cash
or by certification of property additions at a rate of 167% of such
requirements.
GSU has three outstanding series of pollution control bonds which are
collateralized by irrevocable letters of credit which are scheduled to expire
before the scheduled maturity of the bonds. The letter of credit
collateralizing the $50 million 10-5/8% series due May 1, 2014, expires in May
1994, the letter of credit collateralizing the $28.4 million variable rate
series due December 1, 2015, expires in September 1996 and the letter of credit
collateralizing the $20 million variable rate series due April 1, 2016, expires
in April 1996. GSU plans to refinance these series or renew the letters of
credit.
NOTE 7. DIVIDEND RESTRICTIONS
Certain limitations on the payment of cash dividends on common stock are
contained in the Articles, Mortgage Indenture, loan agreements, and applicable
state and federal law. Under existing limitations, as part of the short-term
line of credit discussed in Note 4, $560 million of GSU's retained earnings are
restricted against the payment of common dividends at December 31, 1993. If
such restriction did not exist, the most restrictive limitation as of December
31, 1993, as to the amount of such dividends which might be paid, was contained
in the Articles. Under the restrictions contained in the Articles, as of
December 31, 1993, $21 million of GSU's retained earnings were restricted
against the payment of cash dividends or other distributions on common stock.
On February 1, 1994, GSU paid Entergy Corporation a $100 million cash
dividend on common stock. Prior to the February 1, 1994, dividend payment,
GSU had not paid a common dividend since June 1986.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Financial Condition
Although GSU received partial rate relief relating to River Bend, GSU's
financial position was strained from 1986 to 1990 by its inability to earn a
return on and fully recover its investment and other costs associated with River
Bend. GSU's financial position has continued to improve; however, issues to be
finally resolved in PUCT rate proceedings and appeals thereof, as discussed in
Note 2, combined with the application of accounting standards, may result in
substantial write-offs and charges that could result in substantial net losses
being reported in 1994, and subsequent periods, with resulting substantial
adverse adjustments to common shareholder's equity. Future earnings will
continue to be adversely affected by the lack of full recovery and return on the
investment and other costs associated with River Bend.
Cajun - River Bend
GSU has significant business relationships with Cajun, primarily co-ownership
of River Bend and Big Cajun 2 Unit 3. GSU and Cajun own 70% and 30% of River
Bend, respectively, while Big Cajun 2 Unit 3 is owned 42% and 58% by GSU and
Cajun, respectively. GSU operates River Bend, and Cajun operates Big Cajun 2
Unit 3.
In June 1989, Cajun filed a civil action against GSU in the U. S. District
Court for the Middle District of Louisiana. Cajun stated in its complaint that
the object of the suit is to annul, rescind, terminate, and/or dissolve the
Joint Ownership Participation and Operating Agreement entered into on August 28,
1979 (Operating Agreement) related to River Bend. Cajun alleges fraud and error
by GSU, breach of its fiduciary duties owed to Cajun, and/or GSU's repudiation,
renunciation, abandonment, or dissolution of its core obligations under the
Operating Agreement, as well as the lack or failure of cause and/or
consideration for Cajun's performance under the Operating Agreement. The suit
seeks to recover Cajun's alleged $1.6 billion investment in the unit as damages,
plus attorneys' fees, interest, and costs.
In March 1992, the district court appointed a mediator to engage in
settlement discussions and to schedule settlement conferences between the
parties. Discussions with the mediator began in July 1992, however, GSU
cannot predict what effect, if any, such discussions will have on the
timing or outcome of the case. A trial without a jury is set for April 12,
1994, on the portion of the suit by Cajun to rescind the Operating
Agreement. Two member cooperatives of Cajun have brought an independent action
to declare the River Bend Operating Agreement void, based upon failure to get
prior LPSC approval alleged to be necessary. GSU believes the suits are without
merit and is contesting them vigorously. No assurance can be given as to the
outcome of this litigation. If GSU were ultimately unsuccessful in this
litigation and were required to make substantial payments, GSU would probably be
unable to make such payments and would probably have to seek relief from its
creditors under the Bankruptcy Code.
See Note 12 for the accounting treatment of preacquisition contingencies,
including a charge resulting from an adverse resolution in the Cajun - River
Bend litigation.
In July 1992, Cajun notified GSU that it would fund a limited amount of costs
related to the fourth refueling outage at River Bend, completed in September
1992. Cajun has also not funded its share of the costs associated with certain
additional repairs and improvements at River Bend completed during the refueling
outage. GSU has paid the costs associated with such repairs and improvements
without waiving any rights against Cajun. GSU believes that Cajun is obligated
to pay its share of such costs under the terms of the applicable contract.
Cajun has filed a suit seeking a declaration that it does not owe such funds and
seeking injunctive relief against GSU. GSU is contesting such suit and is
reviewing its available legal remedies.
In September 1992, GSU received a letter from Cajun alleging that the
operating and maintenance costs for River Bend are "far in excess of industry
averages" and that "it would be imprudent for Cajun to fund these excessive
costs." Cajun further stated that until it is satisfied it would fund a maximum
of $700,000 per week under protest for the remainder of 1992. In a December
1992 letter, Cajun stated that it would also withhold costs associated with
certain additional repairs, of which the majority will be incurred during the
next refueling outage, currently scheduled for April 1994. GSU believes that
Cajun's allegations are without merit and is considering its legal and other
remedies available with respect to the underpayments by Cajun. The total
resulting from Cajun's failure to fund repair projects, Cajun's funding
limitation on the fourth refueling outage, and the weekly funding limitation by
Cajun was $33.3 million as of December 31, 1993, compared with a $28.4 million
unfunded balance as of December 31, 1992. These amounts are reflected in long-
term receivables.
During 1994, and for the next several years, it is expected that Cajun's
share of River Bend-related costs will be in the range of $60 million to $70
million per year. Cajun's weak financial condition could have a material
adverse effect on GSU, including a possible Nuclear Regulatory Commission (NRC)
action with respect to the operation of River Bend and a need to bear additional
costs associated with the co-owned facilities. If GSU were required to fund
Cajun's share of costs, there can be no assurance that such payments could be
recovered. Cajun's weak financial condition could also affect the ultimate
collectibility of amounts owed to GSU.
Cajun - Transmission Service
GSU and Cajun are parties to FERC proceedings related to transmission service
charge disputes. In April 1992, FERC issued a final order, and in May 1992, GSU
and Cajun filed motions for rehearings which are pending consideration by FERC.
In June 1992, GSU filed a petition for review in the United States Court of
Appeals regarding certain of the issues decided by FERC. In August 1993, the
United States Court of Appeals rendered an opinion reversing the FERC order
regarding the portion of such disputes relating to the calculations of certain
credits and equalization charges under GSU's service schedules with Cajun. The
opinion remanded the issues to FERC for further proceedings consistent with its
opinion. In January 1994, FERC denied GSU's request to collect a surcharge
while FERC considers the court's remand.
GSU interprets the FERC order and the court of appeals' decision to mean that
Cajun would owe GSU approximately $85 million as of December 31, 1993. GSU
further estimates that if it prevails in its May 1992 motion for rehearing,
Cajun would owe GSU approximately $118 million as of December 31, 1993. If
Cajun were to prevail in its May 1992 motion for rehearing to FERC, and if GSU
were not to prevail in its May 1992 motion for rehearing to FERC, and if FERC
does not implement the court's remand as GSU contends is required, GSU estimates
it would owe Cajun approximately $76 million as of December 31, 1993. The above
amounts are exclusive of a $7.3 million payment by Cajun on December 31, 1990,
which the parties agreed to apply to the disputed transmission service charges.
GSU and Cajun further agreed that their positions at FERC would remain
unaffected by the $7.3 million. Pending FERC's ruling on the May 1992 motions
for rehearing, GSU has continued to bill Cajun utilizing the historical billing
methodology and has booked underpaid transmission charges, including interest,
in the amount of $140.8 million as of December 31, 1993. This amount is
reflected in long-term receivables and in other deferred credits, with no effect
on net income.
Capital Requirements and Financing
Construction expenditures (excluding nuclear fuel) for the years 1994, 1995,
and 1996 are estimated to total $134 million, $128 million, and $119 million,
respectively. GSU will also require $214 million during the period 1994-1996 to
meet long-term debt and preferred stock maturities and sinking fund
requirements. GSU plans to meet the above requirements with internally
generated funds and cash on hand. External financing during the period would be
primarily for refinancing of higher cost securities. See Note 5 and Note 6
regarding the possible issuance of first mortgage bonds and preference stock and
the possible refunding, redemption, purchase or other acquisition of outstanding
securities.
Nuclear Insurance
The Price-Anderson Act limits public liability for a single nuclear incident
to approximately $9.4 billion as of December 31, 1993. GSU has protection for
this liability through a combination of private insurance (currently $200
million) and an industry assessment program. Under the assessment program, the
maximum amount that would be required for each nuclear incident would be $79.28
million per reactor, payable at a rate of $10 million per licensed reactor per
incident per year. GSU has one licensed reactor. Any assessments pertaining to
this program are subject to the 70/30 % ownership interest between GSU and
Cajun. In addition, GSU participates in a private insurance program which
provides coverage for worker tort claims filed for bodily injury caused by
radiation exposure. GSU's maximum assessment under the program is an aggregate
of approximately $3.1 million in the event losses exceed accumulated reserve
funds.
GSU and Cajun are members of certain insurance programs that provide coverage
for property damage, including decontamination and premature decommissioning
expense, to members' nuclear generating plants. As of December 31, 1993, GSU
was insured against such losses up to $2.7 billion with $250 million of this
amount designated to cover any shortfall in the NRC required decommissioning
trust funding. In addition, GSU is a member of an insurance program that covers
certain replacement power and business interruption costs incurred due to
prolonged nuclear unit outages. Under the property damage and replacement
power/business interruption insurance programs, GSU could be subject to
assessments if losses exceed the accumulated funds available to the insurers.
As of December 31, 1993, the maximum amount of such possible assessments to GSU
was $15.9 million.
The amount of property insurance presently carried by GSU exceeds the NRC
minimum requirement for nuclear power plant licensees of $1.06 billion per site.
NRC regulations provide that the proceeds of this insurance must be used, first,
to place and maintain the reactor in a safe and stable condition and, second, to
complete decontamination operations. Only after proceeds are dedicated for such
use and regulatory approval is secured, would any remaining proceeds be made
available for the benefit of plant owners or their creditors.
Spent Nuclear Fuel and Decommissioning Costs
GSU provides for estimated future disposal costs for spent nuclear fuel in
accordance with the Nuclear Waste Policy Act of 1982. GSU entered into a
contract with the DOE, whereby the DOE will furnish disposal service at a cost
of one mill per net KWH generated and sold. The fees payable to the DOE may be
adjusted in the future to assure full recovery. GSU considers all costs incurred
or to be incurred for the disposal of spent nuclear fuel to be proper components
of nuclear fuel expense and provisions to recover such costs have been or will
be made in applications to regulatory authorities.
Due to delays of the DOE's repository program for the acceptance of spent
nuclear fuel, it is uncertain when shipments of spent fuel from GSU will
commence. In the meantime, GSU is responsible for spent fuel storage. Current
on-site spent fuel storage capacity at River Bend is estimated to be sufficient
until 2003. Thereafter, GSU will provide additional storage capacity at an
estimated initial cost of $5 million to $10 million. In addition, approximately
$3 million to $5 million will be required every four to five years subsequent to
2003 until DOE's repository begins accepting River Bend spent fuel.
GSU is recovering in rates amounts sufficient to fund decommissioning
costs for River Bend, based on the original 1985 decommissioning cost study of
approximately $141 million. The amounts recovered in rates are deposited in
external trust funds, with a market value of approximately $18.5 million and
$14.5 million at December 31, 1993 and 1992, respectively. The accumulated
decommissioning liability of $18.1 million as of December 31, 1993, has been
recorded in accumulated depreciation. Decommissioning expense amounting to $3
million was recorded in 1993. A more recent 1991 engineering study, which has
not yet been reflected in rates and used as a basis of funding, indicates
decommissioning costs may be $279.8 million. GSU feels that recent changes in
the laws will tend to allow annual contributions to the trust to remain at
current levels of funding and offset or mitigate the increase in decommissioning
costs, as indicated in the 1991 engineering study. The actual decommissioning
costs may vary from the above estimates because of regulatory requirements,
changes in technology, and increased costs of labor, materials, and equipment,
and management believes that actual decommissioning costs are likely to be
higher than the amounts presented above.
The Energy Act has a provision that assesses domestic nuclear utilities with
fees for the decontamination and decommissioning of the DOE's past uranium
enrichment operations. The decontamination and decommissioning assessments will
be used to set up a fund into which contributions from utilities and the federal
government will be placed. GSU's assessment, which will be adjusted annually
for inflation, is $.6 million annually for approximately 15 years. FERC
requires that utilities treat these assessments as costs of fuel as they are
amortized. The liability of $7.8 million as of December 31, 1993, is recorded
in other current liabilities and other noncurrent liabilities and is offset in
financial statements by a regulatory asset, recorded as a deferred debit.
Long-Term Contracts
NISCO Power Purchases. In 1988, GSU entered into a joint venture with a
primary term of 20 years with Conoco, Inc., Citgo Petroleum Corporation, and
Vista Chemical Company (Industrial Participants) whereby GSU's Nelson Units
1 and 2 were sold to a partnership (NISCO) consisting of the Industrial
Participants and GSU. The Industrial Participants are supplying the fuel for
the units, while GSU operates the units at the discretion of the Industrial
Participants and purchases the electricity produced by the units. GSU is
continuing to sell electricity to the Industrial Participants. For the years
ended December 31, 1993, 1992, and 1991, the purchases of electricity from the
joint venture totaled $62.6 million, $37.8 million, and $61.3 million,
respectively.
Natural Gas Contracts. GSU has long-term gas contracts which will satisfy
approximately 75% of its annual requirements. However, such contracts as a
whole only require GSU to purchase in the range of 40% of expected total gas
needs. Additional gas requirements are satisfied under less expensive short-
term contracts. In November 1992, GSU entered into a transportation service
agreement which obligated the gas supplier to provide GSU with flexible natural
gas swing service to the Sabine and Lewis Creek generating stations. This
service is provided by the supplier's pipeline and salt dome gas storage
facility, which has a present capacity of 1.3 billion cubic feet of natural gas.
Coal Contracts. GSU has contracted for a long-term supply of low-sulfur
Wyoming coal for use at Nelson Unit 6. This contract, which is set to expire in
2004, will provide a supply of 50 million tons over the term of the contract.
Cajun has advised GSU that current contracts will provide an adequate supply of
coal for Big Cajun 2 Unit 3 until 1997.
Environmental Issues
GSU has been notified by the U. S. Environmental Protection Agency (EPA) that
it has been designated as a potentially responsible party for the cleanup of
sites on which GSU and others have or have been alleged to have disposed of mate
rial designated as hazardous waste. GSU is currently negotiating with the EPA
and state authorities regarding the cleanup of some of these sites. Several
class action and other suits have been filed in state and federal courts seeking
relief from GSU and others for damages caused by the disposal of hazardous waste
and for asbestos-related disease which allegedly occurred from exposure on GSU
premises. While the amounts at issue in the cleanup efforts and suits may be
very substantial sums, management believes that its results of operations and
financial condition will not be materially affected by the outcome of the suits.
As of December 31, 1993, GSU has accrued cumulative amounts related to the
cleanup of six sites at which GSU has been designated a potentially responsible
party, totaling $25.2 million since 1990. Through December 31, 1993, GSU has
expensed $7 million cumulatively on the cleanup, resulting in a remaining
liability of $18.2 million as of December 31, 1993.
GSU is also involved in litigation arising in the normal course of business.
While the results of such litigation cannot be predicted with certainty,
management believes that the final outcome will not have a material adverse
effect on its financial condition or operating results when resolved in a future
period.
NOTE 9. LEASES
General
As of December 31, 1993, GSU had capital leases and noncancelable operating
leases (excluding nuclear fuel leases) with minimum lease payments as follows:
Capital Operating
Year Leases Leases
---- ------- ---------
(In Thousands)
1994 $ 12,475 $ 19,720
1995 12,475 19,720
1996 12,475 19,720
1997 12,475 9,509
1998 12,475 11,271
Years thereafter 93,855 96,749
-------- --------
Minimum lease payments 156,230 $176,689
Less: Amount representing interest 63,628 ========
--------
Present value of net minimum lease payments $ 92,602
========
Rental expense for capital and operating leases (excluding nuclear fuel
leases) amounted to approximately $31.9 million, $21.9 million, and $14.9
million, in 1993, 1992, and 1991, respectively.
GSU is leasing the Lewis Creek generating station from its wholly owned
consolidated subsidiary, GSG&T.
Nuclear Fuel Lease
GSU has arrangements to lease nuclear fuel with a non-affiliated third party
which finances its acquisition of nuclear fuel through a credit agreement and
the issuance of notes totaling $130 million as of December 31, 1993. On
January 31, 1994, $25 million of the notes matured, while $40 million of the
notes each will mature on January 31, 1995 and January 31, 1996. It is expected
that alternative financing will be secured by the lessor upon the maturity of
the notes in 1995 and 1996. If the lessor cannot arrange for alternative
financing upon the maturity of its borrowings, GSU must purchase nuclear fuel in
an amount sufficient to enable the lessor to retire such borrowings.
Lease payments are based on nuclear fuel use. Nuclear fuel expense of $43.6
million, $31.6 million, and $58.1 million (including interest of $10.2 million,
$11.5 million and $12.2 million) was charged to operations in 1993, 1992, and
1991, respectively.
NOTE 10. POSTRETIREMENT BENEFITS
Pension Plan
GSU has a defined benefit pension plan covering substantially all of its
employees. The pension plan is noncontributory and provides pension benefits
that are based on employees' credited service and the highest five consecutive
years of employees' compensation during the last ten years before retirement.
GSU funds pension costs in accordance with contribution guidelines established
by the Employee Retirement Income Security Act of 1974, as amended, and the
Internal Revenue Code of 1986, as amended. The assets of the plan consist
primarily of common and preferred stocks and fixed income securities.
GSU's 1993, 1992, and 1991 pension cost, including amounts capitalized,
included the following components:
For the Years Ended December 31,
--------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Service cost - benefits earned during the period $ 10,417 $ 12,396 $ 10,306
Interest cost on projected benefit obligation 17,643 16,307 15,355
Actual return on plan assets (43,400) (28,117) (56,898)
Net amortization and deferral 14,863 2,926 36,347
-------- -------- --------
Net pension cost $ (477) $ 3,512 $ 5,110
======== ======== ========
The funded status of GSU's pension plan as of December 31, 1993 and 1992,
was:
1993 1992
-------- --------
(In Thousands)
Actuarial present value of benefit obligations:
Vested $197,386 $186,845
Nonvested 13,667 11,508
-------- --------
Accumulated benefit obligation $211,053 $198,353
======== ========
Plan assets at fair market value $337,922 $306,660
Projected benefit obligation 259,462 255,573
-------- --------
Plan assets in excess of projected benefit obligation 78,460 51,087
Unrecognized prior service cost 25,977 24,671
Unrecognized transition asset (16,712) (19,099)
Unrecognized net gain (92,910) (62,321)
-------- --------
Accrued pension liability $ (5,185) $ (5,662)
======== ========
The significant actuarial assumptions used in computing the information
above were:
1993 1992 1991
---- ---- ----
Weighted average discount rate 7.50% 6.50% 7.25%
Weighted average increase in future compensation levels 5.00 5.75 6.10
Expected long-term rate of return on plan assets 8.50 8.50 8.50
Transition assets are being amortized over 15 years.
In December 1993, GSU recorded a $17 million charge related to the
announced early retirement program in connection with the Merger, of which $14.9
million was expensed.
Other Postretirement Benefits
GSU also provides certain health care and life insurance benefits for
retired employees. All of GSU's employees may become eligible for these
benefits if they reach retirement age while still working for GSU. The cost of
providing these benefits, recorded on a cash basis, was $5.3 million and $5.5
million for the years 1992 and 1991, respectively.
Effective January 1, 1993, GSU adopted SFAS 106. The new standard requires
a change from a cash method to an accrual method of accounting for
postretirement benefits other than pensions. GSU continues to fund these
benefits on a pay-as-you-go-basis. As of January 1, 1993, the actuarially
determined accumulated postretirement benefit obligation (APBO) earned by
retirees and active employees was estimated to be approximately $128 million.
This obligation is being amortized over a 20-year period beginning in 1993.
In March 1993, the PUCT issued a ruling applicable to all Texas utilities
that amounts recorded in compliance with SFAS 106 and included in a rate filing
test period, will be recoverable in rates (at the time of the next general rate
case) and that the postretirement benefit amounts allowed in rates must then be
funded by the utility. The PUCT made no specific provision in its order
permitting deferral, as a regulatory asset, of these costs. The LPSC ordered
GSU to use the pay-as-you-go method for ratemaking purposes for postretirement
benefits other than pensions, but the LPSC retains the flexibility to examine
companies' accounting for postretirement benefits to determine if special
exceptions to this order are warranted. GSU's net income in 1993 was decreased
by approximately $7.9 million as a result of adopting SFAS 106.
GSU's 1993 postretirement benefit cost, including amounts capitalized and
deferred, included the following components (in thousands):
Service cost - benefits earned during the period $ 5,467
Interest cost on APBO 9,976
Actual return on plan assets -
Amortization of transition obligation 6,402
-------
Net periodic postretirement benefit cost $21,845
=======
The funded status of GSU's postretirement plan as of December 31, 1993,
was (in thousands):
Accumulated postretirement benefit obligation:
Retirees $ 46,270
Other fully eligible participants 38,091
Other active participants 18,359
---------
102,720
Plan assets at fair value -
---------
Plan assets in excess of (less than APBO) (102,720)
Unrecognized transition obligation 121,634
Unrecognized net gain (35,534)
---------
Accrued postretirement benefit liability $ (16,620)
=========
The assumed health care cost trend rate used in measuring the APBO is 10%
for 1994, gradually decreasing each successive year until it reaches 5% in 2002.
A one percentage-point increase in the assumed health care cost trend rate for
each year would increase the APBO as of December 31, 1993, by 13.6% and the sum
of the service cost and interest cost by approximately 22.7%. The assumed
discount rate and rate of increase in future compensation used in determining
the APBO were 7.5%, and 5%, respectively.
NOTE 11. TRANSACTIONS WITH AFFILIATES
Effective December 31, 1993, GSU purchases electricity from and/or sells
electricity to the other System operating companies under rate schedules filed
with FERC.
Operating revenues include revenues from sales to System operating companies
prior to the Merger, totaling $.5 million in 1993, $0 in 1992, and $.5 million
in 1991. Operating expenses include charges from System operating companies for
purchased power and related charges, prior to the Merger, totaling $25.5 million
in 1993, $38.8 million in 1992, and $16.1 million in 1991.
NOTE 12. ENTERGY CORPORATION-GSU MERGER
On December 31, 1993, Entergy Corporation and GSU consummated their Merger.
GSU became a wholly-owned subsidiary of Entergy Corporation and continues to
operate as a corporation under the regulation of the PUCT and the LPSC. As
consideration to GSU's shareholders, Entergy Corporation paid $250 million and
issued 56,667,726 shares of its common stock in exchange for the 114,055,065
outstanding shares of GSU common stock. The Merger was accounted for under the
purchase method of accounting. Various parties have requested rehearings and/or
are appealing the approval orders or plans of the SEC, NRC, LPSC, and FERC.
As a result of the December 31, 1993 Merger closing, GSU recorded expenses
totaling $49 million, net of related tax effects, for early retirement and other
severance related plans and the payment to financial consultants involved in
Merger negotiations on behalf of GSU. See Note 2 for information regarding
Merger related rate agreements.
Entergy Corporation recorded an acquisition adjustment in utility plant in
the amount of $380 million representing the excess of the purchase price over
the net assets acquired of GSU. The acquisition adjustment will be amortized on
a straight-line basis over a 31-year period, which approximates the remaining
average book life of GSU's plant. The allocation of the purchase price has been
based on preliminary estimates which may be revised at a later date. The
possibility of an adverse result in the litigation relating to Cajun (see Note
8) and the possibility of a write-off relating to Texas River Bend ratemaking
issues (see Note 2) represent preacquisition contingencies. There may be other
contingencies associated with GSU which could also constitute preacquisition
contingencies but which have not yet been specifically identified as such by
Entergy Corporation. During the allocation period (which will not exceed one
year after consummation of the transaction), Entergy Corporation will complete
its analyses with respect to these contingencies. Upon completion, should
Entergy Corporation no longer believe GSU has a reasonable possibility of
attaining a favorable ruling in such preacquisition contingencies, any resulting
write-offs and/or losses would cause the reduction of the affected noncurrent
assets and an increase of an equal amount in the acquisition adjustment in
Entergy Corporation's consolidated financial statements, in accordance with the
purchase method of accounting for business combinations. Any resulting write-
offs and/or losses would be charged to operations during the current period on
GSU's financial statements.
NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating results for the four quarters of 1993 and 1992 were:
Income (Loss)
Before
Extraordinary
Items and the
Cumulative Effect Net
Operating Operating of Accounting Income
Revenues Income Changes (Loss)
--------- --------- ------------- -----
(In Thousands)
1993:
First Quarter $404,178 $ 69,408 $ 15,007 $ 25,667
Second Quarter $442,223 $ 81,989 $ 31,066 $ 30,781
Third Quarter $574,607 $118,032 $ 70,155 $ 69,181
Fourth Quarter $406,612 $ 1,187 $(46,767) $(46,767)
1992:
First Quarter $403,279 $ 71,372 $ 24,187 $ 26,209
Second Quarter $417,365 $ 78,999 $ 32,155 $ 27,889
Third Quarter $517,899 $116,252 $ 66,167 $ 65,648
Fourth Quarter $434,831 $ 71,997 $ 16,904 $ 14,102
GSU's business is subject to seasonal fluctuations with the peak period
occurring during the third quarter. See Note 1 for information regarding the
change in accounting for unbilled revenues during 1993. See Note 2 for
information regarding rate refunds during December 1993, and Note 12 for
information regarding Merger-related charges recorded during the fourth quarter
of 1993. See Note 1 for information regarding extraordinary items recorded in
1992 due to the extinguishment of debt and for information regarding the
cumulative effect of a change in accounting for power plant materials and
supplies.
GULF STATES UTILITIES COMPANY
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
(In Thousands)
Operating revenues $1,827,620 $1,773,374 $1,702,235 $1,690,685 $1,607,406
Income (loss) before
extraordinary items and
the cumulative effect of
accounting changes $ 69,461 $ 139,413 $ 112,391 $ (36,399) $ (45,573)
Total assets $7,165,776 $7,164,447 $7,183,119 $7,135,399 $6,751,432
Long-term obligations (1) $2,772,002 $2,798,768 $2,816,577 $2,663,249 $2,954,736
(1) Includes long-term debt (excluding currently maturing debt), preferred and
preference stock with sinking fund, and noncurrent capital lease
obligations.
See Notes 1 and 10 for the effect of accounting changes in 1993 and 1992
and Notes 2 and 8 regarding River Bend rate appeals and litigation with
Cajun.
1993 1992 1991 1990 1989
---------- ---------- --------- ---------- ----------
(Dollars in Thousands)
Electric Department
Operating Revenues:
Residential $ 585,799 $ 560,552 $ 547,147 $ 523,911 $ 487,972
Commercial 415,267 400,803 383,883 378,253 357,568
Industrial 650,230 642,298 582,568 578,928 541,019
Governmental 26,118 26,195 24,792 24,101 22,728
---------- ---------- ---------- ---------- ----------
Total retail 1,677,414 1,629,848 1,538,390 1,505,193 1,409,287
Sales for resale 31,898 24,485 44,136 48,125 51,584
Other 38,649 40,203 41,433 43,317 41,003
---------- ---------- ---------- ---------- ----------
Total Electric Department $1,747,961 $1,694,536 $1,623,959 $1,596,635 $1,501,874
========== ========== ========== ========== ==========
Billed Electric Energy
Sales (Millions of KWH):
Electric Department
Residential 7,192 6,825 6,925 6,834 6,473
Commercial 5,711 5,474 5,460 5,388 5,198
Industrial 14,294 14,413 13,629 13,347 12,333
Governmental 296 302 295 285 275
---------- ---------- ---------- ---------- ----------
Total retail 27,493 27,014 26,309 25,854 24,279
Sales for resale 666 540 1,049 1,180 916
---------- ---------- ---------- ---------- ----------
Total Electric Department 28,159 27,554 27,358 27,034 25,195
Steam Department 1,597 1,722 1,711 1,930 2,271
---------- ---------- ---------- ---------- ----------
Total 29,756 29,276 29,069 28,964 27,466
========== ========== ========== ========== ==========
Louisiana Power & Light Company
1993 Financial Statements
LOUISIANA POWER & LIGHT COMPANY
DEFINITIONS
Certain abbreviations or acronyms used in LP&L's Financial
Statements, Notes to Financial Statements, and Management's Financial
Discussion and Analysis are defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
AP&L Arkansas Power & Light Company
DOE United States Department of Energy
Entergy or System Entergy Corporation and its various direct
and indirect subsidiaries
Entergy Operations Entergy Operations, Inc., a subsidiary of
Entergy Corporation that has operating
responsibility for Grand Gulf 1, Waterford 3,
ANO, and River Bend
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Grand Gulf 1 Unit No. 1 of the Grand Gulf Station
Grand Gulf 2 Unit No. 2 of the Grand Gulf Station
Grand Gulf Station Grand Gulf Steam Electric Generating Station
GSU Gulf States Utilities Company (including
wholly owned subsidiaries - Varibus
Corporation, GSG&T, Inc., Prudential Oil and
Gas, Inc., and Southern Gulf Railway Company)
KWH Kilowatt-Hour(s)
LP&L Louisiana Power & Light Company
LPSC Louisiana Public Service Commission
Money Pool Entergy Money Pool, which allows certain
System companies to borrow from, or lend to,
certain other System companies
MP&L Mississippi Power & Light Company
NOPSI New Orleans Public Service Inc.
OBRA Omnibus Budget Reconciliation Act of 1993
Owner Participant A corporation that, in connection with the
Waterford 3 sale and leaseback transactions,
has acquired a beneficial interest in a
trust, the Owner Trustee of which is the
owner and lessor of undivided interest in
Waterford 3
Owner Trustee Each institution and/or individual acting as
owner trustee under a trust agreement with an
Owner Participant in connection with the
Waterford 3 sale and leaseback transactions
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
promulgated by the FASB
SFAS 106 SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions"
SFAS 109 SFAS No. 109, "Accounting for Income Taxes"
System or Entergy Entergy Corporation and its various direct
and indirect subsidiaries
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI,
collectively
Waterford 3 Unit No. 3 of LP&L's Waterford Steam Electric
Generating Station
LOUISIANA POWER & LIGHT COMPANY
REPORT OF MANAGEMENT
The management of Louisiana Power & Light Company has prepared and is
responsible for the financial statements and related financial information
included herein. The financial statements are based on generally accepted
accounting principles. Financial information included elsewhere in this report
is consistent with the financial statements.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting controls that
is designed to provide reasonable assurance, on a cost-effective basis, as to
the integrity, objectivity, and reliability of the financial records, and as to
the protection of assets. This system includes communication through written
policies and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and the
training of personnel. This system is also tested by a comprehensive internal
audit program.
The independent public accountants provide an objective assessment of the
degree to which management meets its responsibility for fairness of financial
reporting. They regularly evaluate the system of internal accounting controls
and perform such tests and other procedures as they deem necessary to reach and
express an opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide reasonable
assurance that its operations are carried out with a high standard of business
conduct.
/S/ EDWIN LUPBERGER /S/ GERALD D. MCINVALE
EDWIN LUPBERGER GERALD D. MCINVALE
Chairman and Chief Executive Officer Senior Vice President and
Chief Financial Officer
LOUISIANA POWER & LIGHT COMPANY
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Louisiana Power & Light Company Audit Committee of the Board of
Directors is comprised of three directors, who are not officers of LP&L: Joseph
J. Krebs, Jr. (Chairman), William K. Hood, and H. Duke Shackelford. The
committee held four meetings during 1993.
The Audit Committee oversees LP&L's financial reporting process on behalf
of the Board of Directors and provides reasonable assurance to the Board that
sufficient operating, accounting, and financial controls are in existence and
are adequately reviewed by programs of internal and external audits.
The Audit Committee discussed with Entergy's internal auditors and the
independent public accountants (Deloitte & Touche) the overall scope and
specific plans for their respective audits, as well as LP&L's financial
statements and the adequacy of LP&L's internal controls. The committee met,
together and separately, with Entergy's internal auditors and independent public
accountants, without management present, to discuss the results of their audits,
their evaluation of LP&L's internal controls, and the overall quality of LP&L's
financial reporting. The meetings also were designed to facilitate and
encourage any private communication between the committee and the internal
auditors or independent public accountants.
/S/ JOSEPH J. KREBS, JR.
JOSEPH J. KREBS, JR.
Chairman, Audit Committee
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of
Louisiana Power & Light Company
We have audited the accompanying balance sheets of Louisiana Power & Light
Company (LP&L) as of December 31, 1993 and 1992, and the related statements of
income, retained earnings, and cash flows for each of the three years in the
period ended December 31, 1993. These financial statements are the
responsibility of LP&L's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of LP&L at December 31, 1993 and 1992, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1993 in conformity with generally accepted accounting
principles.
As discussed in Notes 3 and 10 to the financial statements, in 1993 LP&L
changed its methods of accounting for income taxes and postretirement benefits
other than pensions, respectively.
/S/ DELOITTE & TOUCHE
DELOITTE & TOUCHE
New Orleans, Louisiana
February 11, 1994
LOUISIANA POWER & LIGHT COMPANY
BALANCE SHEETS
ASSETS
December 31,
------------------------
1993 1992
---------- ----------
(In Thousands)
Utility Plant (Note 1):
Electric $4,646,020 $4,577,410
Electric plant under lease (Note 9) 225,083 225,083
Construction work in progress 133,536 67,535
Nuclear fuel under capital leases (Note 9) 61,375 63,190
Nuclear fuel 3,823 3,437
---------- ----------
Total 5,069,837 4,936,655
Less - accumulated depreciation and amortization 1,496,107 1,380,282
---------- ----------
Utility plant - net 3,573,730 3,556,373
---------- ----------
Other Property and Investments:
Nonutility property 20,060 20,060
Decommissioning trust fund (Note 8) 22,109 17,121
Investment in subsidiary company - at equity (Note 8) 14,230 14,230
Other 984 922
---------- ----------
Total 57,383 52,333
---------- ----------
Current Assets:
Cash equivalents (Note 1):
Temporary cash investments - at cost,
which approximates market:
Associated companies (Note 4) - 593
Other 33,489 22,189
---------- ----------
Total cash equivalents 33,489 22,782
Special deposits 19,077 4,080
Accounts receivable:
Customer (less allowance for doubtful accounts of
$1.1 million in 1993 and $2.0 million in 1992) 66,575 58,067
Associated companies (Note 11) 2,952 8,863
Other 10,656 11,805
Accrued unbilled revenues (Note 1) 64,314 57,716
Deferred fuel costs (Note 1) - 2,939
Accumulated deferred income taxes (Note 3) 6,031 4,915
Materials and supplies - at average cost 87,204 87,856
Rate deferrals (Note 2) 28,422 28,422
Prepayments and other 16,510 41,527
---------- ----------
Total 335,230 328,972
---------- ----------
Deferred Debits:
Rate deferrals (Note 2) 54,031 82,453
SFAS 109 regulatory asset - net (Note 3) 349,703 -
Unamortized loss on reaquired debt 47,853 48,203
Other (Note 8) 46,068 40,814
---------- ----------
Total 497,655 171,470
---------- ----------
TOTAL $4,463,998 $4,109,148
========== ==========
See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
------------------------
1993 1992
---------- ----------
(In Thousands)
Capitalization:
Common stock, no par value, authorized 250,000,000
shares; issued and outstanding 165,173,180 shares in
1993 and 1992 (Note 5) $1,088,900 $1,088,900
Capital stock expense and other (6,109) (7,469)
Retained earnings (Note 7) 89,849 94,510
---------- ----------
Total common shareholder's equity 1,172,640 1,175,941
Preferred stock (Note 5):
Without sinking fund 160,500 160,500
With sinking fund 126,302 148,802
Long-term debt (Note 6) 1,457,626 1,445,947
---------- ----------
Total 2,917,068 2,931,190
---------- ----------
Other Noncurrent Liabilities:
Obligations under capital leases (Note 9) 27,508 28,160
Other (Note 8) 27,672 17,027
---------- ----------
Total 55,180 45,187
---------- ----------
Current Liabilities:
Currently maturing long-term debt (Note 6) 25,315 1,275
Notes payable-associated companies (Note 4) 52,041 -
Accounts payable:
Associated companies (Note 11) 33,523 37,693
Other 76,284 100,312
Customer deposits 52,234 49,558
Taxes accrued 15,110 8,249
Interest accrued 42,141 41,138
Dividends declared 5,938 6,675
Gas contract settlement - liability to customers - 55,998
Deferred revenue - gas supplier judgment proceeds (Note 2) 14,632 42,256
Deferred fuel cost (Note 1) 605 -
Obligations under capital leases (Note 9) 33,867 35,029
Other 9,741 11,428
---------- ----------
Total 361,431 389,611
---------- ----------
Deferred Credits:
Accumulated deferred income taxes (Note 3) 834,899 441,064
Accumulated deferred investment tax credits (Note 3) 188,843 191,528
Deferred revenue - gas supplier judgment proceeds (Note 2) - 14,846
Deferred interest - Waterford 3 lease obligation (Note 9) 25,372 24,796
Other 81,205 70,926
---------- ----------
Total 1,130,319 743,160
---------- ----------
Commitments and Contingencies (Notes 2, 8, and 9)
TOTAL $4,463,998 $4,109,148
========== ==========
See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
----------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Operating Activities:
Net income $188,808 $182,989 $166,572
Noncash items included in net income:
Change in rate deferrals (Note 2) 28,422 28,422 28,422
Depreciation and decommissioning 142,051 138,290 130,898
Deferred income taxes and investment tax credits 40,261 42,896 73,795
Allowance for equity funds used during construction (2,581) (1,714) (1,244)
Amortization of deferred revenues (Note 2) (42,470) (38,646) (36,310)
Changes in working capital:
Receivables (8,046) (5,135) (8,753)
Accounts payable (28,198) 7,733 13,971
Taxes accrued 6,861 6,002 (22,642)
Interest accrued 1,003 2,917 (6,680)
Other working capital accounts 15,205 (16,037) (2,939)
Refunds to customers - gas contract settlement (56,027) (56,066) (56,098)
Decommissioning trust contributions (4,000) (2,000) (7,227)
Other 18,299 5,982 4,403
-------- -------- --------
Net cash flow provided by operating activities 299,588 295,633 276,168
-------- -------- --------
Investing Activities:
Construction expenditures (163,142) (150,527) (135,986)
Allowance for equity funds used during construction 2,581 1,714 1,244
-------- -------- --------
Net cash flow used in investing activities (160,561) (148,813) (134,742)
-------- -------- --------
Financing Activities:
Proceeds from the issuance of:
First mortgage bonds 100,000 269,000 -
Preferred stock - 87,000 85,000
Common stock - - 100,000
Other long-term debt 58,000 44,094 49,907
Changes in short-term borrowings 52,041 - -
Retirement of:
First mortgage bonds (100,919) (309,205) (320,786)
Other long-term debt (22,052) (15,977) (4,702)
Redemption of preferred stock (22,500) (63,981) (60,500)
Dividends paid:
Common stock (167,600) (174,600) (63,552)
Preferred stock (25,290) (28,845) (26,894)
-------- -------- --------
Net cash flow used in financing activities (128,320) (192,514) (241,527)
-------- -------- --------
Net increase (decrease) in cash and cash equivalents 10,707 (45,694) (100,101)
Cash and cash equivalents at beginning of period 22,782 68,476 168,577
-------- -------- --------
Cash and cash equivalents at end of period $33,489 $22,782 $68,476
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $127,497 $126,674 $172,421
Income taxes $62,414 $32,668 $33,133
Noncash investing and financing activities:
Capital lease obligations incurred $33,210 $37,689 $10,002
See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is important to LP&L due to the capital intensive nature of our
business, which requires large investments in long-lived assets. However, large
capital expenditures for the construction of new generating capacity are not
currently planned. LP&L requires significant capital resources for the periodic
maturity of certain series of debt and preferred stock. Net cash flow from
operations totaled $300 million, $296 million, and $276 million in 1993, 1992,
and 1991, respectively. In recent years, this cash flow, supplemented by cash
on hand, has been sufficient to meet substantially all investing and financing
requirements, including capital expenditures, dividends, and debt/preferred
stock maturities. LP&L's ability to fund these capital requirements results, in
part, from our continued efforts to streamline operations and reduce costs, as
well as collections under our Waterford 3 rate phase-in plan which exceed the
current cash requirements for Waterford 3-related costs. (In the income
statement, these revenue collections are offset by the amortization of
previously deferred costs, therefore, there is no effect on net income.) See
Note 2, incorporated herein by reference, for additional information on LP&L's
rate phase-in plan. See Note 8, incorporated herein by reference, for
additional information on LP&L's capital and refinancing requirements in 1994 -
1996. Also, in order to take advantage of lower interest and dividend rates,
LP&L may continue to refinance high-cost debt and preferred stock prior to
maturity.
Earnings coverage tests and bondable property additions limit the first
mortgage bonds and preferred stock that LP&L can issue. Based on the most
restrictive applicable tests as of December 31, 1993, and assuming an annual
interest or dividend rate of 8%, LP&L could have issued $92 million of
additional first mortgage bonds or $686 million of additional preferred stock.
Further, LP&L has the conditional ability to issue first mortgage bonds against
the retirement of first mortgage bonds, in some cases without satisfying an
earnings coverage test.
See Notes 5 and 6, incorporated herein by reference, for information on
LP&L's financing activities and Note 4, incorporated herein by reference, for
information on LP&L's short-term borrowings and lines of credit.
LOUISIANA POWER & LIGHT COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31,
-------------------------------------
1993 1992 1991
---------- ---------- ----------
(In Thousands)
Operating Revenues (Notes 1, 2, and 11): $1,729,666 $1,553,745 $1,528,934
---------- ---------- ----------
Operating Expenses:
Operation (Note 11):
Fuel for electric generation and fuel-related
expenses 338,670 256,313 212,973
Purchased power (Notes 2 and 8) 381,252 335,750 344,637
Other 260,419 250,836 253,080
Maintenance (Note 11) 98,281 92,363 101,896
Depreciation and decommissioning 142,051 138,290 130,898
Taxes other than income taxes 50,391 49,507 48,428
Income taxes (Note 3) 108,568 83,984 76,104
Amortization of rate deferrals (Note 2) 28,422 28,422 28,422
---------- ---------- ----------
Total 1,408,054 1,235,465 1,196,438
---------- ---------- ----------
Operating Income 321,612 318,280 332,496
---------- ---------- ----------
Other Income:
Allowance for equity funds used during
construction 2,581 1,714 1,244
Miscellaneous - net 2,069 6,676 8,739
Income taxes (Note 3) (2,245) (3,053) (8,616)
---------- ---------- ----------
Total 2,405 5,337 1,367
---------- ---------- ----------
Interest Charges:
Interest on long-term debt 124,632 128,672 158,816
Other interest - net 12,325 12,691 9,206
Allowance for borrowed funds used
during construction (1,748) (735) (731)
---------- ---------- ----------
Total 135,209 140,628 167,291
---------- ---------- ----------
Net Income 188,808 182,989 166,572
Preferred Stock Dividend Requirements 24,754 28,416 27,343
---------- ---------- ----------
Earnings Applicable to Common Stock $164,054 $154,573 $139,229
========== ========== ==========
See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
--------------------------------
1993 1992 1991
------- -------- --------
(In Thousands)
Retained Earnings, January 1 $94,510 $117,820 $46,583
Add:
Net income 188,808 182,989 166,572
------- -------- --------
Total 283,318 300,809 213,155
------- -------- --------
Deduct:
Dividends declared:
Preferred stock 24,553 28,416 27,343
Common stock 167,600 174,600 63,552
Capital stock expenses 1,316 3,283 4,440
------- -------- --------
Total 193,469 206,299 95,335
------- -------- --------
Retained Earnings, December 31 (Note 7) $89,849 $94,510 $117,820
======= ======== ========
See Notes to Financial Statements.
LOUISIANA POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Excluding the effects of implementing SFAS 109 and SFAS 106 (see Notes 3
and 10, incorporated herein by reference), net income for 1993 would have been
$198.8 million resulting in an increase of $15.8 million. This increase is due
primarily to increased retail energy sales. Net income increased in 1992 due
primarily to a decrease in interest expense.
Significant factors affecting the results of operations and causing
variances between the years 1993 and 1992, and 1992 and 1991, are discussed
under "Revenues and Sales" and "Expenses" below.
Revenues and Sales
See "Selected Financial Data - Five-Year Comparison," incorporated herein
by reference, following the notes, for information on operating revenues by
source and KWH sales.
Electric operating revenues were higher in 1993 due primarily to increased
fuel adjustment revenues, which do not affect net income, and to increased
residential and commercial energy sales resulting primarily from a return to
more normal weather as compared to milder weather in 1992. Industrial energy
sales also increased primarily in the petrochemical industry.
Electric operating revenues were higher in 1992 due primarily to increased
fuel adjustment revenues and revenue from sales for resale. These increases
were partially offset by decreased retail base revenues as a result of milder
temperatures. Total energy sales remained relatively flat in 1992 with higher
sales for resale offset by lower residential and commercial sales resulting from
these milder temperatures.
Expenses
Fuel for electric generation and fuel-related expenses and purchased power
increased in 1993 due primarily to an increase in generation requirements
resulting primarily from increased retail energy sales and increased fuel costs.
Fuel for electric generation and fuel-related expenses increased in 1992 due
primarily to a higher average per unit cost for gas resulting from increased gas
prices in 1992.
Total income taxes increased in 1993 due primarily to higher pretax income,
an increase in the federal income tax rate as a result of OBRA, and the effect
of implementing SFAS 109.
Interest expense decreased in 1993 and 1992 as a result of the continued
refinancing of high cost debt during 1993 and 1992.
LOUISIANA POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Competition
LP&L welcomes competition in the electric energy business and believes that
a more competitive environment should benefit our customers, employees, and
shareholders of Entergy Corporation. We also recognize that competition
presents us with many challenges, and we have identified the following as our
major competitive challenges:
Retail and Wholesale Rate Issues
Increasing competition in the utility industry brings an increased need to
stabilize or reduce retail rates. LP&L is scheduled for a review of its rates
and rate structure by the LPSC upon expiration of LP&L's current rate freeze in
March 1994. Under the same LPSC order, an approximate $46 million per year
increase in LP&L's retail rates will also expire in March 1994. See Note 2,
incorporated herein by reference, for additional information.
Retail wheeling, a major industry issue which may require utilities to
"wheel" or move power from third parties to their own retail customers, is
evolving gradually. As a result, the retail market could become more
competitive.
In the wholesale rate area, FERC approved in 1992, with certain
modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power, Inc.
to sell wholesale power at market-based rates and to provide to electric
utilities "open access" to the System's transmission system (subject to certain
requirements). GSU was later added to this filing. Various intervenors in the
proceeding filed petitions for review with the United States Court of Appeals
for the District of Columbia Circuit. FERC's order, once it takes effect, will
increase marketing opportunities for LP&L, but will also expose LP&L to the risk
of loss of load or reduced revenues due to competition with alternative
suppliers.
In light of the rate issues discussed above, LP&L is aggressively reducing
costs to avoid potential earnings erosions that might result as well as to
successfully compete by becoming a low-cost producer. To help minimize future
costs, LP&L remains committed to least cost planning. In December 1992, LP&L
filed a Least Cost Integrated Resource Plan (Least Cost Plan) with its retail
regulators. Least cost planning includes demand-side measures such as customer
energy conservation and supply-side measures such as more efficient power
plants. These measures are designed to delay the building of new power plants
for the next 20 years. LP&L plans to periodically file revised Least Cost
Plans.
The Energy Policy Act of 1992
The Energy Policy Act of 1992 (Energy Act) is changing the transmission and
distribution of electricity. This act encourages competition and affords us the
opportunities, and the risks, associated with an open and more competitive
market environment. The Energy Act increases competition in the wholesale
energy market through the creation of exempt wholesale generators (EWGs). The
Energy Act also gives FERC the authority to order investor-owned utilities to
provide transmission access to or for other utilities, including EWGs.
LOUISIANA POWER & LIGHT COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
LP&L maintains accounts in accordance with FERC and other regulatory
guidelines. Certain previously reported amounts have been reclassified to
conform to current classifications.
Revenues and Fuel Costs
LP&L records revenues when billed to its customers and, in addition,
accrues revenue for the nonfuel portion of estimated revenues for energy
delivered since the latest billings.
LP&L's rate schedules include fuel adjustment clauses that allow deferral
of fuel costs until such costs are reflected in the related revenues.
Utility Plant
Utility plant is stated at original cost. Partial disallowances of plant
cost ordered by the regulators have been recorded as an adjustment to utility
plant. The original cost of utility plant retired or removed, plus the
applicable removal costs, less salvage, is charged to accumulated depreciation.
Maintenance, repairs, and minor replacement costs are charged to operating
expenses. Substantially all of LP&L's utility plant is subject to the lien of
its mortgage indenture. In addition, certain assets of LP&L are subject to the
liens of second mortgages related to pollution control revenue bonds.
AFUDC represents the approximate net composite interest cost of borrowed
funds and a reasonable return on the equity funds used for construction.
Although AFUDC increases utility plant and increases earnings, it is only
realized in cash through depreciation provisions included in rates. LP&L's
effective composite rates for AFUDC were 10.4%, 10.7%, and 10.6% for 1993, 1992,
and 1991, respectively.
Utility plant includes the portions of Waterford 3 that were sold and are
currently under lease. LP&L retired this property from its continuing property
records as formerly owned property released from and no longer subject to LP&L's
first mortgage indenture. LP&L is reflecting such leased property for financial
reporting purposes as property under lease from others and depreciating this
property over the life of the plant. See Note 9 for additional lease
disclosure.
Depreciation is computed on the straight-line basis at rates based on the
estimated service lives and costs of removal of the various classes of property.
Depreciation provisions on average depreciable property approximated 3.0% in
1993 and 2.9% in 1992 and 1991.
Income Taxes
LP&L, its parent, and affiliates (excluding GSU prior to 1994) file a
consolidated federal income tax return. Income taxes are allocated to LP&L in
proportion to its contribution to consolidated taxable income. SEC regulations
require that no System company pay more taxes than it would have had a separate
income tax return been filed. Deferred taxes are recorded for all temporary
differences between book and taxable income. Investment tax credits are
deferred and amortized based upon the average useful life of the related
property in accordance with rate treatment. As discussed in Note 3, effective
January 1, 1993, LP&L changed its accounting for income taxes to conform with
SFAS 109.
Reacquired Debt
The premiums and costs associated with reacquired debt are being amortized
over the life of the related new issuances, in accordance with ratemaking
treatment.
Cash and Cash Equivalents
LP&L considers all unrestricted highly liquid debt instruments purchased
with an original maturity of three months or less to be cash equivalents.
Fair Value Disclosure
The estimated fair value amounts of financial instruments have been
determined by LP&L, using available market information and appropriate valuation
methodologies. However, considerable judgment is required in developing the
estimates of fair value. Therefore, estimates are not necessarily indicative of
the amounts that LP&L could realize in a current market exchange. In addition,
gains or losses realized on financial instruments may be reflected in future
rates and not accrue to the benefit of stockholders.
LP&L considers the carrying amounts of financial instruments classified as
current assets and liabilities to be a reasonable estimate of their fair value
because of the short maturity of these instruments. In addition, LP&L does not
presently expect that performance of its obligations will be required in
connection with certain off-balance sheet commitments and guarantees considered
financial instruments. Due to this factor, and because of the related party
nature of these commitments and guarantees, determination of fair value is not
considered practicable. See Notes 5, 6, and 8 for additional fair value
disclosure.
NOTE 2. RATE AND REGULATORY MATTERS
LPSC Investigation
Pursuant to an LPSC request to explain LP&L's "relatively high cost of
debt" compared to other electric utilities subject to LPSC jurisdiction, LP&L
sent a response to the LPSC in August 1993. In an August 1993 report to the
LPSC, the LPSC's legal consultants acknowledged LP&L's rationale for its cost of
debt in comparison to two other utilities subject to the LPSC's jurisdiction.
Further, the legal consultants suggested that certain aspects of the LP&L cost
of debt could be taken up in any rate proceedings after the expiration of LP&L's
rate freeze in March 1994. In October 1993, the LPSC approved a schedule to
conduct a review of LP&L's rates and rate structure upon the expiration of
LP&L's current rate freeze.
Waterford 3 and Grand Gulf 1
In a series of LPSC orders, court decisions, and agreements between
November 1985 and June 1988, LP&L was granted Waterford 3 and Grand Gulf 1 rate
relief. In addition, LP&L, in accordance with judicial decisions and LPSC rate
orders, deferred a net amount of $266 million of its Waterford 3 costs related
to the period November 14, 1985 through January 31, 1988. These deferred costs
are being recovered over approximately 8.6 years beginning in April 1988.
In November 1985, LP&L agreed to permanently absorb, and not recover from
its retail customers, 18% of its 14% (approximately 2.52%) FERC-allocated share
of the costs of capacity and energy of Grand Gulf 1. However, LP&L was allowed
to recover, through the fuel adjustment clause, 4.6 cents per KWH (currently
2.55 cents per KWH through May 1994) for the energy related to the permanently
absorbed percentage, with LP&L's permanently retained percentage to be available
for sale to non-affiliated parties, subject to LPSC approval. For the year
ended December 31, 1993, $91 million was billed to LP&L by System Energy.
March 1989 Order
A March 1989 LPSC Order, which expires in March 1994, entitled LP&L to an
annual increase in retail rates of approximately $45.9 million. Instead of a
rate increase, the LPSC allowed LP&L to retain $188.6 million of proceeds LP&L
received in October 1988 as a result of litigation with a gas supplier.
Therefore, in March 1989 LP&L began amortizing over a 5.3 year period, for the
benefit of ratepayers, the proceeds plus accrued interest through February 1989.
As of December 31, 1993, the unamortized balance of such jurisdictional proceeds
was approximately $14.6 million. LP&L believes that the March 1989 Order has
provided approximately the same amount of additional net income as would an
annual rate increase of $45.9 million. LP&L agreed to a five-year base rate
freeze, at the then current level, except for, among other things, recovery of
certain taxes, net increases or decreases in LP&L's costs resulting from
proceedings at FERC relating to the Grand Gulf Station, or as a result of
catastrophic events. The impact of the March 1989 Order was to increase net
income in 1993, 1992, and 1991 by approximately $26.1, $28.5, and $27.7 million,
respectively.
NOTE 3. INCOME TAXES
Effective January 1, 1993, LP&L adopted SFAS 109. This new standard
requires that deferred income taxes be recorded for all temporary differences
and carryforwards, and that deferred tax balances be based on enacted tax laws
at tax rates that are expected to be in effect when the temporary differences
reverse. SFAS 109 requires that regulated enterprises recognize adjustments
resulting from implementation as regulatory assets or liabilities if it is
probable that such amounts will be recovered from or returned to customers in
future rates. A substantial majority of the adjustments required by SFAS 109
was recorded to deferred tax balance sheet accounts with offsetting adjustments
to regulatory assets and liabilities. The cumulative effect of the adoption of
SFAS 109 is included in income tax expense charged to operations. As a result
of the adoption of SFAS 109, 1993 net income was reduced by $5.7 million, assets
were increased by $309.7 million, and liabilities were increased by $315.4
million.
Income tax expense consisted of the following:
For the Years Ended December 31,
--------------------------------
1993 1992 1991
-------- ------- -------
(In Thousands)
Current:
Federal $62,037 $30,326 $5,180
State 8,514 6,139 3,504
-------- ------- -------
Total 70,551 36,465 8,684
-------- ------- -------
Deferred - net:
Liberalized depreciation 54,297 53,751 56,132
Unbilled revenue 3,474 (7,906) 489
Deferred Waterford 3 expenses (14,043) (14,043) (14,043)
Adjustment of prior years' tax provisions 2,665 (5,331) (3,659)
Waterford 3 sale and leaseback (3,632) (3,526) (3,898)
Gas contract settlement 9,513 15,180 15,342
Nuclear refueling and maintenance (5,768) 1,989 5,485
Materials and supplies inventory adjustments (2,505) (2,497) (841)
Alternative minimum tax (8,781) - 10,361
Contract deferred revenue 438 344 540
Property insurance reserve 23 3,119 (682)
Deferred fuel (1,337) 2,977 (357)
Bond reacquisition (243) 4,868 64
Decontamination and decommissioning fund 5,273 - -
Other 3,643 2,964 2,859
-------- ------- -------
Total 43,017 51,889 67,792
-------- ------- -------
Investment tax credit adjustments - net (2,755) (1,317) 8,244
-------- ------- -------
Recorded income tax expense $110,813 $87,037 $84,720
======== ======= =======
Charged to operations $108,568 $83,984 $76,104
Charged to other income 2,245 3,053 8,616
-------- ------- -------
Recorded income tax expense 110,813 87,037 84,720
Income taxes applied against the debt
component of AFUDC - 442 440
-------- ------- -------
Total income taxes $110,813 $87,479 $85,160
======== ======= =======
Total income taxes differ from the amounts computed by applying the statutory
federal income tax rate to income before taxes. The reasons for the differences
were:
For the Years Ended December 31,
------------------------------------------------------
1993 1992 1991
-------------------- ---------------- ---------------
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
-------- -------- ------- ------ ------- ------
(Dollars in Thousands)
Computed at statutory rate $104,867 35.0 $91,809 34.0 $85,439 34.0
Increases (reductions) in tax resulting from:
State income taxes net of federal
income tax effect 6,727 2.2 4,272 1.6 3,797 1.5
Depreciation 2,550 0.9 3,064 1.1 3,182 1.3
Impact of change in tax rate (2,767) (0.9) (3,989) (1.5) (3,012) (1.2)
Recapture of prior years' consolidated
income tax savings 573 0.2 (175) (0.1) 5,032 2.0
Amortization of investment tax credits (6,876) (2.3) (6,780) (2.5) (6,561) (2.6)
SFAS 109 adjustment 4,193 1.4 - - - -
Other - net 1,546 0.5 (1,164) (0.5) (3,157) (1.3)
-------- ---- ------- ---- ------- ----
Recorded income tax expense $110,813 37.0 $87,037 32.1 $84,720 33.7
Income taxes applied against the debt
component of AFUDC - - 442 .2 440 0.2
-------- ---- ------- ---- ------- ----
Total income taxes $110,813 37.0 $87,479 32.3 $85,160 33.9
======== ==== ======= ==== ======= ====
Significant components of LP&L's net deferred tax liabilities as of
December 31, 1993, were (in thousands):
Deferred tax liabilities:
Net regulatory assets $ (422,371)
Plant related basis differences (665,517)
Rate deferrals (40,737)
Bond reacquisition loss (17,368)
Other (14,429)
-----------
Total $(1,160,422)
===========
Deferred tax assets:
Unbilled revenues $ 13,190
Accumulated deferred investment tax credit 72,667
Gas contract settlement 12,917
Removal cost 47,603
Alternative minimum tax credit 41,618
Standard coal plant 12,898
Waterford 3 sale/leaseback 98,541
Other 32,120
-----------
Total $ 331,554
===========
Net deferred tax liabilities $ (828,868)
===========
The alternative minimum tax (AMT) credit as of December 31, 1993, was $41.6
million. This AMT credit can be carried forward indefinitely and will reduce
LP&L's federal income tax liability in future years.
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized LP&L to effect short-term borrowings up to
$125 million, subject to increase to as much as $259 million after further SEC
approval. This authorization is effective through November 30, 1994. As of
December 31, 1993, LP&L had unused lines of credit for short-term borrowings of
$20.2 million from banks within its service territory. In addition, LP&L can
borrow from the Money Pool, subject to its maximum authorized level of short-
term borrowings and the availability of funds. LP&L had $52 million in
outstanding borrowings under the Money Pool arrangement as of December 31, 1993.
NOTE 5. PREFERRED AND COMMON STOCK
The number of shares and dollar value of LP&L's preferred stock
was:
As of December 31,
----------------------------------------
Shares Call Price Per
Authorized and Total Share as of
Outstanding Dollar Value December 31,
1993 1992 1993 1992 1993
------- ------- ------- -------- -------------
(Dollars in Thousands)
Without sinking fund:
Cumulative, $100 par value
4.96% Series 60,000 60,000 $6,000 $6,000 $104.25
4.16% Series 70,000 70,000 7,000 7,000 $104.21
4.44% Series 70,000 70,000 7,000 7,000 $104.06
5.16% Series 75,000 75,000 7,500 7,500 $104.18
5.40% Series 80,000 80,000 8,000 8,000 $103.00
6.44% Series 80,000 80,000 8,000 8,000 $102.92
7.84% Series 100,000 100,000 10,000 10,000 $103.78
7.36% Series 100,000 100,000 10,000 10,000 $103.36
8.56% Series 100,000 100,000 10,000 10,000 $103.14
Cumulative, $25 par value
8.00% Series (1) 1,480,000 1,480,000 37,000 37,000 -
9.68% Series (1) 2,000,000 2,000,000 50,000 50,000 -
--------- --------- -------- --------
Total without sinking fund 4,215,000 4,215,000 $160,500 $160,500
========= ========= ======== ========
With sinking fund:
Cumulative, $100 par value
7.00% Series (1) 500,000 500,000 $50,000 $50,000 -
8.00% Series (1) 350,000 350,000 35,000 35,000 -
Cumulative, $25 par value
10.72% Series 390,211 630,211 9,755 15,755 $26.34
13.12% Series 61,121 221,121 1,528 5,528 $26.64
14.72% Series 416 200,416 10 5,010 $26.84
12.64% Series 1,200,370 1,500,370 30,009 37,509 $27.37
--------- --------- -------- --------
Total with sinking fund 2,502,118 3,402,118 $126,302 $148,802
========= ========= ======== ========
(1) These series are not redeemable as of December 31, 1993.
The fair value of LP&L's preferred stock with sinking fund was estimated to
be approximately $141.9 million and $171.5 million as of December 31, 1993 and
1992, respectively. The fair value was determined using quoted market prices or
estimates from nationally recognized investment banking firms. See Note 1 for
additional information on disclosure of fair value of financial instruments.
As of December 31, 1993, LP&L had 2,195,000 and 6,320,000 shares of
cumulative, $100 and $25 par value preferred stock, respectively, that were
authorized but unissued.
Changes in the common stock and preferred stock, with and without sinking
fund, during the last three years were:
Number of Shares
--------------------------------------
1993 1992 1991
---------- ----------- -----------
Common stock issuances - - 15,168,800
Preferred stock issuances:
$100 par value - 500,000 350,000
$25 par value - 1,480,000 2,000,000
Preferred stock retirements:
$100 par value - (370,000) (350,000)
$25 par value (900,000) (1,015,160) (1,020,000)
Cash sinking fund requirements for the next five years for preferred stock
outstanding as of December 31, 1993 are (in millions): 1994 - $8.3; 1995 - $6.8;
1996 - $6.8; 1997 - $4.5; and 1998 - $3.8. LP&L has the annual non-cumulative
option to redeem, at par, additional amounts of certain series of its
outstanding preferred stock.
LP&L has SEC authorization for the issuance and sale, through December 31,
1994, of up to $285 million of preferred stock (of which $113 million remained
available as of December 31, 1993). The proceeds would be used for the
refinancing of higher cost debt and preferred stock and general corporate
purposes. LP&L has SEC authorization through December 31, 1994 for the
acquisition, in whole or in part, of up to $75 million aggregate par value of
certain outstanding series of its preferred stock.
NOTE 6. LONG-TERM DEBT
LP&L's long-term debt as of December 31, 1993 and 1992 was:
Maturities Interest Rates
From To From To 1993 1992
---- ----- ----- ------ --------- --------
(In Thousands)
First Mortgage Bonds
1994 1998 4-5/8% 10.36% $204,000 $204,000
1999 2003 7-1/2% 9-3/8% 361,520 306,520
2004 2006 8-3/4% - 52,767
2020 2022 8-1/2% 10-1/8% 185,000 185,000
Governmental Obligations*
1993 2008 6-2/5% 8% 37,794 15,520
2009 2023 5.95% 8-1/4% 350,000 314,589
Long-Term Obligation - Purchase Agreement - 21,737
Waterford 3 Lease Obligation, 8.76% (Note 9) 353,600 353,600
Unamortized Premium and Discount - Net (8,973) (6,511)
---------- ----------
Total Long-Term Debt 1,482,941 1,447,222
Less Amount Due Within One Year 25,315 1,275
---------- ----------
Long-Term Debt Excluding Amount Due Within One Year $1,457,626 $1,445,947
========== ==========
* Consists of pollution control bonds and municipal revenue
bonds, certain series of which are secured by non-interest bearing
first mortgage bonds.
The fair value of LP&L's long-term debt, excluding Waterford 3 lease
obligation and long-term Purchase Agreement, as of December 31, 1993 and 1992
was estimated to be $1,205.1 million and $1,123.0 million, respectively. The
fair value was determined using quoted market prices or estimates from
nationally recognized investment banking firms. See Note 1 for additional
information on disclosure of fair value of financial instruments.
For the years 1994, 1995, 1996, 1997, and 1998, LP&L has long-term debt
maturities and cash sinking fund requirements of (in millions): $25.3, $75.3,
$35.3, $34.3, and $35.3, respectively. In addition, other sinking fund
requirements of approximately $6 million annually may be satisfied by cash or by
certification of property additions at the rate of 167% of such requirements.
LP&L has SEC authorization for the issuance and sale through December 31,
1994, of up to $625 million of first mortgage bonds (of which $256 million
remained available as of December 31, 1993) and to enter into agreements,
subject to meeting certain conditions, with the Parish of St. Charles, Louisiana
(Parish) whereby the Parish would issue and sell up to $250 million of
tax-exempt revenue bonds (of which $98 million remained available as of December
31, 1993) in order to reimburse LP&L for, or to permanently finance, the costs
of certain solid waste disposal, sewage disposal, and/or air or water pollution
control facilities. LP&L also has SEC authorization for the acquisition, in
whole or in part, through December 31, 1994 and prior to their respective
maturities, (1) up to $436 million of its outstanding first mortgage bonds,
including, but not limited to, the 10.36% Series due December 1, 1995, and
(2) up to $75 million of outstanding pollution control revenue bonds, including,
but not limited to, the 8.25% St. Charles Parish Pollution Control Revenue
Bonds, Series 1984 due 2014, and the 8% Second Series 1984 Bonds due 2014.
NOTE 7. DIVIDEND RESTRICTIONS
LP&L's Restated Articles of Incorporation, as amended, and certain of its
indentures, contain provisions restricting the payment of cash dividends or
other distributions on common stock. As of December 31, 1993, none of LP&L's
retained earnings were restricted against the payment of cash dividends or other
distributions on common stock. On February 1, 1994, LP&L paid Entergy
Corporation a $17.9 million cash dividend on common stock.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Capital Requirements and Financing
Construction expenditures (excluding nuclear fuel) for the years 1994,
1995, and 1996 are estimated to total $156 million, $143 million, and
$142 million, respectively. LP&L will also require $158 million during the
period 1994-1996 to meet long-term debt and preferred stock maturities and cash
sinking fund requirements. LP&L plans to meet the above requirements with
internally generated funds and cash on hand, supplemented by the issuance of
debt and preferred stock. See Notes 5 and 6 regarding the possible refunding,
redemption, purchase or other acquisition of certain outstanding series of
preferred stock and long-term debt.
Unit Power Sales Agreement
System Energy has agreed to sell all of its 90% owned and leased share of
capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in
accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI
17%) as ordered by FERC. Charges under this agreement are paid in consideration
for LP&L's respective entitlement to receive capacity and energy, and are
payable irrespective of the quantity of energy delivered so long as the unit
remains in commercial operation. The agreement will remain in effect until
terminated by the parties and approved by FERC, most likely upon Grand Gulf 1's
retirement from service. LP&L's monthly obligation for payments under the
agreement is approximately $8 million.
Availability Agreement
AP&L, LP&L, MP&L, and NOPSI are individually obligated to make payments or
subordinated advances to System Energy in accordance with stated percentages
(AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 24.7%) in amounts that when added
to amounts received under the Unit Power Sales Agreement or otherwise, are
adequate to cover all of System Energy's operating expenses. System Energy has
assigned its rights to payments and advances to certain creditors as security
for certain obligations. Payments or advances under the Availability Agreement
are only required if funds available to System Energy from all sources are less
than the amount required under the Availability Agreement. Since commercial
operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have
exceeded the amounts payable under the Availability Agreement. Accordingly, no
payments have ever been required. In 1989, the Availability Agreement was
amended to provide that the write-off of $900 million of Grand Gulf 2 costs
would be amortized for Availability Agreement purposes over a period of
27 years, in order to avoid the need for payments by AP&L, LP&L, MP&L, and
NOPSI. If AP&L, MP&L, or NOPSI fails to make its Unit Power Sales Agreement
payments, and System Energy is unable to obtain funds from other sources, LP&L
could be liable for payments to System Energy, in amounts that cannot be
determined, over and above its payments under the Unit Power Sales Agreement.
Reallocation Agreement
System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation
Agreement relating to the sale of capacity and energy from the Grand Gulf
Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume
all of AP&L's responsibilities and obligations with respect to the Grand Gulf
Station under the Availability Agreement. FERC's decision allocating a portion
of Grand Gulf 1 capacity and energy to AP&L supersedes the Reallocation
Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2
amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%,
and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the
Reallocation Agreement does not affect AP&L's obligation to System Energy's
lenders under the assignments referred to in the preceding paragraph. AP&L
would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were
unable to meet their contractual obligations. No payments of any amortization
amounts will be required as long as amounts paid to System Energy under the Unit
Power Sales Agreement, including other funds available to System Energy, exceed
amounts required under the Availability Agreement, which is expected to be the
case for the foreseeable future.
System Fuels
LP&L has a 33% interest in System Fuels, a jointly owned subsidiary of
AP&L, LP&L, MP&L, and NOPSI. The parent companies of System Fuels, including
LP&L, agreed to make loans to System Fuels to finance its fuel procurement,
delivery, and storage activities. As of December 31, 1993, LP&L had
approximately $14.2 million of loans outstanding to System Fuels which mature in
2008.
In addition, System Fuels entered into a revolving credit agreement with a
bank that provides $45 million in borrowings to finance System Fuels' nuclear
materials and services inventory. Should System Fuels default on its
obligations under its credit agreement, AP&L, LP&L, and System Energy have
agreed to purchase the nuclear materials and services financed under the
agreement.
Long-Term Contracts
LP&L has a long-term agreement through 2031 to purchase energy generated by
a hydroelectric facility. During 1993, 1992, and 1991, LP&L made payments under
the contract of approximately $73.1 million, $39.1 million, and $43.2 million,
respectively. If the maximum percentage (94%) of the energy is made available
to LP&L, current production projections would require estimated payments of
approximately $47 million per year through 1996, $54 million in 1997, and a
total of $3.5 billion for the years 1998 through 2031. LP&L recovers the costs
of purchased energy through its fuel adjustment clause.
In June 1992, LP&L agreed to a renegotiated 20-year natural gas supply
contract. LP&L has agreed to purchase natural gas in annual amounts equal to
approximately one-third of its projected annual fuel requirements for certain
generating units. Annual demand charges associated with this contract are
estimated to be $9 million through 1997, and a total of $124 million for the
years 1998 through 2012. LP&L recovers the cost of fuel consumed during the
generation of electricity through its fuel adjustment clause.
Nuclear Insurance
The Price-Anderson Act limits public liability for a single nuclear
incident to approximately $9.4 billion, as of December 31, 1993. LP&L has
protection for this liability through a combination of private insurance
(currently $200 million) and an industry assessment program. Under the
assessment program, the maximum amount that would be required for each nuclear
incident would be $79.28 million per reactor, payable at a rate of $10 million
per licensed reactor per incident per year. LP&L has one licensed reactor. In
addition, LP&L participates in a private insurance program which provides
coverage for worker tort claims filed for bodily injury caused by radiation
exposure. LP&L's maximum assessment under the program is an aggregate of
approximately $3.1 million in the event losses exceed accumulated reserve funds.
LP&L is a member of certain insurance programs that provide coverage for
property damage, including decontamination and premature decommissioning
expense, to members' nuclear generating plants. As of December 31, 1993, LP&L
was insured against such losses up to $2.7 billion, with $250 million of this
amount designated to cover any shortfall in the NRC required decommissioning
trust funding. In addition, LP&L is a member of an insurance program that
covers certain costs of replacement power and business interruption incurred due
to prolonged nuclear unit outages. Under the property damage and replacement
power/business interruption insurance programs, LP&L could be subject to
assessments if losses exceed the accumulated funds available to the insurers.
As of December 31, 1993, the maximum amount of such possible assessments to LP&L
was $24.34 million.
The amount of property insurance presently carried by LP&L exceeds the
Nuclear Regulatory Commission's (NRC) minimum requirement for nuclear power
plant licensees of $1.06 billion per site. NRC regulations provide that the
proceeds of this insurance must be used, first, to place and maintain the
reactor in a safe and stable condition and, second, to complete decontamination
operations. Only after proceeds are dedicated for such use and regulatory
approval is secured, would any remaining proceeds be made available for the
benefit of plant owners or their creditors.
Spent Nuclear Fuel and Decommissioning Costs
LP&L provides for estimated future disposal costs for spent nuclear fuel in
accordance with the Nuclear Waste Policy Act of 1982. LP&L entered into a
contract with the DOE, whereby the DOE will furnish disposal service at a cost
of one mill per net KWH generated and sold after April 7, 1983. The fees
payable to the DOE may be adjusted in the future to assure full recovery. LP&L
considers all costs incurred or to be incurred, except accrued interest, for the
disposal of spent nuclear fuel to be proper components of nuclear fuel expense
and provisions to recover such costs have been accepted by the LPSC.
Due to delays of the DOE's repository program for the acceptance of spent
nuclear fuel, it is uncertain when shipments of spent fuel from LP&L will
commence. In the meantime, LP&L is responsible for spent fuel storage. Current
on-site spent fuel storage capacity at Waterford 3 is estimated to be sufficient
until 2000. Thereafter, LP&L will provide additional storage capacity at an
estimated initial cost of $5.0 million to $10.0 million. In addition,
approximately $3.0 million to $5.0 million will be required every four to five
years subsequent to 2000 until the DOE's repository begins accepting Waterford
3's spent fuel.
Decommissioning costs for Waterford 3 were estimated to be $203.0 million
(in 1988 dollars), based on a 1988 update to the original cost study. LP&L had
LPSC authorization to fund and recover $4.0 million of decommissioning costs
annually through 1993, based on the 1988 study update. LP&L will begin funding
$4.8 million in 1994 in anticipation of a 1994 study update and a related LPSC
review and determination of appropriate funding levels. These amounts are
deposited in an external trust fund which has a market value of $23.5 million
and $17.4 million as of December 31, 1993 and 1992, respectively. The
accumulated decommissioning liability of $22.1 million as of December 31, 1993
has been recorded in accumulated depreciation. Decommissioning expense in the
amount of $4.0 million was recorded in 1993. The actual decommissioning costs
may vary from the above estimates because of regulatory requirements, changes in
technology, and increased costs of labor, materials, and equipment, and
management believes that actual decommissioning costs are likely to be higher
than the amounts presented above.
The Energy Act has a provision that assesses domestic nuclear utilities
with fees for the decontamination and decommissioning of the DOE's past uranium
enrichment operations. The decontamination and decommissioning assessments will
be used to set up a fund into which contributions from utilities and the federal
government will be placed. LP&L's annual assessment, which will be adjusted
annually for inflation, is $1.2 million (in 1993 dollars) annually for
approximately 15 years. FERC requires that utilities treat these assessments as
costs of fuel as they are amortized. The cumulative liability of $17.1 million
at December 31, 1993 is recorded in other current liabilities and other
noncurrent liabilities, according to FERC guidelines, and is offset in the
financial statements by a regulatory asset, recorded as a deferred debit.
NOTE 9. LEASES
General
As of December 31, 1993, LP&L had noncancelable operating leases with
minimum lease payments as follows (in thousands):
1994 $4,024
1995 3,844
1996 3,706
1997 3,644
1998 3,549
Years thereafter 6,717
-------
Minimum lease payments $25,484
=======
Rental expense for operating leases amounted to approximately $6.6 million,
$8.7 million, and $8.6 million in 1993, 1992, and 1991, respectively.
Nuclear Fuel Lease
LP&L has an arrangement to lease nuclear fuel in an amount up to $95
million. The lessor finances its acquisition of nuclear fuel through a credit
agreement and the issuance of notes. The credit agreement, which was entered
into in 1989, has been extended to January 1997 and the notes have varying
remaining maturities of up to 5 years. It is expected that the credit
arrangement will be extended or alternative financing will be secured by the
lessor upon the maturity of the current arrangements. If the lessor cannot
arrange for alternative financing upon maturity of its borrowings, LP&L must
purchase nuclear fuel in an amount sufficient to enable the lessor to retire
such borrowings.
Lease payments are based on nuclear fuel use. Nuclear fuel lease expense
of $39.9 million, $38.3 million, and $39.8 million (including interest of $4.9
million, $5.4 million, and $7.5 million) was charged to operations in 1993,
1992, and 1991, respectively.
Waterford 3 Lease Obligations
On September 28, 1989, LP&L entered into three substantially identical, but
entirely separate, transactions for the sale (for an aggregate cash
consideration of $353.6 million) and leaseback of three undivided portions of
its 100% ownership interest in Waterford 3. The three undivided interests in
Waterford 3 sold and leased back exclude certain transmission, pollution
control, and other facilities that are part of Waterford 3. The interests sold
and leased back, as described above, are equivalent on an aggregate cost basis
to approximately 9.3% of Waterford 3. The sales were made to an Owner Trustee
under three separate, but identical, trust agreements with three Owner
Participants. LP&L is leasing back the sold interests from the Owner Trustee on
a net lease basis over an approximate 28-year basic lease term. LP&L has
options to terminate the lease and to repurchase the sold interests in Waterford
3 at certain intervals during the basic lease term. Further, at the end of the
basic lease term, LP&L has an option to renew the lease or to repurchase the
undivided interests in Waterford 3.
The Owner Trustee acquired the interests with funds provided by the Owner
Participants and with funds obtained from the issuance and sale by the Owner
Trustee of intermediate-term and long-term bonds. The lease payments to be made
by LP&L will be sufficient to service the debt incurred by the Owner Trustee.
If LP&L does not exercise its option to repurchase the undivided interests
in Waterford 3 on the fifth anniversary (September 1994) of the closing date of
the sale and leaseback transactions, LP&L will be required to provide collateral
to the Owner Participants for the equity portion of certain amounts payable by
LP&L under the lease. Such collateral requirements are to be in the form of
either a bank letter of credit or the pledge of new series of first mortgage
bonds issued by LP&L under its first mortgage bond indenture.
Upon the occurrence of certain adverse events (including lease events of
default, events of loss, deemed loss events or certain adverse "Financial
Events" with respect to LP&L), LP&L may be obligated to pay amounts sufficient
to permit the Owner Participants to withdraw from the lease transactions and
LP&L may be required to assume the outstanding bonds issued by the Owner Trustee
to finance its acquisition of the undivided interests in Waterford 3.
"Financial Events" include, among other things, failure by LP&L, following the
expiration of any applicable grace or cure periods, to maintain (1) as of the
end of any fiscal quarter, total equity capital (including preferred stock) at
least equal to 30% of adjusted capitalization, or (2) in respect of the 12-month
period ending on the last day of any fiscal quarter, a fixed charge coverage
ratio of at least 1.50. As of December 31, 1993, LP&L's total equity capital
(including preferred stock) was 48.59% of adjusted capitalization and its fixed
charge coverage ratio was 3.18.
In accordance with SFAS No. 98, "Accounting for Leases," due to "continuing
involvement" by LP&L, the sale and leaseback by LP&L of the undivided portions
of Waterford 3, as described above, are required to be reflected for financial
reporting purposes as financing transactions in LP&L's financial statements even
though such portions are no longer owned by LP&L. See Note 1 for further
information regarding financial reporting treatment.
As of December 31, 1993, LP&L had future minimum lease payments (reflecting
an overall implicit rate of 8.76%) in connection with the Waterford 3 sale and
leaseback transactions as follows (in thousands):
1994 $32,568
1995 32,569
1996 35,165
1997 39,805
1998 41,447
Years thereafter 726,744
--------
Minimum lease payments $908,298
========
NOTE 10. POSTRETIREMENT BENEFITS
Pension Plan
LP&L has a defined benefit pension plan covering substantially all of its
employees. The pension plan is noncontributory and provides pension benefits
based on employees' credited service and average compensation, generally during
the last five years before retirement. LP&L funds pension costs in accordance
with contribution guidelines established by the Employee Retirement Income
Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as
amended. The assets of the plan consist primarily of common and preferred
stocks, fixed income securities, interest in a money market fund, and insurance
contracts.
Effective October 1, 1988, LP&L amended its plan to designate NOPSI as a
participating employer. LP&L's pension expense allocation policy results in
substantially the same expense as that which would have been recorded if LP&L
had not designated NOPSI as a participating employer. Pension costs are
allocated to NOPSI based on an evaluation determined by an independent actuary.
Effective June 6, 1990, LP&L's Waterford 3 nuclear employees became
employees of Entergy Operations. However, the employees still remain under
LP&L's plan, and no transfers of related pension liabilities and assets have
been made.
LP&L's 1993, 1992, and 1991 pension cost, including amounts capitalized,
included the following components:
For the Years Ended December 31,
--------------------------------
1993 1992 1991
------- ------ ------
(In Thousands)
Service cost - benefits earned during the period $4,900 $4,307 $4,102
Interest cost on projected benefit obligation 14,684 14,110 13,121
Actual return on plan assets (26,533) (14,329) (38,644)
Net amortization and deferral 8,712 (3,113) 21,940
Other - - 559
------- ------ -------
Net pension cost $1,763 $ 975 $1,078
======= ====== ======
The funded status of LP&L's pension plan as of December 31, 1993 and 1992,
was (excluding amounts allocable to NOPSI):
1993 1992
-------- --------
(In Thousands)
Actuarial present value of accumulated pension plan benefits:
Vested $179,049 $160,001
Nonvested 768 558
-------- --------
Accumulated benefit obligation $179,817 $160,559
======== ========
Plan assets at fair value $224,203 $209,667
Projected benefit obligation 211,928 183,985
-------- --------
Plan assets in excess of projected benefit obligation 12,275 25,682
Unrecognized prior service cost 6,257 6,723
Unrecognized transition asset (22,460) (25,268)
Unrecognized net gain (5,734) (15,036)
-------- --------
(9,662) (7,899)
Unfunded portion of NOPSI pension liability (12,256) (23,161)
-------- --------
Accrued pension liability $(21,918) $(31,060)
======== ========
The significant actuarial assumptions used in computing the information
above for 1993, 1992, and 1991 were as follows: weighted average discount rate,
7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in
future compensation levels, 5.6%; and expected long-term rate of return on plan
assets, 8.5%. Transition assets are being amortized over 15 years.
Other Postretirement Benefits
LP&L also provides certain health care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits if they reach retirement age while still working for LP&L. The cost of
providing these benefits, recorded on a cash basis, to retirees in 1992 was
approximately $3.7 million. Prior to 1992, the cost of providing these benefits
for retirees was not separable from the cost of providing benefits for active
employees. Based on the ratio of the number of retired employees to the total
number of active and retired employees in 1991, the cost of providing these
benefits in 1991, recorded on a cash basis, for retirees was approximately $3.5
million.
Effective January 1, 1993, LP&L adopted SFAS 106. The new standard
requires a change from a cash method to an accrual method of accounting for
postretirement benefits other than pensions. LP&L continues to fund these
benefits on a pay-as-you-go basis. As of January 1, 1993, the actuarially
determined accumulated postretirement benefit obligation (APBO) earned by
retirees and active employees was estimated to be approximately $59.4 million.
This obligation is being amortized over a 20-year period beginning in 1993.
The LPSC ordered LP&L to use the pay-as-you-go method for ratemaking
purposes for postretirement benefits other than pensions, but the LPSC retains
the flexibility to examine individual companies' accounting for postretirement
benefits to determine if special exceptions to this order are warranted. LP&L's
net income in 1993 was decreased by approximately $4.2 million as a result of
adopting SFAS 106.
LP&L's 1993 postretirement benefit cost, including amounts capitalized and
deferred, included the following components (in thousands):
Service cost - benefits earned during the period $2,083
Interest cost on APBO 4,749
Actual return on plan assets -
Amortization of transition obligation 2,971
------
Net periodic postretirement benefit cost $9,803
======
The funded status of LP&L's postretirement plan as of December 31, 1993,
was as follows (in thousands):
Accumulated postretirement benefit obligation:
Retirees $41,769
Other fully eligible participants 6,825
Other active participants 21,085
-------
69,679
Plan assets at fair value -
-------
Plan assets less than APBO (69,679)
Unrecognized transition obligation 56,459
Unrecognized net loss 7,579
-------
Accrued post retirement benefit liability $(5,641)
=======
The assumed health care cost trend rate used in measuring the APBO was 9.9%
for 1994, gradually decreasing each successive year until it reaches 5.6% in
2020. A one percentage-point increase in the assumed health care cost trend
rate for each year would have increased the APBO as of December 31, 1993, by
9.1% and the sum of the service cost and interest cost by approximately 11.8%.
The assumed discount rate and rate of increase in future compensation used in
determining the APBO were 7.5% and 5.5%, respectively.
NOTE 11. TRANSACTIONS WITH AFFILIATES
LP&L buys electricity from and/or sells electricity to AP&L, MP&L, NOPSI,
and System Energy under rate schedules filed with FERC. In addition, LP&L
purchases fuel from System Fuels, receives technical and advisory services from
Entergy Services, Inc. and receives operating services from Entergy Operations.
Operating revenues include revenues from sales to affiliates amounting to
$4.8 million in 1993, $5.5 million in 1992, and $0.2 million in 1991.
Operating expenses include charges from affiliates for fuel costs, purchased
power and related charges, management services, and technical and advisory
services totaling $322 million in 1993, $314.3 million in 1992, and $327.9
million in 1991. LP&L pays directly or reimburses Entergy Operations for the
costs associated with operating Waterford 3 (excluding nuclear fuel), which were
approximately $118.9 million in 1993, $152.1 million in 1992, and $151.1 million
in 1991.
NOTE 12. QUARTERLY FINANCIAL DATA (UNAUDITED)
LP&L's business is subject to seasonal fluctuations with the peak period
occurring during the third quarter. Operating results for the four quarters of
1993 and 1992 were:
Operating Operating Net
Revenues Income Income
--------- --------- -------
(In Thousands)
1993:
First Quarter $357,856 $ 56,875 $25,733
Second Quarter $399,570 $ 79,472 $46,932
Third Quarter $545,487 $124,789 $92,287
Fourth Quarter $426,753 $ 60,476 $23,856
1992:
First Quarter $336,588 $ 59,585 $25,366
Second Quarter $364,694 $ 81,679 $46,560
Third Quarter $464,975 $116,797 $82,627
Fourth Quarter $387,488 $ 60,219 $28,436
LOUISIANA POWER & LIGHT COMPANY
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
(In Thousands)
Operating revenues $1,729,666 $1,553,745 $1,528,934 $1,485,572 $1,426,806
Net income $ 188,808 $ 182,989 $ 166,572 $ 155,049 $ 106,613
Total assets $4,463,998 $4,109,148 $4,131,751 $4,262,124 $4,280,474
Long-term obligations (1) $1,611,436 $1,622,909 $1,582,606 $1,867,369 $1,915,286
(1) Includes long-term debt (excluding currently maturing debt),
preferred stock with sinking fund, and noncurrent capital lease
obligations.
See Notes 3 and 10 for the effect of accounting changes in 1993.
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
(Dollars in Thousands)
Operating Revenues:
Residential $572,738 $518,255 $525,594 $520,800 $496,800
Commercial 345,254 320,688 318,613 314,700 305,600
Industrial 652,574 578,741 558,036 532,800 541,200
Governmental 29,723 27,780 28,303 26,500 25,800
---------- ---------- ---------- ---------- ----------
Total retail 1,600,289 1,445,464 1,430,546 1,394,800 1,369,400
Sales for resale 49,388 38,632 31,997 41,800 38,100
Other 79,989 69,649 66,391 49,000 19,300
---------- ---------- ---------- ---------- ----------
Total $1,729,666 $1,553,745 $1,528,934 $1,485,600 $1,426,800
========== ========== ========== ========== ==========
Billed Electric Energy
Sales (Millions of KWH):
Residential 7,368 6,996 7,182 7,169 6,865
Commercial 4,435 4,307 4,367 4,299 4,175
Industrial 15,914 15,013 14,832 14,170 14,025
Governmental 398 385 405 382 369
---------- ---------- ---------- ---------- ----------
Total retail 28,115 26,701 26,786 26,020 25,434
Sales for resale 1,325 1,305 1,201 1,149 1,014
---------- ---------- ---------- ---------- ----------
Total 29,440 28,006 27,987 27,169 26,448
========== ========== ========== ========== ==========
Mississippi Power & Light Company
1993 Financial Statements
MISSISSIPPI POWER & LIGHT COMPANY
DEFINITIONS
Certain abbreviations or acronyms used in MP&L's Financial Statements,
Notes to Financial Statements, and Management's Financial Discussion and
Analysis are defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
AP&L Arkansas Power & Light Company
Entergy or System Entergy Corporation and its various direct and indirect
subsidiaries
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Final Order on
Rehearing An order issued by the MPSC on September 16, 1985,
with respect to MP&L's Grand Gulf 1-related rate issues
G&R Bonds General and Refunding Mortgage Bonds issued and
issuable under MP&L's G&R Mortgage dated as of
February 1, 1988, as amended
G&R Mortgage General and Refunding Mortgage established by MP&L
effective February 1, 1988, to provide for issuances of
G&R Bonds
Grand Gulf Station Grand Gulf Steam Electric Generating Station
Grand Gulf 1 Unit No. 1 of the Grand Gulf Station
Grand Gulf 2 Unit No. 2 of the Grand Gulf Station
GSU Gulf States Utilities Company (including wholly owned
subsidiaries - Varibus Corporation, GSG&T, Inc.,
Prudential Oil and Gas, Inc., and Southern Gulf Railway
Company)
Independence Station Independence Steam Electric Generating Station
KWH Kilowatt-Hours
LP&L Louisiana Power & Light Company
MWH Megawatt-Hours
Merger The combination transaction, consummated on December
31, 1993, by which GSU became a subsidiary of Entergy
Corporation and Entergy Corporation became a Delaware
Corporation
Money Pool Entergy Money Pool, which allows certain System
companies to borrow from, or lend to, certain other
System companies
MP&L Mississippi Power & Light Company
MPSC Mississippi Public Service Commission
NOPSI New Orleans Public Service Inc.
OBRA Omnibus Budget Reconciliation Act of 1993
Revised Plan MP&L's Grand Gulf 1-related rate phase-in plan,
originally approved by the MPSC in the Final Order on
Rehearing, as modified by the MPSC order issued
September 29, 1988, to bring such plan into compliance
with the requirements of SFAS No. 92
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards promulgated
by the FASB
SFAS 106 SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions"
SFAS 109 SFAS No. 109, "Accounting for Income Taxes"
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System or Entergy Entergy Corporation and its various direct and indirect
subsidiaries
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively
MISSISSIPPI POWER & LIGHT COMPANY
REPORT OF MANAGEMENT
The management of Mississippi Power & Light Company has prepared and is
responsible for the financial statements and related financial information
included herein. The financial statements are based on generally accepted
accounting principles. Financial information included elsewhere in this report
is consistent with the financial statements.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting controls that
is designed to provide reasonable assurance, on a cost-effective basis, as to
the integrity, objectivity, and reliability of the financial records, and as to
the protection of assets. This system includes communication through written
policies and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and the
training of personnel. This system is also tested by a comprehensive internal
audit program.
The independent public accountants provide an objective assessment of the
degree to which management meets its responsibility for fairness of financial
reporting. They regularly evaluate the system of internal accounting controls
and perform such tests and other procedures as they deem necessary to reach and
express an opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide reasonable
assurance that its operations are carried out with a high standard of business
conduct.
/S/ EDWIN LUPBERGER /S/ GERALD D. MCINVALE
EDWIN LUPBERGER GERALD D. MCINVALE
Chairman and Chief Executive Officer Senior Vice President and
Chief Financial Officer
MISSISSIPPI POWER & LIGHT COMPANY
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Mississippi Power & Light Company Audit Committee of the Board of
Directors is comprised of four directors, who are not officers of MP&L: John O.
Emmerich, Jr. (Chairman), John N. Palmer, Sr., Dr. Clyda S. Rent, and Robert M.
Williams, Jr. The committee held four meetings during 1993.
The Audit Committee oversees MP&L's financial reporting process on behalf
of the Board of Directors and provides reasonable assurance to the Board that
sufficient operating, accounting, and financial controls are in existence and
are adequately reviewed by programs of internal and external audits.
The Audit Committee discussed with Entergy's internal auditors and the
independent public accountants (Deloitte & Touche) the overall scope and
specific plans for their respective audits, as well as MP&L's financial
statements and the adequacy of MP&L's internal controls. The committee met,
together and separately, with Entergy's internal auditors and independent public
accountants, without management present, to discuss the results of their audits,
their evaluation of MP&L's internal controls, and the overall quality of MP&L's
financial reporting. The meetings also were designed to facilitate and
encourage any private communication between the committee and the internal
auditors or independent public accountants.
/S/ JOHN O. EMMERICH
JOHN O. EMMERICH
Chairman, Audit Committee
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of
Mississippi Power & Light Company
We have audited the accompanying balance sheets of Mississippi Power &
Light Company (MP&L) as of December 31, 1993 and 1992, and the related
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1993. These financial statements are the
responsibility of MP&L's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of MP&L at December 31, 1993 and 1992, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1993 in conformity with generally accepted accounting
principles.
As discussed in Note 1 to the financial statements, MP&L changed its method
of accounting for revenues in 1993 and, as discussed in Notes 3 and 9 to the
financial statements, in 1993 MP&L changed its methods of accounting for income
taxes and postretirement benefits other than pensions, respectively.
/S/ DELOITTE & TOUCHE
DELOITTE & TOUCHE
New Orleans, Louisiana
February 11, 1994
MISSISSIPPI POWER & LIGHT COMPANY
BALANCE SHEETS
ASSETS
December 31,
-----------------------
1993 1992
---------- ----------
(In Thousands)
Utility Plant (Note 1):
Electric $1,389,229 $1,364,464
Construction work in progress 62,699 25,879
---------- ----------
Total 1,451,928 1,390,343
Less - accumulated depreciation and amortization 577,728 549,150
---------- ----------
Utility plant - net 874,200 841,193
---------- ----------
Other Property and Investments:
Investment in subsidiary company - at equity (Note 8) 5,531 5,531
Other 4,760 4,382
---------- ----------
Total 10,291 9,913
---------- ----------
Current Assets:
Cash and cash equivalents (Note 1):
Cash 7,999 3,438
Temporary cash investments - at cost,
which approximates market:
Associated companies (Note 4) - 2,356
Other - 28,214
---------- ----------
Total cash and cash equivalents 7,999 34,008
Notes receivable (Note 1) 7,118 7,405
Accounts receivable:
Customer (less allowance for doubtful accounts of
$2.5 million in 1993 and $1.3 million in 1992) 33,155 29,284
Associated companies (Note 10) 7,342 3,605
Other 3,672 4,718
Accrued unbilled revenues (Note 1) 57,414 -
Fuel inventory - at average cost 8,652 7,325
Materials and supplies - at average cost 20,886 21,472
Rate deferrals (Note 2) 96,935 72,816
Prepayments and other 13,763 1,354
---------- ----------
Total 256,936 181,987
---------- ----------
Deferred Debits and Other Assets:
Rate deferrals (Note 2) 504,428 600,102
Notes receivable (Note 1) 9,951 15,739
Other 20,931 11,792
---------- ----------
Total 535,310 627,633
---------- ----------
TOTAL $1,676,737 $1,660,726
========== ==========
See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
-----------------------
1993 1992
---------- ----------
(In Thousands)
Capitalization:
Common stock, no par value, authorized 15,000,000
shares; issued and outstanding 8,666,357 shares in
1993 and 1992 (Note 5) $199,326 $199,326
Capital stock expense and other (1,864) (2,716)
Retained earnings (Note 7) 236,337 230,201
---------- ----------
Total common shareholder's equity 433,799 426,811
Preferred stock (Note 5):
Without sinking fund 57,881 57,881
With sinking fund 46,770 63,270
Long-term debt (Note 6) 516,156 512,675
---------- ----------
Total 1,054,606 1,060,637
---------- ----------
Other Noncurrent Liabilities:
Obligations under capital leases 686 842
Other 6,231 2,946
---------- ----------
Total 6,917 3,788
---------- ----------
Current Liabilities:
Currently maturing long-term debt (Note 6) 48,250 55,230
Notes payable - associated companies 11,568 -
Accounts payable:
Associated companies (Note 10) 29,181 27,634
Other 12,157 8,649
Customer deposits 21,474 20,460
Taxes accrued 24,252 28,452
Accumulated deferred income taxes (Note 3) 41,758 31,842
Interest accrued 23,171 22,391
Dividends declared 1,985 2,472
Obligations under capital leases 156 151
Other 17,147 7,745
---------- ----------
Total 231,099 205,026
---------- ----------
Deferred Credits:
Accumulated deferred income taxes (Note 3) 311,616 346,107
Accumulated deferred investment tax
credits (Note 3) 37,193 36,999
SFAS 109 regulatory liability - net (Note 3) 23,626 -
Other 11,680 8,169
---------- ----------
Total 384,115 391,275
---------- ----------
Commitments and Contingencies (Note 8)
TOTAL $1,676,737 $1,660,726
========== ==========
See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
--------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Operating Activities:
Net income $101,743 $65,036 $63,088
Noncash items included in net income:
Cumulative effect of a change in accounting principle (32,706) - -
Change in rate deferrals (Note 2) 71,555 17,530 14,626
Depreciation and amortization 32,152 31,493 30,089
Deferred income taxes and investment tax credits (17,881) 18,685 30,857
Allowance for equity funds used during construction (928) (668) (1,302)
Changes in working capital:
Receivables (11,814) (924) (3,743)
Fuel inventory (1,327) 2,061 (2,577)
Accounts payable 5,055 (14,365) (3,255)
Taxes accrued (4,200) 2,174 640
Interest accrued 780 105 (2,712)
Other working capital accounts (1,120) 1,918 230
Other 8,073 (4,272) 2,564
-------- -------- --------
Net cash flow provided by operating activities 149,382 118,773 128,505
-------- -------- --------
Investing Activities:
Construction expenditures (66,404) (53,481) (58,368)
Allowance for equity funds used during construction 928 668 1,302
-------- -------- --------
Net cash flow used in investing activities (65,476) (52,813) (57,066)
-------- -------- --------
Financing Activities:
Proceeds from issuance of:
General and refunding bonds 250,000 65,000 -
Common stock - 25,000 -
Preferred stock - 19,777 -
Retirement of:
First mortgage bonds (204,501) (101,416) -
General and refunding bonds (55,000) - -
Other long-term debt (230) (210) (200)
Redemption of preferred stock (16,500) (9,500) (9,500)
Dividends paid:
Common stock (85,800) (68,400) (7,847)
Preferred stock (9,452) (9,445) (10,322)
Changes in short-term borrowings 11,568 - (3,000)
-------- -------- --------
Net cash flow used in financing activities (109,915) (79,194) (30,869)
-------- -------- --------
Net increase (decrease) in cash and cash equivalents (26,009) (13,234) 40,570
Cash and cash equivalents at beginning of period 34,008 47,242 6,672
-------- -------- --------
Cash and cash equivalents at end of period $7,999 $34,008 $47,242
======== ======= ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $52,459 $62,727 $69,548
Income taxes $58,831 $14,866 $2,108
See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is important to MP&L due to the capital intensive nature of our
business, which requires large investments in long-lived assets. However, large
capital expenditures for the construction of new generating capacity are not
currently planned. MP&L also requires significant capital resources for the
periodic maturity of certain series of debt and preferred stock. Net cash flow
from operations totaled $149 million, $119 million, and $129 million in 1993,
1992, and 1991, respectively. In recent years, this cash flow, supplemented by
cash on hand and issuances of debt and common and preferred stock, has been
sufficient to meet substantially all investing and financing requirements,
including capital expenditures, dividends, and debt/preferred stock maturities.
MP&L's ability to fund these capital requirements results, in part, from our
continued efforts to streamline operations and reduce costs, as well as
collections under our Grand Gulf 1 rate phase-in plan, which exceed the current
cash requirements for Grand Gulf 1-related costs. (In the income statement,
these revenue collections are offset by the amortization of previously deferred
costs, therefore, there is no effect on net income.) See Note 2, incorporated
herein by reference, for additional information on MP&L's rate phase-in plan.
See Note 8, incorporated herein by reference, for additional information on
MP&L's capital and refinancing requirements in 1994 - 1996. Also, in order to
take advantage of lower interest and dividend rates, MP&L may continue to
refinance high-cost debt and preferred stock prior to maturity.
Earnings coverage tests (which are impacted by the inclusion of the
cumulative effect of the change in accounting principle for accruing unbilled
revenues discussed in Note 1), bondable property additions, and accumulated
deferred Grand Gulf 1-related costs recorded as assets, limit the G&R Bonds and
preferred stock that MP&L can issue. Based on the most restrictive applicable
tests as of December 31, 1993 and assuming an annual interest or dividend rate
of 8%, MP&L could have issued $219 million of additional G&R Bonds or
$548 million of additional preferred stock. Further, MP&L has the conditional
ability to issue G&R Bonds against the retirement of bonds, in some cases
without satisfying an earnings coverage test.
See Notes 5 and 6, incorporated herein by reference, for information on
MP&L's financing activities and Note 4, incorporated herein by reference, for
information on MP&L's short-term borrowings and lines of credit.
MISSISSIPPI POWER & LIGHT COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31,
----------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Operating Revenues (Notes 1, 2, and 10): $895,806 $817,650 $754,632
-------- -------- --------
Operating Expenses:
Operation (Note 10):
Fuel for electric generation and fuel-related
expenses 140,391 112,032 104,553
Purchased power 289,016 301,912 284,868
Other 110,301 104,287 98,884
Maintenance 46,104 42,153 37,660
Depreciation and amortization 32,152 31,493 30,089
Taxes other than income taxes 41,878 40,738 37,534
Income taxes (Note 3) 33,074 21,681 29,936
Rate deferrals (Note 2):
Rate deferrals - (22,876) (53,333)
Amortization of rate deferrals 77,570 61,456 58,480
-------- -------- --------
Total 770,486 692,876 628,671
-------- -------- --------
Operating Income 125,320 124,774 125,961
-------- -------- --------
Other Income (Deductions):
Allowance for equity funds used during
construction 928 668 1,302
Miscellaneous - net 948 4,562 1,525
Income taxes - (debit) (Note 3) (3,462) (1,467) 81
-------- -------- --------
Total (1,586) 3,763 2,908
-------- -------- --------
Interest Charges:
Interest on long-term debt 52,100 60,709 63,628
Other interest - net 3,260 3,357 4,013
Allowance for borrowed funds used during
construction (663) (565) (1,860)
-------- -------- --------
Total 54,697 63,501 65,781
-------- -------- --------
Income before Cumulative Effect of a Change
in Accounting Principle 69,037 65,036 63,088
Cumulative Effect to January 1, 1993, of Accruing
Unbilled Revenues (net of income taxes of
$19,456) (Note 1) 32,706 - -
-------- -------- --------
Net Income 101,743 65,036 63,088
Preferred Stock Dividend Requirements 9,160 9,513 10,074
-------- -------- --------
Earnings Applicable to Common Stock $92,583 $55,523 $53,014
======== ======== ========
See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
----------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Retained Earnings, January 1 $230,201 $243,819 $199,393
Add:
Net income 101,743 65,036 63,088
-------- -------- --------
Total 331,944 308,855 262,481
-------- -------- --------
Deduct:
Dividends declared:
Preferred stock 8,964 9,513 10,074
Common stock 85,800 68,400 7,847
Preferred stock expenses 843 741 741
-------- -------- --------
Total 95,607 78,654 18,662
-------- -------- --------
Retained Earnings, December 31 (Note 7) $236,337 $230,201 $243,819
======== ======== ========
See Notes to Financial Statements.
MISSISSIPPI POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income increased in 1993 due primarily to the one-time recording of the
cumulative effect of the change in accounting principle for unbilled revenues
(see Note 1, incorporated herein by reference) and its ongoing effects,
partially offset by the effects of implementing SFAS 109 and SFAS 106 (see Notes
3 and 9, incorporated herein by reference). Effective January 1, 1993, MP&L
began accruing as revenues the charges for energy delivered to customers but not
yet billed. Electric revenues were previously recorded on a cycle-billing
basis. Excluding the above mentioned items, net income for 1993 would have been
$71.9 million. This $6.9 million increase is due primarily to an increase in
retail energy sales and a decrease in interest expense from the refinancing of
high-cost debt. Net income increased in 1992 due primarily to increased
operating revenues and decreased interest expense and income tax expense,
partially offset by increased maintenance expense.
Significant factors affecting the results of operations and causing
variances between the years 1993 and 1992, and 1992 and 1991, are discussed
under "Revenues and Sales," "Expenses," and "Other" below.
Revenues and Sales
See "Selected Financial Data - Five-Year Comparison," incorporated herein
by reference, following the notes, for information on operating revenues by
source and KWH sales.
Electric operating revenues were higher in 1993 due to increased
residential and commercial energy sales resulting primarily from a return to
more normal weather as compared to milder weather in 1992. Industrial energy
sales also increased due to higher sales to the rubber and plastics, petroleum
refining, and petroleum pipelines sectors. Sales for resale to associated
companies were higher due to changes in generation availability and requirements
among AP&L, LP&L, MP&L, and NOPSI . Additionally, electric operating revenues
increased due to increased fuel adjustment revenues and increased collections of
previously deferred Grand Gulf 1-related costs, neither of which affects net
income. These increases were partially offset by a decrease in other revenue
related to MP&L's rate deferral over/under recovery which reflects adjustments
for the difference between actual and estimated costs, and does not affect net
income.
Electric operating revenues were higher in 1992 resulting from an increase
in other revenue related to MP&L's rate deferral over/under recovery and an
increase in retail operating revenues due to lower fuel adjustment credits.
Neither of these revenue fluctuations affected net income. Revenues from sales
for resale were higher in 1992 resulting from the September 1991 one-time intra-
system equalization billing adjustment. (Certain 1985-1991 intra-system
equalization billings under the System Agreement were adjusted in 1991, reducing
operating revenues by approximately $10.6 million.) While total energy sales
were relatively flat in 1992, increased sales for resale to nonassociated
companies, resulting from changes in generation availability and requirements
among AP&L, LP&L, MP&L, and NOPSI, were offset by lower retail sales resulting
from milder temperatures.
Expenses
Fuel for electric generation and fuel-related expenses increased in 1993
due primarily to an increase in generation requirements resulting primarily from
increased energy sales, as discussed in "Revenues and Sales" above, and
increased fuel costs. Rate deferrals decreased in 1993 and 1992 as the deferral
period for MP&L's phase-in plan for Grand Gulf 1-related costs ended in 1992.
Further, the amortization of rate deferrals increased in 1993 reflecting the
fact that MP&L, based on the Revised Plan, collected more Grand Gulf 1-related
costs from its customers in 1993 than it recovered in 1992.
Maintenance expense was higher in 1993 and 1992 due primarily to an
increase in scheduled maintenance at MP&L's power plants. Total income taxes
increased in 1993 due to the effect of higher pretax income, an increase in the
federal income tax rate as a result of OBRA, and the effect of implementing SFAS
109. Total income taxes were lower in 1992 due primarily to an increase in
estimated income tax benefits related to tax depreciation resulting from certain
elections made in 1991.
Other
Miscellaneous other income - net increased in 1992 due primarily to interest
income in connection with the settlement of deferred coal charges from System
Fuels. Interest on long-term debt decreased in 1993 due primarily to the
continued refinancing of high-cost debt.
MISSISSIPPI POWER & LIGHT COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Competition
MP&L welcomes competition in the electric energy business and believes that
a more competitive environment should benefit our customers, employees, and
shareholders of Entergy Corporation. We also recognize that competition
presents us with many challenges, and we have identified the following as our
major competitive challenges:
Retail and Wholesale Rate Issues
Increasing competition in the utility industry brings an increased need to
stabilize or reduce retail rates. The retail regulatory environment is shifting
from traditional rate-base regulation to incentive-rate regulation. Incentive-
rate and performance-based plans encourage efficiencies and productivity while
permitting utilities to share in the results. In February 1994, the MPSC
conducted a general review of MP&L's current rates and in March 1994, the MPSC
issued a final order adopting a formula rate plan for MP&L that will allow for
periodic small adjustments in rates based on a comparison of earned to benchmark
returns and upon certain performance factors. The order also adopted previously
agreed-upon stipulations of 1) a required return on equity of 11% and 2) certain
accounting adjustments that result in a 4.3% ($28.1 million) reduction in MP&L's
June 30, 1993, test-year operating revenues. The MPSC's order requires MP&L to
file rates designed to provide for this reduction in operating revenues for the
test year on or before March 18, 1994, to become effective for service rendered
on or after March 25, 1994. See Note 2, incorporated herein by reference, for
further information.
Further in connection with the Merger, MP&L agreed with its retail
regulator not to request any general retail rate increases or implement
increases under the incentive plan that would take effect before November 1998,
with certain exceptions. See Note 2, incorporated herein by reference, for
further information.
Retail wheeling, a major industry issue which may require utilities to
"wheel" or move power from third parties to their own retail customers, is
evolving gradually. As a result, the retail market could become more
competitive.
In the wholesale rate area, FERC approved in 1992, with certain
modifications, the proposals of AP&L, LP&L, MP&L, NOPSI and Entergy Power, Inc.
to sell wholesale power at market-based rates and to provide to electric
utilities "open access" to the System's transmission system (subject to certain
requirements). GSU was later added to the filing. Various intervenors in the
proceeding filed petitions for review with the United States Court of Appeals
for the District of Columbia Circuit. FERC's order, once it takes effect, will
increase marketing opportunities for MP&L, but will also expose MP&L to the risk
of loss of load or reduced revenues due to competition with alternative
suppliers.
In light of the rate issues discussed above, MP&L is aggressively reducing
costs to avoid potential earnings erosions that might result as well as to
successfully compete by becoming a low-cost producer. To help minimize future
costs, MP&L remains committed to least cost planning. In December 1992, MP&L
filed a Least Cost Integrated Resource Plan (Least Cost Plan) with its retail
regulator. Least cost planning includes demand-side measures such as customer
energy conservation and supply-side measures such as more efficient power
plants. These measures are designed to delay the building of new power plants
for the next 20 years. MP&L plans to periodically file revised Least Cost
Plans.
The Energy Policy Act of 1992
The Energy Policy Act of 1992 (Energy Act) is changing the transmission and
distribution of electricity. This act encourages competition and affords us the
opportunities, and the risks, associated with an open and more competitive
market environment. The Energy Act increases competition in the wholesale
energy market through the creation of exempt wholesale generators (EWGs). The
Energy Act also gives FERC the authority to order investor-owned utilities to
provide transmission access to or for other utilities, including EWGs.
MISSISSIPPI POWER & LIGHT COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
MP&L maintains accounts in accordance with FERC and other regulatory
guidelines. Certain previously reported amounts have been reclassified to
conform to current classifications.
Revenues and Fuel Costs
Prior to January 1, 1993, MP&L recorded revenues when billed to its
customers with no accrual for energy delivered but not yet billed. To provide a
better matching of revenues and expenses, effective January 1, 1993, MP&L
adopted a change in accounting principle to provide for accrual of estimated
unbilled revenues. The cumulative effect of this accounting change as of
January 1, 1993, increased net income by $32.7 million. Had this new accounting
method been in effect during prior years, net income before the cumulative
effect would not have been materially different from that shown in the
accompanying financial statements.
MP&L's rate schedules include fuel adjustment clauses that allow current
recovery of estimated fuel costs, with subsequent adjustments of estimates to
actual.
Utility Plant
Utility plant is stated at original cost. The original cost of utility
plant retired or removed, plus the applicable removal costs, less salvage, is
charged to accumulated depreciation. Maintenance, repairs, and minor
replacement costs are charged to operating expenses. Substantially all of
MP&L's utility plant is subject to the lien of its first mortgage bond indenture
and the second lien of its G&R Mortgage bond indenture.
AFUDC represents the approximate net composite interest cost of borrowed
funds and a reasonable return on the equity funds used for construction.
Although AFUDC increases utility plant and increases earnings, it is only
realized in cash through depreciation provisions included in rates. MP&L's
effective composite rates for AFUDC were 11.8%, 12.0%, and 10.4% for 1993, 1992,
and 1991, respectively.
Depreciation is computed on the straight-line basis at rates based on the
estimated service lives and costs of removal of the various classes of property.
Depreciation provisions on average depreciable property approximated 2.4% in
1993, 2.5% in 1992, and 2.4% in 1991.
Jointly-Owned Generating Station
MP&L owns 25% of the Independence Station, a two-unit, coal -fired
generating station located near Newark, Arkansas. The total capability of
Independence Station is 528 megawatts. MP&L records its investment in and
expenses associated with this station to the extent of its ownership and
participation. MP&L's investment in the Independence Station was approximately
$219.8 million less accumulated depreciation of approximately $67.3 million as
of December 31, 1993.
Notes Receivable
MP&L currently has a program, wherein it finances heat pumps for its
customers through notes receivable. Such notes are repayable in equal monthly
installments of principal and interest over a five-year period and bear interest
at a market-based rate at the time of sale. The amounts financed are classified
on its balance sheet as current and noncurrent notes receivable.
Income Taxes
MP&L, its parent, and affiliates (excluding GSU prior to 1994) file a
consolidated federal income tax return. Income taxes are allocated to MP&L in
proportion to its contribution to consolidated taxable income. SEC regulations
require that no System company pay more taxes than it would have had a separate
income tax return been filed. Deferred taxes are recorded for all temporary
differences between book and taxable income. Investment tax credits are
deferred and amortized based upon the average useful life of the related
property, in accordance with rate treatment. As discussed in Note 3, effective
January 1, 1993, MP&L changed its accounting for income taxes to conform with
SFAS 109.
In addition, MP&L files a consolidated Mississippi state income tax return
with certain other System companies.
Cash and Cash Equivalents
MP&L considers all unrestricted highly liquid debt instruments purchased
with an original maturity of three months or less to be cash equivalents.
Fair Value Disclosure
The estimated fair value amounts of financial instruments have been
determined by MP&L, using available market information and appropriate valuation
methodologies. However, considerable judgment is required in developing the
estimates of fair value. Therefore, estimates are not necessarily indicative of
the amounts that MP&L could realize in a current market exchange. In addition,
gains or losses realized on financial instruments may be reflected in future
rates and not accrue to the benefit of stockholders.
MP&L considers the carrying amounts of financial instruments classified as
current assets and liabilities to be a reasonable estimate of their fair value
because of the short maturity of these instruments. In addition, MP&L does not
presently expect that performance of its obligations will be required in
connection with certain off-balance sheet commitments and guarantees considered
financial instruments. Due to this factor, and because of the related party
nature of these commitments and guarantees, determination of fair value is not
considered practicable. See Notes 5 and 6 for additional fair value disclosure.
NOTE 2. RATE AND REGULATORY MATTERS
Incentive Rate Plan
In July 1993, the MPSC ordered MP&L to file a formulary incentive rate plan
designed to allow for periodic small adjustments in rates based upon a
comparison of earned to benchmark returns and upon performance factors
incorporated in the plan. In November 1993, MP&L filed a formula rate plan
(Proposed Plan) with the MPSC to become effective on March 1, 1994, with any
initial adjustment to base rates in June 1994. Under the Proposed Plan, a
formula would be established under which MP&L's earned rate of return would be
calculated automatically every 12 months and compared to a benchmark rate of
return, which would be calculated under a separate formula within the Proposed
Plan. If MP&L's earned rate of return falls within a bandwidth around the
benchmark rate of return, there would be no adjustment in rates. If MP&L's
earnings are above the bandwidth, the Proposed Plan would automatically reduce
MP&L's base rates. Alternatively, if MP&L's earnings are below the bandwidth,
the Proposed Plan would automatically increase MP&L's base rates (subject to the
five-year rate cap described below). The reduction or increase in base rates
would be an amount representing 50% of the difference between the earned rate of
return and the nearest limit of the bandwidth. In no event would the annual
adjustment in rates exceed the lesser of 2% of MP&L's aggregate retail revenues,
or $14.5 million. Under the Proposed Plan, the benchmark rate of return, and
consequently the bandwidth, would be adjusted slightly upward or downward based
upon MP&L's performance on three performance factors: customer reliability,
customer satisfaction, and customer price.
Subsequently, the MPSC conducted a general review of MP&L's current rates
and later issued a final order adopting the Proposed Plan and previously agreed-
upon stipulations of 1) a required return on equity of 11% and 2) certain
accounting adjustments that result in a 4.3% ($28.1 million) reduction in MP&L's
June 30, 1993, test-year base revenues. The MPSC's order requires MP&L to file
rates designed to provide for this reduction in operating revenues for the test
year on or before March 18, 1994, to become effective for service rendered on or
after March 25, 1994.
Rate Agreement
In November 1993, MP&L and the MPSC entered into a settlement agreement
whereby the MPSC agreed to withdraw its request for hearings and its objections
in the SEC proceeding related to the Merger. MP&L agreed that MP&L's retail
ratepayers would be protected from (1) increases in MP&L's cost of capital
resulting from risks associated with the Merger; (2) recovery of any portion of
the acquisition premium or transactional costs associated with the Merger; (3)
certain direct allocations of costs associated with GSU's River Bend nuclear
unit; and (4) any losses of GSU resulting from resolution of litigation in
connection with its ownership of River Bend. In a related stipulation, MP&L
also agreed (a) that retail base rates under its proposed formula rate plan
would not be increased above November 1, 1993 levels, and (b) that MP&L would
not request any general retail rate increase that would increase retail rates
above the level of MP&L's rates in effect as of November 1, 1993, except, among
other things, for increases associated with the Least Cost Plan, recovery of
deferred Grand Gulf 1-related costs, recovery under the fuel adjustment clause,
adjustments for certain taxes, and force majeure (defined to include, among
other things, war, natural catastrophes, and high inflation), in each case for a
period of five years beginning November 9, 1993.
Grand Gulf 1
MP&L's Revised Plan provides, among other things, for the recovery by MP&L,
in equal annual installments over ten years beginning October 1, 1988, of all
Grand Gulf 1-related costs deferred through September 30, 1988 pursuant to the
Final Order on Rehearing. Additionally, the Revised Plan provided that MP&L
defer, in decreasing amounts, a portion of its Grand Gulf 1-related costs over
four years beginning October 1, 1988. These deferrals are being recovered by
MP&L over a six-year period beginning in October 1992 and ending in September
1998. The Revised Plan also allows for the current recovery of carrying charges
on all deferred amounts.
NOTE 3. INCOME TAXES
Effective January 1, 1993, MP&L adopted SFAS 109. This new standard
requires that deferred income taxes be recorded for all temporary differences
and carryforwards, and that deferred tax balances be based on enacted tax laws
at tax rates that are expected to be in effect when the temporary differences
reverse. SFAS 109 requires that regulated enterprises recognize adjustments
resulting from implementation as regulatory assets or liabilities if it is
probable that such amounts will be recovered from or returned to customers in
future rates. A substantial majority of the adjustments required by SFAS 109
was recorded to deferred tax balance sheet accounts with offsetting adjustments
to regulatory assets and liabilities. The cumulative effect of the adoption of
SFAS 109 is included in income tax expense charged to operations. As a result
of the adoption of SFAS 109, 1993 net income was reduced by $1.7 million, assets
were increased by $50.2 million, and liabilities were increased by $51.9
million.
Income tax expense consisted of the following:
For the Years Ended December 31,
--------------------------------
1993 1992 1991
------ ------ -------
(In Thousands)
Current:
Federal $46,744 $4,532 $(1,000)
State 7,673 (69) -
------- ------- -------
Total 54,417 4,463 (1,000)
------- ------- -------
Deferred - net:
Federal reclassification due to net - 28,561 29,756
operating loss
State reclassification due to net - 4,883 4,587
operating loss
Liberalized depreciation 5,293 9,448 8,565
Rate Deferral - net (31,317) (11,220) (10,137)
Unbilled revenue 21,373 (5,722) 1,207
Pension liability (647) (1,233) (157)
Adjustments of prior year taxes 4,299 (3,471) (84)
Bond reacquisition 3,208 264 (228)
Other (1,670) (1,079) (1,020)
------- ------- -------
Total 539 20,431 32,489
------- ------- -------
Investment tax credit adjustments - net 1,036 (1,746) (1,634)
------- ------- -------
Recorded income tax expense $55,992 $23,148 $29,855
======= ======= =======
Charged to operations $33,074 $21,681 $29,936
Charged (credited) to other income 3,462 1,467 (81)
Charged to cumulative effect 19,456 - -
------- ------- -------
Total income taxes $55,992 $23,148 $29,855
======= ======= =======
Total income taxes differ from the amounts computed by applying the
statutory federal income tax rate to income before taxes. The reasons for the
differences were:
For the Years Ended December 31,
--------------------------------------------------------
1993 1992 1991
----------------- ---------------- ----------------
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
------- -------- -------- ------- ------- -------
(Dollars in Thousands)
Computed at statutory rate $55,207 35.0 $29,983 34.0 $31,601 34.0
Increases (reductions) in tax resulting from:
State income taxes net of federal income
tax effect 3,253 2.0 2,703 3.1 3,175 3.4
Depreciation (5,890) (3.7) (2,571) (2.9) 944 1.0
Amortization of excess deferred income taxes (4,680) (3.0) (2,456) (2.8) (3,257) (3.5)
Amortization of investment tax credits (1,772) (1.1) (1,746) (2.0) (1,634) (1.8)
Adjustments of prior year taxes 5,228 3.3 (2,760) (3.2) (1,149) (1.2)
SFAS 109 adjustment 3,439 2.2 - - - -
Other - net 1,207 0.8 (5) - 175 0.2
------- ---- ------- ---- ------- ----
Total income taxes $55,992 35.5 $23,148 26.2 $29,855 32.1
======= ==== ======= ==== ======= ====
Significant components of MP&L's net deferred tax liabilities as of
December 31, 1993, were (in thousands):
Deferred tax liabilities:
Plant related basis differences $(166,650)
Rate deferrals (246,604)
Other (6,406)
---------
Total $(419,660)
=========
Deferred tax assets:
Net regulatory liabilities $9,411
Accumulated deferred investment tax credits 13,420
Recoverable income tax 13,854
Alternative minimum tax credit 1,192
Removal cost 10,725
Standard coal plant 4,854
Pension related items 2,488
Other 10,342
-------
Total $66,286
=======
Net deferred tax liabilities $(353,374)
=========
The alternative minimum tax (AMT) credit as of December 31, 1993, was
$1.2 million. This AMT credit can be carried forward indefinitely and will
reduce MP&L's federal income tax liability in future years.
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized MP&L to effect short-term borrowings up to
$100 million, subject to increase to as much as $113 million after further SEC
approval. These authorizations are effective through November 30, 1994. As of
December 31, 1993, MP&L had unused lines of credit for short-term borrowing of
$30 million from banks within its service territory. In addition, MP&L can
borrow from the Money Pool, subject to its maximum authorized level of
short-term borrowings and the availability of funds. MP&L's short-term
borrowings are limited by the terms of its G&R Mortgage to amounts not exceeding
the greater of 10% of capitalization or 50% of Grand Gulf 1 rate deferrals
available to support the issuance of G&R Bonds. MP&L had $11.6 million in
outstanding borrowings under the Money Pool arrangement as of December 31, 1993.
NOTE 5. PREFERRED AND COMMON STOCK
The number of shares and dollar value of MP&L's cumulative, $100 par value
preferred stock was:
As of December 31,
----------------------------------------
Shares Call Price Per
Authorized and Total Share as of
Outstanding Dollar Value December 31,
1993 1992 1993 1992 1993
------- ------- ------- -------- -----------
(Dollars in Thousands)
Without sinking fund:
4.36% Series 59,920 59,920 $5,992 $5,992 $103.86
4.56% Series 43,888 43,888 4,389 4,389 $107.00
4.92% Series 100,000 100,000 10,000 10,000 $102.88
7.44% Series 100,000 100,000 10,000 10,000 $102.81
8.36% Series 200,000 200,000 20,000 20,000 -
9.16% Series 75,000 75,000 7,500 7,500 $104.06
-------- -------- ------- -------
Total without sinking fund 578,808 578,808 $57,881 $57,881
======== ======== ======= =======
With sinking fund:
9.00% Series 140,000 210,000 $14,000 $21,000 $106.75
9.76% Series 280,000 350,000 28,000 35,000 $103.26
12.00% Series 47,700 57,700 4,770 5,770 $106.00
16.16% Series - 15,000 - 1,500 -
-------- -------- ------- -------
Total with sinking fund 467,700 632,700 $46,770 $63,270
======== ======== ======= =======
The fair value of MP&L's preferred stock with sinking fund was estimated to
be approximately $49.3 million and $66.2 million as of December 31, 1993 and
1992, respectively. The fair value was determined using quoted market prices or
estimates from nationally recognized investment banking firms. See Note 1 for
additional information on disclosure of fair value of financial instruments.
As of December 31, 1993, MP&L had 175,000 shares of cumulative, $100 par
value preferred stock that were authorized but unissued. On February 4, 1994,
MP&L amended its charter authorizing 1,500,000 additional shares of $100 par
value preferred stock.
Changes in the common stock and preferred stock, with and without sinking
fund, during the last three years were:
Number of Shares
-------------------------------
1993 1992 1991
-------- --------- -------
Common stock issuances($23 issuance price) - 1,086,957 -
Preferred stock issuances: - 200,000 -
Preferred stock retirements: (165,000) (95,000) (95,000)
Cash sinking fund requirements for the next five years for preferred stock
outstanding as of December 31, 1993, are (in thousands): 1994 - $14,500; 1995 -
$14,500; 1996 - $7,500; 1997 - $7,500; and 1998 - $500. MP&L has the annual
non-cumulative option to redeem at par, additional amounts of its 12.00% series
preferred stock outstanding.
MP&L has SEC authorization for the issuance and sale through December 31,
1995, of up to $70 million of preferred stock (of which $50 million remained
available as of December 31, 1993), and for the possible acquisition, in whole
or in part, of not more than $50 million aggregate par value of MP&L's
outstanding preferred stock, including but not limited to the 12.00% Series and
the 9.76% Series. The proceeds of any sales of preferred stock would be used
for the refinancing of higher cost of debt and preferred stock and general
corporate purposes.
NOTE 6. LONG-TERM DEBT
The long-term debt of MP&L as of December 31, 1993 and 1992, was:
Maturities Interest Rates
From To From To 1993 1992
-------- ---------
(In Thousands)
First Mortgage Bonds
1994 1998 4-5/8% 6-3/8% $55,000 $55,000
1999 2003 7-3/4% 9-5/8% - 102,500
2004 2008 9-7/8% - 25,000
2014 2018 9-5/8% - 70,000
G&R Bonds
1993 1997 5.95% 14.95%* 215,000 270,000
2003 2023 6-5/8% 8.65% 250,000 -
Governmental Obligations**
1992 2008 7-1/2% 8-1/2% 17,925 18,155
2012 2014 9% 9-1/2% 30,000 30,000
Unamortized Premium and Discount-Net (3,519) (2,750)
-------- --------
Total Long-Term Debt 564,406 567,905
Less Amount Due Within One Year 48,250 55,230
-------- --------
Long-Term Debt Excluding Amount Due Within One Year $516,156 $512,675
======== ========
* The 14.95% series of $20 million is due 2/1/95. All other series are at
interest rates within the range of 5.95% - 11.2%.
** Consists of pollution control revenue bonds, certain series of which are
secured by non-interest bearing first mortgage bonds.
The fair value of MP&L's long-term debt as of December 31, 1993 and 1992,
was estimated to be $594.0 million and $595.0 million, respectively. The fair
value was determined using quoted market prices or estimates from nationally
recognized investment banking firms. See Note 1 for additional information on
disclosure of fair value of financial instruments.
For the years 1994, 1995, 1996, 1997 and 1998, MP&L has long-term debt
maturities and cash sinking fund requirements of (in millions) $48.2, $66.2,
$61.3, $96.3, and $0.3, respectively. In addition, other sinking fund
requirements of approximately $0.2 million annually may be satisfied by cash or
by certification of property additions at the rate of 167% of such requirements.
The G&R Mortgage prohibits the issuance of additional first mortgage bonds
(including for refunding purposes) under MP&L's first mortgage indenture, except
such first mortgage bonds as may hereafter be issued from time to time at MP&L's
option to the corporate trustee under the G&R Mortgage to provide additional
security for MP&L's G&R Bonds.
Under MP&L's G&R Mortgage indenture and subject to the earnings coverage
test discussed below, G&R Bonds are issuable based upon 70% of property
additions since December 31, 1987, plus up to 50% of cumulative deferred Grand
Gulf 1-related costs recorded as an asset on the books of MP&L, provided that
the maximum amount of G&R Bonds issuable against cumulative deferred Grand
Gulf 1-related costs may not exceed $400 million. The G&R Mortgage contains an
earnings coverage test requiring a minimum earnings coverage (except for certain
refunding issues) of twice the pro-forma annual mortgage interest requirements
for the issuance of additional G&R Bonds. As of December 31, 1993, the total
amount of G&R Bonds outstanding aggregated $465 million.
MP&L has requested SEC authorization allowing the issuance and sale through
December 31, 1995, of up to $550 million of G&R Bonds (of which $235 million
remained available as of December 31, 1993) and up to $25 million of tax -exempt
bonds. MP&L has also received SEC authorization through December 31, 1995, for
the possible acquisition, in whole or in part, of not more than $200 million
aggregate principal amount of outstanding bonds, including, but not limited to
MP&L's G&R Bonds, 14.95% Series due 1995; and not more than $25 million
aggregate principal amount of outstanding pollution control revenue bonds,
including but not limited to Independence County Pollution Control Revenue
Bonds, 9% 1982 Series B due 2013, 9.50% 1982 Series C due 2014, 9% 1982 -A
Series A due 2013, and 9.50% 1982-A Series B due 2014.
NOTE 7. DIVIDEND RESTRICTIONS
MP&L's bond indentures relating to long-term debt contain provisions
restricting the payment of cash dividends or other distributions on common
stock. As of December 31, 1993, $139.6 million of MP&L's retained earnings were
restricted against the payment of cash dividends or other distributions on
common stock. On February 1, 1994, MP&L paid Entergy Corporation a $4.6 million
cash dividend on common stock.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Capital Requirements and Financing
Construction expenditures for the years 1994, 1995, and 1996 are estimated
to total $61 million, $63 million, and $63 million, respectively. MP&L will
also require $212 million during the period 1994-1996 to meet long-term debt and
preferred stock maturities and cash sinking fund requirements. MP&L plans to
meet the above requirements with internally generated funds and cash on hand,
supplemented by the issuance of long-term debt. See Notes 5 and 6 regarding the
possible issuance, refunding, redemption, purchase or other acquisition of
certain outstanding series of preferred stock and long-term debt. See Note 11
for information on additional capital requirements related to a February 1994
ice storm.
Unit Power Sales Agreement
System Energy has agreed to sell all of its 90% owned and leased share of
capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in
accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and
NOPSI 17%) as ordered by FERC. Charges under this agreement are paid in
consideration for MP&L's respective entitlement to receive capacity and energy,
and are payable irrespective of the quantity of energy delivered so long as the
unit remains in commercial operation. The agreement will remain in effect until
terminated by the parties and approved by FERC, most likely upon Grand Gulf 1's
retirement from service. MP&L's monthly obligation for payments to System Energy
for Grand Gulf 1 capacity and energy is approximately $18 million.
Availability Agreement
AP&L, LP&L, MP&L, and NOPSI are individually obligated to make payments or
subordinated advances to System Energy in accordance with stated percentages
(AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 24.7%) in amounts that when added
to amounts received under the Unit Power Sales Agreement or otherwise, are
adequate to cover all of System Energy's operating expenses. System Energy has
assigned its rights to payments and advances to certain creditors as security
for certain obligations. Payments or advances under the Availability Agreement
are only required if funds available to System Energy from all sources are less
than the amount required under the Availability Agreement. Since commercial
operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have
exceeded the amounts payable under the Availability Agreement. Accordingly, no
payments have ever been required. In 1989, the Availability Agreement was
amended to provide that the write-off of $900 million of Grand Gulf 2 costs
would be amortized for Availability Agreement purposes over a period of 27 years
in order to avoid the need for payments by AP&L, LP&L, MP&L, and NOPSI.
Reallocation Agreement
System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation
Agreement relating to the sale of capacity and energy from the Grand Gulf
Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume
all of AP&L's responsibilities and obligations with respect to the Grand Gulf
Station under the Availability Agreement. FERC's decision allocating a portion
of Grand Gulf 1 capacity and energy to AP&L supersedes the Reallocation
Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2
amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%,
and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the
Reallocation Agreement does not affect AP&L's obligation to System Energy's
lenders under the assignments referred to in the preceding paragraph. AP&L
would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were
unable to meet their contractual obligations. No payments of any amortization
amounts will be required as long as amounts paid to System Energy under the Unit
Power Sales Agreement, including other funds available to System Energy, exceed
amounts required under the Availability Agreement, which is expected to be the
case for the foreseeable future.
System Fuels
MP&L has a 19% interest in System Fuels, a jointly-owned subsidiary of
AP&L, LP&L, MP&L, and NOPSI. The parent companies of System Fuels, including
MP&L, agreed to make loans to System Fuels to finance its fuel procurement,
delivery, and storage activities. As of December 31, 1993, MP&L had
approximately $5.5 million of loans outstanding to System Fuels which mature in
2008.
On April 30, 1993, AP&L assumed System Fuels' rights and obligations in
connection with System Fuels' coal car leases. The other parent companies of
System Fuels have been released from their obligations with respect to the coal
car leases. However, MP&L, as a co-owner of the Independence Station, which
uses the coal transported by the leased coal cars, will continue to reimburse
AP&L for MP&L's share of the costs associated with the leases.
Fuel Purchase Commitments
MP&L has a four-year gas purchase agreement with Koch Gateway Pipeline
Company (formerly United Gas Pipeline Company) under which, beginning January 1,
1991, MP&L is purchasing approximately 34.1 billion cubic feet of gas. As of
December 31, 1993, MP&L had purchased approximately 23.4 billion cubic feet of
gas.
MP&L owns certain coal mining equipment and facilities at a mine in
Wyoming. The mine's estimated reserves are presently expected to provide the
projected requirements of the Independence Station through at least 2014.
NOTE 9. POSTRETIREMENT BENEFITS
Pension Plan
MP&L has a defined benefit pension plan covering substantially all of its
employees. The pension plan is noncontributory and provides pension benefits
based on employees' credited service and average compensation, generally during
the last five years before retirement. MP&L funds pension costs in accordance
with contribution guidelines established by the Employee Retirement Income
Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as
amended. The assets of the plan consist primarily of common and preferred
stocks, fixed income securities, interest in a money market fund, and insurance
contracts.
MP&L's 1993, 1992, and 1991 pension cost, including amounts capitalized,
included the following components:
For the Years Ended December 31,
--------------------------------
1993 1992 1991
------ ------ ------
(In Thousands)
Service cost - benefits earned during the period $2,409 $2,059 $2,061
Interest cost on projected benefit obligation 8,583 8,269 7,472
Actual return on plan assets (15,053) (8,474) (22,422)
Net amortization and deferral 5,325 (1,009) 13,323
Other - - 403
------ ---- ------
Net pension cost $1,264 $845 $837
====== ==== ======
The funded status of MP&L's pension plan as of December 31, 1993 and 1992,
was:
1993 1992
-------- --------
(In Thousands)
Actuarial present value of accumulated pension plan benefits:
Vested $101,664 $92,473
Nonvested 390 283
-------- --------
Accumulated benefit obligation $102,054 $92,756
======== ========
Plan assets at fair value $126,990 $119,173
Projected benefit obligation 122,056 107,658
-------- --------
Plan assets in excess of projected benefit obligation 4,934 11,515
Unrecognized prior service cost 3,574 3,856
Unrecognized transition asset (10,003) (11,253)
Unrecognized net gain (1,798) (6,146)
-------- --------
Accrued pension liability $ (3,293) $ (2,028)
======== ========
The significant actuarial assumptions used in computing the information
above for 1993, 1992, and 1991 were as follows: weighted average discount
rate, 7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of
increase in future compensation levels, 5.6%; and expected long-term rate of
return on plan assets, 8.5%. Transition assets are being amortized over 15
years.
Other Postretirement Benefits
MP&L also provides certain health care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits if they reach retirement age while still working for MP&L. The cost of
providing these benefits, recorded on a cash basis, to retirees in 1992 was
approximately $1.6 million. Prior to 1992, the cost of providing these benefits
for retirees was not separable from the cost of providing benefits for active
employees. Based on the ratio of the number of retired employees to the total
number of active and retired employees in 1991, the cost of providing these
benefits in 1991, recorded on a cash basis, for retirees was approximately $1.1
million.
Effective January 1, 1993, MP&L adopted SFAS 106. The new standard
requires a change from a cash method to an accrual method of accounting for
postretirement benefits other than pensions. MP&L continues to fund these
benefits on a pay-as-you-go basis. At January 1, 1993, the actuarially
determined accumulated postretirement benefit obligation (APBO) earned by
retirees and active employees was estimated to be approximately $30 million.
This obligation is being amortized over a 20-year period beginning in 1993.
MP&L is expensing its SFAS 106 costs, which will be reflected in rates pursuant
to an order from the MPSC in connection with MP&L's formulary incentive rate
plan (see Note 2). MP&L's net income in 1993 was decreased by approximately
$2.0 million as a result of adopting SFAS 106.
MP&L's 1993 postretirement benefit cost, including amounts capitalized and
deferred, included the following components (in thousands):
Service cost - benefits earned during the period $812
Interest cost on APBO 2,400
Actual return on plan assets -
Amortization of transition obligation 1,502
------
Net periodic postretirement benefit cost $4,714
======
The funded status of MP&L's postretirement plan as of December 31, 1993,
was (in thousands):
Accumulated postretirement benefit obligations:
Retirees $21,435
Other fully eligible participants 5,816
Other active participants 7,794
-------
35,045
Plan assets at fair value -
-------
Plan assets less than APBO (35,045)
Unrecognized transition obligation 28,537
Unrecognized net loss 3,745
-------
Accrued post retirement benefit liability $(2,763)
=======
The assumed health care cost trend rate used in measuring the APBO was 9.9%
for 1994, gradually decreasing each successive year until it reaches 5.6% in
2020. A one percentage-point increase in the assumed health care cost trend
rate for each year would have increased the APBO as of December 31, 1993, by
8.6% and the sum of the service cost and interest cost by approximately 10.9%.
The assumed discount rate and rate of increase in future compensation used in
determining the APBO were 7.5% and 5.5%, respectively.
NOTE 10. TRANSACTIONS WITH AFFILIATES
MP&L buys electricity from and/or sells electricity to AP&L, LP&L, NOPSI,
and System Energy under rate schedules filed with FERC. In addition, MP&L
purchases fuel from System Fuels and receives technical and advisory services
from Entergy Services, Inc..
Operating revenues include revenues from sales to affiliates amounting to
$40.6 million in 1993, $18.0 million in 1992, and $9.8 million in 1991. As a
result of an internal review designed to ensure consistency among the System
operating companies, certain 1985-1991 intra-system equalization billings
pursuant to the System Agreement were adjusted in 1991 and reduced operating
revenue in the amount of approximately $10.6 million. Operating expenses
include charges from affiliates for fuel costs, purchased power and related
charges, and technical and advisory services totaling $360.5 million in 1993,
$364.0 million in 1992, $310.8 million in 1991.
See Note 1 for information on MP&L's jointly-owned generating station.
NOTE 11. SUBSEQUENT EVENT (UNAUDITED)
In early February 1994, an ice storm left more than 80,000 MP&L customers
without electric power in its service area. The storm was the most severe
natural disaster ever to affect MP&L, causing damage to transmission and
distribution lines, equipment, poles, and facilities in certain areas. A
substantial portion of the related costs, which are estimated to be $75 million
to $100 million, are expected to be capitalized. Estimated construction
expenditures (see Note 8) have not yet been updated to reflect the above
amounts.
The MPSC acknowledged that there is precedent in Mississippi for recovery
of certain costs associated with storms and natural disasters and the
restoration of service resulting from such events. MP&L plans to immediately
file for rate recovery of the costs related to the ice storm.
NOTE 12. QUARTERLY FINANCIAL DATA (UNAUDITED)
MP&L's business is subject to seasonal fluctuations with the peak period
occurring during the third quarter. Operating results for the four quarters of
1993 and 1992 were:
Operating Operating Net
Revenues Income Income
----------- ---------- ----------
(In Thousands)
1993:
First Quarter (1) $179,467 $24,134 $42,782
Second Quarter $229,506 $38,471 $25,339
Third Quarter $264,419 $39,896 $26,921
Fourth Quarter $222,414 $22,819 $ 6,701
1992:
First Quarter $186,791 $26,866 $11,083
Second Quarter $202,297 $25,830 $10,306
Third Quarter $229,209 $40,673 $25,002
Fourth Quarter $199,353 $31,405 (2) $18,645 (2)
(1) The first quarter of 1993 reflects a nonrecurring increase in net income of
$32.7 million, net of taxes of $19.5 million, due to the recording of the
cumulative effect of the change in accounting principle for unbilled
revenues (see Note 1). Beginning with the second quarter, the remaining
quarters are not generally comparable to prior year quarters because of the
ongoing effects of the accounting change.
(2) The fourth quarter of 1992 reflects a decrease in income tax expense of
$4.8 million due to estimates of income tax benefits related to tax
depreciation having been adjusted as a result of certain elections made in
conjunction with the filing of the 1991 tax return.
MISSISSIPPI POWER & LIGHT COMPANY
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
(In Thousands)
Operating revenues $ 895,806 $ 817,650 $ 754,632 $ 761,188 $ 709,746
Income before cumulative
effect of a change in
accounting principle $ 69,037 $ 65,036 $ 63,088 $ 60,830 $ 12,419
Total assets $1,676,737 $1,660,726 $1,672,275 $1,616,522 $1,565,707
Long-term obligations (1) $ 563,612 $ 576,787 $ 576,599 $ 679,458 $ 693,333
(1) Includes long-term debt (excluding currently maturing debt), preferred
stock with sinking fund, and noncurrent capital lease obligations.
See Notes 1, 3, and 9 for the effect of accounting changes in 1993.
1993 1992 1991 1990 1989
-------- -------- -------- -------- --------
(Dollars in Thousands)
Operating Revenues:
Residential $343,585 $308,346 $307,283 $302,622 $274,841
Commercial 252,798 235,137 229,597 227,140 212,107
Industrial 183,537 168,853 162,072 160,007 147,146
Governmental 28,708 26,250 25,630 25,117 23,624
-------- -------- -------- -------- --------
Total retail 808,628 738,586 724,582 714,886 657,718
Sales for resale 55,740 37,983 25,487 35,678 45,886
Other 31,438 41,081 4,563 10,624 6,142
-------- -------- -------- -------- --------
Total $895,806 $817,650 $754,632 $761,188 $709,746
======== ======== ======== ======== ========
Billed Electric Energy
Sales (Millions of KWH):
Residential 3,983 3,644 3,739 3,701 3,452
Commercial 2,928 2,804 2,807 2,802 2,679
Industrial 2,787 2,631 2,582 2,564 2,368
Governmental 336 318 321 318 308
-------- -------- -------- -------- --------
Total retail 10,034 9,397 9,449 9,385 8,807
Sales for resale 1,428 1,190 1,032 902 1,038
-------- -------- -------- -------- --------
Total 11,462 10,587 10,481 10,287 9,845
======== ======== ======== ======== ========
New Orleans Public Service Inc.
1993 Financial Statements
NEW ORLEANS PUBLIC SERVICE INC.
DEFINITIONS
Certain abbreviations or acronyms used in NOPSI's Financial Statements,
Notes to Financial Statements, and Management's Financial Discussion and
Analysis are defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
Alliance The Alliance for Affordable Energy, and others
AP&L Arkansas Power & Light Company
City of New Orleans
or City New Orleans, Louisiana
Council Council of the City of New Orleans, Louisiana
Entergy or System Entergy Corporation and its various direct and indirect
subsidiaries
FASB Financial Accounting Standards Board
February 4 Resolution The Resolution (including the Determinations and Order
referred to therein) adopted by the Council on
February 4, 1988, disallowing the recovery by NOPSI of
$135 million of previously deferred Grand Gulf
1-related costs
FERC Federal Energy Regulatory Commission
G&R Bonds General and Refunding Mortgage Bonds issued and
issuable by NOPSI
Grand Gulf 1 Unit No. 1 of the Grand Gulf Station
Grand Gulf 2 Unit No. 2 of the Grand Gulf Station
Grand Gulf Station Grand Gulf Steam Electric Generating Station
GSU Gulf States Utilities Company (including wholly owned
subsidiaries - Varibus Corporation, GSG&T, Inc.,
Prudential Oil and Gas, Inc., and Southern Gulf Railway
Company)
KWH Kilowatt-Hour(s)
LP&L Louisiana Power & Light Company
Merger The combination transaction, consummated on December
31, 1993, by which GSU became a subsidiary of Entergy
Corporation and Entergy Corporation became a Delaware
Corporation
Money Pool Entergy Money Pool, which allows certain System
companies to borrow from, or lend to, certain other
System companies
MP&L Mississippi Power & Light Company
1986 Rate Settlement Agreement, effective March 25, 1986, between NOPSI and
the Council regarding NOPSI's Grand Gulf 1-related rate
issues
1989 Settlement
Agreement An agreement between the Council and NOPSI, effective
July 21, 1989, that settled certain local retail rate
issues regarding Grand Gulf 1
1991 NOPSI Settlement Settlement, retroactive to October 4, 1991, among
NOPSI, the Council and the Alliance that settled
certain Grand Gulf 1 prudence issues and pending
litigation related to the February 4 Resolution
NOPSI New Orleans Public Service Inc.
OBRA Omnibus Budget Reconciliation Act of 1993
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards promulgated
by the FASB
SFAS 106 SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions"
SFAS 109 SFAS No. 109, "Accounting for Income Taxes"
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively
System or Entergy Entergy Corporation and its various direct and indirect
subsidiaries
NEW ORLEANS PUBLIC SERVICE INC.
REPORT OF MANAGEMENT
The management of New Orleans Public Service Inc. has prepared and is
responsible for the financial statements and related financial information
included herein. The financial statements are based on generally accepted
accounting principles. Financial information included elsewhere in this report
is consistent with the financial statements.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting controls that
is designed to provide reasonable assurance, on a cost-effective basis, as to
the integrity, objectivity, and reliability of the financial records, and as to
the protection of assets. This system includes communication through written
policies and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and the
training of personnel. This system is also tested by a comprehensive internal
audit program.
The independent public accountants provide an objective assessment of the
degree to which management meets its responsibility for fairness of financial
reporting. They regularly evaluate the system of internal accounting controls
and perform such tests and other procedures as they deem necessary to reach and
express an opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide reasonable
assurance that its operations are carried out with a high standard of business
conduct.
/S/ EDWIN LUPBERGER /S/ GERALD D. MCINVALE
EDWIN LUPBERGER GERALD D. MCINVALE
Chairman and Chief Executive Officer Senior Vice President and
Chief Financial Officer
NEW ORLEANS PUBLIC SERVICE INC.
AUDIT COMMITTEE CHAIRMAN'S LETTER
The New Orleans Public Service Inc. Audit Committee of the Board of
Directors is comprised of four directors, who are not officers of NOPSI: Anne M.
Milling (Chairman), James M. Cain, Brooke H. Duncan and Dr. Norman C. Francis.
The committee held four meetings during 1993.
The Audit Committee oversees NOPSI's financial reporting process on behalf
of the Board of Directors and provides reasonable assurance to the Board that
sufficient operating, accounting, and financial controls are in existence and
are adequately reviewed by programs of internal and external audits.
The Audit Committee discussed with Entergy's internal auditors and the
independent public accountants (Deloitte & Touche) the overall scope and
specific plans for their respective audits, as well as NOPSI's financial
statements and the adequacy of NOPSI's internal controls. The committee met,
together and separately, with Entergy's internal auditors and independent public
accountants, without management present, to discuss the results of their audits,
their evaluation of NOPSI's internal controls, and the overall quality of
NOPSI's financial reporting. The meetings also were designed to facilitate and
encourage any private communication between the committee and the internal
auditors or independent public accountants.
/S/ ANNE M. MILLING
ANNE M. MILLING
Chairman, Audit Committee
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of
New Orleans Public Service Inc.
We have audited the accompanying balance sheets of New Orleans Public
Service Inc. (NOPSI) as of December 31, 1993 and 1992, and the related
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1993. These financial statements are the
responsibility of NOPSI's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of NOPSI at December 31, 1993 and 1992, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1993 in conformity with generally accepted accounting
principles.
As discussed in Note 1 to the financial statements, NOPSI changed its
method of accounting for revenues in 1993 and, as discussed in Notes 3 and 9 to
the financial statements, in 1993 NOPSI changed its methods of accounting for
income taxes and postretirement benefits other than pensions, respectively.
/S/ DELOITTE & TOUCHE
DELOITTE & TOUCHE
New Orleans, Louisiana
February 11, 1994
NEW ORLEANS PUBLIC SERVICE INC.
BALANCE SHEETS
ASSETS
December 31,
----------------------
1993 1992
-------- --------
(In Thousands)
Utility Plant (Note 1):
Electric $476,976 $466,319
Natural gas 113,666 110,399
Construction work in progress 15,205 6,906
-------- --------
Total 605,847 583,624
Less - accumulated depreciation and amortization 330,268 315,439
-------- --------
Utility plant - net 275,579 268,185
-------- --------
Other Investments:
Investment in subsidiary company - at equity (Note 8) 3,259 3,259
-------- --------
Current Assets:
Cash and cash equivalents (Note 1):
Cash 1,176 -
Temporary cash investments - at cost,
which approximates market:
Associated companies (Note 4) 10,034 3,513
Other 32,107 42,557
-------- --------
Total cash and cash equivalents 43,317 46,070
Accounts receivable:
Customer (less allowance for doubtful accounts of $0.8
million in 1993 and $1.4 million in 1992) 35,801 30,525
Associated companies (Note 10) 1,378 2,232
Other 876 676
Accrued unbilled revenues (Note 1) 19,643 -
Deferred electric fuel and resale gas costs (Note 1) 6,323 486
Accumulated deferred income taxes (Note 3) - 4,566
Materials and supplies - at average cost 11,885 11,925
Rate deferrals (Note 2) 24,587 15,617
Prepayments and other 2,994 3,633
-------- --------
Total 146,804 115,730
-------- --------
Deferred Debits:
Rate deferrals (Note 2) 204,190 229,002
SFAS 109 regulatory asset - net (Note 3) 9,004 -
Other 8,769 5,515
-------- --------
Total 221,963 234,517
-------- --------
TOTAL $647,605 $621,691
======== ========
See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC.
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
----------------------
1993 1992
-------- --------
(In Thousands)
Capitalization:
Common stock, $4 par value, authorized 10,000,000
shares; issued and outstanding 8,435,900 shares
in 1993 and 1992 $33,744 $33,744
Paid-in capital 36,156 36,097
Retained earnings subsequent to the elimination of the
accumulated deficit of $13.9 million on November 30,
1988 (Note 7) 100,556 98,560
-------- --------
Total common shareholder's equity 170,456 168,401
Preferred stock (Note 5):
Without sinking fund 19,780 19,780
With sinking fund 4,950 6,450
Long-term debt (Note 6) 188,312 159,467
-------- --------
Total 383,498 354,098
-------- --------
Other Noncurrent Liabilities:
Accumulated provision for losses (Note 1) 18,022 17,799
Other 3,351 -
-------- --------
Total 21,373 17,799
-------- --------
Current Liabilities:
Currently maturing long-term debt (Note 6) 15,000 44,400
Accounts payable:
Associated companies (Note 10) 23,080 21,527
Other 22,011 22,395
Customer deposits 16,617 15,552
Accumulated deferred income taxes (Note 3) 4,968 -
Taxes accrued 5,161 5,243
Interest accrued 5,472 6,791
Dividends declared 432 490
Other 6,935 1,477
-------- --------
Total 99,676 117,875
-------- --------
Deferred Credits:
Accumulated deferred income taxes (Note 3) 105,096 100,423
Accumulated deferred investment tax credits (Note 3) 11,592 12,338
Other 26,370 19,158
-------- --------
Total 143,058 131,919
-------- --------
Commitments and Contingencies (Notes 2 and 8)
TOTAL $647,605 $621,691
======== ========
See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
---------------------------------
1993 1992 1991
------- ------- --------
(In Thousands)
Operating Activities:
Net income $47,709 $26,424 $74,699
Noncash items included in net income:
Cumulative effect of a change in accounting
principle (10,948) - -
Change in rate deferrals (Note 2) 15,842 2,856 (55,151)
Depreciation and amortization 17,284 16,619 15,973
Deferred income taxes and investment tax credits (2,132) (865) 36,180
Allowance for equity funds used during
construction (141) (119) (102)
Changes in working capital:
Receivables (6,725) 1,579 2,007
Accounts payable 1,169 (1,455) 2,802
Taxes accrued (82) 1,473 2,471
Interest accrued (1,319) (1,687) (168)
Other working capital accounts 1,365 (6,344) 58
Pension payment - (23,131) -
Other 8,345 7,047 2,888
------- ------- --------
Net cash flow provided by operating activities 70,367 22,397 81,657
------- ------- --------
Investing Activities:
Construction expenditures (24,813) (21,043) (22,535)
Allowance for equity funds used during
construction 141 119 102
------- ------- --------
Net cash flow used in investing activities (24,672) (20,924) (22,433)
------- ------- --------
Financing Activities:
Proceeds from the issuance of general
and refunding bonds 100,000 - -
Retirement of:
General and refunding bonds (44,400) - -
First mortgage bonds (56,823) (28,000) (16,400)
Redemption of preferred stock (1,500) (1,500) (1,500)
Dividends paid:
Common stock (43,900) (32,154) (4,453)
Preferred stock (1,825) (2,057) (2,289)
------- ------- --------
Net cash flow used in financing activities (48,448) (63,711) (24,642)
------- ------- --------
Net increase (decrease) in cash and cash equivalents (2,753) (62,238) 34,582
Cash and cash equivalents at beginning of period 46,070 108,308 73,726
------- ------- --------
Cash and cash equivalents at end of period $43,317 $46,070 $108,308
======= ======= ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $21,953 $26,330 $25,341
Income taxes $25,661 $15,632 $6,357
See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is important to NOPSI due to the capital intensive nature of our
business, which requires large investments in long-lived assets. However, large
capital expenditures for the construction of new generating capacity are not
currently planned. NOPSI requires significant capital resources for the
periodic maturity of certain series of debt and preferred stock. Net cash flow
from operations totaled $70 million, $22 million, and $82 million in 1993, 1992,
and 1991, respectively. In recent years, this cash flow, supplemented by cash
on hand, has been sufficient to meet substantially all investing and financing
requirements, including capital expenditures, dividends, and debt/preferred
stock maturities. NOPSI's ability to fund these capital requirements results,
in part, from our continued efforts to streamline operations and reduce costs,
as well as collections under our Grand Gulf 1 rate phase-in plan which exceed
the current cash requirements for Grand Gulf 1-related costs. (In the income
statement, these revenue collections are offset by the amortization of
previously deferred costs, therefore, there is no effect on net income.) See
Note 2, incorporated herein by reference, for additional information on NOPSI's
rate phase-in plan. See Note 8, incorporated herein by reference, for
additional information on NOPSI's capital and refinancing requirements in 1994 -
1996. Also, in order to take advantage of lower interest and dividend rates,
NOPSI may continue to refinance high-cost debt and preferred stock prior to
maturity.
Earnings coverage tests (which are impacted by the inclusion of the
cumulative effect of the change in accounting principle for accruing unbilled
revenues discussed in Note 1), bondable property additions, and accumulated
deferred Grand Gulf 1-related costs recorded as assets, limit the G&R Bonds and
preferred stock that NOPSI can issue. Based on the most restrictive applicable
tests as of December 31, 1993 and an assumed annual interest or dividend rate
of 8%, NOPSI could have issued $40 million of additional G&R Bonds or $306
million of additional preferred stock. Further, NOPSI has the conditional
ability to issue G&R bonds against the retirement of bonds, in some cases
without satisfying an earnings coverage test.
See Notes 5 and 6, incorporated herein by reference, for information on
NOPSI's financing activities and Note 4, incorporated herein by reference, for
information on NOPSI's short-term borrowings and lines of credit.
NEW ORLEANS PUBLIC SERVICE INC.
STATEMENTS OF INCOME
For the Years Ended December 31,
---------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Operating Revenues (Notes 1, 2, and 10):
Electric $423,830 $391,936 $399,214
Natural gas 90,992 72,943 76,951
-------- -------- --------
Total 514,822 464,879 476,165
-------- -------- --------
Operating Expenses:
Operation (Note 10):
Fuel for electric generation
and fuel-related expenses 59,859 47,566 38,428
Purchased power 165,963 170,703 168,315
Gas purchased for resale 52,592 43,212 49,986
Other 69,658 74,696 74,713
Maintenance 18,139 17,039 18,118
Depreciation and amortization 17,284 16,619 15,973
Taxes other than income taxes 26,643 27,487 25,733
Income taxes (Note 3) 24,232 14,382 41,998
Rate deferrals (Note 2):
Rate deferrals (1,651) (1,300) (3,348)
Amortization of rate deferrals 22,351 4,426 38,627
Deferral of previously incurred
Grand Gulf 1-related costs - - (90,000)
-------- -------- --------
Total 455,070 414,830 378,543
-------- -------- --------
Operating Income 59,752 50,049 97,622
-------- -------- --------
Other Income (Deductions):
Allowance for equity funds used
during construction 141 119 102
Miscellaneous - net (1,055) 3,056 5,329
Income taxes (Note 3) (1,115) (1,683) (3,242)
-------- -------- --------
Total (2,029) 1,492 2,189
-------- -------- --------
Interest Charges:
Interest on long-term debt 19,478 22,934 23,865
Other interest - net 1,614 2,290 1,358
Allowance for borrowed funds used
during construction (130) (107) (111)
-------- -------- --------
Total 20,962 25,117 25,112
-------- -------- --------
Income before Cumulative Effect of
a Change in Accounting Principle 36,761 26,424 74,699
Cumulative Effect to January 1, 1993
of Accruing Unbilled Revenues (net
of income taxes of $6,592) (Note 1) 10,948 - -
-------- -------- --------
Net Income 47,709 26,424 74,699
Preferred Stock Dividend Requirements 1,768 1,999 2,231
-------- -------- --------
Earnings Applicable to Common Stock $45,941 $24,425 $72,468
======== ======== ========
See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC.
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
-----------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Retained Earnings, January 1 $98,560 $106,341 $33,918
Add:
Net income 47,709 26,424 74,699
-------- -------- --------
Total 146,269 132,765 108,617
-------- -------- --------
Deduct:
Dividends declared:
Preferred stock 1,768 1,999 2,231
Common stock 43,900 32,154 -
Capital stock expenses 45 52 45
-------- -------- --------
Total 45,713 34,205 2,276
-------- -------- --------
Retained Earnings, December 31 (Note 7) $100,556 $98,560 $106,341
======== ======== ========
See Notes to Financial Statements.
NEW ORLEANS PUBLIC SERVICE INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income increased in 1993 due primarily to the one-time recording of
the cumulative effect of the change in accounting principle for unbilled
revenues (see Note 1, incorporated herein by reference) and its ongoing
effects, partially offset by the effect of implementing SFAS 106 (see Note 9,
incorporated herein by reference). Effective January 1, 1993, NOPSI began
accruing as revenues the charges for energy delivered to customers but not yet
billed. Electric and gas revenues were previously recorded on a cycle-billing
basis. Excluding the above mentioned items, net income for 1993 would have
been $37.8 million. This $11.4 million increase is due primarily to increased
gas revenues and increased electric retail energy sales. Net income decreased
in 1992 due primarily to the net income effect of the $90 million 1991 NOPSI
Settlement, which resulted in a $48.6 million increase in 1991 net income.
Significant factors affecting the results of operations and causing
variances between the years 1993 and 1992, and 1992 and 1991, are discussed
under "Revenues and Sales" and "Expenses" below.
Revenues and Sales
See "Selected Financial Data-Five-Year Comparison," incorporated herein by
reference, following the notes, for information on electric operating revenues
by source and KWH sales.
Electric operating revenues were higher in 1993 due primarily to increased
fuel adjustment revenues and increased collections of previously deferred Grand
Gulf 1-related costs, neither of which affects net income, and increased
residential energy sales resulting primarily from a return to more normal
weather as compared to milder weather in 1992. Electric operating revenues
were slightly lower in 1992 due primarily to decreased retail sales as a result
of milder temperatures. Total electric energy sales were lower in 1992
resulting from these milder temperatures.
Gas operating revenues increased in 1993 due primarily to an increase in
gas rates and increased fuel adjustment revenues resulting from higher average
per unit cost for gas purchased. Gas operating revenues decreased in 1992 due
primarily to decreased recovery of resale gas costs through the city gate
adjustment clause, partially offset by higher base revenues due to the gas rate
increase in May 1992.
Expenses
Fuel for electric generation and fuel-related expenses increased in 1993
due primarily to increased gas costs and increased generation requirements
resulting primarily from increased energy sales as discussed in "Revenues and
Sales" above. Fuel for electric generation and fuel-related expenses increased
in 1992 due to increased generation.
Gas purchased for resale increased in 1993 due primarily to a higher
average per unit cost for gas purchased while it declined in 1992 due primarily
to a lower average per unit cost.
The changes in the amortization of rate deferrals in 1993 and 1992 are
primarily a result of the 1991 NOPSI Settlement, which allowed NOPSI to record
an additional $90 million of previously incurred Grand Gulf 1-related costs.
Total income taxes increased in 1993 due primarily to higher pretax income
and an increase in the federal income tax rate as a result of OBRA. Total
income taxes decreased in 1992 due primarily to lower pretax income resulting
from the effect of the 1991 NOPSI Settlement.
NEW ORLEANS PUBLIC SERVICE INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
Competition
NOPSI welcomes competition in the electric energy business and believes
that a more competitive environment should benefit our customers, employees, and
shareholders of Entergy Corporation. We also recognize that competition
presents us with many challenges, and we have identified the following as our
major competitive challenges:
Retail and Wholesale Rate Issues
Increasing competition in the utility industry brings an increased need to
stabilize or reduce retail rates. NOPSI is currently operating under electric
and gas base rate freezes through October 31, 1996. Also, in connection with
the Merger, NOPSI agreed with the Council to reduce its annual electric base
rates by $4.8 million effective for bills rendered on or after November 1, 1993.
See Note 2, incorporated herein by reference, for further information.
Retail wheeling, a major industry issue which may require utilities to
"wheel" or move power from third parties to their own retail customers, is
evolving gradually. As a result, the retail market could become more
competitive.
In the wholesale rate area, FERC approved in 1992, with certain
modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power, Inc.
to sell wholesale power at market-based rates and to provide to electric
utilities "open access" to the System's transmission system (subject to certain
requirements). GSU was later added to this filing. Various intervenors in the
proceeding filed petitions for review with the United States Court of Appeals
for the District of Columbia Circuit. FERC's order, once it takes effect, will
increase marketing opportunities for NOPSI, but will also expose NOPSI to the
risk of loss of load or reduced revenues due to competition with alternative
suppliers.
In light of the rate issues discussed above, NOPSI is aggressively
reducing costs to avoid potential earnings erosions that might result as well as
to successfully compete by becoming a low-cost producer. To help minimize
future costs, NOPSI remains committed to least cost planning. In December 1992,
NOPSI filed a Least Cost Integrated Resource Plan (Least Cost Plan) with its
retail regulator. Least cost planning includes demand-side measures such as
customer energy conservation and supply-side measures such as more efficient
power plants. These measures are designed to delay the building of new power
plants for the next 20 years. NOPSI plans to periodically file revised Least
Cost Plans.
The Energy Policy Act of 1992
The Energy Policy Act of 1992 (Energy Act) is changing the transmission and
distribution of electricity. This act encourages competition and affords us the
opportunities, and the risks, associated with an open and more competitive
market environment. The Energy Act increases competition in the wholesale
energy market through the creation of exempt wholesale generators (EWGs). The
Energy Act also gives FERC the authority to order investor-owned utilities to
provide transmission access to or for other utilities, including EWGs.
NEW ORLEANS PUBLIC SERVICE INC.
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NOPSI maintains accounts in accordance with FERC and other regulatory
guidelines. Certain previously reported amounts have been reclassified to
conform to current classifications.
Revenues and Fuel Costs
Prior to January 1, 1993, NOPSI recorded revenues when billed to its
customers with no accrual for energy delivered but not yet billed. To provide a
better matching of revenues and expenses, effective January 1, 1993, NOPSI
adopted a change in accounting principle to provide for accrual of the nonfuel
portion of estimated unbilled revenues. The cumulative effect of this
accounting change as of January 1, 1993, increased net income by $10.9 million.
Had this new accounting method been in effect during prior years, net income
before the cumulative effect would not have been materially different from that
shown in the accompanying financial statements.
NOPSI's rate schedules include electric fuel adjustment and city gate gas
cost adjustment clauses that allow deferral of fuel costs until such costs are
reflected in the related revenues.
Utility Plant
Utility plant is stated at original cost. The original cost of utility
plant retired or removed, plus the applicable removal costs, less salvage, is
charged to accumulated depreciation. Maintenance, repairs, and minor
replacement costs are charged to operating expenses. Substantially all of
NOPSI's utility plant is subject to the liens of its mortgage bond indentures.
AFUDC represents the approximate net composite interest cost of borrowed
funds and a reasonable return on the equity funds used for construction.
Although AFUDC increases utility plant and increases earnings, it is only
realized in cash through depreciation provisions included in rates. NOPSI's
effective composite rates for AFUDC were 11.4%, 12.1%, and 11.3% for 1993, 1992,
and 1991, respectively.
Depreciation is computed on the straight-line basis at rates based on the
estimated service lives and costs of removal of the various classes of property.
Depreciation provisions on average depreciable property approximated 3.1% in
1993 and 1992, and 3.2% in 1991.
Income Taxes
NOPSI, its parent, and affiliates (excluding GSU prior to 1994) file a
consolidated federal income tax return. Income taxes are allocated to NOPSI in
proportion to its contribution to consolidated taxable income. SEC regulations
require that no System company pay more taxes than it would have had a separate
income tax return been filed. Deferred taxes are recorded for all temporary
differences between book and taxable income. Investment tax credits are
deferred and amortized based upon the average useful life of the related
property in accordance with rate treatment. As discussed in Note 3, effective
January 1, 1993, NOPSI changed its accounting for income taxes to conform with
SFAS 109.
Other Noncurrent Liabilities
NOPSI records provisions for uninsured property risks and claims for
injuries and damages through charges to operation expenses on an accrual basis.
Provisions for these accruals, classified as other noncurrent liabilities, have
been allowed for ratemaking purposes.
Cash and Cash Equivalents
NOPSI considers all unrestricted highly liquid debt instruments purchased
with an original maturity of three months or less to be cash equivalents.
Fair Value Disclosure
The estimated fair value amounts of financial instruments have been
determined by NOPSI, using available market information and appropriate
valuation methodologies. However, considerable judgment is required in
developing the estimates of fair value. Therefore, estimates are not
necessarily indicative of the amounts that NOPSI could realize in a current
market exchange. In addition, gains or losses realized on financial instruments
may be reflected in future rates and not accrue to the benefit of stockholders.
NOPSI considers the carrying amounts of financial instruments classified as
current assets and liabilities to be a reasonable estimate of their fair value
because of the short maturity of these instruments. In addition, NOPSI does not
presently expect that performance of its obligations will be required in
connection with certain off-balance sheet commitments and guarantees considered
financial instruments. Due to this factor, and because of the related party
nature of these commitments and guarantees, determination of fair value is not
considered practicable. See Notes 5 and 6 for additional fair value disclosure.
NOTE 2. RATE AND REGULATORY MATTERS
Rate Agreement
In November 1993, the Council adopted resolutions accepting a proposal by
NOPSI to settle certain issues related to the Merger. Pursuant to the
resolutions, the Council agreed to withdraw from the SEC proceeding related to
the Merger. In return, NOPSI agreed, among other things, that retail ratepayers
in the City of New Orleans would be protected from (1) increases in NOPSI's cost
of capital resulting from risks associated with the Merger; (2) recovery of any
portion of the acquisition premium or transactional costs associated with the
Merger; (3) certain direct allocations of costs associated with GSU's River Bend
nuclear unit; and (4) any losses of GSU resulting from resolution of litigation
in connection with its ownership of River Bend. NOPSI was required to reduce
its annual electric base rates by $4.8 million effective for bills rendered on
or after November 1, 1993, and to expense its SFAS 106 costs. NOPSI's SFAS 106
expenses through October 31, 1996, will be allowed by the Council for purposes
of evaluating the appropriateness of NOPSI's rates. The Council also agreed not
to seek to disallow the first $3.5 million of costs incurred through October 31,
1993, in connection with the Least Cost Plan.
Prudence Settlement and Finalized Phase-In Plan
The February 4 Resolution required NOPSI to write off, and not recover from
its retail electric customers, $135 million of its previously deferred costs
associated with Grand Gulf 1. This write-off, which was recorded in NOPSI's
1987 financial statements, was in addition to the $51.2 million of Grand Gulf
1-related costs originally absorbed and not recovered by NOPSI as part of the
1986 Rate Settlement. In 1991, NOPSI reached a settlement (1991 NOPSI
Settlement) with the Council and with the Alliance that resolved the Grand Gulf
1 prudence issues and the pending litigation related to the February 4
Resolution.
The 1991 NOPSI Settlement supersedes both the 1986 Rate Settlement (which
established a rate phase-in plan designed to reduce the immediate effect on
ratepayers of the inclusion of Grand Gulf 1 costs in rates) and the February 4
Resolution and provides that there will be no further disallowance of the
recovery of any Grand Gulf 1-related costs incurred by NOPSI based on any
alleged imprudence by NOPSI that may have occurred or may be alleged to have
occurred prior to the effective date of the 1991 NOPSI Settlement. The 1991
NOPSI Settlement included the following terms:
(i)
Effective Date Base Electric Rates(1)
---------------- ------------------------
October 4, 1991 $11.3 million decrease(2)
October 31, 1992 $ 7.3 million increase
October 31, 1993 $ 6.7 million increase(3)
October 31, 1994 $ 5.2 million increase
October 31, 1995 $ 4.4 million increase
(1) These changes are subject to adjustment to reflect implementation of the
Least Cost Plan.
(2) The October 4, 1991 decrease partly offset an April 1991 increase of
$18.9 million.
(3) This increase was partially offset by the $4.8 million base rate
reduction described above.
(ii) In connection with the rate changes set forth in (i) above, NOPSI
implemented a finalized phase-in plan covering a ten-year period from
October 1, 1991 through September 30, 2001, for recovery of all Grand
Gulf 1 deferred costs, including associated carrying charges.
(iii) NOPSI agreed to a five-year electric base rate freeze extending
through October 31, 1996, excluding the annual rate increases provided for
in (i) above and except for increases to reflect an increase in state
and/or federal income tax rates or a catastrophic event such as a
hurricane. NOPSI also agreed that during the period October 1, 1993
through October 31, 1996 the Council will have the right to investigate the
appropriateness of NOPSI's rates if NOPSI's return on average equity on its
electric operations (calculated in accordance with the applicable
provisions of the 1991 NOPSI Settlement) for twelve month periods
subsequent to September 30, 1992 were to exceed 13.76%, and, after
hearing(s), to impose a credit on NOPSI's customers' bills in an amount
that would have allowed NOPSI, during the relevant test year, to earn a
return on equity incident to its electric operations of no less than
12.76%. The Council agreed otherwise not to reduce NOPSI's base electric
rates during the period through October 31, 1996 except to reflect a
decrease in state and/or federal income tax rates.
(iv) NOPSI will include in the "over/under" provision of its fuel
adjustment clause, on a monthly basis, the difference, if any, between the
non-fuel Grand Gulf 1 costs billed by System Energy to NOPSI and the
estimate of such costs attached to the 1991 NOPSI Settlement, with the
Council having the right to suspend this provision in the event of a
catastrophe involving Grand Gulf 1. In the event the Council suspends this
provision, NOPSI will have the right to seek a rate increase
notwithstanding (iii) above.
NOPSI recorded on its balance sheet in 1991 as a deferred asset an
additional $90 million of previously incurred Grand Gulf 1-related costs with a
corresponding pretax gain on the income statement. The $90 million represents
the increase in the present value of the recovery stream of deferred Grand
Gulf 1-related costs consistent with the recoverable costs as set forth in
(ii) above. The gain increased 1991 net income by $48.6 million after taxes.
Gas Rate Filing
In May 1992, NOPSI and the Council reached a settlement regarding NOPSI's
application for an increase in gas rates. The settlement includes the following
terms, among others:
(i) an aggregate net rate increase of $7.5 million, effective on
May 22, 1992, phased in over a two-year period. The year one net increase
is stipulated to be $3.8 million, with an additional $3.0 million being
deferred for recovery in equal annual installments in years two through
six. The net increase in year two of $3.7 million includes $730,000 for
recovery of the costs deferred in year one (including associated carrying
charges).
(ii) except as provided above, and except for increases to reflect an
increase in state and/or federal income tax rates or a catastrophic event
such as a hurricane, NOPSI has agreed to a gas base rate freeze through
October 31, 1996.
In addition, the settlement provides that earnings from gas operations will
be included with those from electric operations for purposes of the return on
average equity ceiling provisions of the 1991 NOPSI Settlement (discussed above)
and revises the method of calculating such return on equity ceiling.
NOTE 3. INCOME TAXES
Effective January 1, 1993, NOPSI adopted SFAS 109. This new standard
requires that deferred income taxes be recorded for all temporary differences
and carryforwards, and that deferred tax balances be based on enacted tax laws
at tax rates that are expected to be in effect when the temporary differences
reverse. SFAS 109 requires that regulated enterprises recognize adjustments
resulting from implementation as regulatory assets or liabilities if it is
probable that such amounts will be recovered from or returned to customers in
future rates. A substantial majority of the adjustments required by SFAS 109
was recorded to deferred tax balance sheet accounts with offsetting adjustments
to regulatory assets and liabilities. The cumulative effect of the adoption of
SFAS 109 is included in income tax expense charged to operations. As a result
of the adoption of SFAS 109, 1993 net income was increased by $0.3 million,
assets were increased by $4.1 million, and liabilities were increased by $3.8
million.
Income tax expense consisted of the following:
For the Years Ended December 31,
--------------------------------
1993 1992 1991
------- ------- ------
(In Thousands)
Current:
Federal $23,400 $16,575 $8,885
State 4,079 - -
------- ------- -------
Total 27,479 16,575 8,885
------- ------- -------
Deferred - net:
Rate deferrals - net (7,395) (1,185) 20,548
1989 Settlement Agreement - - 1,821
Net operating loss carryforward utilization 42 2,747 15,186
Unbilled revenue 4,621 (2,800) 1,513
Pension expense 2,935 (1,044) (1,041)
Liberalized depreciation (19) (286) (469)
Deferred fuel or gas costs 2,251 1,904 (479)
Bond reacquisition 1,074 328 -
Alternative Minimum Tax 2,317 (3) (590)
Other (623) (1) 458
------- ------- -------
Total 5,203 (340) 36,947
------- ------- -------
Investment tax credit adjustments - net (743) (170) (592)
------- ------- -------
Recorded income tax expense $31,939 $16,065 $45,240
======= ======= =======
Charged to operations $24,232 $14,382 $41,998
Charged to other income 1,115 1,683 3,242
Charged to cumulative income 6,592 - -
------- ------- -------
Total income taxes $31,939 $16,065 $45,240
======= ======= =======
Total income taxes differ from the amounts computed by applying the
statutory federal income tax rate to income before taxes. The reasons for the
differences were:
For the Years Ended December 31,
----------------------------------------------------
1993 1992 1991
--------------- ---------------- ----------------
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
------ ------ ------- ------ ------- ------
(Dollars in Thousands)
Computed at statutory rate $27,877 35.0 $14,446 34.0 $40,779 34.0
Increases (reductions) in tax resulting from:
State income taxes net of federal income
tax effect 3,411 4.3 1,462 3.5 4,420 3.7
Depreciation (780) (1.0) (731) (1.7) (654) (0.6)
Amortization of investment tax credits (745) (0.9) (752) (1.8) (650) (0.6)
Recapture of prior years' consolidated
income tax savings 323 0.4 481 1.1 1,180 1.0
Amortization of excess deferred income tax 384 0.5 376 0.9 376 0.3
Adjustment of prior year taxes 2,413 3.0 391 0.9 (400) (0.3)
SFAS 109 adjustment (1,170) (1.5) - - - -
Other--net 226 0.3 391 0.9 189 0.2
------- ---- ------- ---- ------- ----
Total income taxes $31,939 40.1 $16,064 37.8 $45,240 37.7
======= ==== ======= ==== ======= ====
Significant components of NOPSI's net deferred tax liabilities as of
December 31, 1993, were (in thousands):
Deferred tax liabilities:
Net regulatory assets $(13,465)
Plant related basis differences (49,753)
Rate deferrals (80,380)
Other (5,194)
---------
Total $(148,792)
=========
Deferred tax assets:
Unbilled revenues $5,812
Accumulated deferred investment tax credit 4,460
Pension related items 5,804
Removal cost 8,197
Standard coal plant 2,861
Operating reserves 6,934
Other 4,660
---------
Total $38,728
=========
Net deferred tax liabilities $(110,064)
=========
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized NOPSI to effect short-term borrowings of up to
$43 million. This authorization is effective through November 30, 1994. In
addition, NOPSI can borrow from the Money Pool, subject to its maximum
authorized level of short-term borrowings and the availability of funds.
NOPSI's short-term borrowings are also limited by the terms of its G&R Bond
indenture to amounts not exceeding, in general, the greater of 10% of
capitalization or 50% of Grand Gulf 1 rate deferrals available to support the
issuance of G&R Bonds. NOPSI had no outstanding short-term borrowings under
these arrangements as of December 31, 1993.
NOTE 5. PREFERRED STOCK
The number of shares and dollar value of NOPSI's cumulative, $100 par value
preferred stock was:
As of December 31,
---------------------------------
Shares Call Price Per
Authorized and Total Share as of
Outstanding Dollar Value December 31,
1993 1992 1993 1992 1993
------- ------- ------- ------- ------------
(Dollars in Thousands)
Without sinking fund:
4 3/4% Preferred Stock 77,798 77,798 $7,780 $7,780 $105.00
4.36% Series 60,000 60,000 6,000 6,000 $104.58
5.56% Series 60,000 60,000 6,000 6,000 $102.59
------- ------- ------- -------
Total without sinking fund 197,798 197,798 $19,780 $19,780
======= ======= ======= =======
With sinking fund:
15.44% Series 49,495 64,495 $4,950 $6,450 $107.72
======= ======= ====== ======
The fair value of NOPSI's preferred stock with sinking fund was estimated
to be approximately $5.3 million and $6.5 million as of December 31, 1993 and
1992, respectively. The fair value was determined using quoted market prices or
estimates from nationally recognized investment banking firms. See Note 1 for
additional information on disclosure of fair value of financial instruments.
Changes in the preferred stock during the last three years were:
Number of Shares
-------------------------------
1993 1992 1991
--------- -------- --------
Preferred stock retirements:
$100 par value (15,000) (15,000) (15,000)
Cash sinking fund requirements for the next five years for preferred stock
outstanding as of December 31, 1993, are $750,000 annually. NOPSI has the
annual non-cumulative option to redeem, at par, up to an additional $750,000 of
its 15.44% Series preferred stock outstanding.
NOPSI has regulatory authorization for the issuance and sale through
December 31, 1994, of up to $20 million of preferred stock and, for the
acquisition through December 31, 1994, of up to $6.5 million of its outstanding
preferred stock.
NOTE 6. LONG-TERM DEBT
NOPSI's long-term debt as of December 31, 1993 and 1992, was:
Maturities Interest Rates
From To From To 1993 1992
---- ---- ----- ---- ------- -------
(In Thousands)
First Mortgage Bonds
1994 1998 5-5/8% 11.0% $35,250 $60,250
2004 2008 9-1/2% 10.0% - 30,000
G&R Bonds
1993 1998 10.95% 13.9% 69,200 113,600
1999 2023 7.0% 8.0% 100,000 -
Unamortized Premium and Discount-Net (1,138) 17
-------- --------
Total Long-Term Debt 203,312 203,867
Less Amount Due Within One Year 15,000 44,400
-------- --------
Long-Term Debt Excluding Amount Due Within One Year $188,312 $159,467
======== ========
The fair value of NOPSI's long-term debt as of December 31, 1993 and 1992
was estimated to be (in millions) $211.5 and $216.1 respectively. Fair values
were determined using bid prices reported by dealer markets and by nationally
recognized investment banking firms. See Note 1 for additional information on
disclosure of fair value of financial instruments.
For the years 1994, 1995, 1996, 1997, and 1998, NOPSI has long-term debt
maturities and cash sinking fund requirements of (in millions) $15, $24.2,
$38.3, $27, and $0, respectively. In addition, other sinking fund requirements
of approximately $0.2 million annually may be satisfied by cash or by
certification of property additions at the rate of 167% of such requirements.
NOPSI has regulatory authorization for the issuance and sale through
December 31, 1994, of up to $145 million of G&R Bonds (of which $45 million
remained available as of December 31, 1993) and for the acquisition, through
December 31, 1994, in whole or in part, prior to their respective maturities, of
up to $135 million of its outstanding first mortgage and/or G&R Bonds.
Under NOPSI's G&R Mortgage, G&R Bonds are issuable based upon 70% of
bondable property additions or based upon 50% of accumulated deferred Grand
Gulf 1-related costs. The G&R Mortgage precludes the issuance of any additional
G&R Bonds if the total amount of outstanding Rate Recovery Mortgage Bonds issued
on the basis of the uncollected balance of deferred Grand Gulf 1-related costs
exceeds 66 2/3% of the balance of such deferred costs. As of December 31, 1993,
the total amount of Rate Recovery Mortgage Bonds outstanding aggregated
$69.2 million, or 30.2% of NOPSI's accumulated deferred Grand Gulf 1-related
costs.
NOTE 7. DIVIDEND RESTRICTIONS
NOPSI's Restatement of Articles of Incorporation, as amended, and certain
of its indentures contain provisions restricting the payment of cash dividends
or other distributions on common stock. As of December 31, 1993, $24.2 million
of NOPSI's retained earnings were restricted against the payment of cash
dividends or other distributions on common stock.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Capital Requirements and Financing
Construction expenditures for the years 1994, 1995, and 1996 are estimated
to total $26 million each year. NOPSI will also require $80 million during the
period 1994-1996 to meet long-term debt and preferred stock maturities and cash
sinking fund requirements. NOPSI plans to meet the above requirements with
internally generated funds and cash on hand. See Notes 5 and 6 regarding the
possible refinancing, redemption, purchase, or other acquisition of certain
outstanding series of preferred stock and long-term debt.
Unit Power Sales Agreement
System Energy has agreed to sell all of its 90% owned and leased share of
capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in
accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI
17%) as ordered by FERC. Charges under this agreement are paid in consideration
for NOPSI's respective entitlement to receive capacity and energy, and are
payable irrespective of the quantity of energy delivered so long as the unit
remains in commercial operation. The agreement will remain in effect until
terminated by the parties and approved by FERC, most likely upon Grand Gulf 1's
retirement from service. NOPSI's monthly obligation for payments under the
agreement is approximately $9 million.
Availability Agreement
AP&L, LP&L, MP&L, and NOPSI are individually obligated to make payments or
subordinated advances to System Energy in accordance with stated percentages
(AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 24.7%) in amounts that when added
to amounts received under the Unit Power Sales Agreement or otherwise, are
adequate to cover all of System Energy's operating expenses. System Energy has
assigned its rights to payments and advances to certain creditors as security
for certain obligations. Payments or advances under the Availability Agreement
are only required if funds available to System Energy from all sources are less
than the amount required under the Availability Agreement. Since commercial
operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have
exceeded the amounts payable under the Availability Agreement. Accordingly, no
payments have ever been required. In 1989, the Availability Agreement was
amended to provide that the write-off of $900 million of Grand Gulf 2 costs
would be amortized for Availability Agreement purposes over a period of 27
years, in order to avoid the need for payments by AP&L, LP&L, MP&L, and NOPSI.
If AP&L, LP&L, or MP&L fails to make its Unit Power Sales Agreement payments,
and System Energy is unable to obtain funds from other sources, NOPSI could be
liable for payments to System Energy, in amounts that cannot be determined, over
and above its payments under the Unit Power Sales Agreement.
Reallocation Agreement
System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation
Agreement relating to the sale of capacity and energy from the Grand Gulf
Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume
all of AP&L's responsibilities and obligations with respect to the Grand Gulf
Station under the Availability Agreement. FERC's decision allocating a portion
of Grand Gulf 1 capacity and energy to AP&L supersedes the Reallocation
Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2
amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%,
and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the
Reallocation Agreement does not affect AP&L's obligation to System Energy's
lenders under the assignments referred to in the preceding paragraph. AP&L
would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were
unable to meet their contractual obligations. No payments of any amortization
amounts will be required as long as amounts paid to System Energy under the Unit
Power Sales Agreement, including other funds available to System Energy, exceed
amounts required under the Availability Agreement, which is expected to be the
case for the foreseeable future.
System Fuels
NOPSI has a 13% interest in System Fuels, a jointly owned subsidiary of
AP&L, LP&L, MP&L, and NOPSI. The parent companies of System Fuels, including
NOPSI, agreed to make loans to System Fuels to finance its fuel procurement,
delivery, and storage activities. As of December 31, 1993, NOPSI had
approximately $3.3 million of loans outstanding to System Fuels which mature in
2008.
City Franchise Ordinances
NOPSI provides electric and gas service in the City of New Orleans pursuant
to City franchise ordinances which state, among other things, that the City has
a continuing option to purchase NOPSI's electric and gas utility properties.
NOTE 9. POSTRETIREMENT BENEFITS
Pension Plan
NOPSI is a participating employer in a defined benefit pension plan
sponsored by LP&L, covering substantially all employees. The pension plan is
noncontributory and provides pension benefits based on employees' credited
service and average compensation, generally during the last five years before
retirement. Pension costs are funded in accordance with contribution guidelines
established by the Employee Retirement Income Security Act of 1974, as amended,
and the Internal Revenue Code of 1986, as amended. The assets of the plan
consist primarily of common and preferred stocks, fixed income securities,
interest in a money market fund, and insurance contracts.
NOPSI's 1993, 1992, and 1991 pension cost, including amounts capitalized,
included the following components:
For the Years Ended December 31,
--------------------------------
1993* 1992* 1991*
------- ------ -------
(In Thousands)
Service cost - benefits earned during the period $1,387 $1,253 $1,366
Interest cost on projected benefit obligation 2,422 2,119 1,572
Net amortization and deferral (49) 173 35
Other - - 600
------ ------ ------
Net pension cost $3,760 $3,545 $3,573
====== ====== ======
* Pension cost represents NOPSI's allocated portion of the total pension
expense (as calculated by an independent actuary) for the defined benefit
pension plan sponsored by LP&L.
The funded status of LP&L's pension plan allocable to NOPSI employees as of
December 31, 1993 and 1992, was:
1993 1992
------- -------
(In Thousands)
Actuarial present value of accumulated pension plan benefits:
Vested $26,173 $22,276
Nonvested 36 26
------- -------
Accumulated benefit obligation $26,209 $22,302
======= ========
Plan assets at fair value $7,523 $ (2,289)
Projected benefit obligation 36,831 29,944
-------- --------
Plan assets less than projected benefit obligation (29,308) (32,233)
Unrecognized prior service cost 2,462 2,702
Unrecognized transition asset (1,354) (1,550)
Unrecognized net loss 12,184 7,920
-------- --------
(16,016) (23,161)
Unfunded portion of NOPSI pension liability 12,256 23,161
-------- --------
Accrued pension liability $ (3,760) $ -
======== ========
The significant actuarial assumptions used in computing the information
above for 1993, 1992, and 1991 were as follows: weighted average discount rate,
7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in
future compensation levels, 5.6%; and expected long-term rate of return on plan
assets, 8.5%. Transition assets are being amortized over the average remaining
service period of active participants.
Other Postretirement Benefits
NOPSI also provides certain health care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits if they reach retirement age while still working for NOPSI. The cost
of providing these benefits, recorded on a cash basis, to retirees in 1992 was
approximately $3.7 million. Prior to 1992, the cost of providing these benefits
for retirees was not separable from the cost of providing benefits for active
employees. Based on the ratio of the number of retired employees to the total
number of active and retired employees in 1991, the cost of providing these
benefits in 1991, recorded on a cash basis, for retirees was approximately $2.6
million.
Effective January 1, 1993, NOPSI adopted SFAS 106. The new standard
requires a change from a cash method to an accrual method of accounting for
postretirement benefits other than pensions. NOPSI continues to fund these
benefits on a pay-as-you-go basis. As of January 1, 1993, the actuarially
determined accumulated postretirement benefit obligation (APBO) earned by
retirees and active employees was estimated to be approximately $53.6 million.
This obligation is being amortized over a 20-year period beginning in 1993.
NOPSI is expensing its SFAS 106 costs pursuant to resolutions adopted in
November 1993 by the Council related to the Merger. NOPSI's SFAS 106 expenses
through October 31, 1996, will be allowed by the Council for purposes of
evaluating the appropriateness of NOPSI's rates. NOPSI's net income in 1993 was
decreased by approximately $2.2 million as a result of adopting SFAS 106.
NOPSI's 1993 postretirement benefit cost, including amounts capitalized and
deferred, included the following components (in thousands):
Service cost - benefits earned during the period $822
Interest cost on APBO 4,248
Actual return on plan assets -
Amortization of transition obligation 2,678
------
Net periodic postretirement benefit cost $7,748
======
The funded status of NOPSI's postretirement plan as of December 31, 1993,
was (in thousands):
Accumulated postretirement benefit obligation:
Retirees $46,218
Other fully eligible participants 3,565
Other active participants 9,152
-------
58,935
Plan assets at fair value -
-------
Plan assets less than APBO (58,935)
Unrecognized transition obligation 50,895
Unrecognized net loss 4,835
-------
Accrued post retirement benefit liability $(3,205)
=======
The assumed health care cost trend rate used in measuring the APBO was 9.9%
for 1994, gradually decreasing each successive year until it reaches 5.6% in
2020. A one percentage-point increase in the assumed health care cost trend
rate for each year would have increased the APBO as of December 31, 1993, by
7.7% and the sum of the service cost and interest cost by approximately 9.6%
The assumed discount rate and rate of increase in future compensation used in
determining the APBO were 7.5% and 5.5%, respectively.
NOTE 10. TRANSACTIONS WITH AFFILIATES
NOPSI buys electricity from and/or sells electricity to AP&L, LP&L, MP&L,
and System Energy under rate schedules filed with FERC. In addition, NOPSI
purchases fuel from System Fuels and receives technical and advisory services
from Entergy Services, Inc.
Operating revenues include revenues from sales to affiliates amounting to
$2.5 million in 1993, $3.1 million in 1992, and $2.8 million in 1991. Operating
expenses include charges from affiliates for fuel costs, purchased power and
related charges, and technical and advisory services totaling $176.3 million in
1993, $183.0 million in 1992, and $187.9 million in 1991.
NOTE 11. BUSINESS SEGMENT INFORMATION
NOPSI supplies electric and natural gas services in the City. NOPSI's
segment information follows:
1993 1992 1991
----------------- ------------------ ----------------------
Electric Gas Electric Gas Electric Gas
-------- ------- -------- ------- -------- -------
(In Thousands)
Operating revenues $423,830 $90,992 $391,936 $72,943 $399,214 $76,951
Revenue from sales to
unaffiliated customers (1) $421,343 $90,992 $388,851 $72,943 $396,456 $76,951
Operating income (loss)
before income taxes $ 72,572 $11,412 $ 63,167 $ 1,264 $143,031 (2) $(3,411)
Operating income (loss) $ 52,046 $ 7,706 $ 47,194 $ 2,855 $ 98,096 (2) $ (474)
Net utility plant $211,776 $63,803 $206,402 $61,783 $204,200 $59,237
Depreciation expense $ 14,308 $ 2,976 $ 13,776 $ 2,843 $ 13,278 $ 2,695
Construction expenditures $ 19,774 $ 5,039 $ 15,724 $ 5,319 $ 18,084 $ 4,451
(1) NOPSI's intersegment transactions are not material (less than 1% of sales
to unaffiliated customers).
(2) Operating income before income taxes and operating income reflect a
nonrecurring increase of $90.0 million and $48.6 million, respectively, in
connection with the 1991 NOPSI Settlement.
NOTE 12. QUARTERLY FINANCIAL DATA (UNAUDITED)
NOPSI's business is subject to seasonal fluctuations with the peak periods
occurring during the third quarter for electric and during the first quarter for
gas. Operating results for the four quarters of 1993 and 1992 were:
Net
Operating Operating Income
Revenues Income (Loss)
--------- --------- ------
(In Thousands)
1993:
First Quarter (1) $108,566 $ 8,828 $14,930
Second Quarter $120,182 $17,789 $12,714
Third Quarter $154,610 $29,648 $24,843
Fourth Quarter $131,464 $ 3,487 $(4,778)
1992:
First Quarter $106,598 $11,423 $ 5,819
Second Quarter $101,993 $ 7,382 $ 1,672
Third Quarter $139,362 $25,551 $19,931
Fourth Quarter $116,926 $ 5,693 $ (998)
(1) The first quarter of 1993 reflects a nonrecurring increase in net income of
$10.9 million, net of taxes of $6.6 million, due to the recording of the
cumulative effect of the change in accounting principle for unbilled
revenues (see Note 1). Beginning with the second quarter, the remaining
quarters are not generally comparable to prior year quarters because of the
ongoing effects of the accounting change.
NEW ORLEANS PUBLIC SERVICE INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1993 1992 1991 1990 1989
--------- -------- -------- -------- --------
(In Thousands)
Operating revenues $514,822 $464,879 $476,165 $485,246 $470,909
Income before cumulative
effect of a change in
accounting principle $ 36,761 $ 26,424 $ 74,699 $ 27,542 $ 14,464
Total assets $647,605 $621,691 $685,217 $577,283 $564,251
Long-term obligations (1) $193,262 $165,917 $231,901 $243,239 $261,495
(1) Includes long-term debt (excluding currently maturing debt) and preferred
stock with sinking fund.
See Notes 1, 3, and 9 for the effect of accounting changes in 1993.
1993 1992 1991 1990 1989
-------- -------- -------- -------- --------
(Dollars in Thousands)
Electric Operating Revenues:
Residential $151,423 $137,668 $136,030 $141,900 $134,000
Commercial 167,788 160,229 159,118 162,600 158,000
Industrial 26,205 23,860 24,062 27,000 25,200
Governmental 61,548 56,023 55,097 53,500 51,500
-------- -------- -------- -------- --------
Total retail 406,964 377,780 374,307 385,000 368,700
Sales for resale 11,778 10,320 9,805 8,400 8,000
Other 5,088 3,836 15,102 3,900 3,800
-------- -------- -------- -------- --------
Total $423,830 $391,936 $399,214 $397,300 $380,500
======== ======== ======== ======== ========
Billed Electric Energy Sales
(Millions of KWH):
Residential 1,914 1,806 1,844 1,903 1,830
Commercial 1,989 1,977 2,023 2,054 2,035
Industrial 499 457 487 530 490
Governmental 924 888 887 846 837
-------- -------- -------- -------- --------
Total retail 5,326 5,128 5,241 5,333 5,192
Sales for resale 351 405 418 294 284
-------- -------- -------- -------- --------
Total 5,677 5,533 5,659 5,627 5,476
======== ======== ======== ======== ========
System Energy Resources, Inc.
1993 Financial Statements
SYSTEM ENERGY RESOURCES, INC.
DEFINITIONS
Certain abbreviations or acronyms used in System Energy's Financial
Statements, Notes to Financial Statements, and Management's Financial Discussion
and Analysis are defined below:
Abbreviation or Acronym Term
AFUDC Allowance for Funds Used During Construction
ALJ Administrative Law Judge
AP&L Arkansas Power & Light Company
APSC Arkansas Public Service Commission
Capital Funds Agreement Agreement, dated as of June 21, 1974, as amended,
between System Energy and Entergy Corporation, and the
assignments thereof
City of New Orleans
or City New Orleans, Louisiana
DOE United States Department of Energy
Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy
Corporation that has operating responsibility for Grand
Gulf 1, Waterford 3, ANO, and River Bend
Entergy or System Entergy Corporation and its various direct and indirect
subsidiaries
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FERC Complaint Case
Settlement Settlement, effective May 21, 1991, whereby System
Energy credited approximately $47.6 million in the
aggregate (including interest) against its June 1991
bills to AP&L, LP&L, MP&L, and NOPSI for capacity and
energy from Grand Gulf 1
FERC Return on Equity
Case Settlement, effective October 25, 1993, whereby System
Energy refunded approximately $29.6 million in the
aggregate (including interest) against its October 1993
bills to AP&L, LP&L, MP&L, and NOPSI when FERC reduced
System Energy's Return on Equity from 13% to 11%
prospectively from November 3, 1992
Grand Gulf Station Grand Gulf Steam Electric Generating Station
Grand Gulf 1 Unit No. 1 of the Grand Gulf Station
Grand Gulf 2 Unit No. 2 of the Grand Gulf Station
GSU Gulf States Utilities Company (including wholly owned
subsidiaries - Varibus Corporation, GSG&T, Inc.,
Prudential Oil and Gas, Inc., and Southern Gulf Railway
Company)
KWH Kilowatt-Hours
LP&L Louisiana Power & Light Company
LPSC Louisiana Public Service Commission
Money Pool Entergy Money Pool which allows certain System
companies to borrow from, or lend to, certain other
System companies
MP&L Mississippi Power & Light Company
MPSC Mississippi Public Service Commission
NOPSI New Orleans Public Service Inc.
NRC Nuclear Regulatory Commission
OBRA Omnibus Budget Reconciliation Act of 1993
Reallocation Agreement 1981 Agreement, superseded in part by a June 13, 1985
decision of FERC, among AP&L, LP&L, MP&L, NOPSI, and
System Energy relating to the sale of capacity and
energy from the Grand Gulf Station
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards promulgated
by the FASB
SFAS 109 SFAS No. 109, "Accounting for Income Taxes"
SMEPA South Mississippi Electric Power Association
System or Entergy Entergy Corporation and its various direct and indirect
subsidiaries
System Energy System Energy Resources, Inc.
System Fuels System Fuels, Inc.
System operating
companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively
Unit Power Sales
Agreement Agreement, dated as of June 10, 1982, as amended, among
AP&L, LP&L, MP&L, NOPSI, and System Energy, relating to
the sale of capacity and energy from System Energy's
share of Grand Gulf 1
SYSTEM ENERGY RESOURCES, INC.
REPORT OF MANAGEMENT
The management of System Energy Resources, Inc. has prepared and is
responsible for the financial statements and related financial information
included herein. The financial statements are based on generally accepted
accounting principles. Financial information included elsewhere in this report
is consistent with the financial statements.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting controls that
is designed to provide reasonable assurance, on a cost-effective basis, as to
the integrity, objectivity, and reliability of the financial records, and as to
the protection of assets. This system includes communication through written
policies and procedures, an employee Code of Conduct, and an organizational
structure that provides for appropriate division of responsibility and the
training of personnel. This system is also tested by a comprehensive internal
audit program.
The independent public accountants provide an objective assessment of the
degree to which management meets its responsibility for fairness of financial
reporting. They regularly evaluate the system of internal accounting controls
and perform such tests and other procedures as they deem necessary to reach and
express an opinion on the fairness of the financial statements.
Management believes that these policies and procedures provide reasonable
assurance that its operations are carried out with a high standard of business
conduct.
/S/ DONALD C. HINTZ /S/ GERALD D. MCINVALE
DONALD C. HINTZ GERALD D. MCINVALE
President and Chief Executive Officer Senior Vice President and
Chief Financial Officer
SYSTEM ENERGY RESOURCES, INC.
AUDIT COMMITTEE CHAIRMAN'S LETTER
The Entergy Operations Board of Directors' Audit Committee functions as the
Audit Committee for System Energy. The Audit Committee is comprised of three
directors, who are not officers of System Energy or Entergy Operations: Brooke
H. Duncan (Chairman), Robert D. Pugh, and William Clifford Smith. The
committee held four meetings during 1993.
The Audit Committee oversees System Energy's financial reporting process on
behalf of the Board of Directors and provides reasonable assurance to the Board
that sufficient operating, accounting, and financial controls are in existence
and are adequately reviewed by programs of internal and external audits.
The Audit Committee discussed with Entergy's internal auditors and the
independent public accountants (Deloitte & Touche) the overall scope and
specific plans for their respective audits, as well as System Energy's financial
statements and the adequacy of System Energy's internal controls. The committee
met, together and separately, with Entergy's internal auditors and independent
public accountants, without management present, to discuss the results of their
audits, their evaluation of System Energy's internal controls, and the overall
quality of System Energy's financial reporting. The meetings also were designed
to facilitate and encourage any private communication between the committee and
the internal auditors or independent public accountants.
/S/ BROOKE H. DUNCAN
BROOKE H. DUNCAN
Chairman, Audit Committee
INDEPENDENT AUDITORS' REPORT
To the Shareholder and the Board of Directors of
System Energy Resources, Inc.
We have audited the accompanying balance sheets of System Energy Resources,
Inc. (System Energy) as of December 31, 1993 and 1992, and the related
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1993. These financial statements are the
responsibility of System Energy's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of System Energy at December 31, 1993 and 1992,
and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 1993 in conformity with generally accepted
accounting principles.
As discussed in Note 2, "Rate and Regulatory Matters - FERC Audit" of Notes
to Financial Statements, a regulatory proceeding is pending, which, if
ultimately resolved in an adverse manner, would require that System Energy (1)
write off and not recover in rates approximately $95 million of costs charged to
utility plant resulting from System Energy's accounting for certain allocated
income tax charges and (2) make refunds for overcollections from the Entergy
System operating companies related thereto. The ultimate outcome of this
uncertainty cannot presently be determined. Accordingly, no provision has been
made in the accompanying financial statements for the possible effects of a
decision adverse to System Energy.
As discussed in Note 3 to the financial statements, in 1993 System Energy
changed its method of accounting for income taxes.
/S/ DELOITTE & TOUCHE
DELOITTE & TOUCHE
New Orleans, Louisiana
February 11, 1994
SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
ASSETS
December 31,
-------------------------
1993 1992
---------- ----------
(In Thousands)
Utility Plant (Note 1):
Electric $3,027,537 $3,019,241
Electric plant under lease (Note 8) 437,941 437,317
Construction work in progress 41,442 30,658
Nuclear fuel under capital lease (Note 7 and 8) 79,625 67,991
---------- ----------
Total 3,586,545 3,555,207
Less - accumulated depreciation 669,666 572,302
---------- ----------
Utility plant - net 2,916,879 2,982,905
---------- ----------
Other Investments:
Decommissioning trust funds (Note 7) 24,787 19,127
---------- ----------
Current Assets:
Cash and cash equivalents (Note 1):
Cash 2,424 -
Temporary cash investments - at cost,
which approximates market:
Associated companies (Note 4) 46,601 13,993
Other 147,107 167,802
---------- ----------
Total cash and cash equivalents 196,132 181,795
Accounts receivable:
Associated companies (Note 10) 57,216 60,601
Other 2,057 4,871
Materials and supplies - at average cost 69,765 71,660
Recoverable income taxes (Note 3) 63,400 47,900
Prepayments and other 4,835 3,497
---------- ----------
Total 393,405 370,324
---------- ----------
Deferred Debits:
Recoverable income taxes (Note 3) 29,289 174,941
SFAS 109 regulatory asset - net (Note 3) 384,317 -
Unamortized loss on reacquired debt 17,258 14,723
Other (Note 7 and 8) 125,131 110,421
---------- ----------
Total 555,995 300,085
---------- ----------
TOTAL $3,891,066 $3,672,441
========== ==========
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
-------------------------
1993 1992
---------- ----------
(In Thousands)
Capitalization:
Common stock, no par value, authorized
1,000,000 shares; issued and outstanding
789,350 shares in 1993 and 1992 $789,350 $789,350
Paid-in capital 7 -
Retained earnings (Note 6) 228,574 367,747
---------- ----------
Total common shareholder's equity 1,017,931 1,157,097
Long-term debt (Note 5) 1,511,914 1,755,308
---------- ----------
Total 2,529,845 2,912,405
---------- ----------
Other Noncurrent Liabilities:
Obligations under capital leases (Note 8) 24,679 12,991
Other (Note 7) 18,229 18,919
---------- ----------
Total 42,908 31,910
---------- ----------
Current Liabilities:
Currently maturing long-term debt (Note 5) 230,000 30,000
Accounts payable:
Associated companies (Note 10) 1,928 2,164
Other 18,223 33,110
Taxes accrued 20,952 23,224
Interest accrued 48,929 50,560
Obligations under capital leases (Note 8) 55,000 55,000
Other 2,805 530
---------- ----------
Total 377,837 194,588
---------- ----------
Deferred Credits:
Accumulated deferred income taxes (Note 3) 775,630 349,081
Accumulated deferred investment tax credits (Note 3) 113,849 144,284
Other 50,997 40,173
---------- ----------
Total 940,476 533,538
---------- ----------
Commitments and Contingencies (Notes 2, 7, and 8)
TOTAL $3,891,066 $3,672,441
========== ==========
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
-------------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Operating Activities:
Net income $93,927 $130,141 $104,622
Noncash items included in net income:
Depreciation and decommissioning 90,920 85,932 85,986
Deferred income taxes and investment tax credits 15,832 70,356 79,660
Allowance for equity funds used during construction (772) (681) (763)
Amortization of debt discount 4,520 6,417 7,495
Changes in working capital:
Receivables 6,199 225 (5,530)
Accounts payable (15,123) (30,517) 37,511
Taxes accrued (2,272) 2,672 (178)
Interest accrued (1,631) 1,252 (10,245)
Other working capital accounts 2,832 (4,412) 15,716
Recoverable income taxes (Note 3) 130,152 (3,475) (14,277)
Decommissioning trust contributions (4,911) (5,641) (2,201)
Other (1,617) 86 (15,454)
-------- -------- --------
Net cash flow provided by operating activities 318,056 252,355 282,342
-------- -------- --------
Investing Activities:
Construction expenditures (23,083) (21,671) (21,663)
Allowance for equity funds used during construction 772 681 763
Nuclear fuel purchases (32,822) (13,724) (28,922)
Proceeds from sale and leaseback of nuclear fuel 32,822 28,094 14,552
Change in other temporary investments - - 125,225
-------- -------- --------
Net cash flow provided by (used in) investing activities (22,311) (6,620) 89,955
-------- -------- --------
Financing Activities:
Proceeds from the issuance of first mortgage bonds 60,000 220,000 -
Retirement of first mortgage bonds (108,308) (240,750) (294,000)
Common stock dividend payments (233,100) (137,700) (115,785)
-------- -------- --------
Net cash flow used in financing activities (281,408) (158,450) (409,785)
-------- -------- --------
Net increase (decrease) in cash and cash equivalents 14,337 87,285 (37,488)
Cash and cash equivalents at beginning of period 181,795 94,510 131,998
-------- -------- --------
Cash and cash equivalents at end of period $196,132 $181,795 $94,510
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized $186,786 $201,287 $238,199
Income taxes (refund) ($65,992) $21,431 ($12,667)
Noncash investing and financing activities:
Capital lease obligations incurred $45,089 $28,094 $14,552
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
The financial condition of System Energy significantly depends on the
continued commercial operation of Grand Gulf 1 and on the receipt of payments
from AP&L, LP&L, MP&L, and NOPSI. Payments under the Unit Power Sales Agreement
are System Energy's only source of operating revenues. Net cash flow from
operations totaled $318 million, $252 million, and $282 million in 1993, 1992,
and 1991, respectively. In recent years, this cash flow has been sufficient to
meet substantially all investing and financing requirements, including capital
expenditures, dividends, and debt maturities. See Note 7, incorporated herein
by reference, for information on System Energy's capital and refinancing
requirements in 1994 - 1996. Further, in order to take advantage of lower
interest rates, System Energy may continue to refinance high-cost debt prior to
maturity.
In addition, System Energy's financial condition could be affected by the
outcome of a pending FERC audit matter. In December 1990, FERC Division of
Audits issued a report for System Energy that recommended that System Energy
write off and not recover in its rates approximately $95 million of Grand Gulf 1
costs included in utility plant, and compute refunds for over collections from
AP&L, LP&L, MP&L, and NOPSI. In August 1992, FERC issued an opinion and order
(August 4 Order) affirming an initial decision by a FERC ALJ. System Energy
filed a Request for Rehearing, and in October 1992, FERC issued an order
allowing additional time for its consideration of the request, and it deferred
System Energy's refund obligation until 30 days after FERC issues an order on
rehearing. If the decision is implemented, System Energy estimates that as of
December 31, 1993, net income would be reduced by $151.6 million. This amount
includes refund obligations of approximately $113.0 million (including
interest). See Note 2, incorporated herein for reference, for additional
information.
Earnings coverage tests, bondable property additions, and equity ratio
requirements contained in its mortgage, and in its letters of credit and
reimbursement agreement in connection with its sale and leaseback transactions,
limit the amount of first mortgage bonds that System Energy can issue. Based on
the most restrictive applicable tests as of December 31, 1993, and assuming an
annual interest rate of 8%, System Energy could have issued $290 million of
additional first mortgage bonds. System Energy has the conditional ability to
issue first mortgage bonds against the retirement of first mortgage bonds, in
some cases, without satisfying an earnings coverage test.
In connection with the financing of Grand Gulf 1, Entergy Corporation has
undertaken, in the Capital Funds Agreement, to provide to System Energy
sufficient capital to (1) maintain System Energy's equity capital at an amount
equal to at least 35% of System Energy's total capitalization (excluding
short-term debt), (2) permit the continuation of commercial operation of Grand
Gulf 1, and (3) enable System Energy to pay in full all borrowings, whether at
maturity, on prepayment, on acceleration, or otherwise. In addition, Entergy
Corporation has agreed in the Capital Funds Agreement to make certain cash
capital contributions, if required, to enable System Energy to make payments
when due on specific issues of its long-term debt.
See Note 4, incorporated herein by reference, for information regarding
System Energy's short-term borrowings.
SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF INCOME
For the Years Ended December 31,
---------------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Operating Revenues (Note 2): $650,768 $723,410 $686,664
-------- -------- --------
Operating Expenses:
Operation (Note 10):
Fuel for electric generation
and fuel-related expenses 42,296 55,110 78,060
Other 114,086 102,971 79,494
Maintenance (Note 10) 21,263 29,370 14,358
Depreciation and decommissioning (Note 7) 90,920 90,628 87,296
Taxes other than income taxes 26,589 28,717 27,342
Income taxes (Note 3) 83,412 93,438 81,302
-------- -------- --------
Total 378,566 400,234 367,852
-------- -------- --------
Operating Income 272,202 323,176 318,812
-------- -------- --------
Other Income:
Allowance for equity funds used
during construction 772 681 763
Miscellaneous - net 6,518 5,816 6,378
Income taxes (Notes 1 and 3) 4,859 4,584 7,726
-------- -------- --------
Total 12,149 11,081 14,867
-------- -------- --------
Interest Charges:
Interest on long-term debt 184,818 196,618 218,538
Other interest - net 6,120 7,923 11,111
Allowance for borrowed funds used
during construction (514) (425) (592)
-------- -------- --------
Total 190,424 204,116 229,057
-------- -------- --------
Net Income $93,927 $130,141 $104,622
======== ======== ========
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
----------------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Retained Earnings, January 1 $367,747 $375,306 $386,469
Add:
Net income 93,927 130,141 104,622
-------- -------- --------
Total 461,674 505,447 491,091
-------- -------- --------
Deduct:
Dividends declared 233,100 137,700 115,785
-------- -------- --------
Retained Earnings, December 31 (Note 6) $228,574 $367,747 $375,306
======== ======== ========
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Net income decreased in 1993 primarily due to the impact of the FERC
Return on Equity Case settlement regarding the return on equity component of
System Energy's formula wholesale rates (see Note 2, incorporated herein by
reference). This decrease in revenue was partially offset by a reduction in
interest expense due to the refinancing of high-cost debt.
Net income increased in 1992 primarily due to the impact of the FERC
Complaint Case settlement recorded in June 1991, which reduced net income in
1991. See Note 2, incorporated herein by reference, for further information on
this settlement. In addition, 1992 net income was impacted by a reduction in
interest expense (as a result of the repayment of and refunding of higher cost
debt) not recovered through rates and the lower return System Energy earned on
its net investment in Grand Gulf 1 during 1992.
Significant factors affecting the results of operations and causing
variances between the years 1993 and 1992, and 1992 and 1991 are discussed
under "Revenues" and "Expenses" below.
Revenues
System Energy's operating revenues recover operating expenses,
depreciation, and capital costs attributable to Grand Gulf 1. The capital
costs are computed by allowing a return, currently set at a rate of 11.0%, (see
Note 2, incorporated herein by reference, for further information on the FERC
Return on Equity Case) on System Energy's common equity funds allocable to its
investment in Grand Gulf 1 plus System Energy's effective interest cost for its
debt allocable to this investment.
Operating revenues decreased in 1993 due primarily to the effect of the
FERC Return on Equity Case settlement which reduced System Energy's return on
equity as discussed in "Net Income" above and a lower return on System Energy's
decreasing investment in Grand Gulf 1 (caused by depreciation of the unit).
Future revenues attributable to the return on equity will consequently be lower
as a result of the reduction in return on equity. Also, future revenues
attributable to the return on investment are expected to decline each year as a
result of the depreciation of System Energy's investment in Grand Gulf 1.
Operating revenues were higher in 1992 due primarily to the effect of the FERC
Complaint Case settlement in 1991. The higher operating revenues in 1992 also
reflect the increase in 1992 operating expenses primarily associated with the
scheduled fifth refueling outage partially offset by a lower return earned on
its investment in Grand Gulf 1 resulting from a decrease in net unit
investment.
Expenses
Grand Gulf 1 was on-line for 284 of 365 days in 1993 as compared with 298
of 366 days in 1992. The unit capability factor, which is a measure of the
unit's performance (based on a ratio of available energy generation to the
maximum power capability multiplied by the period hours), was 76.1% for 1993 as
compared with 79.9% for 1992. These variances are primarily due to the unit's
sixth and fifth refueling outages that lasted from September 28, 1993 to
December 3, 1993, (67 days) and April 17, 1992 to June 9, 1992; (52 days),
respectively and, to a lesser extent, to unplanned outages in September 1993
(14 days) and January 1992 (10 days). These outages contributed significantly
to the decrease in fuel for electric generation and fuel related expenses. The
decrease in fuel expense in 1993 and 1992 is also due to refueling with less
expensive nuclear fuel. (Approximately one-third of the reactor core was
replaced during each outage.) Increased operating efficiency also contributed
to the 1993 decrease. Nonfuel operation and maintenance expense increased in
1992 due primarily to the fifth refueling outage as mentioned above.
The FERC Complaint Case settlement, recorded by System Energy in
June 1991, contributed to fluctuations in 1992 operating results. Other
operation expense increased in 1992 due, in part, to the provision of that
settlement that called for 1991 credits from System Energy to AP&L, LP&L, MP&L,
and NOPSI relating to System Energy's rate treatment of the portions of Grand
Gulf 1 sold and leased back.
Total income taxes decreased in 1993 due primarily to lower pretax book
income partially offset by an increase in the federal income tax rate as a
result of OBRA. Income taxes increased in 1992 due primarily to the effects of
the FERC Complaint Case settlement.
SYSTEM ENERGY RESOURCES, INC.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
SIGNIFICANT FACTORS AND KNOWN TRENDS
FERC Audit
See Note 2, incorporated herein by reference, for information with respect
to possible write-offs and refunds which may result from a decision issued by
FERC.
SYSTEM ENERGY RESOURCES, INC.
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
System Energy maintains accounts in accordance with FERC guidelines.
Certain previously reported amounts have been reclassified to conform to current
classifications.
Organization
System Energy is a generating company providing electricity to AP&L, LP&L,
MP&L, and NOPSI and has a 90% interest in Grand Gulf 1, a nuclear generating
station that began commercial operation in 1985. In June 1990, Entergy
Operations assumed responsibility for the operation and maintenance of Grand
Gulf 1.
System Energy has a combined ownership and leasehold interest of 90% and
SMEPA has an undivided ownership interest of 10% in Grand Gulf 1. System Energy
records its investment associated with Grand Gulf 1 to the extent to which it
owns and maintains a leasehold interest in the generating station. Likewise,
System Energy's operating expenses reflected in the accompanying financial
statements represent 90% of such Grand Gulf 1 expenses.
Utility Plant
Utility plant is stated at original cost. The original cost of utility
plant retired or removed, plus the applicable removal costs, less salvage, is
charged to accumulated depreciation. Maintenance, repairs, and minor
replacement costs are charged to operating expenses. Substantially all of the
utility plant owned by System Energy is subject to the lien of its first
mortgage bond indenture.
AFUDC represents the approximate net composite interest cost of borrowed
funds and a reasonable return on the equity funds used for construction.
Although AFUDC increases utility plant and represents current earnings, it is
only realized in cash through depreciation provisions included in rates. System
Energy's effective composite rates for AFUDC were 11.6%, 12.3%, and 12.4% for
1993, 1992, and 1991, respectively.
Utility plant includes the portions of Grand Gulf 1 that were sold and are
currently under lease. System Energy retired this property from its continuing
property records as formerly owned property released from and no longer subject
to System Energy's mortgage and deed of trust. System Energy is reflecting such
leased property for financial reporting purposes as property under lease from
others and is depreciating this property over the life of the basic lease term.
Such depreciation is being deferred until recoverable from customers in future
periods. See Note 8.
Depreciation is computed on a straight-line basis at rates based on the
estimated service lives and costs of removal of the various classes of property.
Depreciation provisions on average depreciable property approximated 2.9% in
1993, 1992, and 1991.
Income Taxes
System Energy, its parent, and affiliates (excluding GSU prior to 1994)
file a consolidated federal income tax return. Income taxes are allocated to
System Energy in proportion to its contribution to consolidated taxable income.
SEC regulations require that no System company pay more taxes than it would have
had a separate income tax return been filed. Deferred taxes are recorded for
all temporary differences between book and taxable income. Investment tax
credits are deferred and amortized based upon the average useful life of the
related property in accordance with rate treatment. As discussed in Note 3,
effective January 1, 1993, System Energy changed its accounting for income taxes
to conform with the SFAS 109.
In addition, System Energy files a consolidated Mississippi state income
tax return with certain other System companies.
Cash and Cash Equivalents
System Energy considers all unrestricted highly liquid debt instruments
purchased with an original maturity of three months or less to be cash
equivalents.
Fair Value Disclosure
The estimated fair value amounts of financial instruments have been
determined by System Energy, using available market information and appropriate
valuation methodologies. However, considerable judgment is required in
developing the estimates of fair value. Therefore, estimates are not
necessarily indicative of the amounts that System Energy could realize in a
current market exchange. In addition, gains or losses realized on financial
instruments may be reflected in future rates and not accrue to the benefit of
stockholders.
System Energy considers the carrying amounts of financial instruments
classified as current assets and liabilities to be a reasonable estimate of
their fair value because of the short maturity of these instruments. In
addition, System Energy does not presently expect that performance of its
obligations will be required in connection with certain off-balance sheet
commitments and guarantees considered financial instruments. Due to this
factor, and because of the related party nature of these commitments and
guarantees, determination of fair value is not considered practicable. See
Notes 5 and 7 for additional fair value disclosure.
NOTE 2. RATE AND REGULATORY MATTERS
FERC Audit
In December 1990, FERC Division of Audits issued a report for System Energy
for the years 1986 through 1988. The report recommended that System Energy (1)
write off and not recover in rates approximately $95 million of Grand Gulf 1
costs included in utility plant related to certain System income tax allocation
procedures (and System Energy's accounting resulting from certain allocated
income tax charges) alleged to be inconsistent with FERC's accounting
requirements and (2) compute refunds for the years 1987 to date to correct for
over collections from AP&L, LP&L, MP&L, and NOPSI.
In August 1992, FERC issued an opinion and order (August 4 Order) which
found that System Energy overstated its Grand Gulf 1 utility plant account by
approximately $95 million as indicated in FERC's report. The order required
System Energy to make adjusting accounting entries and refunds, with interest,
to AP&L, LP&L, MP&L, and NOPSI within 90 days from the date of the order.
System Energy filed a Request for Rehearing, and in October 1992, FERC issued an
order allowing additional time for its consideration of the request. In
addition, it deferred System Energy's refund obligation until 30 days after FERC
issues an order on rehearing. Should such refunds and adjusting entries be
necessary, System Energy estimates that as of December 31, 1993, its net income
would be reduced by approximately $152.3 million. This amount includes System
Energy's potential refund obligation which is estimated to be $113.0 million
(including interest) as of December 31, 1993. The ongoing effect of this order,
if implemented, would be to reduce System Energy's revenues by approximately
$19.8 million during the first twelve months following the write-off and by a
comparable amount (but decreasing by approximately $0.4 million per year) in
each subsequent year.
If the August 4 Order is implemented, System Energy would need the consent
of certain banks to temporarily waive the fixed charge coverage and equity ratio
covenants in the letters of credit and reimbursement agreement related to the
Grand Gulf 1 sale and leaseback transactions (see Note 7) in order to avoid
violation of the covenant. System Energy has obtained the consent of the banks
to waive these covenants, for the 12-month period beginning with the earlier of
the write-off or the first refund, if the August 4 Order is implemented prior to
December 31, 1994. The waiver is conditioned upon System Energy not paying any
common stock dividends to Entergy Corporation until the equity ratio covenant is
once again met. Absent a waiver, System Energy's failure to perform these
covenants could cause a draw under the letters of credit and/or early
termination of the letters of credit. If the letters of credit were not
replaced in a timely manner, a default or early termination of System Energy's
leases could result.
System Energy believes that its consolidated income tax accounting
procedures and related rate treatment are in compliance with SEC and FERC
requirements and is vigorously contesting this issue. The ultimate resolution
of this matter cannot be predicted.
FERC Return on Equity Case
In August 1992, FERC instituted an investigation of the return on equity
(ROE) component of all formula wholesale rates for System Energy as well as
AP&L, LP&L, MP&L, and NOPSI. Payments received by System Energy under the Unit
Power Sales Agreement are its only source of operating revenue. Rates under the
Unit Power Sales Agreement are based on System Energy's cost of service
including a return on common equity which had been set at 13% (see below).
In August 1993, Entergy and the state regulatory agencies that intervened
in the proceeding reached an agreement (Settlement Agreement) in this matter.
The Settlement Agreement, which was approved by FERC on October 25, 1993,
provides that an 11.0% ROE will be included in the formula rates under the Unit
Power Sales Agreement. The Unit Power Sales Agreement formula rate, including
the 11.0% ROE component, will remain in effect without change for two years,
until early August 1995. System Energy's refunds payable to AP&L, LP&L, MP&L,
and NOPSI, which were due prospectively from November 3, 1992, were reflected as
a credit to their bills in October 1993. These refunds decreased System
Energy's 1993 revenues and net income by approximately $29.4 million and $18.2
million, respectively.
FERC Complaint Case Settlement
In February 1990, the APSC, the LPSC, the MPSC, the Mississippi Attorney
General, and the City of New Orleans filed a complaint with FERC against System
Energy and Entergy Services, Inc. (as agent for Entergy Corporation, AP&L, LP&L,
MP&L, and NOPSI) alleging that the rates being charged to AP&L, LP&L, MP&L, and
NOPSI by System Energy for capacity and energy from Grand Gulf 1 were not just
and reasonable. This filing was consolidated with proceedings related to System
Energy's decommissioning collections.
In May 1991, a settlement was reached which, among other things (1) reduced
System Energy's rate of return on common equity from 14% to 13% effective
retroactively to April 1990 (pursuant to a subsequent settlement in the FERC
Return on Equity Case - see above - the allowed rate of return was further
reduced to 11% effective November 3, 1992); (2) imposed no ceiling for
ratemaking purposes on System Energy's common equity ratio; (3) established a
zero cash working capital allowance, effective retroactively to April 1990;
(4) resolved the cost of service treatment of certain Grand Gulf 2 assets
transferred to Grand Gulf 1; (5) set the amount to be collected in rates for the
cost of decommissioning System Energy's 90% interest in Grand Gulf 1 at
approximately $198 million in 1989 dollars (with a new study of these costs to
be prepared and submitted to FERC on or before June 1, 1995); (6) increased
System Energy's decommissioning expense collections from approximately
$1.1 million to approximately $4.3 million per year, effective retroactively to
June 1990, subject to a 5% annual inflation adjustment; and (7) provided for
1991 credits from System Energy to AP&L, LP&L, MP&L, and NOPSI totaling
approximately $17 million relating to System Energy's rate treatment of the
portions of Grand Gulf 1 sold and leased back. The settlement did not resolve
income tax accounting issues raised in the complaint (see "FERC Audit" above).
The settlement was approved by FERC in September 1991.
Based on the settlement, System Energy credited in 1991 approximately
$47.6 million in the aggregate (including interest) against its bills to AP&L,
LP&L, MP&L, and NOPSI for capacity and energy from Grand Gulf 1. As a result of
the FERC Complaint Case settlement, 1991 net income was reduced by approximately
$36.0 million, of which approximately $15.8 million relates to billings in 1990.
NOTE 3. INCOME TAXES
Effective January 1, 1993, System Energy adopted SFAS 109. This new
standard requires that deferred income taxes be recorded for all temporary
differences and carryforwards, and that deferred tax balances be based on
enacted tax laws at tax rates that are expected to be in effect when the
temporary differences reverse. SFAS 109 requires that regulated enterprises
recognize adjustments resulting from implementation as regulatory assets or
liabilities if it is probable that such amounts will be recovered from or
returned to customers in future rates. A substantial majority of the
adjustments required by SFAS 109 was recorded to deferred tax balance sheet
accounts with offsetting adjustments to regulatory assets and liabilities. The
cumulative effect of the adoption of SFAS 109 is included in income tax expense
charged to operations. As a result of the adoption of SFAS 109, 1993 net income
was increased by $0.4 million, assets were increased by $327.9 million, and
liabilities were increased by $327.5 million.
Income tax expense consisted of the following:
For the Years Ended December 31,
--------------------------------
1993 1992 1991
------- ------- --------
(In Thousands)
Current:
Federal $59,049 $13,890 $(31,900)
State 3,671 6,786 5,052
------- ------- --------
Total 62,720 20,676 (26,848)
------- ------- --------
Deferred - net:
Liberalized depreciation 46,600 43,873 45,551
Nuclear fuel 2,706 (3,299) (2,927)
Capitalized interest (456) (1,402) (1,441)
Taxes capitalized (929) (935) (572)
Decontamination and decommissioning fund 5,601 - -
Bond reacquisition (787) 852 (1,857)
Sale and leaseback (4,057) (4,122) (4,044)
Other (2,394) 3,088 2,458
------- ------- --------
Total 46,284 38,055 37,168
------- ------- --------
Investment tax credit adjustments - net (30,452) 30,123 63,256
------- ------- --------
Recorded income tax expense $78,552 $88,854 $73,576
======= ======= ========
Charged to operations $83,412 $93,438 $81,302
Credited to other income (4,859) (4,584) (7,726)
------- ------- --------
Recorded income tax expense 78,553 88,854 73,576
Income taxes applied against the debt - 253 352
component of AFUDC
------- ------- --------
Total income taxes $78,553 $89,107 $73,928
======= ======= ========
Total income taxes differ from the amounts computed by applying the
statutory federal income tax rate to income or loss before taxes. The reasons
for the differences were:
For the Years Ended December 31,
------------------------------------------------------
1993 1992 1991
----------------- --------------- ---------------
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
-------- ------ ------- ------- ------- ------
(Dollars in Thousands)
Computed at statutory rate $60,368 35.0 $74,458 34.0 $60,587 34.0
Increases (reductions) in tax resulting from:
Depreciation 12,839 7.4 11,520 5.3 8,343 4.7
State income taxes net of federal
income tax effect 6,778 3.9 8,380 3.8 6,084 3.4
Amortization of investment tax credits (3,759) (2.2) (3,865) (1.8) (1,928) (1.1)
Other - (net) 2,327 1.4 (1,639) (0.7) 490 0.3
------- ---- ------- ---- ------- ----
Recorded income tax expense 78,553 45.5 88,854 40.6 73,576 41.3
Income taxes applied against the debt
component of AFUDC - - 253 0.1 352 0.2
------- ---- ------- ---- ------- ----
Total income taxes $78,553 45.5 $89,107 40.7 $73,928 41.5
======= ==== ======= ==== ======= ====
Significant components of System Energy's net deferred tax liabilities as
of December 31, 1993, were (in thousands):
Deferred tax liabilities:
Net regulatory assets $(425,318)
Plant related basis differences (552,782)
Other (16,343)
---------
Total $(994,443)
=========
Deferred tax assets:
Sale and leaseback $142,850
Accumulated deferred investment tax credit 43,547
Alternative minimum tax credit 20,452
Recoverable income tax 92,689
Other 11,964
--------
Total $311,502
========
Net deferred tax liabilities $(682,941)
=========
Recoverable income taxes include the tax effects of the substantial loss
generated in September 1989 by the Grand Gulf 2 write-off. The loss increased
System Energy's tax net operating loss carryforward to a total of approximately
$265.5 million as of December 31, 1993, which may be utilized in the future to
offset taxable income. If not utilized to offset Federal taxable income, income
tax benefits related to the net operating loss carryforwards will expire in the
years 2004 through 2007. In connection with an Internal Revenue Service (IRS)
audit of Entergy's 1988, 1989, and 1990 consolidated federal income tax returns,
the IRS is proposing that adjustments be made to the Grand Gulf 2 abandonment
loss deduction claimed on Entergy's 1989 consolidated federal income tax return.
If any such adjustments are necessary, the effect on System Energy's net income
should be immaterial. Entergy intends to contest the proposed adjustments if
finalized by the IRS. The outcome of such proceedings cannot be predicted at
this time.
The alternative minimum tax (AMT) credit at December 31, 1993, was $20.5
million. This AMT credit can be carried forward indefinitely and will reduce
System Energy's federal income tax liability in the future.
NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS
The SEC has authorized System Energy to effect short-term borrowings up to
$125 million, subject to increase to as much as $238 million after further SEC
approval. These authorizations are effective through November 30, 1994. In
addition, System Energy can borrow from the Money Pool, subject to its maximum
authorized level of short-term borrowings and the availability of funds. System
Energy had no short-term borrowings or bank lines of credit as of December 31,
1993.
NOTE 5. LONG-TERM DEBT
The long-term debt of System Energy as of December 31, 1993 and 1992, was as
follows:
Maturities Interest Rates
From To From To 1993 1992
---- ---- ----- ----- --------- ---------
(In Thousands)
First Mortgage Bonds
1994 1998 6.0% 14%* $615,000 $555,000
1999 2003 8-1/4% 11% 130,000 235,000
2016 11-3/8% 90,319 90,319
Governmental Obligations**
2013 2016 8-1/4% 12-1/2% 416,600 416,600
Grand Gulf Lease Obligation, 7.02% (Note 8) 500,000 500,000
Unamortized Discount (10,005) (11,611)
---------- ----------
Total Long-Term Debt 1,741,914 1,785,308
Less Amount Due Within One Year 230,000 30,000
---------- ----------
Long-Term Debt Excluding Amount Due Within $1,511,914 $1,755,308
One Year ========== ==========
* The 14% series of $200 million is due 11/15/94. All other series are at
interest rates within the range of 6% - 11.375%.
** Consists of pollution control bonds, certain series of which are secured by
non-interest bearing first mortgage bonds.
The fair value of System Energy's long-term debt, excluding Grand Gulf
lease obligation, as of December 31, 1993 and 1992, was estimated to be $1,397.8
million and $1,442.7 million, respectively. Fair values were determined using
bid prices reported by dealer markets and by nationally recognized investment
banking firms. For the years 1994, 1995, 1996, 1997, and 1998 System Energy has
long-term debt maturities and sinking fund requirements (in millions) of $230,
$135, $250, $10, and $70, respectively.
System Energy has SEC authorization for the issuance and sale of up to $500
million of first mortgage bonds through December 31, 1994, (of which $220
million remained available as of December 31, 1993). In addition, System Energy
has SEC authorization for the acquisition of not more than $500 million of its
outstanding first mortgage bonds through December 31, 1994, all of which
remained available as of December 31, 1993.
NOTE 6. DIVIDEND RESTRICTIONS
Various agreements relating to the long-term debt of System Energy restrict
the payment of cash dividends or other distributions on its common stock. As of
December 31, 1993, $152.7 million of System Energy's retained earnings were
restricted against the payment of cash dividends or other distributions on
common stock. On February 1, 1994, System Energy paid Entergy Corporation a
$57.8 million cash dividend on common stock.
NOTE 7. COMMITMENTS AND CONTINGENCIES
Capital Requirements and Financing
Construction expenditures (excluding nuclear fuel) for the years 1994,
1995, and 1996 are estimated to total $26 million, $22 million, and $23 million,
respectively. System Energy will also require $615 million during the period
1994-1996 to meet long-term debt and preferred stock maturities and sinking fund
requirements. System Energy plans to meet the above requirements with
internally generated funds and cash on hand, supplemented by the issuance of
long-term debt. See Note 5 for the possible issuance of new first mortgage
bonds and the potential refunding, redemption, purchase, or other acquisition of
certain series of outstanding first mortgage bonds.
Capital Funds Agreement
Entergy Corporation has agreed to arrange for or supply to System Energy
sufficient amounts of capital to (1) maintain System Energy's equity capital at
not less than 35% of System Energy's total capitalization (excluding short-term
debt) and (2) continue commercial operation of Grand Gulf 1 and enable System
Energy to pay its borrowings under any circumstances. In addition, under
supplements to the Capital Funds Agreement assigning System Energy's rights as
security for specific debt of System Energy, Entergy Corporation has agreed to
make cash capital contributions to enable System Energy to make payments on such
debt when due.
System Energy has entered into various agreements with AP&L, LP&L, MP&L,
and NOPSI, whereby AP&L, LP&L, MP&L, and NOPSI are obligated to purchase their
respective entitlements of capacity (discussed below) and energy from System
Energy's 90% ownership and leasehold interest in Grand Gulf 1, and to make
payments that, together with other available funds, are adequate to cover System
Energy's operating expenses. System Energy would have to secure funds from
other sources, including Entergy's obligations under the Capital Funds
Agreement, to cover any shortfalls from payments received from AP&L, LP&L, MP&L,
and NOPSI under these agreements.
Unit Power Sales Agreement
System Energy has agreed to sell all of its 90% owned and leased share of
capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in
accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI
17%) as ordered by FERC. Charges under this agreement are paid in consideration
for the respective entitlements of AP&L, LP&L, MP&L, and NOPSI to receive
capacity and energy, and are payable irrespective of the quantity of energy
delivered so long as the unit remains in commercial operation. The agreement
will remain in effect until terminated by the parties and approved by FERC,
which most likely would occur after Grand Gulf 1's retirement from service. The
monthly obligation for payments from AP&L, LP&L, MP&L, and NOPSI to System
Energy is approximately $54 million.
Availability Agreement
AP&L, LP&L, MP&L, and NOPSI are individually obligated in accordance with
stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 24.7%) to make
payments or subordinated advances to System Energy in amounts that, when added
to amounts received under the Unit Power Sales Agreement or otherwise, are
adequate to cover all of System Energy's operating expenses as defined,
including an amount sufficient to amortize Grand Gulf 2 over 27 years, as
discussed below. System Energy has assigned its rights to payments and advances
to certain creditors as security for certain obligations. Payments or advances
under the Availability Agreement are only required if funds available to System
Energy from all sources are less than the amount required under the Availability
Agreement. Since commercial operation of Grand Gulf 1, payments under the Unit
Power Sales Agreement have exceeded the amounts payable under the Availability
Agreement. Accordingly, no payments have ever been required. In 1989, the
Availability Agreement was amended to provide that the write-off of
approximately $900 million of Grand Gulf 2 costs would be amortized for
Availability Agreement purposes over a period of 27 years, in order to avoid the
need for payments under the Availability Agreement by AP&L, LP&L, MP&L, and
NOPSI.
Reallocation Agreement
System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation
Agreement relating to the sale of capacity and energy from the Grand Gulf
Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume
all of AP&L's responsibilities and obligations with respect to the Grand Gulf
Station under the Availability Agreement. FERC's decision allocating a portion
of Grand Gulf 1 capacity and energy to AP&L supersedes the Reallocation
Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2
amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%,
and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the
Reallocation Agreement does not affect AP&L's obligation to System Energy's
lenders under the assignments referred to in the preceding paragraph. AP&L
would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were
unable to meet their contractual obligations. No payments of any amortization
amounts will be required as long as amounts paid to System Energy under the Unit
Power Sales Agreement, including other funds available to System Energy, exceed
amounts required under the Availability Agreement, which is expected to be the
case for the foreseeable future.
Reimbursement Agreement
In December 1988, System Energy entered into two entirely separate, but
identical, arrangements for the sales and leasebacks of an approximate aggregate
11.5% ownership interest in Grand Gulf 1 (see Note 8). In connection with the
equity funding of the sale and leaseback arrangements, letters of credit are
required to be maintained to secure certain amounts payable for the benefit of
the equity investors by System Energy under the leases. The current letters of
credit are effective until January 15, 1997.
Under the provisions of the Reimbursement Agreement, as amended, related to
the letters of credit, System Energy has agreed to a number of covenants
relating to the maintenance of certain capitalization and fixed charge coverage
ratios. System Energy agreed, during the term of the reimbursement agreement,
to maintain its equity at not less than 33% of its adjusted capitalization (as
defined in the Reimbursement Agreement to include certain amounts not included
in capitalization for financial statement purposes). In addition, System Energy
must maintain, with respect to each fiscal quarter during the term of the
reimbursement agreement, a ratio of adjusted net income to interest expense
(calculated, in each case, as specified in the reimbursement agreement) of at
least 1.60. As of December 31, 1993, System Energy's equity approximated 34.74%
of its adjusted capitalization, and its fixed charge coverage ratio was 1.88.
Failure by System Energy to perform its covenants under the Reimbursement
Agreement could give rise to a draw under the letters of credit and/or an early
termination of the letters of credit. If such letters of credit were not
replaced in a timely manner, a default under System Energy's related leases
could result. Draws under the letters of credit must be repaid by System Energy
within 5 days (or in some cases, 90 days) following the date of drawing.
See Note 2 for information with respect to a FERC order that, if ultimately
sustained and implemented, could cause System Energy to fall below the required
equity and fixed charge coverage covenant levels.
Nuclear Insurance
The Price-Anderson Act limits public liability for a single nuclear
incident to approximately $9.4 billion, as of December 31, 1993. System Energy
has protection for this liability through a combination of private insurance
(currently $200 million) and an industry assessment program. Under the
assessment program, the maximum amount that would be required for each nuclear
incident would be $79.28 million per reactor, payable at a rate of $10 million
per licensed reactor per incident per year. As a co-licensee of Grand Gulf 1
with System Energy, SMEPA would share 10% of this obligation. System Energy has
one licensed reactor. In addition, System Energy participates in a private
insurance program which provides coverage for worker tort claims filed for
bodily injury caused by radiation exposure. System Energy's maximum assessment
under the program is an aggregate of approximately $3.1 million in the event
losses exceed accumulated reserve funds.
System Energy on behalf of itself and other insured interests (including
other co-owners of Grand Gulf 1) is a member of certain insurance programs that
provide coverage for property damage, including decontamination and premature
decommissioning expense. As of December 31, 1993, System Energy was insured
against such losses up to $2.7 billion with $250 million of this amount
designated to cover any shortfall in the NRC required decommission trust
funding. Under the property damage insurance programs, System Energy could be
subject to assessments if losses exceed the accumulated funds available to the
insurers. As of December 31, 1993, the maximum amount of such possible
assessments to System Energy was $21.89 million. Under its agreement with
System Energy, SMEPA would share in System Energy's obligation.
The amount of property insurance presently carried by System Energy exceeds
the NRC minimum requirement for nuclear power plant licensees of $1.06 billion
per site. NRC regulations provide that the proceeds of this insurance must
be used, first, to place and maintain the reactor in a safe and stable
condition and, second, to complete decontamination operations. Only after
proceeds are dedicated for such use and regulatory approval is secured, would
any remaining proceeds be made available for the benefit of plant owners or
their creditors.
Spent Nuclear Fuel and Decommissioning Costs
System Energy provides for estimated future disposal costs for spent
nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. System
Energy entered into a contract with the DOE, whereby the DOE will furnish
disposal service at a cost of one mill per net KWH generated and sold after
April 7, 1983. The fees payable to the DOE may be adjusted in the future to
assure full recovery. System Energy considers all costs incurred or to be
incurred for the disposal of spent nuclear fuel to be proper components of
nuclear fuel expense and recovers such costs in rates.
Due to delays of the DOE's repository program for the acceptance of spent
nuclear fuel, it is uncertain when shipments of spent fuel from System Energy
will commence. In the meantime, System Energy is responsible for spent fuel
storage. Current on-site spent fuel storage capacity at Grand Gulf 1 is
estimated to be sufficient until 2004. Thereafter, System Energy will provide
additional storage capacity at an estimated initial cost of $5 million to $10
million. In addition, approximately $3 million to $5 million will be required
every four to five years subsequent to 2004 until DOE's repository begins
accepting Grand Gulf 1 spent fuel.
Decommissioning costs were estimated to approximate $248.7 million in 1989
dollars based on a 1989 decommissioning cost study. However, as a result of the
FERC Complaint Case settlement, the amount to be collected in rates for the
total cost of decommissioning System Energy's 90% interest in Grand Gulf 1 was
set at approximately $198 million (in 1989 dollars). These collections are
deposited in external trust funds which have a market value of $26.8 million and
$20.1 million at December 31, 1993 and 1992, respectively. The accumulated
decommissioning liability of $24.8 million has been recorded in other deferred
credits as of December 31, 1993. Decommissioning expense in the amount of $4.9
million was recorded in 1993. System Energy regularly reviews and updates
estimated decommissioning costs (an updated cost study is scheduled to be
completed by mid-1994), and applications will be made to the appropriate
regulatory authorities to reflect in rates any future change in projected
decommissioning costs. The actual decommissioning costs may vary from the above
estimates because of regulatory requirements, changes in technology, and
increased costs of labor, materials, and equipment, and management believes that
actual decommissioning costs are likely to be higher than the amounts presented
above.
The Energy Act has a provision that assesses domestic nuclear utilities
with fees for the decontamination and decommissioning of DOE's past uranium
enrichment operations. The decontamination and decommissioning provisions will
be used to set up a fund into which contributions from utilities and the federal
government will be placed. System Energy's annual assessment, which will be
adjusted annually for inflation, is approximately $1.3 million (in 1993 dollars)
for approximately 15 years. FERC requires that utilities treat these
assessments as costs of fuel as they are amortized. The cumulative liability of
$16.8 million as of December 31, 1993, is recorded in other current liabilities
and other non-current liabilities, according to FERC guidelines, and is offset
in the financial statements by a regulatory asset, recorded as a deferred debit.
System Fuels
System Fuels entered into a revolving credit agreement with a bank that
provides $45 million in borrowings to finance System Fuels' nuclear materials
and services inventory. Should System Fuels default on its obligations under
its credit agreement, AP&L, LP&L, and System Energy have agreed to purchase the
nuclear materials and services financed under the agreement.
NOTE 8. LEASES
Nuclear Fuel Lease
System Energy has an arrangement to lease nuclear fuel in an aggregate
amount up to $105 million. The lessor finances its acquisition of nuclear fuel
through a credit agreement and the issuance of notes. The credit agreement
which was entered into in 1989 has been extended to February 1997 and the notes
have varying remaining maturities of up to 4 years. It is expected that the
credit arrangements will be extended or alternative financing will be secured by
the lessor upon the maturity of the current arrangements. If the lessor cannot
arrange for alternative financing upon maturity of its borrowings, System Energy
must purchase nuclear fuel in an amount sufficient to enable the lessor to
retire such borrowings.
Lease payments are based on nuclear fuel use. Nuclear fuel lease expense
of $36.2 million, $48.4 million, and $66.9 million (including interest of $5.1
million, $8.5 million, and $11.1 million) was charged to operations in 1993,
1992, and 1991, respectively.
Sale and Leaseback Transactions
On December 28, 1988, System Energy entered into two entirely separate, but
identical, arrangements for the sales and leasebacks of an approximate aggregate
11.5% undivided ownership interest in Grand Gulf 1 for an aggregate cash
consideration of $500 million. System Energy is leasing back the undivided
interest on a net lease basis over a 26 1/2-year basic lease term. System
Energy has options to terminate the leases and to repurchase the undivided
interest in Grand Gulf 1 at certain intervals during the basic lease term.
Further, at the end of the basic lease term, System Energy has an option to
renew the leases or to repurchase the undivided interest in Grand Gulf 1. See
Note 7 with respect to certain other terms of the transaction.
On January 11, 1994, System Energy refinanced the debt portion of the sale
and leaseback arrangements of the undivided portions of Grand Gulf 1. The
secured lease obligation bonds of $356 million, 7.43% series due 2011 and $79
million, 8.2% series due 2014 will be indirectly secured by liens on, and a
security interest in, certain ownership interests and the respective leases
relating to Grand Gulf 1. See Note 7, incorporated herein by reference, for
information on letters of credit maintained by System Energy for the benefit of
the equity investors in the transactions.
In accordance with SFAS No. 98, "Accounting for Leases," due to "continuing
involvement" by System Energy, the sale and leaseback arrangements of the
undivided portions of Grand Gulf 1, as described above, are required to be
reflected for financial reporting purposes as financing transactions in System
Energy's financial statements. The amounts charged to expense for financial
reporting purposes include the interest portion of the lease obligations and
depreciation of the plant. However, operating revenues include the recovery of
the lease payments because the transactions are accounted for as sales and
leasebacks for rate-making purposes. The total of interest and depreciation
expense exceeds the corresponding revenues realized during the early part of the
lease term. Consistent with a recommendation contained in a FERC audit report,
System Energy recorded as a deferred asset the difference between the recovery
of the lease payments and the amounts expensed for interest and depreciation and
is recording such difference as a deferred asset on an ongoing basis. The
amount of this deferred asset was $71.2 million and $59.1 million as of December
31, 1993 and 1992, respectively. See Note 1 for further information regarding
the accounting for the sale and leaseback transactions.
As of December 31, 1993, System Energy had future minimum lease payments
(reflecting an implicit rate of 7.02% after the above refinancing) as follows
(in thousands):
1994 $ 17,423*
1995 42,464
1996 42,753
1997 42,753
1998 42,753
Years thereafter 845,573
----------
Total $1,033,719
==========
* An additional $24 million payment was made in January 1994 prior to the
refinancing of the debt portion of the sale and leaseback arrangements.
NOTE 9. POSTRETIREMENT BENEFITS
Pension Plan
System Energy participates in a defined benefit pension plan sponsored by
Entergy. Effective June 1990, all of System Energy's employees became employees
of Entergy Operations. However, the employees still remain under System
Energy's plan and no transfers of related pension liabilities and assets have
been made. The pension plan, which covers substantially all of its employees,
is noncontributory and provides pension benefits based on employees' credited
service and average compensation, generally during the last five years before
retirement. System Energy funds pension costs in accordance with contribution
guidelines established by the Employee Retirement Income Security Act of 1974,
as amended, and the Internal Revenue Code of 1986, as amended. The assets of
the plan consist primarily of common and preferred stocks, fixed income
securities, interest in a money market fund, and insurance contracts.
System Energy's 1993, 1992, and 1991 pension cost (credit), including
amounts capitalized, included the following components:
For the Years Ended December 31,
-------------------------------
1993 1992 1991
------ ------ ------
(In Thousands)
Service cost - benefits earned during the period $2,045 $1,737 $1,327
Interest cost on projected benefit obligation 1,709 1,439 1,035
Actual return on plan assets (3,828) (2,070) (5,432)
Net amortization and deferral 972 (587) 2,991
Other - - 17
------ ------ ------
Net pension cost (income) $898 $519 $(62)
====== ====== ======
The funded status of System Energy's pension plan as of December 31, 1993
and 1992, was:
1993 1992
------- -------
(In Thousands)
Actuarial present value of accumulated pension plan benefits:
Vested $16,728 $12,400
Non vested 615 428
------- -------
Accumulated benefit obligation $17,343 $12,828
======= =======
Plan assets at fair value $33,914 $30,167
Projected benefit obligation 28,933 20,759
------- -------
Plan assets in excess of projected benefit obligation 4,981 9,408
Unrecognized prior service cost 879 925
Unrecognized transition asset (7,080) (7,677)
Unrecognized net loss (gain) 1,802 (1,176)
------- -------
Accrued pension asset $582 $1,480
======= =======
The significant actuarial assumptions used in computing the information
above for 1993, 1992, and 1991 were as follows: weighted average discount rate,
7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in
future compensation levels, 5.6%; and expected long-term rate of return on plan
assets, 8.5%. Transition assets are being amortized over the average remaining
service period of active participants.
NOTE 10. TRANSACTIONS WITH AFFILIATES
System Energy sells all of the capacity and energy from its share of Grand
Gulf 1 to AP&L, LP&L, MP&L, and NOPSI under rate schedules approved by FERC.
Accordingly, all of System Energy's operating revenues consist of billings to
AP&L, LP&L, MP&L, and NOPSI.
MP&L provides a minimal amount of technical and advisory services and other
miscellaneous services to System Energy. In addition, pursuant to a service
agreement, System Energy receives technical and advisory services from Entergy
Services, Inc. Charges from MP&L and Entergy Services, Inc. for technical,
advisory and miscellaneous services amounted to approximately $12.3 million in
1993, $13.8 million in 1992, and $10.9 million in 1991. System Energy pays
directly or reimburses Entergy Operations for the costs associated with
operating Grand Gulf 1 (excluding nuclear fuel) which were approximately $151.3
million in 1993, $179 million in 1992, and $136 million in 1991.
In addition, certain materials and services required for fabrication of
nuclear fuel are acquired and financed by System Fuels and then sold to System
Energy as needed. Charges for these materials and services, which represent
additions to nuclear fuel, amounted to approximately $32.8 million in 1993,
$13.7 million in 1992, and $28.9 million in 1991.
NOTE 11. QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating results for the four quarters of 1993 and 1992 were:
Operating Operating Net
Revenue Income Income
---------- ---------- -------
(In Thousands)
1993:
First Quarter $164,630 $76,331 $31,782
Second Quarter $153,527 $65,539 $21,268
Third Quarter (1) $155,071 $63,992 $23,040
Fourth Quarter $177,540 $66,340 $17,837
1992:
First Quarter $177,466 $82,294 $33,198
Second Quarter $194,140 $81,688 $32,321
Third Quarter $177,464 $80,784 $32,584
Fourth Quarter $174,340 $78,410 $32,038
(1) The third quarter of 1993 reflects a nonrecurring decrease in operating
revenues of $14.3 million and a decrease in operating income and net income
of $8.7 million, net of tax, due to the settlement of the FERC Return on
Equity Case (See Note 2).
SYSTEM ENERGY RESOURCES, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
(Dollars in Thousands)
Operating revenues $ 650,768 $ 723,410 $ 686,664 $ 801,618 $ 837,307
Net income (loss) $ 93,927 $ 130,141 $ 104,622 $ 168,677 $ (655,524)
Total assets $3,891,066 $3,672,441 $3,642,203 $3,883,241 $3,987,055
Long-term obligations (1) $1,536,593 $1,768,299 $1,707,470 $1,849,000 $2,229,022
Electric energy sales
(Millions of KWH) 7,113 7,354 8,220 6,666 7,064
(1) Includes long-term debt (excluding current maturities) and noncurrent
capital lease obligations.
See Note 2 for information with respect to possible write-offs and refunds
which may result from a decision issued by FERC and Note 3 for the effect of the
accounting change for income taxes in 1993.
Item 9. Changes In and Disagreements With Accountants On Accounting and
Financial Disclosure.
No event that would be described in response to this item has occurred with
respect to Entergy, System Energy, AP&L, GSU, LP&L, MP&L, or NOPSI.
PART III
Item 10. Directors and Executive Officers Of The Registrants.
All officers and directors listed below held the specified positions with
their respective companies as of the date of filing this report.
ENTERGY CORPORATION
Directors
Information required by this item concerning directors of Entergy
Corporation is set forth under the heading "Election of Directors" contained in
the Proxy Statement of Entergy Corporation to be filed in connection with its
Annual Meeting of Stockholders to be held May 6, 1994, and is incorporated
herein by reference.
Name Age Position Period
Officers
Edwin Lupberger(a) 57 Chairman of the Board, Chief Executive
Officer of Entergy Corporation 1985-Present
Chairman of the Board, Chief Executive
Officer of AP&L, LP&L, MP&L, and NOPSI 1993-Present
Chairman of the Board, Chief Executive
Officer of GSU 1994-Present
Chairman of the Board of System Energy and
Entergy Enterprises 1986-Present
Chairman of the Board of Entergy
Operations 1990-Present
Chairman of the Board of Entergy Services 1985-Present
Chief Executive Officer of Entergy
Services and Entergy Enterprises 1991-Present
Director of Entergy Enterprises 1984-Present
Chief Executive Officer of Entergy Power,
Inc., Entergy Power Development
Corporation, and Entergy-Richmond Power
Corporation 1993-Present
President of Entergy Corporation 1985-1991
Chairman of the Board of Entergy Power 1990-1993
President of Entergy Services and Entergy
Enterprises 1990-1991
Chairman of the Board of System Fuels 1986-1990
Director of System Fuels 1986-1992
Jerry L. Maulden 57 President and Chief Operating Officer of
Entergy Corporation 1993-Present
Vice Chairman and Chief Operating Officer
of AP&L, GSU, LP&L, MP&L, and NOPSI 1993-Present
Director of AP&L 1979-Present
Director of GSU 1993-Present
Director of LP&L and NOPSI 1991-Present
Director of MP&L 1988-Present
Director of Entergy Operations 1990-Present
Director of System Energy 1987-Present
Vice Chairman of Entergy Services 1992-Present
Chairman of the Board of AP&L 1989-1993
Chief Executive Officer of AP&L 1979-1993
Chairman of the Board and Chief Executive
Officer of LP&L and NOPSI 1991-1993
Chairman of the Board and Chief Executive
Officer of MP&L 1989-1993
Group President, System Executive -
Transmission, Distribution, and Customer
Service of Entergy Corporation 1991-1993
Senior Vice President, System Executive -
Arkansas/Mississippi/Missouri Division
of Entergy Corporation 1988-1991
Director of System Fuels 1979-1992
Group President, System Executive -
Transmission, Distribution, and Customer
Service of Entergy Services 1991-1992
Director of Entergy Enterprises 1984-1991
Jerry D. Jackson 49 Executive Vice President - Finance and
External Affairs of Entergy Corporation 1990-Present
Executive Vice President - Finance and
External Affairs, Secretary and Director
of AP&L, LP&L, MP&L and NOPSI 1992-Present
Executive Vice President - Finance and
External Affairs of GSU 1993-Present
President and Chief Administrative Officer
of Entergy Services 1992-Present
Secretary of Entergy Corporation 1991-Present
Director of System Entergy 1993-Present
Director of Entergy Services 1990-Present
Executive Vice President - Finance and
External Affairs of Entergy Services 1990-1992
Director of Entergy Power 1990-1992
President of Entergy Enterprises 1991-1992
Director of Entergy Enterprises 1990-1992
Senior Vice President, System Executive -
Legal and External Affairs of Entergy
Corporation and Entergy Services 1987-1990
Donald C. Hintz 51 Senior Vice President and Chief Nuclear
Officer of Entergy Corporation 1993-Present
Senior Vice President - Nuclear of AP&L 1990-Present
Senior Vice President - Nuclear of GSU 1993-Present
Senior Vice President - Nuclear of LP&L 1992-Present
Director of AP&L, LP&L, NOPSI, System
Energy, System Fuels, and Entergy
Services 1992-Present
Director of GSU and MP&L 1993-Present
Chief Executive Officer and President of
System Energy and Entergy Operations 1992-Present
Director of Entergy Operations 1990-Present
Chief Operating Officer and Executive Vice
President of Entergy Operations 1990-1992
Group Vice President - Nuclear of LP&L 1990-1992
Chief Operating Officer and Executive Vice
President of System Energy 1989-1990
Senior Vice President - Power Production
of Wisconsin Public Service 1988-1989
Donald Hunter 60 Senior Vice President of Entergy
Corporation 1992-Present
Senior Vice President and Director of
Entergy Services 1992-Present
Senior Vice President - Fossil Operations
of AP&L, LP&L, MP&L, NOPSI, and Entergy
Services 1990-1992
President and Chief Operating Officer of
LP&L 1989-1990
Chief Operating Officer of NOPSI 1989-1990
Executive Vice President of LP&L and NOPSI 1987-1990
President, Chief Executive Officer, and
Director of System Fuels 1990-1992
Director of Entergy Enterprises 1991-1992
Jack L. King(b) 54 Senior Vice President of Entergy
Corporation 1987-Present
Chief Operating Officer, President, and
Director of Entergy Enterprises 1992-Present
Chairman of the Board of Entergy Systems
and Service, Inc., Entergy Argentina
S.A., and Entergy S.A. 1992-Present
Chief Executive Officer and President of
Entergy Power Development Corporation 1992-1993
Director of AP&L, LP&L, MP&L, NOPSI,
Entergy Power, and Entergy Services 1990-1992
Chairman of the Board of Entergy Power 1993-1993
Chief Executive Officer of Entergy Power 1990-1993
Chairman of the Board, Chief Executive
Officer, and President of Entergy-
Richmond Power Corporation 1992-1993
President of Entergy Power 1990-1993
Executive Vice President - Operations of
Entergy Services 1990-1992
Chairman of the Board of System Fuels 1990-1992
Senior Vice President, System Executive -
Operations of Entergy Services 1987-1990
Chief Executive Officer and President of
Entergy Systems and Service, Inc.,
Entergy Argentina S.A., and Entergy S.A. 1992-1993
Gerald D. McInvale 50 Senior Vice President and Chief Financial
Officer of Entergy Corporation, AP&L,
LP&L, MP&L, NOPSI, System Energy,
Entergy Operations, Entergy Services,
and Entergy Enterprises 1991-Present
Senior Vice President and Chief Financial
Officer of GSU 1993-Present
Senior Vice President, Chief Financial
Officer, Director, and Treasurer of
Entergy Power 1993-Present
Director of System Fuels 1992-Present
Treasurer of Entergy Enterprises 1992-Present
Director of Entergy Systems and Service,
Inc. 1993-Present
Vice President, Director, and Treasurer of
Entergy Power Development Corporation
and Entergy-Richmond Power Corporation 1993-Present
President - Executive Information
Strategies (consulting firm), Dallas,
Texas 1990-1991
Senior Vice President and Chief Financial
Officer of Frito-Lay, Inc. (Subsidiary
of PepsiCo, Inc.) Dallas, Texas 1987-1990
Michael G. Thompson 53 Senior Vice President and Chief Legal
Officer of Entergy Corporation and
Entergy Services 1992-Present
Senior Vice President, Chief Legal
Officer, Director, and Secretary of
Entergy Power 1993-Present
Senior Vice President, Chief Legal
Officer, and Secretary of Entergy
Enterprises 1992-Present
Vice President, Director, and Secretary of
Entergy Power Development Corporation
and Entergy-Richmond Power Corporation 1992-Present
Director of Entergy Systems and Service,
Inc. 1992-Present
Secretary of Entergy Systems and Service,
Inc. 1993-Present
Assistant Secretary of Entergy Corporation 1993-Present
Senior Partner of Friday, Eldredge & Clark
(law firm) 1987-1992
S. M. Henry
Brown, Jr. 55 Vice President - Federal Governmental
Affairs of Entergy Corporation and
Entergy Services 1989-Present
Director - Public Affairs - Carolina Power
& Light Company 1988-1989
Charles L. Kelly 57 Vice President - Corporate Communications
and Public Relations of Entergy
Corporation 1992-Present
Vice President - Corporate Communications
and Public Relations of Entergy Services 1991-Present
Vice President - Corporate Communications
of AP&L 1981-1991
Lee W. Randall 44 Vice President and Chief Accounting
Officer of Entergy Corporation, AP&L,
LP&L, MP&L, NOPSI, System Energy,
Entergy Operations, and Entergy Services 1991-Present
Vice President, Chief Accounting Officer,
and Assistant Secretary of GSU 1993-Present
Assistant Secretary of AP&L, LP&L, MP&L,
NOPSI, Entergy Operations, and Entergy
Services 1991-Present
Senior Vice President - Finance and
Administration and Chief Financial
Officer of AP&L 1988-1991
Secretary of AP&L 1989-1991
Assistant Treasurer of AP&L 1988-1991
Glenn E. Harder 43 Treasurer of Entergy Corporation and
Entergy Services 1993-Present
Vice President - Financial Strategies and
Treasurer of AP&L, LP&L, MP&L, NOPSI,
System Energy, and Entergy Operations 1993-Present
Vice President - Financial Strategies and
Treasurer of GSU 1993-Present
Vice President - Financial Strategies of
Entergy Services 1991-Present
Treasurer and Assistant Secretary of
System Fuels 1993-Present
Vice President - Administrative Services
and Regulatory Affairs of System Energy 1991-1993
Vice President - Accounting and Treasurer
of System Energy 1986-1991
Vice President - Accounting and Treasurer
of Entergy Operations 1990-1991
Vice President - Administrative Services
and Regulatory Affairs of Entergy
Operations 1991-1991
ARKANSAS POWER & LIGHT COMPANY
Directors
Michael B. Bemis(c) 46 Executive Vice President - Customer
Service and Director of AP&L, LP&L,
MP&L, and NOPSI 1992-Present
Executive Vice President - Customer
Service of GSU 1993-Present
Executive Vice President - Customer
Service of Entergy Services 1992-Present
Director of System Fuels 1992-Present
President and Chief Operating Officer of
LP&L and NOPSI 1992-1992
President and Chief Operating Officer of
MP&L 1989-1991
Secretary of MP&L 1991-1991
John A.
Cooper, Jr.(d) 55 Director of Entergy Corporation 1985-Present
Director of AP&L 1992-Present
Chairman of the Board of Cooper
Communities, Inc., Bella Vista, AR 1990-Present
Chairman of the Board of COFAM, Inc. 1991-Present
Cathy Cunningham(e) 48 Director of AP&L 1983-Present
Self employed in real estate development
and contracting, Heber Springs, West
Helena and Helena, AR 1982-Present
Richard P.
Herget, Jr.(f) 54 Director of AP&L 1981-Present
Vice Chairman of Rebsamen Insurance,
Little Rock, AR 1992-Present
Managing Director of Marsh & McLennan,
Inc. (Insurance) 1987-1992
Tommy H.
Hillman(g) 57 Director of AP&L 1985-Present
President of Winrock Farms, Inc.
(Agriculture), Carlisle, AR 1980-Present
Chairman of Riceland Foods, Inc. 1985-1993
Donald C. Hintz 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Kaneaster
Hodges, Jr.(h) 55 Director of Entergy Corporation 1984-Present
Director of AP&L 1981-Present
Attorney-at-Law, Sole Practitioner,
Newport, AR 1981-Present
Jerry D. Jackson 49 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
R. Drake Keith 58 President and Director of AP&L 1989-Present
Chief Operating Officer of AP&L 1989-1992
Secretary of AP&L 1991-1992
Edwin Lupberger 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Dr. Raymond P.
Miller, Sr.(i) 57 Director of AP&L 1982-Present
Physician, Little Rock, AR 1970-Present
Roy L. Murphy(j) 66 Director of AP&L 1977-Present
Chairman of the Board of Mid-South
Engineering Co. (consulting engineers),
Hot Springs, AR 1969-Present
President of Mid-South Engineering Co. 1969-1991
William C.
Nolan, Jr.(k) 54 Director of AP&L 1971-Present
Attorney-at-Law, Nolan & Alderson,
Attorneys, El Dorado, AR 1969-Present
Robert D. Pugh(l) 65 Director of Entergy Corporation 1977-Present
Director of AP&L 1971-Present
Director of Entergy Operations 1990-Present
Chairman of the Board of Portland Bank and
Portland Bankshares, Inc. 1991-Present
Chairman of the Board of Portland Gin
Company (Agricultural and Agri-Business)
Portland, AR 1981-Present
Woodson D.
Walker(m) 43 Director of AP&L 1985-Present
Attorney-at-Law, Walker, Roaf, Campbell,
Ivory & Dunklin, P.A., Little Rock, AR 1977-Present
Gus B. Walton, Jr. 52 Director of AP&L 1981-Present
Vice President, Secretary, and part owner
of Frederick Poe Travel Service, Inc.
(Travel Service), Little Rock, AR 1983-Present
Michael E.
Wilson(n) 51 Director of AP&L 1980-Present
Chairman of the Board and Chief Executive
Officer of Lee Wilson & Company
(Agricultural and Agri-Business),
Wilson, AR 1987-Present
President and Director of Delta Valley &
Southern Railway Company 1979-Present
Officers
Edwin Lupberger 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
R. Drake Keith 58 See the information under the AP&L
Directors Section above, incorporated
herein by reference.
Michael B. Bemis 46 See the information under the AP&L
Directors Section above, incorporated
herein by reference.
Jerry D. Jackson 49 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Frank F. Gallaher 48 Executive Vice President - Fossil
Operations of AP&L, LP&L, MP&L, NOPSI,
and Entergy Services 1993-Present
President of GSU 1994-Present
Director of GSU 1993-Present
Chairman of the Board of System Fuels 1992-Present
Director of Entergy Services 1992-Present
Senior Vice President - Fossil Operations
of AP&L, LP&L, MP&L, NOPSI, and Entergy
Services 1992-1993
Vice President and Chief Engineer of MP&L 1985-1990
Vice President - System Planning of
Entergy Services 1990-1992
Donald C. Hintz 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Gerald D. McInvale 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael R. Niggli 44 Senior Vice President - Marketing of AP&L,
GSU, LP&L, MP&L, NOPSI, and Entergy
Services 1993-Present
Vice President - Customer Service of LP&L,
NOPSI, and Entergy Services 1993-1993
Vice President - Strategic Planning of
Entergy Services 1990-1992
Vice President - Fuels Management of
Entergy Services 1988-1990
Vice President and Director of Entergy
Enterprises 1991-1992
Cecil L.
Alexander(o) 58 Vice President - Governmental Affairs of
AP&L 1991-Present
Vice President - Public Affairs of AP&L 1989-1991
Vice President - Governmental Relations of
AP&L 1985-1989
Glenn E. Harder 43 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Richard J. Landy 48 Vice President - Human Resources and
Administration of AP&L, LP&L, MP&L,
NOPSI, Entergy Services, and EOI 1991-Present
Vice President - Human Resources and
Administration of GSU 1993-Present
Vice President - Human Resources and
Administration of System Energy 1986-1990
Vice President - Human Resources and
Administration of Entergy Operations 1990-1991
James S. Pilgrim 58 Vice President - Customer Service of AP&L 1994-Present
Vice President - Northern Region,
Operations Customer Service of Entergy
Services 1993-Present
Director, Central Region, TDCS Customer
Service 1993-1994
Central Division Manager of MP&L 1991-1993
Northern Division Manager of MP&L 1988-1991
Lee W. Randall 44 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
C. Hiram Walters 57 Vice President - Customer Service of AP&L 1993-Present
Vice President - Customer Service of LP&L 1994-Present
Vice President - Central Region of Entergy
Services 1993-Present
Vice President - Customer Service of MP&L 1984-1991
Senior Vice President - Customer Service
of Entergy Services 1991-1992
GULF STATES UTILITIES COMPANY
Directors
Robert H.
Barrow (p) 72 Director of GSU 1984-Present
General of United States Marine Corps. 1969-Present
Frank F. Gallaher 48 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Frank W.
Harrison Jr.(q) 65 Director of GSU 1990-Present
Independent Geologist, Lafayette, LA 1959-Present
Donald C. Hintz 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
William F.
Klausing 65 Director of GSU 1991-Present
Senior Vice President and Manager of
Irving Trust Company's Public Utilities
Division, New York, NY 1985-1989
Edwin Lupberger 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Paul W.
Murrill(r) 59 Director of Entergy Corporation 1993-Present
Director of GSU 1978-Present
Director of Entergy Operations 1994-Present
Eugene H. Owen(s) 64 Director of Entergy Corporation 1993-Present
Director of GSU 1989-Present
Chairman of the Board and Chief Executive
Officer of Owen and White, Inc.
(engineering consulting firm) 1956-Present
Chairman of the Board and President of
Utility Holdings, Inc., (holding company
for Baton Rouge Water Company, Parish
Water Company and Louisiana Water
Company) Baton Rouge, LA 1986-Present
President of Parish Water Company, Inc.,
Baton Rouge, LA 1987-Present
President of Baton Rouge Water Company,
Baton Rouge, LA 1987-Present
President of Louisiana Water Company,
Baton Rouge, LA 1982-Present
M. Bookman Peters 60 Director of GSU 1990-Present
Certified Public Accountant 1961-Present
Financial Consultant 1990-Present
Chairman of the Board and Chief Executive
Officer of First City Texas-Bryan, N.A.,
Bryan, TX 1962-1990
Regional Director of First City
Bancorporation of Texas, Inc. 1981-1990
Monroe J.
Rathbone, Jr.(t) 68 Director of GSU 1975-Present
General Surgeon 1958-Present
Medical Director of Our Lady of the Lake
Regional Medical Center, Baton Rouge, LA 1983-Present
Sam F. Segnar(u) 66 Director of GSU 1988-Present
Chairman and Chief Executive Officer of
Sam F. Segnar (Interests which include
construction, development, heavy
equipment, aviation, and insurance), The
Woodlands, TX 1989-Present
Chairman of the Board of Collecting Bank,
N.A., Houston, TX 1989-1992
Bismark A.
Steinhagen 59 Director of Entergy Corporation 1993-Present
Director of GSU 1974-Present
Chairman of the Board of Steinhagen Oil
Company, Inc., (oil and gasoline
distributor), Beaumont, TX 1984-Present
Chairman of the Board of Starmart
Holdings, Inc. 1991-Present
James E.
Taussig, II 57 Director of GSU 1975-Present
Director of Varibus Corporation 1980-Present
Director and President of Taussig
Corporation (real estate development and
investments), Lake Charles, LA 1978-Present
Director and President of Taussig
Properties Corporation, (real estate
brokerage), Lake Charles, LA 1968-Present
Chairman of the Board and Director of
Calcasieu Financial Services
Corporation, (consumer finance and
mortgage lender) Lake Charles, LA 1978-Present
Officers
Edwin Lupberger 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Frank F. Gallaher 48 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Michael B. Bemis 46 See the information under the AP&L
Directors Section above, incorporated
herein by reference.
Jerry D. Jackson 49 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Donald C. Hintz 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Gerald D. McInvale 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael R. Niggli 44 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Leslie D. Cobb 59 Vice President and Secretary of GSU 1989-Present
Director of GSG&T, Inc. 1990-Present
Director of Prudential Oil and Gas, Inc. 1988-Present
Secretary of GSG&T, Inc. 1987-Present
Secretary of Prudential Oil and Gas, Inc. 1988-Present
Secretary-Treasurer of Southern Gulf
Railway Co. 1993-Present
Corporate Secretary of GSU 1979-1989
Glenn E. Harder 43 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Richard J. Landy 48 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Lee W. Randall 44 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Calvin J. Hebert 59 Vice President - Customer Service of GSU 1993-Present
Senior Vice President - Division
Operations of GSU 1992-1993
Senior Vice President - External Affairs
of GSU 1986-1992
Bobby J. Willis 57 Vice President and Controller of GSU 1985-Present
President and Treasurer of Prudential Oil
& Gas, Inc. 1987-Present
President and Controller of Varibus
Corporation 1986-Present
Director of GSG&T, Inc. 1992-Present
Director of Prudential Oil & Gas, Inc. 1987-Present
Director of Varibus Corporation 1986-Present
LOUISIANA POWER & LIGHT COMPANY
Directors
Michael B. Bemis 46 See the information under the AP&L
Directors Section above, incorporated
herein by reference.
John J. Cordaro 60 President and Director of LP&L and NOPSI 1992-Present
Group Vice President - External Affairs of
LP&L and NOPSI 1989-1992
Donald C. Hintz 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
William K. Hood(v) 43 Director of LP&L 1989-Present
Manages the daily operations of four
automobile dealerships and various
related companies 1972-Present
Jerry D. Jackson 49 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Tex R. Kilpatrick 60 Director of LP&L 1972-Present
Chairman and Chief Executive Officer of
Central American and Ashley Life
Insurance Company 1993-Present
President of Central American Life
Insurance Company, West Monroe, LA 1957-Present
Joseph J.
Krebs, Jr. 63 Director of LP&L 1983-Present
Chairman and Chief Executive Officer of J.
J. Krebs & Sons, Inc. (Engineering,
Planning and Surveying) 1977-Present
Director of NOPSI 1983-1992
Edwin Lupberger 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
H. Duke
Shackelford(w) 67 Director of Entergy Corporation 1981-Present
Director of LP&L 1972-Present
Planter 1950-Present
President of Shackelford Company, Inc. 1973-Present
President of Bonita Gin, Inc. 1991-Present
President of Louisiana Cotton Warehouse
Co., Inc. (Agricultural and
Agri-Business) 1978-Present
President of Shackelford Gin, Inc. 1976-1991
Chairman, Union Oil Mill, Inc.
(Agricultural and Agri-Business),
Bonita, LA 1981-1989
Wm. Clifford
Smith(x) 58 Director of Entergy Corporation 1983-Present
Director of LP&L 1981-Present
Director of Entergy Operations 1990-Present
President of T. Baker Smith & Son, Inc.
(Consultants-Civil Engineer and Land
Survey) 1962-Present
Officers
Edwin Lupberger 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
John J. Cordaro 60 See the information under the LP&L
Directors Section above, incorporated
herein by reference.
Michael B. Bemis 46 See the information under the AP&L
Directors Section above, incorporated
herein by reference.
Jerry D. Jackson 49 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Frank F. Gallaher 48 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Donald C. Hintz 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Gerald D. McInvale 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael R. Niggli 44 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Shelton G.
Cunningham, Jr. 53 Vice President - Rates and Regulatory
Affairs of LP&L and NOPSI 1991-Present
Vice President - Entergy Corporation/GSU
Transition Regulatory Affairs of Entergy
Services 1993-Present
Vice President - Regulatory Affairs of
Entergy Services 1992-1993
Senior Vice President - Rates and
Regulatory Affairs of LP&L and NOPSI 1989-1991
Richard C. Guthrie 51 Vice President - Governmental Affairs of
LP&L and NOPSI 1992-Present
Vice President - Public Affairs of LP&L
and NOPSI 1986-1992
Glenn E. Harder 43 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Richard J. Landy 48 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
James D. Bruno 54 Vice President - Customer Service of LP&L
and NOPSI 1994-Present
Vice President - Metro Region of Entergy
Services 1993-Present
Region Director - Metro Region 1991-1993
Vice President - Division Manager -
Orleans Division 1988-1991
William E. Colston 58 Vice President - Customer Service of LP&L 1993-Present
Vice President - Southern Region of
Entergy Services 1993-Present
Vice President - Division Manager of LP&L 1988-1991
Regional Director of LP&L 1991-1992
Lee W. Randall 44 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
C. Hiram Walters 57 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
MISSISSIPPI POWER & LIGHT COMPANY
Directors
Michael B. Bemis 46 See the information under the AP&L
Directors Section above, incorporated
herein by reference.
Frank R. Day(y) 62 Director of MP&L 1981-Present
Chairman of the Board and Chief Executive
Officer of Trustmark National Bank,
Jackson, MS 1981-Present
Chairman of the Board and Chief Executive
Officer of Trustmark Corporation (Bank
Holding Company) 1981-Present
Chairman of the Board of Smith County
Bank, Taylorsville, MS 1972-Present
Chairman of the Board of the Bank of
Edwards, Edwards, MS 1985-1992
President of Smith County Bank,
Taylorsville, MS 1972-1993
John O.
Emmerich, Jr. 64 Director of MP&L 1989-Present
Editor & Publisher of Greenwood
Commonwealth, Greenwood, MS 1973-Present
Norman B.
Gillis, Jr.(z) 66 Director of MP&L 1966-Present
Attorney-at-Law, Gillis & Gillis,
Attorneys, McComb, MS 1950-Present
Donald C. Hintz 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry D. Jackson 49 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Robert E.
Kennington, II 61 Director of MP&L 1974-Present
Chairman of the Board of Grenada Sunburst
System Corporation (Bank Holding
Company) and of Sunburst Bank, Grenada,
MS 1975-Present
Chief Executive Officer of Grenada
Sunburst System Corporation (Bank
Holding Company) and of Sunburst Bank,
Grenada, MS 1975-1992
Edwin Lupberger 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Donald E.
Meiners(aa) 58 President and Director of MP&L 1992-Present
Senior Vice President, System Executive -
Services Division of Entergy Corporation 1988-1990
President and Chief Operating Officer of
LP&L and NOPSI 1990-1991
Chief Operating Officer and Secretary of
MP&L 1992-1992
President and Chief Executive Officer of
Entergy Services, System Fuels, and
Entergy Enterprises 1987-1990
John N.
Palmer, Sr.(bb) 59 Director of Entergy Corporation 1992-Present
Director of MP&L 1987-Present
Chairman of the Board and Chief Executive
Officer of Mobile Telecommunication
Technologies Corporation 1989-Present
Dr. Clyda S. Rent 52 Director of MP&L 1991-Present
President of Mississippi University for
Women, Columbus, MS 1989-Present
Vice President of Queens College,
Charlotte, NC 1984-1989
E. B. Robinson, Jr
.(cc) 52 Director of MP&L 1984-Present
Chairman of the Board and Chief Executive
Officer of Deposit Guaranty Corporation
and Deposit Guaranty National Bank,
Jackson, MS 1984-Present
Dr. Walter
Washington 70 Director of Entergy Corporation and MP&L 1977-Present
President of Alcorn State University,
Lorman, MS 1969-Present
Robert M.
Williams, Jr. 58 Director of MP&L 1976-Present
Partner - Reeves-Williams (Building and
Development) Southhaven, MS 1969-Present
Officers
Edwin Lupberger 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Donald E. Meiners 58 See the information under the MP&L
Directors Section above, incorporated
herein by reference.
Michael B. Bemis 46 See the information under the AP&L
Directors Section above, incorporated
herein by reference.
Jerry D. Jackson 49 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Frank F. Gallaher 48 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Gerald D. McInvale 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael R. Niggli 44 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Bill F. Cossar 55 Vice President - Governmental Affairs of
MP&L 1987-Present
Johnny D. Ervin 44 Vice President - Customer Service of MP&L 1991-Present
Vice President - Eastern Region of Entergy
Services 1993-Present
Director of Entergy Enterprises 1991-1992
Vice President - Marketing of LP&L and
NOPSI 1990-1991
Vice President - Division Manager of LP&L 1988-1990
Glenn E. Harder 43 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Richard J. Landy 48 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Lee W. Randall 44 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
NEW ORLEANS PUBLIC SERVICE INC.
Directors
Michael B. Bemis 46 See the information under the AP&L
Directors Section above, incorporated
herein by reference.
James M. Cain(dd) 60 Director of NOPSI 1978-Present
Vice Chairman of Entergy Corporation and
Entergy Services 1991-1993
Director of LP&L 1978-1993
Director of System Energy 1978-1993
Director of Entergy Operations 1990-1993
Director of Systems Fuels 1978-1993
Senior Vice President, System Executive,
Louisiana Division of Entergy
Corporation 1988-1991
Chairman of the Board of LP&L 1989-1991
Chief Executive Officer of LP&L 1983-1991
Chairman of the Board of NOPSI 1990-1991
Chief Executive Officer of NOPSI 1989-1990
President of NOPSI 1978-1990
Chief Administrative Officer of Entergy
Services 1991-1992
Director of Entergy Services 1975-1993
Director of Entergy Enterprises 1984-1991
John J. Cordaro 60 See the information under the LP&L
Directors Section above, incorporated
herein by reference.
Brooke H.
Duncan(ee) 70 Director of Entergy Corporation 1983-Present
Director of NOPSI 1967-Present
Director of Entergy Operations 1992-Present
President and Chief Executive Officer of
Jno. Worner Hardware, Inc. 1980-Present
President of The Montegut Corporation
(formerly The Foster Company Inc., a
canvas fabricator) 1966-Present
Dr. Norman C.
Francis(ff) 62 Director of NOPSI 1992-Present
President of Xavier University of
Louisiana 1968-Present
Donald C. Hintz 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry D. Jackson 49 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Edwin Lupberger 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Anne M. Milling 53 Director of NOPSI 1991-Present
John B. Smallpage 68 Director of NOPSI 1969-Present
Chairman of the Board and Secretary of
Donovan Marine, Inc., New Orleans, LA 1970-Present
Charles C.
Teamer, Sr.(gg) 60 Director of NOPSI 1978-Present
Vice President for Fiscal Affairs of
Dillard University, New Orleans, LA 1965-Present
Officers
Edwin Lupberger 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
John J. Cordaro 60 See the information under the LP&L
Directors Section above, incorporated
herein by reference.
Michael B. Bemis 46 See the information under the AP&L
Directors Section above, incorporated
herein by reference.
Jerry D. Jackson 49 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Frank F. Gallaher 48 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Gerald D. McInvale 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Michael R. Niggli 44 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
James D. Bruno 54 See the information under the LP&L
Officers Section above, incorporated
herein by reference.
Shelton G.
Cunningham, Jr. 53 See the information under the LP&L
Officers Section above, incorporated
herein by reference.
Richard C. Guthrie 51 See the information under the LP&L
Officers Section above, incorporated
herein by reference.
Glenn E. Harder 43 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Richard J. Landy 48 See the information under the AP&L
Officers Section above, incorporated
herein by reference.
Lee W. Randall 44 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
SYSTEM ENERGY
Directors
Donald C. Hintz 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry D. Jackson 49 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Edwin Lupberger 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Jerry L. Maulden 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Officers
Edwin Lupberger 57 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Donald C. Hintz 51 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Gerald D.
McInvale 50 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Glenn E. Harder 43 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Lee W. Randall 44 See the information under the Entergy
Corporation Officers Section above,
incorporated herein by reference.
Joseph L. Blount 47 Secretary of System Energy and Entergy
Operations 1991-Present
Vice President Legal and External Affairs
of Entergy Operations 1990-1993
Vice President Legal and External Affairs
of System Energy 1989-1990
Assistant Secretary for System Energy 1987-1991
General Counsel and Assistant to President
of System Energy 1986-1989
Assistant Secretary for Entergy Operations 1990-1991
(a) Mr. Lupberger is a director of First Commerce Corporation, New Orleans, LA,
International Shipholding Corporation, New Orleans, LA, and First National
Bank of Commerce, New Orleans, LA.
(b) Mr. King is a director of First Pacific Networks, Inc. ("FPN") and Systems
and Service International, Inc. ("SASI"). Entergy Enterprises owns 9.95%
of the common stock of FPN, and a subsidiary of Entergy Enterprises,
Entergy Systems and Service, Inc., owns 9.95% of the common stock of SASI.
(c) Mr. Bemis is a director of Deposit Guaranty National Bank, Jackson, MS and
Deposit Guaranty Corporation, Jackson, MS.
(d) Mr. Cooper is a director of Wal-Mart Stores, Inc., Bentonville, AR and J.
B. Hunt Transport Services, Inc., Lowell, AR.
(e) Ms. Cunningham is a director of First National Bank of Phillips County,
Helena, AR.
(f) Mr. Herget is a director of Union National Bank and Union Modern Mortgage
Corporation, Little Rock, AR.
(g) Mr. Hillman is a director of Riceland Foods, Inc., Hazen, AR, Hazen First
State Bank, Hazen, AR, Bank of North Arkansas, Melbourne, AR, First
National Bank of Stuttgart, Stuttgart, AR, Investark Bankshares, Inc.,
Stuttgart, AR, and Carlisle Bankshares, Inc., Carlisle, AR.
(h) Mr. Hodges is a director of Worthen Banking Corporation, Little Rock, AR
and Newport Federal Savings and Loan Association, Newport, AR.
(i) Dr. Miller is a director of Worthen Banking Corporation, Little Rock, AR.
(j) Mr. Murphy is a director of Arkansas Bank & Trust Company, Hot Springs, AR.
(k) Mr. Nolan is a director of First Financial Bank of El Dorado, El Dorado,
AR, First Commercial Corporation, Little Rock, AR, and Murphy Oil
Corporation, El Dorado, AR.
(l) Mr. Pugh is a director of Portland Bank and Portland Bankshares, Inc.,
Portland, AR and Worthen National Bank of Pine Bluff, Pine Bluff, AR.
(m) Mr. Walker is a director of Worthen Bank and Trust Company, Little Rock,
AR.
(n) Mr. Wilson is a director of American State Bank, Osceola, AR.
(o) Mr. Alexander is a director of First National Bank of Cleburne County,
Heber Springs, AR.
(p) General Barrow is a director of United Companies Financial Corporation,
Baton Rouge, LA.
(q) Mr. Harrison is a director of Premier Bancorp, Inc., Baton Rouge, LA,
Premier Bank, Baton Rouge, LA, and American Liberty Financial Corporation,
Baton Rouge, LA.
(r) Dr. Murrill is a director of First Mississippi Corporation, Jackson, MS,
Tidewater, Inc., New Orleans, LA, FirstMiss Gold, Inc., Reno, NV,
Piccadilly Cafeterias, Baton Rouge, LA, Howell Corporation, Houston, TX,
and Zygo Corporation, Middlefield, CT.
(s) Mr. Owen is a director of Premier Bancorp, Inc., Baton Rouge, LA and
Premier Bank, Baton Rouge, LA.
(t) Dr. Rathbone, Jr. is a director of American Liberty Financial Corporation
and Insurance Company, Baton Rouge, LA. .
(u) Mr. Segnar is a director of Hartmarx Corporation, Chicago, IL, Textron
Inc., Providence, RI, Seagull Energy Corporation, Houston, TX, Mapco, Inc.,
Tulsa, OK, and Pro-Bank, Woodlands and Conroe, TX.
(v) Mr. Hood is a director of First Guaranty Bank, Hammond, LA.
(w) Mr. Shackelford is a director of Bastrop National Bank, Bastrop, LA.
(x) Mr. Smith is a director of American Bank & Trust Company of Houma, Houma,
LA and American Bancshares of Houma, Inc., Houma, LA.
(y) Mr. Day is a director of Trustmark National Bank, Jackson, MS, Trustmark
Corporation, Jackson, MS, Smith County Bank, Taylorsville, MS, Bank of
Edwards, Edwards, MS, Bell South Telecommunications, Atlanta, GA, and South
Central Bell Telephone Company, Jackson, MS.
(z) Mr. Gillis is a director of Trustmark National Bank, Jackson, MS and First
Capital Corporation, Jackson, MS.
(aa) Mr. Meiners is a director of Trustmark National Bank, Jackson, MS, and
Trustmark Corporation, Jackson, MS.
(bb) Mr. Palmer is a director of Deposit Guaranty National Bank, Jackson, MS and
Mobile Telecommunication Technologies (MTEL), Jackson, MS.
(cc) Mr. Robinson is a director of Deposit Guaranty National Bank, Jackson, MS,
and Deposit Guaranty Corporation, Jackson, MS.
(dd) Mr. Cain is a director of Whitney National Bank and Whitney Holding
Corporation (bank holding company), New Orleans, LA and Delchamps, Inc.,
Mobile, AL.
(ee) Mr. Duncan is a director of Hibernia National Bank, Hibernia Corporation,
New Orleans, LA.
(ff) Dr. Francis is a director of The Equitable Life Assurance Society of the
United States, New York, NY, Liberty Bank and Trust, New Orleans, LA, and
First National Bank of Commerce, New Orleans, LA.
(gg) Mr. Teamer is a director of First National Bank of Commerce, New Orleans,
LA.
Each director and officer of the applicable System company is elected
yearly to serve until the first Board Meeting following the Annual Meeting of
Stockholders and until a successor is elected and qualified. Annual meetings
are currently expected to be held as follows:
Entergy Corporation - May 6, 1994
AP&L - May 25, 1994
GSU - May 24, 1994
LP&L - May 23, 1994
MP&L - May 26, 1994
NOPSI - May 23, 1994
System Energy - April 29, 1994
Directorships shown above are generally limited to entities subject to
Section 12 or 15(d) of the Securities and Exchange Act of 1934 or to the
Investment Company Act of 1940.
Section 16(a) of the Securities Exchange Act of 1934 and Section 17(a) of
the Public Utility Holding Company Act of 1935 require each registrant's
officers, directors and persons who own more than 10% of a registered class of
such registrant's equity securities to file reports of ownership and changes in
ownership concerning the securities of Entergy Corporation and its subsidiaries
with the Securities and Exchange Commission and to furnish Entergy Corporation
with copies of all Section 16(a) and 17(a) forms they file. Numerous forms
relating to Sections 16(a) and 17(a) were required to be filed by officers and
directors of Entergy Corporation and of GSU because of the Entergy/GSU merger.
However, the following persons who became officers or directors of GSU following
the Entergy/GSU merger were late in filing their GSU Form 3: Michael B. Bemis,
Frank F. Gallaher, Glenn E. Harder, Donald C. Hintz, Jerry D. Jackson, Richard
J. Landy, Edwin Lupberger, Jerry L. Maulden, Gerald D. McInvale, Michael R.
Niggli, and Lee W. Randall. None of the above-named persons are the beneficial
owners of any securities of GSU and, therefore, are required to file Form 3
solely by virtue of their positions as officers or directors of GSU. These
forms have now been filed with the Securities and Exchange Commission.
Additionally, in 1992, the spouse of Duke Shackelford, a director of Entergy
Corporation and LP&L, inherited 450 shares of Entergy Corporation common stock.
A Form 5 was not timely filed reporting this transaction. This report has now
been filed with the Securities and Exchange Commission.
On June 26, 1991, the assets of The Foster Company, Inc. were sold to
another company, and all undisputed creditors who notified The Foster Company,
Inc. of their claims prior to the sale were paid in full. After the sale of the
assets, only a shell corporation remained. Subsequently, several claims and
lawsuits were filed against the shell corporation. As a result of these
actions, the shell corporation (which was renamed the Montegut Corporation on
November 7, 1991) filed a petition for liquidation under the federal bankruptcy
laws on November 25, 1991. The matter is pending. Mr. Brooke H. Duncan, who
will retire in May, 1994, as a director of Entergy Corporation and NOPSI, served
as President and Director of the Foster Company, Inc. and continues in those
capacities with the Montegut Corporation.
Item 11. Executive Compensation
ENTERGY CORPORATION
Information called for by this item concerning the directors and officers
of Entergy Corporation and the Personnel Committee of Entergy Corporation's
Board of Directors is set forth under the headings "Executive Compensation" and
"Personnel Committee Interlocks and Insider Participation" contained in the
Proxy Statement of Entergy Corporation to be filed in connection with its Annual
Meeting of Stockholders to be held on May 6, 1994, which information is
incorporated herein by reference.
AP&L, GSU, LP&L, MP&L, NOPSI, AND SYSTEM ENERGY
Summary Compensation Tables
The following tables include the Chief Executive Officers and the four
other most highly compensated executive officers in office as of December 31,
1993 at AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy. This determination was
based on total annual base salary and bonuses (excluding bonuses of an
extraordinary and nonrecurring nature) from all System sources earned during the
year 1993. See Item 10. "Directors and Executive Officers of the Registrants",
incorporated herein by reference, for information on the principal positions of
certain of the executive officers named in the table below.
AP&L, LP&L, MP&L, NOPSI, and System Entergy
As shown in Item 10, most executive officers named below are employed by
several System companies. Because it would be impracticable to allocate such
officers' salaries among the various companies, the table below includes
aggregate compensation paid by all System companies. However, GSU paid none of
the reported compensation for the named officers.
Long-Term Compensation
Annual Compensation Awards Payouts
Other Restricted Securities (d) (e)
(f) Annual Stock Underlying LTIP All Other
Name Year Salary Bonus Compensation Awards Options Payouts Compensation
---- ---- ------ ----- ------------ ------ ------- ------- ------------
Michael B. Bemis 1993 $258,538 $161,142 $62,372 (b) 2,500 shares $50,125 $74,619
1992 258,059 170,186 35,927 (b) 2,500 45,094 71,492
1991 245,383 87,878 (a) (b) (c) 0 (a)
Glenn E. Harder 1993 $145,959 $59,349 $4,236 (b) 0 shares $0 $17,111
1992 139,000 24,845 3,898 (b) 0 0 17,611
1991 122,321 15,291 (a) (b) (c) 0 (a)
Donald C. Hintz* 1993 $265,386 $166,560 $48,548 (b) 5,000 shares $85,774 $24,462
1992 228,024 114,822 38,364 (b) 2,500 77,165 24,205
1991 191,653 80,326 (a) (b) (c) 0 (a)
Jerry D. Jackson 1993 $288,559 $217,287 $36,166 (b) 6,719 shares $100,250 $25,961
1992 254,167 152,500 27,008 (b) 5,000 90,188 25,447
1991 225,000 82,575 (a) (b) (c) 31,500 (a)
Edwin Lupberger** 1993 $542,077 $437,610 $20,327 (b) 13,438 shares $248,313 $32,957
1992 527,499 374,100 39,760 (b) 10,000 180,375 33,671
1991 489,996 147,626 (a) (b) (c) 65,625 (a)
Jerry L. Maulden 1993 $385,000 $286,985 $84,655 (b) 5,000 shares $100,250 $25,639
1992 392,233 259,316 79,280 (b) 5,000 90,188 24,920
1991 360,069 156,724 (a) (b) (c) 54,900 (a)
Gerald D. McInvale 1993 $221,696 $141,811 $48,805 (b) 2,500 shares $50,125 $22,667
1992 209,975 93,686 45,585 (b) 2,500 45,094 43,594
1991 132,356 28,280 (a) (b) (c) 0 (a)
Lee W. Randall 1993 $176,321 $57,142 $8,014 (b) 0 shares $0 $17,986
1992 168,859 37,094 6,818 (b) 0 0 19,555
1991 167,890 24,929 (a) (b) (c) 0 (a)
* Chief Executive Officer of System Energy.
** Chief Executive Officer of AP&L, LP&L, MP&L, and NOPSI.
(a) Disclosure in this category is subject to transition rules, and amounts for
1991 are not required to be included herein.
(b) Restricted stock awarded under the Equity Ownership Plan is subject to
performance based criteria. Restricted stock awards in 1993 are reported
under the "Long-Term Incentive Plan Awards" table, and reference is made to
this table for information on the aggregate number of restricted shares
awarded during 1993 and the vesting schedule for such shares. At December
31, 1993, the number and value of the aggregate restricted stock holdings
were as follows: Mr. Bemis: 2,500 shares, $90,000; Mr. Hintz: 4,279 shares,
$154,044; Mr. Jackson: 5,000 shares, $180,000; Mr. Lupberger: 15,000
shares, $540,000; Mr. Maulden: 5,000 shares, $180,000; and Mr. McInvale:
2,500 shares, $90,000. Accumulated dividends are paid on restricted stock
when vested. The value of stock for which restrictions were lifted in
1993, and the applicable portion of accumulated cash dividends, are
reported in the LTIP Payouts column in the above table. The value of
restricted stock awards as of December 31, 1993 is determined by
multiplying the total number of shares awarded by the closing market price
of Entergy Corporation common stock on the New York Stock Exchange
Composite Transactions on December 31, 1993 ($36.00 per share).
(c) There were no stock options granted in 1991.
(d) 1991 amounts shown above include Long-Term Incentive Plan payouts earned in
1991 that were not calculable in time for inclusion in the Compensation
Table in the Form 10-K for 1991. 1993 and 1992 amounts include the value
of restricted shares that vested in 1993 and 1992 under Entergy's Equity
Ownership Plan.
(e) Includes the following:
(1) 1993 Executive Medical Plan premiums of $3,019 for each of the above-
named executives in 1993.
(2) 1993 employer contributions to the Defined Contribution Restoration
Plan as follows: Mr. Bemis $1,800; Mr. Harder $0; Mr. Hintz $886;
Mr. Jackson $1,245; Mr. Lupberger $8,564; Mr. Maulden $5,519; Mr.
McInvale $0; Mr. Randall $0.
(3) 1993 employer contributions to the Employee Stock Ownership Plan as
follows: Mr. Bemis $2,682; Mr. Harder $2,682; Mr. Hintz $2,682;
Mr. Jackson $2,682; Mr. Lupberger $2,682; Mr. Maulden $0; Mr. McInvale
$2,682; Mr. Randall $2,682.
(4) 1993 employer contributions to the System Savings Plan as follows:
Mr. Bemis $7,075; Mr. Harder $4,210; Mr. Hintz $7,075; Mr. Jackson
$7,075; Mr. Lupberger $7,075; Mr. Maulden $6,031; Mr. McInvale $6,301;
Mr. Randall $5,085.
(5) 1993 reimbursements under the Executive Financial Counseling Program
as follows: Mr. Bemis $0; Mr. Hintz $0; Mr. Jackson $1,140;
Mr. Lupberger $4,605; Mr. Maulden $1,350; Mr. McInvale $765.
(6) 1993 payments under the Private Ownership Vehicle Plan as follows:
Mr. Bemis $9,900; Mr. Harder $7,200; Mr. Hintz $10,800; Mr. Jackson
$10,800; Mr. Lupberger $7,012; Mr. Maulden $9,720; Mr. McInvale
$9,900; Mr. Randall $7,200.
(7) 1993 reimbursement for moving expenses as follows: Mr. Bemis $50,143.
(f) Includes bonuses earned pursuant to the Annual Incentive Plan as well as
any bonuses of an extraordinary or nonrecurring nature.
GSU
All of the reported compensation for the officers named below was paid by GSU.
The listed positions were held by these officers in 1993. See item 10.
"Directors and Executive Officers of the Registrants" for current GSU officers.
Long-Term Compensation
Annual Compensation Awards Payouts
Other Restricted Securities (c)
Annual Stock Underlying LTIP All Other
Name Year Salary Bonus Compensation Awards SARs(d) Payouts Compensation
---- ---- ------ ----- ------------ -------- --------- -------- ------------
Donald M. Clements, Jr.(e) 1993 $130,938 $74,345 $0 (b) 11,250 shares (b) $4,614
Senior Vice President - 1992 109,152 25,000 0 (b) 0 (b) 3,850
External Affairs 1991 (e) (e) (a) (b) 0 (b) (a)
Joseph L. Donnelly* 1993 $402,083 $229,088 $0 (b) 38,500 shares (b) $28,271
Chief Executive Officer 1992 358,938 100,000 0 (b) 32,600 (b) 40,777
1991 217,667 0 (a) (b) 9,200 (b) (a)
Calvin J. Hebert 1993 $169,817 $44,345 $0 (b) 5,350 shares (b) $61,668
Senior Vice President - 1992 159,917 0 0 (b) 8,050 (b) 32,715
Division Operations 1991 147,167 0 (a) (b) 8,000 (b) (a)
Edward M. Loggins 1993 $233,750 $57,392 $0 (b) 20,400 shares (b) $16,385
Senior Executive Vice 1992 218,500 0 0 (b) 9,700 (b) 27,423
President 1991 204,000 0 (a) (b) 9,700 (b) (a)
Jack L. Schenck 1993 $158,688 $44,345 $0 (b) 10,700 shares (b) $11,225
Sr. Vice President & 1992 145,329 20,000 0 (b) 4,700 (b) 7,732
Chief Financial Officer 1991 107,550 0 (a) (b) 4,700 (b) (a)
* Chief Executive Officer of GSU as of December 31, 1993.
(a) Disclosure in this category is subject to transition rules, and amounts for
1991 are not required to be included herein.
(b) GSU does not have a Restricted Stock Awards program or a Long-Term
Incentive Plan Awards program.
(c) Includes the following:
(1) 1993 payments by GSU of excess life insurance cost as follows: Mr.
Clements $682; Mr. Donnelly $16,146; Mr. Hebert $240; Mr. Loggins
$9,140; Mr. Schenck $3,816.
(2) 1993 company contributions to the GSU Thrift Plan as follows: Mr.
Clements $3,932; Mr. Donnelly $7,075; Mr. Hebert $5,095; Mr. Loggins
$7,075; Mr. Schenck $4,776.
(3) 1993 company contributions to the GSU Non-qualified Accrued
Contributions Plan as follows: Mr. Donnelly $5,050; Mr. Loggins $170.
(4) Above market earnings on compensation deferred during the period
December 1985-December 1986, as follows: Mr. Donnelly $0; Mr. Hebert
$56,333; Mr. Loggins $0; Mr. Schenck $2,633.
(d) These SARs were attached to shares of GSU common stock. At December 31,
1993, the SARs were exercised and cash was received by the named
executives. See additional disclosure in the "Aggregated Option/SAR
Exercises in 1993 and December 31, 1993 Option Values" table.
(e) No compensation figures are provided for Mr. Clements for year 1991 because
he was not an officer of GSU until June, 1992. All of his 1992
compensation is shown.
(f) Mr. Clements, Mr. Donnelly, Mr. Loggins, and Mr. Schenck have subsequently
resigned as officers of GSU. Therefore, they are not listed above as GSU
officers in Item 10. "Directors and Executive Officers Of The Registrants".
Option/SAR Grants in 1993
The following tables summarize option/SAR grants during 1993 to the
executive officers named in the Summary Compensation Tables above. The absence,
in the table below, of any named officer indicates that no options/SARs were
granted to such officer.
AP&L, LP&L, MP&L, NOPSI, and System Entergy
Individual Grants Potential Realizable
% of Total Value
Number of Options at Assumed Annual
Securities Granted to Exercise Rates of Stock
Underlying Employees Price Price Appreciation
Options in (per Expiration for Option Term(c)
Name Granted(a) 1993 share)(a) Date 5% 10%
---- ----------- ------- --------- ---------- --------- --------
Michael B. Bemis 2,500 3.4% $34.75 02/01/03 $54,635 $138,456
Donald C. Hintz 5,000 6.8% 34.75 02/01/03 109,270 276,913
Jerry D. Jackson 5,000 6.8% 34.75 02/01/03 109,270 276,913
1,719(b) 2.3% 39.75 09/02/03 42,973 108,901
Edwin Lupberger 10,000 13.6% 34.75 02/01/03 218,541 553,826
3,438(b) 4.7% 39.75 09/02/03 85,945 217,802
Jerry L. Maulden 5,000 6.8% 34.75 02/01/03 109,270 276,913
Gerald D. McInvale 2,500 3.4% 34.75 02/01/03 54,635 138,456
(a) Options were granted on February 1, 1993, pursuant to the Equity Ownership
Plan. All options granted on February 1, 1993 have an exercise price equal
to the closing price of Entergy Corporation common stock on the New York
Stock Exchange Composite Transactions on January 29, 1993. These options
became exercisable on August 1, 1993.
(b) Pursuant to the Equity Ownership Plan, if a participant exercises an option
during the term of employment and pays all or any portion of the price
through the surrender of shares of Entergy Corporation common stock, the
Personnel Committee may grant to such participant an additional option to
purchase the number of shares so surrendered. Any such additional option
shall have an exercise price equal to the fair market value of Entergy
Corporation common stock as of the date of its grant. On September 2,
1993, Messrs. Jackson and Lupberger exercised stock options and the
additional options indicated above were granted pursuant to this reload
feature of the Equity Ownership Plan. The reloaded stock options become
exercisable six months from the grant date and have an exercise price equal
to the closing price of Entergy Corporation common stock on the New York
Stock Exchange Composite Transactions on September 2, 1993.
(c) Calculation based on the stock option exercise price over a ten-year period
assuming annual compounding. The columns present estimates of potential
values based on simple mathematical assumptions. The actual value, if any,
an executive officer may realize is dependent upon the market price on the
date of option exercise.
GSU
Individual Grants Potential Realizable
% of Total Value
Number of SARs at Assumed Annual
Securities Granted to Exercise Rates of Stock
Underlying Employees Price Price Appreciation
SARs in (per Expiration for SARs Term
Name Granted(a) 1993 share) Date(a) 5% (a) 10% (a)
---- ---------- ---------- ------ ------- ------ -------
Donald M. Clements, Jr. 11,250 5.8% $16.50 - - -
Joseph L. Donnelly 38,500 19.8% 16.50 - - -
Calvin J. Hebert 5,350 2.7% 16.50 - - -
Edward M. Loggins 20,400 10.5% 16.50 - - -
Jack L. Schenck 10,700 5.5% 16.50 - - -
(a) According to the terms of the Stock Appreciation Plan as amended, effective
on the merger date of December 31, 1993, all SARs issued and granted more
than 6 months prior to the merger date were deemed exercised and payment
was made to the named executives. Thus, all SARs were exercised and all
value realized on the SARs as of December 31, 1993.
Aggregated Option/SAR Exercises in 1993 and December 31, 1993 Option Values
The following tables summarize the number and value of options exercised
during 1993, as well as, the number and value of unexercised options/SARs as of
December 31, 1993 held by the executive officers named in the Summary
Compensation Tables above. The absence, in the tables below, of any named
officer indicates that such officer did not exercise any options in 1993 and
held no unexercised options/SARs as of December 31, 1993.
AP&L, LP&L, MP&L, NOPSI, and System Entergy
Number of
Securities Underlying Value of Unexercised
Unexercised Options In-the-Money Options
Shares Acquired Value as of December 31, 1993 as of December 31, 1993(a)
Name on Exercise Realized(b) Exercisable Unexercisable(c) Exercisable Unexercisable
---- --------------- ----------- ----------- ---------------- ----------- -------------
Michael B. Bemis 0 0 5,000 0 $19,063 0
Donald C. Hintz 0 0 7,500 0 22,188 0
Jerry D. Jackson 2,308 $23,369 7,692 1,719 23,412 0
Edwin Lupberger 4,614 46,717 15,386 3,438 46,836 0
Jerry L. Maulden 0 0 10,000 0 38,125 0
Gerald D. McInvale 0 0 5,000 0 19,063 0
(a) Based on the difference between the closing price of Entergy Corporation
common stock on the New York Stock Exchange Composite Transactions on
December 31, 1993, and the option exercise price.
(b) Based on the difference between the closing price of Entergy Corporation
common stock on the New York Stock Exchange Composite Transactions on the
exercise date of September 2, 1993, and the option exercise price.
(c) Stock options granted on September 2, 1993 are not exercisable for a period
of six months from the date of grant.
GSU
Number of
Securities Underlying Value of Unexercised
Unexercised SARs In-the-Money SARs
Shares Acquired Value as of December 31, 1993 (c) as of December 31, 1993 (c)
Name on Exercise (a) Realized (b) Exercisable Unexercisable Exercisable Unexercisable
---- --------------- ------------ ----------- ------------- ----------- -------------
Donald M. Clements, Jr. 12,750 $54,469 0 0 0 0
Joseph L. Donnelly 165,500 1,166,625 0 0 0 0
Calvin J. Hebert 41,100 238,925 0 0 0 0
Edward M. Loggins 61,100 342,900 0 0 0 0
Jack L. Schenck 43,500 255,875 0 0 0 0
(a) Amount represents the number of SARs exercised during 1993.
(b) Value realized is equal to the difference between the closing price of GSU
common stock on the New York Stock Exchange Composite Transactions, on the
grant date and such price on the date of exercise.
(c) There were no outstanding SARs at December 31, 1993. See additional
disclosure regarding SAR exercises in the "Option/SAR Grants in 1993"
table.
Long-Term Incentive Plan Awards in 1993
AP&L, LP&L, MP&L, NOPSI, and System Energy
The following table summarizes awards of restricted shares of Entergy
Corporation common stock under the Equity Ownership Plan in 1993 to the
executive officers of these companies named in the Summary Compensation Table
above. The absence, in the table below, of any named officer indicates that no
restricted shares were awarded to such officer in 1993.
Estimated Future Payouts Under
Performance Non-Stock Price-Based Plans(a)
Number Period Until
of Maturation Below
Name Shares Or Payout Threshold(b) Threshold(c) Target(d) Maximum(e)
---- ------ ------------ ------------ ------------ --------- ----------
Edwin Lupberger 5,000 01/01/93-12/31/03 0 5,000 5,000 5,000
(a) Restricted shares awarded will vest incrementally over a period not to
exceed 10 years, subject to the attainment of specific stockholder earnings
goals and cost containment goals for the year. Restrictions are lifted
based upon assigned weighted averages of these performance measures, with
the specific relative percentage weight of such measures varying depending
upon the individual. The value an executive officer may realize is
dependent upon both the number of shares that vest and the future market
price of Entergy Corporation common stock.
(b) If goals are met at less than the 50% level of achievement in a given year,
no restrictions will be lifted that year. Thus, if this level of
performance is reached in each year, no shares will vest.
(c) If goals are met at the 50-99% level of achievement in a given year, 20% of
the restrictions will be lifted that year. Thus, if this level of
performance is reached in each year, all shares will vest within 5 years.
(d) If goals are met at the 100-149% level of achievement in a given year, 25%
of the restrictions will be lifted that year. Thus, if this level of
performance is reached in each year, all shares will vest within 4 years.
(e) If goals are met at the 150% level of achievement (the maximum percent
achievable) in a given year, 33 1/3% of the restrictions will be lifted
that year. Thus, if this level of performance is reached in each year, all
shares will vest within 3 years.
Pension Plan Tables
AP&L, LP&L, MP&L, NOPSI, and System Energy
Retirement Income Plan Table
Annual
Covered Years of Service
Compensation 10 15 20 25 30 35
------------ --- -- -- -- -- --
$100,000 $15,000 $ 22,500 $ 30,000 $ 37,500 $ 45,000 $ 52,500
200,000 30,000 45,000 60,000 75,000 90,000 105,000
300,000 45,000 67,500 90,000 112,500 135,000 157,500
400,000 60,000 90,000 120,000 150,000 180,000 210,000
500,000 75,000 112,500 150,000 187,500 225,000 262,500
650,000 97,500 146,250 195,000 243,750 292,500 341,250
AP&L, LP&L, MP&L, and System Energy each individually sponsors or
participates in a Retirement Income Plan (a defined benefit plan) that provides
a benefit for employees at retirement from the System based upon (1) generally
all years of service beginning at age 21 through termination, with a forty-year
maximum, times (2) 1.5% for each year of service, times (3) the final average
salary. NOPSI is a participating employer in LP&L's Retirement Income Plan.
System Energy is a participating employer in the Retirement Income Plan
sponsored by Entergy Corporation. Final average salary is based on the highest
60 months of covered compensation in the last 120 months of service. The normal
form of benefit for a single employee is a lifetime annuity and for a married
employee is a 50% joint and survivor annuity. Other actuarially equivalent
options are available to each retiree. Retirement benefits are not subject to
any deduction for Social Security or other offset amounts. The amount of the
named individuals' annual compensation covered by the plan as of December 31,
1993 is represented by the base salary column in the Summary Compensation Table
of AP&L, LP&L, MP&L, NOPSI, and System Energy.
The maximum benefit under each Retirement Income Plan is limited by
Sections 401 and 415 of the Internal Revenue Code; however, AP&L, LP&L, MP&L,
NOPSI, and System Energy have elected to participate in the Pension Equalization
Plan sponsored by Entergy Corporation. Under this plan, certain executives,
including the named executive officers, would receive an amount equal to the
benefit payable under the Retirement Income Plans, without regard to the
limitations, less the amount actually payable under the Retirement Income Plans.
Each Retirement Income Plan was amended effective February 1, 1991 to
provide a minimum accrued benefit as of that date to any employee who was vested
as of that date. For purposes of calculating such minimum accrued benefit, each
eligible employee was deemed to have had an additional five years of service and
age as of that date. The additional years of age did not count toward
eligibility for early retirement, but served only to reduce the early retirement
discount factor for those employees who were at least age 50 as of that date.
The credited years of service under the Retirement Income Plan (without
giving effect to the five additional years of service credited pursuant to the
February 1, 1991 amendment as discussed above) as of December 31, 1993 for the
following executive officers named in the Summary Compensation Table of AP&L,
LP&L, MP&L, NOPSI, and System Energy were: Mr. Bemis 11; Mr. Harder 15;
Mr. Maulden 28; Mr. Randall 14. The credited years of service under the
respective Retirement Income Plans, as amended, as of December 31, 1993 for the
following executive officers named in the Summary Compensation Table, as a
result of entering into supplemental retirement agreements, were as follows:
Mr. Hintz 22; Mr. Jackson 14; Mr. Lupberger 30; Mr. McInvale 21.
In addition to the Retirement Income Plan discussed above, AP&L, LP&L,
MP&L, NOPSI and System Energy participate in the Supplemental Retirement Plan of
Entergy Corporation and Subsidiaries (SRP) and the Post-Retirement Plan of
Entergy Corporation and Subsidiaries (PRP). Participation is limited to one of
these two plans and is at the invitation of AP&L, LP&L, MP&L, NOPSI, and System
Energy. The participant may receive from the appropriate System company a
monthly benefit payment not in excess of .025 (under the SRP) or .0333 (under
the PRP) times the participant's average basic annual salary (as defined in the
plans) for a maximum of 120 months. As of January 31, 1994, Mr. Hintz has
entered into a SRP participation contract, and all of the other executive
officers of AP&L, LP&L, MP&L, NOPSI, and System Energy named in the Summary
Compensation Table (except for Mr. McInvale) have entered into PRP participation
contracts.
System Executive Retirement Plan Table (1)
Annual
Covered Years of Service
Compensation 10 15 20 25 30+
------------ -- -- -- -- --
$ 200,000 $ 60,000 $ 90,000 $100,000 $110,000 $120,000
300,000 90,000 135,000 150,000 165,000 180,000
400,000 120,000 180,000 200,000 220,000 240,000
500,000 150,000 225,000 250,000 275,000 300,000
600,000 180,000 270,000 300,000 330,000 360,000
700,000 210,000 315,000 350,000 385,000 420,000
1,000,000 300,000 450,000 500,000 550,000 600,000
___________
(1) Benefits shown are based on a target replacement ratio of 50% based on the
years of service and covered compensation shown. The benefits for 10, 15, and
20 or more years of service at the 45% and 55% replacement levels would decrease
(in the case of 45%) or increase (in the case of 55%) by the following
percentages: 3.0%, 4.5%, and 5.0%, respectively.
In 1993, Entergy Corporation adopted the System Executive Retirement Plan
(SERP). AP&L, LP&L, MP&L, NOPSI, and System Energy are participating employers
in the SERP. The SERP is an unfunded defined benefit plan offered at retirement
to certain senior executives, which would currently include all the executive
officers named in the Summary Compensation Table of AP&L, LP&L, MP&L, NOPSI, and
System Energy. Participating executives choose, at retirement, between the
retirement benefits paid under provisions of the SERP or those payable under the
executive retirement benefit plans discussed above. Covered pay under the SERP
includes final annual base salary (see the Summary Compensation Table of AP&L,
LP&L, MP&L, NOPSI, and System Energy for the base salary covered by the SERP as
of December 31, 1993) plus the Target Incentive Award (i.e., a percentage of
final annual base salary) for the participant in effect at retirement. The
Target Incentive Award as of December 31, 1993, was: 58% for Messrs. Jackson,
Lupberger and Maulden; 48% for Messrs. Bemis, Hintz and McInvale; and, 35% for
Messrs. Harder and Randall. Benefits paid under the SERP are calculated by
multiplying the covered pay times target pay replacement ratios (45%, 50%, or
55%, dependent on job rating at retirement) that are attained, according to plan
design, at 20 years of credited service. The target ratios are increased by 1%
for each year of service over 20 years, up to a maximum of 30 years of service.
In accordance with the SERP formula, the target ratios are reduced for each year
of service below 20 years.
The normal form of benefit for a single employee is a lifetime annuity and
for a married employee is a 50% joint and survivor annuity. All SERP payments
are guaranteed for ten years. Other actuarially equivalent options are
available to each retiree. SERP benefits are offset by any and all defined
benefit plan payments from the company and from prior employers. SERP benefits
are not subject to Social Security offsets.
Eligibility for and receipt of benefits under any of the executive plans
described above are contingent upon several factors. The participant must agree
that, without the specific consent of the System company for which such
participant was last employed, he may take no employment after retirement with
any entity that is in competition with or similar in nature to, AP&L, LP&L,
MP&L, NOPSI, and System Energy or any affiliate thereof. Eligibility for
benefits is forfeitable for various reasons, including violation of an agreement
with AP&L, LP&L, MP&L, NOPSI, and System Energy, resignation of employment, or
termination for cause.
GSU
Employees' Trusteed Retirement Plan Table
Annual
Covered Years of Service
Compensation 10 15 20 25 30 35
------------ -- -- -- -- -- --
$100,000 $15,167 $22,751 $30,335 $37,918 $ 45,502 $ 53,086
150,000 23,167 34,751 46,335 57,918 69,502 81,086
200,000 31,167 46,751 62,335 77,918 93,502 109,086
235,840* 36,902 55,353 73,803 92,254 110,705 129,156**
* Maximum 1993 annual covered compensation imposed by Section 401 of the
Internal Revenue Code.
** Maximum 1993 annual benefit imposed by Section 415 of the Internal Revenue
Code is $115,641 payable at age 65.
GSU has an Employees' Trusteed Retirement Plan that provides a benefit for
employees at retirement from GSU based upon generally all years of service
beginning at age 21 through termination, with a thirty-five year maximum, times
(2) 1.2% of that portion of the participant's average final compensation not in
excess of his average Social Security wage base, plus 1.6% of the part of such
compensation in excess of such average Social Security wage base. This amount
is reduced by the total amounts payable under a certain group annuity contract.
Average final compensation is based on the 60 consecutive months during the last
ten years of credited service which produce the highest average or during all
months of credited service if such service is less than 60 months. The normal
form of benefit for a single employee is a single life annuity and the actuarial
equivalent 50% joint and survivor annuity of the employee is married. The above
table illustrates annual retirement benefits expressed in terms of single life
annuities based on the base salary and service shown and retirement at age 65.
The amount of the named individuals' annual compensation covered by the plan as
of December 31, 1993 is represented by the base salary column in the Summary
Compensation Table of GSU.
The credited years of service under the Employees' Trusteed Retirement Plan
as of December 31, 1993 for the following executive officers named in the
Summary Compensation Table were: Mr. Clements, 14 years; Mr. Donnelly, 14
years; Mr. Hebert, 29 years; Mr. Loggins, 33 years; Mr. Schenck, 12 years.
In addition to the Employees' Trusteed Retirement Plan discussed above, GSU
provides, among other benefits to officers, an Executive Income Security Plan
for key managerial personnel. The plan provides participants with certain
retirement, disability, termination, and survivors' benefits. To the extent
that such benefits are not funded by the employee benefit plans of GSU or by
vested benefits payable by the participants' former employers, GSU is obligated
to make supplemental payments to participants or their survivors. The plan
provides that upon the death or disability of a participant during his
employment, he or his designated survivors will receive (i) during the first
year following his death or disability an amount not to exceed his annual base
salary, and (ii) thereafter for a number of years until the participant attains
or would have attained age 65, but not less than nine years, an amount equal to
one-half of the participant's annual base salary. The plan also provides
supplemental retirement benefits for life for participants retiring after
reaching age 65 equal to 1/2 of the participant's average final compensation
rate, with 1/2 of such benefit upon the death of the participant being payable
to a surviving spouse for life.
GSU amended and restated the plan effective March 1, 1991, to provide such
benefits for life upon termination of employment of a participating officer or
key managerial employee without cause (as defined in the plan) or if the
participant separates from employment for good reason (as defined in the plan),
with 1/2 of such benefits to be payable to a surviving spouse for life.
Further, the plan was amended to provide medical benefits for a participant and
his family when the participant separates from service. These medical benefits
generally continue until the participant is eligible to receive medical benefits
from a subsequent employer; but in the case of a participant who is over 50 at
the time of separation and was participating in the plan on March 1, 1991,
medical benefits continue for life. By virtue of the 1991 amendment and
restatement, benefits for a participant cannot be modified once he becomes
eligible to participate in the plan.
Compensation of Directors
Employees of any Entergy System company who serve on the Board of Directors
of any Entergy System company receive no compensation as directors. Directors
of AP&L, LP&L, MP&L, and NOPSI who are not employees of a System company are
paid an attendance fee of $1,000 for attendance at meetings of their respective
Board of Directors, $1,000 (except for the chairman of such committee who is
paid $1,500) for attendance at meetings of committees of the Board and $1,000
for participation, on behalf of their respective company, in any inspection trip
or conference not held on the same day as a Board or committee meeting. All
non-employee directors are also compensated on a quarterly basis in the form of
fixed awards of Entergy Corporation common stock pursuant to the Stock Plan for
Outside Directors (Directors Plan) and cash based on 1/2 the value of the stock
awarded pursuant to the Directors Plan. This level of directors' compensation
is set to enable Entergy Corporation to attract and retain persons of
outstanding competence to serve on the Boards of Directors. Directors are paid
a portion of their compensation in the form of Entergy Corporation's common
stock in order to assure that directors will have a personal interest in the
performance of the stock of Entergy Corporation. Non-employee directors are
awarded 50 shares of Entergy Corporation common stock quarterly, which may be
authorized but unissued shares or shares acquired in the open market. System
Energy has no non-employee directors.
Retired non-employee outside directors of AP&L, LP&L, MP&L, and NOPSI with
a minimum of five years of service on the respective Boards of Directors are
paid $200 a month for a term corresponding to the number of years of service.
Retired directors with over ten years of service receive a lifetime benefit of
$200 a month.
Directors of GSU or its subsidiaries, who are not officers of GSU are paid
the following fees: $15,000 per year retainer, an additional retainer of $2,400
to the director who serves as Chairman of the Executive Committee, $700 per day
per Board meeting attended plus out-of-pocket expenses, $600 per day per
committee meeting attended plus out-of-pocket expenses, and an additional fee of
$150 per meeting to each director who serves as Chairman of the Executive,
Audit, Compensation, Nominating Committees, the Board Committee on Nuclear
Safety, the Business Policy Committee, or any other Committee composed of
members of the Board. Also, when an outside director attends a specific
business activity on behalf of GSU, at the request of the Chairman of the Board
of Directors, he receives a fee of $600 per day plus out-of-pocket expenses.
Outside directors of GSU may elect to defer 25 percent, 50 percent or 100
percent of their director's compensation. Under this nonqualified plan, a
director's deferred compensation will accrue simple interest at the greater of
(1) a rate equivalent to that payable by GSU on its average daily short-term
debt during a preceding period or (2) a rate equivalent to that received by GSU
on its average daily short-term investments during the preceding year.
Directors may select deferred compensation payments to commence after death,
upon permanent disability, after a certain age on a specific date, or after
cessation of directorship of GSU, and may select payment in a lump sum or in
annual installments. In 1993, two GSU directors participated in the deferred
compensation plan.
In 1991, the GSU Compensation Committee of the Board of Directors approved
a retirement plan for directors of GSU. Under this plan all directors who serve
continuously for a period of years will receive a percentage of their retainer
fee in effect at the time of their retirement for life. The retirement benefit
will be 30 percent of the retainer fee for service of not less than five nor
more than nine years, 40 percent for service of not less than ten nor more than
fourteen years, and 50 percent for fifteen or more years of service. For those
directors who retire prior to the retirement age as specified in the GSU Bylaws,
the benefits will be reduced. The plan also provides disability retirement if
the director has served at least five years prior to the disability. The
benefits payable under this plan are general unsecured obligations of GSU and no
funds or other amendments have been reserved or set aside by GSU to provide a
source of payment or funding.
In 1983, the GSU Board of Directors approved a proposal to have hospital
and medical coverage through GSU's insurance carrier made available to members
of the GSU Board. Under the terms of this proposal, (i) hospital and medical
coverage will be secondary to coverage by a director's primary place of
employment and/or Medicare, if applicable, (ii) two-thirds of the cost of
providing the coverage to the director will be paid by GSU and the remaining
one-third by the director, (iii) that portion of the premium paid by GSU will
be reported as taxable income to the director as required by the Internal
Revenue Service, and (iv) a director may retain his coverage after leaving the
Board, if he has served five or more full elected terms on the Board. Under
this plan in 1993, insurance premiums were paid to Provident Companies on
behalf of the following directors: $1,424 for Gen. Barrow, $119 for Mr.
Harrison, $3,944 for Mr. Peters, and $1,424 for Dr. Rathbone, Jr.
In 1984, the GSU Board of Directors approved a plan whereby Coopers &
Lybrand would make available their services to provide counseling and tax
service individually to all directors for the purpose of assisting them with the
establishment of individual Keogh plans and directed that the necessary changes
be made in the compensation, benefit plans and other supplemental arrangements
of management directors to enable them to participate also in such Keogh plans.
In 1993 Coopers & Lybrand provided tax services to Dr. Murrill in the amount of
$9,254.
Dr. Murrill received in 1993 and will continue to receive payments from GSU
under a retirement agreement and has received payments for consulting services,
but none of such payments to him is for services as a director.
For 1994, GSU adopted the Entergy System's compensation plans for outside
directors.
Employment Contracts and Termination of Employment and Change-in-Control
Arrangements
GSU
GSU has agreed to employ Mr. Donnelly to serve at the pleasure of the Board
at a salary fixed by the Board, and to assure (i) a pension benefit equivalent
to that which would be provided by GSU's Employees' Trusteed Retirement Plan if
he were given credit for prior service of 21.16 years, less credits for accrued
benefits under certain GSU plans and social security, and calculated without
application for the limit imposed by law on benefits that may be paid under
qualified plans, (ii) payment upon termination of employment in certain events
of a severance benefit equivalent to one year's base salary, (iii) payment after
retirement of a death benefit equivalent to three times his highest annual base
salary during the three years preceding retirement, (iv) certain financial
consulting and other services, and (v) a contingent pension benefit for his
spouse equal to fifty percent of his retirement benefit. Except for certain
credits described above, these benefits are in addition to those he would be
entitled to under GSU plans in which he is a participant. To the extent
benefits to which Mr. Donnelly may become entitled are not funded through GSU
plans, they will represent general obligations of GSU. In the event of a change
of control of GSU and a termination by Mr. Donnelly of his employment for good
reason (as defined in the Executive Continuity Plan), the agreement provides he
is not entitled to the severance benefit but is entitled to the pension benefit
without regard to his age. Effective as of January 5, 1994 Mr. Donnelly
resigned from his offices as Chairman of the Board of Directors, President,
Chief Executive Officer, and Director of GSU, and agreed that he would retire as
an employee of GSU as of April 1, 1994. On January 22, 1994, Mr. Donnelly
resigned as Vice Chairman and Director of Entergy Corporation and entered into a
three-year consulting contract providing for an annual fee of $200,000.
GSU established on January 18, 1991, an Executive Continuity Plan for
elected and appointed officers providing for severance benefits equal to 2.99
times the officer's annual compensation upon termination of employment for
reasons other than cause or upon a resignation of employment for good reason
within two years after a change in control of GSU. Benefits are prorated if the
officer is within three years of normal retirement age (65) at termination of
employment. The plan further provides for continued participation in medical,
dental and life insurance programs for three years following termination unless
such benefits are available from a subsequent employer. The plan provides for
outplacement assistance to aid a terminated officer in securing another
position. Upon consummation of the Entergy/GSU merger on December 31, 1993, GSU
made a contribution of $16,330,693 to a trust equivalent to the then present
value of the maximum benefits which might be payable under the plan. If and to
the extent the benefits are not thereafter paid to the participants, the balance
in the trust will be returned to GSU.
As a result of the Entergy/GSU merger, GSU is obligated to pay benefits
under the Executive Income Security Plan to those persons who were participants
at the time of the merger and who later terminated their employment under
circumstances described in the plan. For additional description of the benefits
under the Executive Income Security Plan, see the "Pension Plan Tables - GSU"
section noted above.
Personnel/Compensation Committee Interlocks and Insider Participation
The following persons served as members of the Personnel Committee of
AP&L's, LP&L's, MP&L's, NOPSI's and System Energy's Board of Directors and the
Compensation Committee of GSU's Board of Directors in 1993:
AP&L
John A. Cooper, Jr.*
Edwin Lupberger
Roy L. Murphy
Woodson D. Walker
GSU
Monroe J. Rathbone, Jr., M.D.
Sam F. Segnar*
Bismark A. Steinhagen
LP&L
Tex. R. Kilpatrick*
Edwin Lupberger
Wm. Clifford Smith
MP&L
Norman B. Gillis
Robert E. Kennington, II*
Edwin Lupberger
Robert M. Williams, Jr.
NOPSI
Edwin Lupberger
Anne M. Milling
John B. Smallpage*
System Energy
System Energy does not have a Personnel Committee of the Board of
Directors. The compensation of System Energy's executive officers (with the
exception of one officer) is set by the Personnel Committee of Entergy
Corporation's Board of Directors. No officers or employees of System Energy
participated in deliberations concerning compensation in 1993.
_______________
* Denotes Chairman of the Personnel/Compensation Committee
Mr. Lupberger is currently and was during 1993 an officer of AP&L, LP&L,
MP&L, and NOPSI and also served as an executive officer of their subsidiary,
System Fuels, from 1981-1990.
Mr. Jackson, Executive Vice President - Finance and External Affairs and
Secretary of AP&L, served until May 13, 1993 on the compensation committee of
the Board of Directors of Cooper Communities, Inc., whose chairman is John A.
Cooper, Jr., a director of AP&L.
During 1993, T. Baker Smith & Son, Inc. performed land surveying services
for, and received payments of approximately $153,000 from, LP&L. Mr. Wm.
Clifford Smith, a director of LP&L and a member of LP&L's Personnel Committee,
is President of T. Baker Smith & Son, Inc. Mr. Smith's children own 100% of the
voting stock of T. Baker Smith & Son, Inc.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Entergy Corporation owns 100% of the outstanding common stock of
registrants AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy. The information
with respect to persons known by Entergy Corporation to be beneficial owners of
more than 5% of Entergy Corporation's common stock is included under the heading
"Voting Securities Outstanding" in the Proxy Statement of Entergy Corporation to
be filed in connection with its Annual Meeting of Stockholders to be held May 6,
1994, which information is incorporated herein by reference. The registrants
know of no contractual arrangements which may, at a subsequent date, result in a
change in control of any of the registrants.
The directors, the executive officers named in the Summary Compensation
Tables, and the directors and officers as a group for Entergy Corporation, AP&L,
GSU, LP&L, MP&L, NOPSI, and System Energy, respectively, beneficially owned
directly or indirectly the following cumulative preferred stock of a System
company and common stock of Entergy Corporation:
As of December 31, 1993
Entergy Corporation
Common Stock
Preferred Stock(a) Amount and Nature
Amount and Nature of of Beneficial
Beneficial Ownership(b) Ownership(b)
Sole Voting Sole Voting Other
and Other and Beneficial
Investment Beneficial Investment Ownership
Name Power(c) Ownership Power(c) (d)(e)(f)(g)(l)(m)
---- -------- ----------- ---------- ------------------
Entergy Corporation
W. Frank Blount* - - 2,134 -
John A. Cooper, Jr.* 6,000(a) - 5,484 -
Joseph L. Donnelly*** - - 126 1,477
Brooke H. Duncan* - - 2,100 -
Lucie J. Fjeldstad* - - 1,284 -
Dr. Norman C. Francis* - - 100 -
Donald C. Hintz** - - 1,519 13,462
Kaneaster Hodges, Jr.* - - 2,000 -
Donald Hunter** - - 1,917 10,499
Jerry D. Jackson** - - 5,220 16,888
Robert v.d. Luft* - - 1,384 -
Edwin Lupberger** - - 7,867 40,147
Jerry L. Maulden** - - 21,998 25,190
Adm. Kinnaird R. McKee* - - 2,500 -
Paul W. Murrill* - - 1,300 -
James R. Nichols* - - 2,423 -
Eugene H. Owen* - 3,500(a) 558 -
John N. Palmer, Sr.* - - 11,907 -
Robert D. Pugh* - - 4,500 6,000(h)
H. Duke Shackelford* - - 6,200 3,950(h)
Wm. Clifford Smith* - - 2,905 -
Bismark A. Steinhagen* - - 5,803 -
Dr. Walter Washington* - - 442 4,017
All directors and executive
officers 6,000 3,578 109,931 185,511
AP&L
Michael B. Bemis** - - 5,999 12,297
John A. Cooper, Jr.* 6,000(a) - 5,484 -
Cathy Cunningham* - - 1,200 1,000(i)
Richard P. Herget, Jr.* - - 725 -
Tommy H. Hillman* - - - 200(j)
Donald C. Hintz** - - 1,519 13,462
Kaneaster Hodges, Jr.* - - 2,000 -
Jerry D. Jackson** - - 5,220 16,888
R. Drake Keith*** - - 2,048 11,306
Edwin Lupberger** - - 7,867 40,147
Jerry L. Maulden** - - 21,998 25,190
Raymond P. Miller, Sr.* - - 500 -
Roy L. Murphy* - - 400 -
William C. Nolan, Jr.* - - 476 -
Robert D. Pugh* - - 4,500 6,000(h)
Gus B. Walton, Jr.* - - 20,127 -
Michael E. Wilson* - - 255 -
All directors and executive 6,000 - 90,107 173,388
officers
GSU
Robert H. Barrow* - - 61 -
Joseph L. Donnelly** - - 126 1,477
Frank F. Gallaher*** - - 1,913 7,691
Frank W. Harrison, Jr.* - - 769 -
Calvin J. Hebert** - - 1,016 -
Donald C. Hintz*** - - 1,519 13,462
William F. Klausing* - - 334 -
Edward M. Loggins** - - 125 2,120
Jerry L. Maulden*** - - 21,998 25,190
Paul W. Murrill* - - 1,300 -
Eugene H. Owen* - 3,500(a) 558 -
M. Bookman Peters* - - 558 -
Monroe J. Rathbone, Jr.* - - 278 -
Jack L. Schenck** - - - 641
Sam F. Segnar* - - 279 -
Bismark A. Steinhagen* - - 5,803 -
James E. Taussig, II* - - 906 -
All directors and executive
officers - 3,500 67,210 165,108
LP&L
Michael B. Bemis** - - 5,999 12,297
John J. Cordaro*** - - 1,131 7,831
Donald C. Hintz** - - 1,519 13,462
William K. Hood* 800(a) - 1,750 -
Jerry D. Jackson** - - 5,220 16,888
Tex R. Kilpatrick* - - 1,478 993(k)
Joseph J. Krebs, Jr.* - - 453 -
Edwin Lupberger** - - 7,867 40,147
Jerry L. Maulden** - - 21,998 25,190
H. Duke Shackelford* - - 6,200 3,950(h)
Wm. Clifford Smith* - - 2,905 -
All directors and executive
officers 800 - 65,553 170,286
MP&L
Michael B. Bemis** - - 5,999 12,297
Frank R. Day* - - 2,050 -
John O. Emmerich, Jr.* - - 500 -
Jerry D. Jackson** - - 5,220 16,888
Edwin Lupberger** - - 7,867 40,147
Jerry L. Maulden** - - 21,998 25,190
Gerald D. McInvale** - - 1,152 7,949
Donald E. Meiners*** - - 830 11,962
John N. Palmer, Sr.* - - 11,907 -
Dr. Clyda S. Rent* - - 450 -
E. B. Robinson, Jr.* - - 300 -
Dr. Walter Washington* - - 442 4,017
Robert M. Williams, Jr.* - - 500 1,200
All directors and executive
officers - - 64,928 169,626
NOPSI
Michael B. Bemis** - - 5,999 12,297
James M. Cain* - - 1,215 8,421
John J. Cordaro*** - - 1,131 7,831
Brooke H. Duncan* - - 2,100 -
Norman C. Francis* - - 100 -
Donald C. Hintz* - - 1,519 13,462
Jerry D. Jackson** - - 5,220 16,888
Edwin Lupberger** - - 7,867 40,147
Jerry L. Maulden** - - 21,998 25,190
Gerald D. McInvale** - - 1,152 7,949
John B. Smallpage* - - 500 -
Charles C. Teamer, Sr.* - - 324 -
All directors and executive
officers - - 53,022 170,390
System Energy
Glenn E. Harder** - - 58 3,568
Donald C. Hintz** - - 1,519 13,462
Jerry D. Jackson* - - 5,220 16,888
Edwin Lupberger** - - 7,867 40,147
Jerry L. Maulden* - - 21,998 25,190
Gerald D. McInvale** - - 1,152 7,949
Lee W. Randall** - - - 4,094
All directors and executive
officers - - 38,348 113,313
* Director of the respective Company
** Named Executive Officer of the respective Company
*** Officer and Director of the respective Company
(a) Stock ownership amounts refer to Preferred Stock, $100 Par Value, (except
for the 6,000 shares of AP&L's $0.01 Par Value ($25 liquidation value),
Preferred Stock held by John A. Cooper Trust; 3,500 shares of AP&L's $0.01
Par Value ($25 liquidation value), Preferred Stock held by Eugene H. Owen;
and 800 Shares of LP&L's $25 Par Value Preferred Stock held by William K.
Hood). Mr. Cooper disclaims any personal interest in these shares.
(b) Based on information furnished by the respective individuals. The
ownership amounts shown for each individual and for all directors and
executive officers as a group do not exceed one percent of the outstanding
securities of any class of security so owned.
(c) Includes all shares which the individual has the sole power to vote and
dispose of, or to direct the voting and disposition of.
(d) Includes, for the named persons, shares of Entergy Corporation common stock
held in the Employee Stock Ownership Plan of the registrants as follows:
Michael B. Bemis, 666 shares; James M. Cain, 802 shares; John J. Cordaro,
940 shares; Glenn E. Harder, 686 shares; Donald C. Hintz, 703 shares;
Donald Hunter, 703 shares; Jerry D. Jackson, 703 shares; R. Drake Keith,
703 shares; Edwin Lupberger, 770 shares; Jerry L. Maulden, 743 shares;
Gerald D. McInvale, 103 shares; Donald E. Meiners, 516 shares; and Lee W.
Randall, 739 shares.
(e) Includes, for the named persons, shares of Entergy Corporation common stock
held in the System Savings Plan as follows: Michael B. Bemis, 4,131 shares;
James M. Cain 7,619 shares; John J. Cordaro, 1,391 shares; Glenn E. Harder,
2,882 shares; Donald C. Hintz, 980 shares; Donald Hunter 2,296 shares;
Jerry D. Jackson, 1,774 shares; R. Drake Keith, 3,429 shares; Edwin
Lupberger; 5,553 shares; Jerry L. Maulden, 9,447 shares; Gerald D.
McInvale, 346 shares; Donald E. Meiners, 3,946 shares; and Lee W. Randall,
3,355 shares.
(f) Includes, for the named persons, unvested restricted shares of Entergy
Corporation common stock held in the Equity Ownership Plan as follows:
Michael B. Bemis, 2,500 shares; John J. Cordaro, 3,000 shares; Donald C.
Hintz, 4,279 shares; Donald Hunter, 2,500 shares; Jerry D. Jackson,
5,000 shares; R. Drake Keith, 2,500 shares; Edwin Lupberger, 15,000 shares;
Jerry L. Maulden, 5,000 shares; Gerald D. McInvale, 2,500 shares; and
Donald E. Meiners, 2,500 shares.
(g) Includes, for the named persons, shares of Entergy Corporation common stock
in the form of unexercised stock options awarded pursuant to the Equity
Ownership Plan as follows: Michael B. Bemis, 5,000 shares; John J. Cordaro
2,500 shares; Donald C. Hintz, 7,500 shares; Donald Hunter, 5,000 shares;
Jerry D. Jackson, 9,411 shares; R. Drake Keith, 4,674 shares; Edwin
Lupberger, 18,824 shares; Jerry L. Maulden, 10,000 shares; Gerald D.
McInvale, 5,000 shares; and Donald E. Meiners, 5,000 shares.
(h) Includes, for the named persons, shares of Entergy Corporation common stock
held by their spouses. The named persons disclaim any personal interest in
these shares as follows: Robert D. Pugh 6,000 shares; and H. Duke
Shackleford, 3,950 shares.
(i) Reflects 500 shares of Entergy common stock owned by a Profit Sharing Plan
at Cunningham Butane Gas Company and 500 shares of Entergy common stock not
owned solely by Cathy Cunningham of which she has shared voting and
investment power.
(j) Reflects 200 shares owned by Tommy Hillman Farms, Inc.
(k) Tex R. Kilpatrick is President of Central American Life Insurance Company
which owns 993 shares of Entergy common stock.
(l) Includes, for the named person, shares of Entergy Corporation common stock
held in the GSU Thrift Plan as follows: Jack L. Schenck, 302 shares.
(m) Includes, for the named persons, shares of Entergy Corporation common stock
held in the GSU Employee Stock Ownership Plan as follows: Joseph L.
Donnelly, 1,477 shares; Edward M. Loggins, 2,120 shares; and Jack L.
Schenck, 339 shares.
Item 13. Certain Relationships and Related Transactions.
Information called for by this item concerning the directors and officers
of Entergy Corporation is set forth under the heading "Certain Transactions" in
the Proxy Statement of Entergy Corporation to be filed in connection with its
Annual Meeting of Stockholders to be held on May 6, 1994, which information is
incorporated herein by reference.
See Item 11. "Executive Compensation - Personnel/Compensation Committee
Interlocks and Insider Participation" for information on certain transactions
required to be reported under this item.
The System companies do not have policies whereby transactions involving
executive officers and directors of the System are approved by a majority of
disinterested directors. However, pursuant to the Entergy Corporation Code of
Conduct, transactions involving a System company and its executive officers must
have prior approval by the next higher reporting level of that individual, and
transactions involving a System company and its directors must be reported to
the secretary of the appropriate System company.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a)1. Financial Statements and Independent Auditors' Reports,
incorporated herein by reference, for Entergy, AP&L, GSU, LP&L,
MP&L, NOPSI, and System Energy are listed in the Index to
Financial Statements (see pages 57 and 58)
(a)2. Financial Statement Schedules
Independent Auditors' Reports on Financial Statement Schedules,
incorporated herein by reference (see pages 349 and 350.
Financial Statement Schedules are listed in the Index to
Financial Statement Schedules, incorporated herein by reference
(see page S-1)
(a)3. Exhibits
Exhibits for Entergy, AP&L, GSU, LP&L, MP&L, NOPSI, and System
Energy are listed in the Exhibit Index, incorporated herein by
reference (see page E-1), Each management contract or
compensatory plan or arrangement required to be filed as an
exhibit hereto is identified as such by footnote in the Exhibit
Index.
(b) Reports on Form 8-K
GSU
A current report on Form 8-K, dated November 30, 1993, was filed
with the SEC on December 1, 1993, reporting information under
Item 7 "Financial Statements and Exhibits".
A current report on Form 8-K, dated January 18, 1994, was filed
with the SEC on January 18, 1994, reporting information under
Item 5 "Other Materially Important Events".
A current report on Form 8-K, dated February 1, 1994, was filed
with the SEC on February 8, 1994, reporting information under
Items 2 and 7.
Entergy Corporation, AP&L, GSU, LP&L, MP&L and NOPSI
Current Reports on Form 8-K, dated December 31, 1993, were filed
by these companies on January 3, 1994 reporting the
consummation of the Entergy Corporation - GSU merger under Item
5 (in the case of AP&L, LP&L, MP&L and NOPSI), Items 2 and 7
(in the case of Entergy Corporation and GSU).
EXPERTS
All statements in Part I of this Annual Report on Form 10-K as to
matters of law and legal conclusions, based on the belief or opinion
of System Energy or any System operating company or otherwise,
pertaining to the titles to properties, franchises and other operating
rights of certain of the registrants filing this Annual Report on Form
10-K, and their subsidiaries, the regulations to which they are
subject and any legal proceedings to which they are parties are made
on the authority of Friday, Eldredge & Clark, 2000 First Commercial
Building, 400 West Capitol, Little Rock, Arkansas, as to AP&L and as
to Entergy Services in regards to flood litigation; Monroe & Lemann (A
Professional Corporation), 201 St. Charles Avenue, Suite 3300, New
Orleans, Louisiana, as to LP&L and NOPSI; and Wise Carter Child &
Caraway, Professional Association, Heritage Building, Jackson,
Mississippi, as to MP&L and System Energy.
The statements attributed to Clark, Thomas & Winters, a
professional corporation, as to legal conclusions with respect to
GSU's rate regulation in Texas under Item 1. "Rate Matters and
Regulation - Rate Matters - Retail Rate Matters - GSU" and in Note 2
to Entergy Corporation and Subsidiaries Consolidated Financial
Statements and GSU's Financial Statements, "Rate and Regulatory
Matters," have been reviewed by such firm and are included herein upon
the authority of such firm as experts.
The statements attributed to Sandlin Associates regarding the
analysis of River Bend Construction costs of GSU under Item 1. "Rate
Matters and Regulation - Rate Matters - Retail Rate Matters - GSU" and
in Note 2 to Entergy Corporation and Subsidiaries Consolidated
Financial Statements and GSU's Financial Statements, "Rate and
Regulatory Matters", have been reviewed by such firm and are included
herein upon the authority of such firm as experts.
ENTERGY CORPORATION
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
ENTERGY CORPORATION
By /s/ Lee W. Randall
Lee W. Randall, Vice President
and Chief Accounting Officer
Date: March 14, 1994
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
/s/ Lee W. Randall Vice President and March 14, 1994
Lee W. Randall Chief Accounting Officer
(Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer and
Director; Principal Executive Officer); Gerald D. McInvale
(Senior Vice President and Chief Financial Officer;
Principal Financial Officer); W. Frank Blount, John A.
Cooper, Jr., Brooke H. Duncan, Lucie J. Fjeldstad, Kaneaster
Hodges, Jr., Robert v.d. Luft, Kinnaird R. McKee, Paul W.
Murrill, James R. Nichols, Eugene H. Owen, John N.
Palmer, Robert D. Pugh, H. Duke Shackelford, Wm. Clifford
Smith, Bismark A. Steinhagen, and Walter Washington
(Directors).
By: /s/ Lee W. Randall March 14, 1994
(Lee W. Randall, Attorney-in-fact)
ARKANSAS POWER & LIGHT COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
ARKANSAS POWER & LIGHT COMPANY
By /s/ Lee W. Randall
Lee W. Randall, Vice President
and Chief Accounting Officer
Date: March 14, 1994
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
/s/ Lee W. Randall
Lee W. Randall Vice President and Chief March 14, 1994
Accounting Officer
(Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive
Officer and Director; Principal Executive Officer); Gerald
D. McInvale (Senior Vice President and Chief
Financial Officer; Principal Financial Officer); Michael
B. Bemis, John A. Cooper, Jr., Cathy Cunningham, Richard
P. Herget, Jr., Tommy H. Hillman, Donald C. Hintz,
Kaneaster Hodges, Jr., Jerry D. Jackson, R. Drake Keith,
Jerry L. Maulden, Raymond P. Miller, Sr., Roy L. Murphy,
William C. Nolan, Jr., Robert D. Pugh, Woodson D. Walker,
Gus B. Walton, Jr., Michael E. Wilson (Directors).
By: /s/ Lee W. Randall March 14, 1994
(Lee W. Randall, Attorney-in-fact)
GULF STATES UTILITIES COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
GULF STATES UTILITIES COMPANY
By /s/ Lee W. Randall
Lee W. Randall, Vice President
and Chief Accounting Officer
Date: March 14, 1994
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
/s/ Lee W. Randall Vice President and March 14, 1994
Lee W. Randall Chief Accounting Officer
(Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive Officer
and Director; Principal Executive Officer); Gerald D. McInvale
(Senior Vice President and Chief Financial Officer;
Principal Financial Officer); Robert H. Barrow, Frank F.
Gallaher, Frank W. Harrison, Jr., Donald C. Hintz, Jerry
L. Maulden, Paul W. Murrill, Eugene H. Owen, M. Bookman
Peters, Monroe J. Rathbone, Jr., Sam F. Segnar, Bismark
A. Steinhagen, James E. Taussig, II. (Directors).
By: /s/ Lee W. Randall March 14, 1994
(Lee W. Randall, Attorney-in-fact)
LOUISIANA POWER & LIGHT COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
LOUISIANA POWER & LIGHT COMPANY
By /s/ Lee W. Randall
Lee W. Randall, Vice President
and Chief Accounting Officer
Date: March 14, 1994
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
/s/ Lee W. Randall
Lee W. Randall Vice President and Chief March 14, 1994
Accounting Officer
(Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive
Officer and Director; Principal Executive Officer);
Gerald D. McInvale (Senior Vice President and Chief
Financial Officer; Principal Financial Officer); Michael
B. Bemis, John J. Cordaro, Donald C. Hintz, William K.
Hood, Jerry D. Jackson, Tex R. Kilpatrick, Joseph J.
Krebs, Jr., Jerry L. Maulden, H. Duke Shackelford, Wm.
Clifford Smith (Directors).
By: /s/ Lee W. Randall March 14, 1994
(Lee W. Randall, Attorney-in-fact)
MISSISSIPPI POWER & LIGHT COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
MISSISSIPPI POWER & LIGHT COMPANY
By /s/ Lee W. Randall
Lee W. Randall, Vice President
and Chief Accounting Officer
Date: March 14, 1994
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
/s/ Lee W. Randall
Lee W. Randall Vice President and Chief March 14, 1994
Accounting Officer
(Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive
Officer and Director; Principal Executive Officer);
Gerald D. McInvale (Senior Vice President and Chief
Financial Officer; Principal Financial Officer); Michael
B. Bemis, Frank R. Day, John O. Emmerich, Jr., Norman B.
Gillis, Jr., Donald C. Hintz, Jerry D. Jackson, Robert E.
Kennington, II, Jerry L. Maulden, Donald E. Meiners, John
N. Palmer, Sr., Clyda S. Rent, Walter Washington, Robert
M. Williams, Jr. (Directors).
By: /s/ Lee W. Randall March 14, 1994
(Lee W. Randall, Attorney-in-fact)
NEW ORLEANS PUBLIC SERVICE INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
NEW ORLEANS PUBLIC SERVICE INC.
By /s/ Lee W. Randall
Lee W. Randall, Vice President
and Chief Accounting Officer
Date: March 14, 1994
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
/s/ Lee W. Randall
Lee W. Randall Vice President and Chief March 14, 1994
Accounting Officer
(Principal Accounting Officer)
Edwin Lupberger (Chairman of the Board, Chief Executive
Officer and Director; Principal Executive Officer);
Gerald D. McInvale (Senior Vice President and Chief
Financial Officer; Principal Financial Officer); Michael
B. Bemis, James M. Cain, John J. Cordaro, Brooke H.
Duncan, Norman C. Francis, Donald C. Hintz, Jerry D.
Jackson, Jerry L. Maulden, Anne M. Milling, John B.
Smallpage, Charles C. Teamer, Sr. (Directors).
By: /s/ Lee W. Randall March 14, 1994
(Lee W. Randall, Attorney-in-fact)
SYSTEM ENERGY RESOURCES, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized. The signature of the undersigned company shall be deemed
to relate only to matters having reference to such company and any
subsidiaries thereof.
SYSTEM ENERGY RESOURCES, INC.
By /s/ Lee W. Randall
Lee W. Randall, Vice President
and Chief Accounting Officer
Date: March 14, 1994
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated. The signature of each of the undersigned shall be deemed
to relate only to matters having reference to the above-named company
and any subsidiaries thereof.
Signature Title Date
/s/ Lee W. Randall
Lee W. Randall Vice President and Chief March 14, 1994
Accounting Officer
(Principal Accounting Officer)
Donald C. Hintz (President, Chief Executive Officer and
Director; Principal Executive Officer); Gerald D.
McInvale (Senior Vice President and Chief Financial
Officer; Principal Financial Officer); Edwin Lupberger
(Chairman of the Board), Jerry D. Jackson, Jerry L.
Maulden (Directors).
By: /s/ Lee W. Randall March 14, 1994
(Lee W. Randall, Attorney-in-fact)
EXHIBIT 23(a)
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Post-Effective
Amendment Nos. 2, 3, 4A, and 5A on Form S-8 to Registration Statement
No. 33-54298 of Entergy Corporation on Form S-4, and the related
Prospectuses, of our reports dated February 11, 1994 (which
express an unqualified opinion and include explanatory paragraphs as
to uncertainties because of certain regulatory and litigation
matters), appearing in this Annual Report on Form 10-K of Entergy
Corporation for the year ended December 31, 1993.
We also consent to the incorporation by reference in Registration
Statements Nos. 33-36149, 33-48356 and 33-50289 of Arkansas Power &
Light Company on Form S-3, and the related Prospectuses, of our
reports dated February 11, 1994, appearing in this Annual Report on
Form 10-K of Arkansas Power & Light Company for the year ended
December 31, 1993.
We also consent to the incorporation by reference in Registration
Statements Nos. 33-46085, 33-39221 and 33-50937 of Louisiana Power &
Light Company on Form S-3, and the related Prospectuses, of our
reports dated February 11, 1994, appearing in this Annual Report on
Form 10-K of Louisiana Power & Light Company for the year ended
December 31, 1993.
We also consent to the incorporation by reference in Registration
Statements Nos. 33-53004, 33-55826 and 33-50507 of Mississippi Power &
Light Company on Form S-3, and the related Prospectuses, of our
reports dated February 11, 1994, appearing in this Annual Report on
Form 10-K of Mississippi Power & Light Company for the year ended
December 31, 1993.
We also consent to the incorporation by reference in Registration
Statement No. 33-57926 of New Orleans Public Service Inc. on Form S-3,
and the related Prospectus, of our reports dated February 11, 1994,
appearing in this Annual Report on Form 10-K of New Orleans Public
Service Inc. for the year ended December 31, 1993.
We also consent to the incorporation by reference in Registration
Statement No. 33-47662 of System Energy Resources, Inc. on Form S-3,
and the related Prospectus, of our reports dated February 11, 1994
(which express an unqualified opinion and include an explanatory
paragraph as to an uncertainty resulting from a regulatory
proceeding), appearing in this Annual Report on Form 10-K of System
Energy Resources, Inc. for the year ended December 31, 1993.
/s/ Deloitte & Touche
DELOITTE & TOUCHE
New Orleans, Louisiana
March 14, 1994
EXHIBIT 23(b)
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration
statements of Gulf States Utilities Company on Form S-3 (File Numbers
33-49739 and 33-51181) and Form S-8 (File Numbers 2-76551 and 2-98011)
of our reports, dated February 11, 1994, on our audits of the
financial statements and financial statement schedules of Gulf States
Utilities Company as of December 31, 1993 and 1992, and for the years
ended December 31, 1993, 1992 and 1991, which reports include
explanatory paragraphs related to rate-related contingencies, legal
proceedings and changes in accounting for income taxes, postretirement
benefits, unbilled revenue and power plant materials and supplies and
are included in this Annual Report on Form 10-K.
/s/ Coopers & Lybrand
Coopers & Lybrand
Houston, Texas
March 14, 1994
EXHIBIT 23(c)
CONSENT OF EXPERTS
We consent to the reference to our firm under the heading
"Experts" in this Annual Report on Form 10-K. We further consent to
the incorporation by reference of such reference to our firm into
Arkansas Power & Light Company's ("AP&L") Registration Statements
(Form S-3, File Nos. 33-36149, 33-48356 and 33-50289) and related
Prospectuses, pertaining to AP&L's First Mortgage Bonds and Preferred
Stock.
Very truly yours,
/s/ Friday, Eldredge & Clark
FRIDAY, ELDREDGE & CLARK
Date: March 14, 1994
EXHIBIT 23(d)
CONSENT
We consent to the reference to our firm under the heading
"Experts", and to the inclusion in this Annual Report on Form 10-K of
Gulf States Utilities Company ("GSU") of the statements of legal
conclusions attributed to us herein (the Statements of Legal
Conclusions) under Part I, Item 1. Business - "Rate Matters and
Regulation" and in the discussion of Texas jurisdictional matters set
forth in Note 2 to GSU's Financial Statements and Note 2 to Entergy
Corporation and Subsidiaries Consolidated Financial Statements
appearing as Item 8. of Part II of this Form 10-K, which Statements of
Legal Conclusions have been prepared or reviewed by us (Clark, Thomas
& Winters, a Professional Corporation). We also consent to the
incorporation by reference in the registration statements of GSU on
Form S-3 and Form S-8 (File Numbers 2-76551, 2-98011, 33-49739, and
33-51181) of such reference and Statements of Legal Conclusions.
/s/ Clark, Thomas & Winters,
A Professional Corporation
CLARK, THOMAS & WINTERS
A Professional Corporation
Austin, Texas
March 14, 1994
EXHIBIT 23(e)
CONSENT
We consent to the reference to our firm under the heading
"Experts" and to the inclusion in this Annual Report on Form 10-K of
Gulf States Utilities Company ("GSU") of the statements (Statements)
regarding the analysis by our Firm of River Bend construction costs
which are made herein under Part I, Item 1. Business - "Rate Matters
and Regulation" and in the discussion of Texas jurisdictional matters
set forth in Note 2 to GSU's Financial Statements and Note 2 to
Entergy Corporation and Subsidiaries' Consolidated Financial
Statements appearing as Item 8. of Part II of this Form 10-K, which
Statements have been prepared or reviewed by us (Sandlin Associates).
We also consent to the incorporation by reference in the registration
statements of GSU on Form S-3 and Form S-8 (File Numbers 2-76551, 2-
98011, 33-49739 and 33-51181) of such reference and Statements.
/s/ Sandlin Associates
Management Consultants
SANDLIN ASSOCIATES
Management Consultants
Pasco, Washington
March 14, 1994
EXHIBIT 23(f)
CONSENT OF EXPERTS
We consent to the reference to our firm under the heading
"Experts" in this Annual Report on Form 10-K. We further consent to
the incorporation by reference of such reference to our firm into
Louisiana Power & Light Company's ("LP&L") Registration Statements
(Form S-3, File Nos. 33-46085, 33-39221 and 33-50937) and the related
Prospectuses, pertaining to LP&L's First Mortgage Bonds and Preferred
Stock, and into New Orleans Public Service Inc.'s ("NOPSI")
Registration Statement (Form S-3, File No. 33-57926) and the related
Prospectus pertaining to NOPSI's General and Refunding Mortgage Bonds.
Very truly yours,
/s/ Monroe & Lemann
MONROE & LEMANN
Date: March 14, 1994
EXHIBIT 23(g)
CONSENT OF EXPERTS
We consent to the reference to our firm under the heading
"Experts" in this Annual Report on Form 10-K. We further consent to
the incorporation by reference of such reference to our firm into
System Energy Resources, Inc.'s (System Energy) Registration Statement
on Form S-3 (File No. 33-47662) and the related prospectus pertaining
to System Energy's First Mortgage Bonds, and into Mississippi Power &
Light Company's ("MP&L") Registration Statements on Form S-3 (File
Nos. 33-53004, 33-55826 and 33-50507) and the related prospectuses
pertaining to MP&L's Preferred Stock and General and Refunding
Mortgage Bonds.
Very truly yours,
WISE CARTER CHILD & CARAWAY
Professional Association
By /s/ Robert B. McGehee
Date: March 14, 1994
INDEPENDENT AUDITORS' REPORT ON FINANCIAL STATEMENT SCHEDULES
To the Shareholders and the Board of Directors
of Entergy Corporation
We have audited the consolidated financial statements of Entergy
Corporation and subsidiaries and the financial statements of Arkansas
Power & Light Company, Louisiana Power & Light Company, Mississippi
Power & Light Company, New Orleans Public Service Inc., and System
Energy Resources, Inc. as of December 31, 1993 and 1992, and for each
of the three years in the period ended December 31, 1993, and have
issued our reports thereon dated February 11, 1994, which report as to
Entergy Corporation includes explanatory paragraphs as to
uncertainties because of certain regulatory and litigation matters,
and which report as to System Energy Resources, Inc. includes an
explanatory paragraph as to an uncertainty resulting from a regulatory
proceeding; such reports are included elsewhere in this Form 10-K.
Our audits also included the financial statement schedules of these
companies, listed in Item 14(a)2. These financial statement schedules
are the responsibility of the companies' managements. Our
responsibility is to express an opinion based on our audits. We did
not audit the financial statements of Gulf States Utilities Company (a
consolidated subsidiary of Entergy Corporation acquired on December
31, 1993), which statements reflect total assets constituting 31% of
consolidated total assets at December 31, 1993. Those statements were
audited by other auditors whose report (which included explanatory
paragraphs regarding uncertainties because of certain regulatory and
litigation matters) has been furnished to us, and our opinion, insofar
as it relates to the amounts included for Gulf States Utilities
Company, is based solely on the report of such other auditors. In our
opinion, based on our audits and the report of the other auditors,
such financial statement schedules, when considered in relation to the
basic financial statements taken as a whole, present fairly in all
material respects the information set forth therein.
/s/ Deloitte & Touche
DELOITTE & TOUCHE
New Orleans, Louisiana
February 11, 1994
INDEPENDENT AUDITORS' REPORT ON FINANCIAL STATEMENT SCHEDULES
To the Shareholders and the Board of Directors
of Gulf States Utilities Company
Our report on the financial statements of Gulf States Utilities
Company, which includes explanatory paragraphs related to rate-related
contingencies, legal proceedings and changes in accounting is included
in this Form 10-K. In connection with our audits of such financial
statements, we have also audited the related financial statement
schedules of Gulf States Utilities Company included in Item 14(a)2 of
this Form 10-K.
In our opinion, the financial statement schedules referred to
above, when considered in relation to the basic financial statements
taken as a whole, present fairly, in all material respects, the
information required to be included therein.
/s/ Coopers & Lybrand
Coopers & Lybrand
Houston, Texas
February 11, 1994
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule
III Financial Statements of Entergy Corporation:
Balance Sheets, December 31, 1993 and 1992
Statements of Income - For the Years Ended December 31, 1993,
1992 and 1991
Statements of Retained Earnings and Paid-In Capital - For the Years
Ended December 31, 1993, 1992 and 1991
Statements of Cash Flows - For the Years Ended December 31, 1993,
1992 and 1991
V Utility Plant
1993, 1992 and 1991:
Entergy Corporation and Subsidiaries
Arkansas Power & Light Company
Gulf States Utilities Company
Louisiana Power & Light Company
Mississippi Power & Light Company
New Orleans Public Service Inc.
System Energy Resources, Inc.
VI Accumulated Depreciation and Amortization of Property
1993, 1992 and 1991:
Entergy Corporation and Subsidiaries
Arkansas Power & Light Company
Gulf States Utilities Company
Louisiana Power & Light Company
Mississippi Power & Light Company
New Orleans Public Service Inc.
System Energy Resources, Inc.
VIII Valuation and Qualifying Accounts
1993, 1992 and 1991:
Entergy Corporation and Subsidiaries
Arkansas Power & Light Company
Gulf States Utilities Company
Louisiana Power & Light Company
Mississippi Power & Light Company
New Orleans Public Service Inc.
X Supplementary Income Statement Information
1993, 1992 and 1991:
Entergy Corporation and Subsidiaries
Arkansas Power & Light Company
Gulf States Utilities Company
Louisiana Power & Light Company
Mississippi Power & Light Company
New Orleans Public Service Inc.
System Energy Resources, Inc.
Schedules other than those listed above are omitted because they are not
required, not applicable or the required information is shown in the financial
statements or notes thereto.
Columns have been omitted from schedules filed because the information
is not applicable.
ENTERGY CORPORATION
SCHEDULE III - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
BALANCE SHEETS
December 31,
---------------------------
1993 1992
---------- ----------
(In Thousands)
ASSETS
Construction work in progress $22,861 -
---------- ----------
Investment in Wholly-owned Subsidiaries 6,449,165 $4,153,966
---------- ----------
Current Assets:
Cash equivalents:
Temporary cash investments - at cost,
which approximates market:
Associated companies 100,401 9,225
Other 52,150 110,481
---------- ----------
Total cash equivalents 152,551 119,706
Other temporary investments - 17,012
Accounts receivable:
Associated companies 3,086 2,805
Other 2,467 2,179
Interest receivable 1,073 560
Other 1,166 481
---------- ----------
Total 160,343 142,743
---------- ----------
Deferred Debits 93,479 32,387
---------- ----------
TOTAL $6,725,848 $4,329,096
========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $.01 par value in 1993 and $5 par
value in 1992: authorized 500,000,000 shares;
issued and outstanding 231,219,737 shares in
1993; issued 175,137,392 shares in 1992 $2,312 $875,687
Paid-in capital 4,223,682 1,327,589
Retained earnings 2,310,082 2,062,188
Less cost of treasury stock (1,943 shares in 1992) - 54
---------- ----------
Total common shareholders' equity 6,536,076 4,265,410
---------- ----------
Current Liabilities:
Notes payable 43,000 -
Accounts payable:
Associated companies 7,556 7,006
Other 10,069 9,252
Other current liabilities 1,849 633
---------- ----------
Total 62,474 16,891
---------- ----------
Deferred Credits and Noncurrent Liabilities 127,298 46,795
---------- ----------
Total $6,725,848 $4,329,096
========== ==========
Entergy Corporation and Subsidiaries Notes to Consolidated Financial Statements in
Part II, Item 8 are incorporated herin by reference.
ENTERGY CORPORATION
SCHEDULE III - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
STATEMENTS OF INCOME
For the Years Ended December 31,
----------------------------------------------
1993 1992 1991
-------- -------- --------
(In Thousands)
Income:
Equity in income of subsidiaries $557,681 $454,947 $471,250
Interest on temporary investments 18,520 20,011 39,664
-------- -------- --------
Total 576,201 474,958 510,914
-------- -------- --------
Expenses and Other Deductions:
Administrative and general expenses 25,129 32,412 27,422
Income taxes 3,587 4,734 93
Taxes other than income (credit) (696) 167 1,156
Interest (credit) (3,749) 8 211
-------- -------- --------
Total 24,271 37,321 28,882
-------- -------- --------
Net Income $551,930 $437,637 $482,032
======== ======== ========
Entergy Corporation and Subsidiaries Notes to Connsolidated Financial Statements in Part II,
Item 8 are incorporated herein by reference.
ENTERGY CORPORATION
SCHEDULE III - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL
For The Year Ended December 31,
----------------------------------------
1993 1992 1991
---------- ---------- ----------
(In Thousands)
Retained Earnings, January 1 $2,062,188 $1,943,298 $1,775,000
Add - Net income 551,930 437,637 482,032
---------- ---------- ----------
Total 2,614,118 2,380,935 2,257,032
---------- ---------- ----------
Deduct:
Dividends declared on common stock 288,342 255,479 228,555
Common stock retirements 13,906 59,187 80,009
Capital stock and other expenses 1,788 4,081 5,170
---------- ---------- ----------
Total 304,036 318,747 313,734
---------- ---------- ----------
Retained Earnings, December 31 $2,310,082 $2,062,188 $1,943,298
========== ========== ==========
Paid-in Capital, January 1 $1,327,589 $1,357,883 $1,408,640
Add:
Gain (loss) on reacquisition of
subsidiaries' preferred stock (20) (1,323) 35
Issuance of 56,667,726 shares of common
stock in the merger with GSU 2,027,325 - -
Issuance of 174,552,011 shares of common
stock at $.01 par value net of the
retirement of 174,552,011 shares of
common stock at $5.00 par value 871,015 - -
---------- ---------- ----------
Total 4,225,909 1,356,560 1,408,675
---------- ---------- ----------
Deduct:
Common stock retirements 4,389 28,127 49,391
Capital stock discounts and other expenses (2,162) 844 1,401
---------- ---------- ----------
Total 2,227 28,971 50,792
---------- ---------- ----------
Paid-in Capital, December 31 $4,223,682 $1,327,589 $1,357,883
========== ========== ==========
Entergy Corporation and Subsidiaries Notes to Consolidated Financial Statements
in Part II, Item 8 are incorporated herein by reference.
ENTERGY CORPORATION
SCHEDULE III - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
-----------------------------------------
1993 1992 1991
---------- -------- --------
(In Thousands)
Operating Activities:
Net income $551,930 $437,637 $482,032
Noncash items included in net income:
Equity in earnings of subsidiaries (557,681) (454,947) (471,250)
Deferred income taxes 3,771 3,146 (3,146)
Changes in working capital:
Receivables (1,082) 2,875 6,812
Payables 1,367 (26,241) 1,099
Other working capital accounts 531 16,034 (1,368)
Common stock dividends received from subsidiaries 686,700 487,854 231,537
Other (20,938) (15,012) (4,259)
---------- -------- --------
Net cash flow provided by operating activities 664,598 451,346 241,457
---------- -------- --------
Investing Activities:
Merger with GSU - cash paid (250,000) - -
Investment in subsidiaries (86,221) (79,228) (114,650)
Capital expenditures (22,861) - -
Decrease in other temporary investments 17,012 114,651 25,355
Advance to subsidiary (24,642) (12,005) (24,163)
---------- -------- --------
Net cash flow provided by (used in) investing activities (366,712) 23,418 (113,458)
---------- -------- --------
Financing Activities:
Changes in short-term borrowings 43,000 - -
Common stock dividends paid (287,483) (256,117) (228,816)
Retirement of common stock (20,558) (105,673) (161,640)
---------- -------- --------
Net cash flow used in financing activities (265,041) (361,790) (390,456)
---------- -------- --------
Net increase (decrease) in cash and cash equivalents 32,845 112,974 (262,457)
Cash and cash equivalents at beginning of period 119,706 6,732 269,189
---------- -------- --------
Cash and cash equivalents at end of period $152,551 $119,706 $6,732
========== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Noncash investing and financing activities:
Merger with GSU-Common stock issued $2,031,101 - -
Entergy Corporation and Subsidiaries Notes to Consolidated Financial Statements
in Part II, Item 8 are incorporated herein by reference.
ENTERGY CORPORATION AND SUBSIDIARIES
SCHEDULE V - UTILITY PLANT
Year Ended December 31, 1993
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F Column G
Other
Changes-
Balance at Debits Balance
Classification Beginning Additions Retirements (Credits) Acquisition at End
(Note 4) of Period at Cost or Sales (Notes 2-3) of GSU of Period
- -----------------------------------------------------------------------------------------------------------------------------
Electric Utility Plant:
Intangible $90,813 $16,678 $22,847 $(19,105) - $65,539
Production (Note 3) 9,033,191 84,114 23,939 20,023 $4,571,911 13,685,300
Transmission 1,401,286 22,304 3,054 (19) 833,730 2,254,247
Distribution 2,810,941 154,953 28,062 (10) 1,083,628 4,021,450
General 474,652 48,682 2,393 (52) 123,415 644,304
Leased to others 5,144 - - - - 5,144
Leased from others (Note 1) 662,400 773 149 - 86,039 749,063
Plant and Property held for future use 48,814 - 1,053 (16) 156,724 204,469
Plant In Service-CWIP in rate base - - - - (14,786) (14,786)
Louisiana regulatory asset - - - - 71,367 71,367
Natural Gas:
Intangible 377 69 - - - 446
Transmission 6,504 409 1 - - 6,912
Distribution 97,324 3,264 489 - 41,454 141,553
General 6,194 15 - - 1,332 7,541
Steam Products Plant:
Production - - - - 70,615 70,615
Distribution - - - - 4,811 4,811
General - - - - 263 263
Construction work in progress 309,552 179,425 5,672 (273) 50,080 533,112
Nuclear fuel 254,299 242,259 244,193 - 94,828 347,193
Plant acquisition adjustments 1,133 - - (85) 380,117 381,165
----------- -------- -------- -------- ---------- -----------
Total Utility Plant $15,202,624 $752,945 $331,852 $463 $7,555,528 $23,179,708
=========== ======== ======== ======== ========== ===========
___________
Notes:
(1) Includes amounts associated with the Grand Gulf 1 and Waterford 3 sale and
leaseback transactions.
(2) Transfers among functional groups of accounts $31
===========
(3) Amortization of plant acquisition adjustments $(85)
Transfers to non-utility plant (12,232)
Transfers to preliminary survey and investigation charges (273)
Transfers to construction work in progress (19)
Transfers to electric utility plant - production 13,072
-----------
Total $463
===========
(4) Depreciation is computed on the straight-line basis at rates based on the estimated
service lives of the various classes of property. Depreciation provisions on average
depreciable property approximated 3% in 1993.
ENTERGY CORPORATION AND SUBSIDIARIES
SCHEDULE V - UTILITY PLANT
Year Ended December 31, 1992
(In Thousands)
- ------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Changes-
Balance at Retirements Debits Balance
Classification Beginning Additions or Sales (Credits) at End
(Note 4) of Period at Cost (Notes 5-6) (Notes 2-3) of Period
- ------------------------------------------------------------------------------------------------------------------------
Electric Utility Plant:
Intangible $66,118 $24,339 $(234) $122 $90,813
Production 8,955,524 129,225 51,547 (11) 9,033,191
Transmission 1,363,773 46,623 9,076 (34) 1,401,286
Distribution 2,715,057 165,786 69,887 (15) 2,810,941
General 295,033 47,921 19,464 151,162 474,652
Leased to others 5,144 - - - 5,144
Leased from others (Note 1) 662,150 3,822 3,572 - 662,400
Plant held for future use 47,842 2 3,315 4,285 48,814
Natural Gas:
Intangible 377 - - - 377
Transmission 6,488 16 - - 6,504
Distribution 92,465 5,149 290 - 97,324
General 5,630 569 5 - 6,194
Construction work in progress 305,916 3,649 - (13) 309,552
Nuclear fuel 290,136 86,457 120,172 (2,122) 254,299
Plant acquisition adjustments 1,367 - - (234) 1,133
----------- -------- -------- -------- -----------
Total Utility Plant $14,813,020 $513,558 $277,094 $153,140 $15,202,624
=========== ======== ======== ======== ===========
___________
Notes:
(1) Includes amounts associated with the Grand Gulf 1 and Waterford 3 sale and
leaseback transactions.
(2) Transfers among functional groups of accounts $164
(3) Amortization of plant acquisition adjustments $(234)
Transfers of service companies' property to electric utility plant - general 151,221
from other property
Transfers to construction work in progress 191
Transfers to non-utility plant (21)
Transfers to preliminary survey and investigation charges (205)
Refund of state sales tax and related interest paid under protest (2,122)
FERC Complaint Case Settlement 4,310
----------
Total $153,140
(4) Depreciation is computed on the straight-line basis at rates based on the estimated
service lives of the various classes of property. Depreciation provisions on average
depreciable property approximated 3.0% in 1992.
(5) Transfers to Entergy Services from General Plant $183
==========
(6) Sales of Missouri property $52,783
==========
ENTERGY CORPORATION AND SUBSIDIARIES
SCHEDULE V - UTILITY PLANT
Year Ended December 31, 1991
(In Thousands)
- ------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Changes-
Balance at Debits Balance
Classification Beginning Additions Retirements (Credits) at End
(Note 4) of Period at Cost or Sales (Notes 2-3) of Period
- ------------------------------------------------------------------------------------------------------------------------
Electric Utility Plant:
Intangible $48,362 $17,996 $240 - $66,118
Production 8,900,671 96,732 26,249 $(15,630) 8,955,524
Transmission 1,290,481 75,112 1,794 (26) 1,363,773
Distribution 2,577,101 160,656 22,703 3 2,715,057
General 288,044 27,688 8,925 (11,774) 295,033
Leased to others 5,144 - - - 5,144
Leased from others (Note 1) 660,291 2,798 939 - 662,150
Plant held for future use 39,426 1,053 365 7,728 47,842
Natural Gas:
Intangible 141 236 - - 377
Transmission 6,500 (12) - - 6,488
Distribution 88,435 4,326 296 - 92,465
General 6,078 (316) 132 - 5,630
Construction work in progress 305,888 3,721 - (3,693) 305,916
Nuclear fuel 373,016 124,717 208,547 950 290,136
Plant acquisition adjustments 1,763 - - (396) 1,367
----------- -------- -------- -------- -----------
Total Utility Plant $14,591,341 $514,707 $270,190 $(22,838) $14,813,020
=========== ======== ======== ======== ===========
___________
Notes:
(1) Includes amounts associated with the Grand Gulf 1 and Waterford 3 sale and
leaseback transactions.
(2) Transfers among functional groups of accounts $15,802
===========
(3) Amortization of plant acquisition adjustments $(396)
Transfers to preliminary survey and investigation charges (3,693)
State sales tax and related interest paid under protest 950
FERC Complaint Case Settlement 7,694
Lease reclassification (27,393)
-----------
Total $(22,838)
===========
(4) Depreciation is computed on the straight-line basis at rates based on the estimated
service lives of the various classes of property. Depreciation provisions on average
depreciable property approximated 3.0% in 1991.
ARKANSAS POWER & LIGHT COMPANY
SCHEDULE V - UTILITY PLANT
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Changes-
Balance at Retirements Debits Balance
Classification Beginning Additions or Sales (Credits) at End
(Note 3) of Period at Cost (Note 2) (Notes 1) of Period
- -----------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
Electric Utility Plant:
Intangible $88,233 $14,687 $22,847 $(19,105) $60,968
Production 2,131,637 48,661 8,380 6,952 2,178,870
Transmission 644,321 10,032 1,091 - 653,262
Distribution 1,081,852 63,222 12,263 - 1,132,811
General 117,244 11,423 870 (79) 127,718
Plant held for future use 6,605 - - - 6,605
Construction work in progress 174,909 22,096 - - 197,005
Nuclear fuel 102,435 50,299 59,128 - 93,606
Plant acquisition adjustments 298 - - (38) 260
---------- -------- -------- -------- ----------
Total Utility Plant $4,347,534 $220,420 $104,579 $(12,270) $4,451,105
========== ======== ======== ======== ==========
Year Ended December 31, 1992
Electric Utility Plant:
Intangible $64,948 $23,290 $5 - $88,233
Production 2,098,632 37,531 4,526 - 2,131,637
Transmission 636,928 15,519 8,126 - 644,321
Distribution 1,079,660 56,856 54,664 - 1,081,852
General 116,611 7,749 7,116 - 117,244
Plant held for future use 6,625 2 - $(22) 6,605
Construction work in progress 139,773 35,136 - - 174,909
Nuclear fuel 121,689 36,624 55,878 - 102,435
Plant acquisition adjustments 340 - - (42) 298
---------- -------- -------- -------- ----------
Total Utility Plant $4,265,206 $212,707 $130,315 $(64) $4,347,534
========== ======== ======== ======== ==========
Year Ended December 31, 1991
Electric Utility Plant:
Intangible $47,007 $17,941 - - $64,948
Production 2,060,032 45,319 $6,719 - 2,098,632
Transmission 625,244 12,214 530 - 636,928
Distribution 1,022,421 66,419 9,180 - 1,079,660
General 130,685 6,490 2,926 $(17,638) 116,611
Plant held for future use 6,625 - - - 6,625
Construction work in progress 138,185 1,588 - - 139,773
Nuclear fuel 151,793 34,883 64,987 - 121,689
Plant acquisition adjustments 387 - - (47) 340
---------- -------- -------- -------- ----------
Total Utility Plant $4,182,379 $184,854 $84,342 $(17,685) $4,265,206
========== ======== ======== ======== ==========
___________
Notes: 1993 1992 1991
---- ---- ----
(1) Amortization of plant acquisition adjustments $(38) $(42) $(47)
Transfers to non-utility plant (12,232) (22) -
Lease reclassifications - - (17,638)
-------- -------- ----------
Total $(12,270) $(64) $(17,685)
======== ======== ==========
(2) Includes amounts associated with:
Transfer to Entergy Services from General Plant - $183 $2,808
Sale of Missouri Property - 52,783 -
-------- -------- ----------
Total - $52,966 $2,808
======== ======== ==========
(3) Depreciation is computed on the straight-line basis at
rates based on the estimated service lives of the various classes
of property. Depreciation provisions on average
depreciable property approximated 3.4% in 1993, 1992, and 1991.
GULF STATES UTILITIES COMPANY
SCHEDULE V - UTILITY PLANT
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Changes -
Balance at Additions Retirements Debits Balance at
Classification Beginning at Cost or Sales (Credits) End of
(Note 5) of Period (Note 1) (Note 2) (Note 3) Period
- -----------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1993
Electric Utility Plant:
Production $4,582,874 $7,354 $18,287 $(30) $4,571,911
Transmission 821,013 13,214 799 302 833,730
Distribution 1,034,708 64,318 15,091 (307) 1,083,628
General 118,184 5,867 639 3 123,415
Capital leases 87,214 911 2,086 - 86,039
Property held for future use 156,657 67 - - 156,724
Plant In Service-CWIP in rate base (14,786) - - - (14,786)
Louisiana regulatory asset 71,367 - - - 71,367
Natural Gas Utility Plant:
Distribution 39,994 1,501 41 - 41,454
General 1,166 211 45 - 1,332
Steam Products Plant:
Production 67,209 4,145 739 - 70,615
Distribution 4,818 1 8 - 4,811
General 265 - 2 - 263
Construction work in progress 32,305 17,775 - - 50,080
Nuclear fuel 106,565 19,261 30,998 - 94,828
---------- -------- ------- ---- ----------
Total Utility Plant $7,109,553 $134,625 $68,735 $(32) $7,175,411
========== ======== ======= ==== ==========
Year ended December 31, 1992
Electric Utility Plant:
Production $4,610,743 $33,232 $61,130 $29 $4,582,874
Transmission 807,025 12,260 1,546 3,274 821,013
Distribution 998,406 47,281 7,698 (3,281) 1,034,708
General 113,210 5,624 636 (14) 118,184
Capital leases 19,012 68,948 746 - 87,214
Property held for future use 157,293 (9) 630 3 156,657
Plant In Service-CWIP in rate base (14,786) - - - (14,786)
Louisiana regulatory asset 71,367 - - - 71,367
Natural Gas Utility Plant:
Distribution 39,027 1,136 169 - 39,994
General 1,062 112 8 - 1,166
Steam Products Plant:
Production 66,414 804 9 - 67,209
Distribution 4,729 89 - - 4,818
General 265 1 1 - 265
Construction work in progress 36,538 (4,233) - - 32,305
Nuclear fuel 107,071 18,074 18,580 - 106,565
---------- -------- ------- ---- ----------
Total Utility Plant $7,017,376 $183,319 $91,153 $11 $7,109,553
========== ======== ======= ==== ==========
GULF STATES UTILITIES COMPANY
SCHEDULE V - UTILITY PLANT
(Continued)
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Changes -
Balance at Additions Retirements Debits Balance at
Classification Beginning at Cost or Sales (Credits) End of
(Note 5) of Period (Note 1) (Note 2) (Note 3) Period
- -----------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1991
Electric Utility Plant:
Production $4,600,833 $11,095 $1,122 $ (63) $4,610,743
Transmission 794,872 13,673 3,762 2,242 807,025
Distribution 964,420 46,099 9,866 (2,247) 998,406
General 108,463 4,987 259 19 113,210
Capital leases 19,423 - 411 - 19,012
Plant purchased or sold - - - - -
Property held for future use 157,449 (156) 1 1 157,293
Plant In Service-CWIP in rate base (14,648) (138) - - (14,786)
Louisiana regulatory asset (Note 4) - - - 71,367 71,367
Natural Gas Utility Plant:
Distribution 38,522 593 88 - 39,027
General 970 97 5 - 1,062
Steam Products Plant:
Production 66,313 333 294 62 66,414
Distribution 4,722 - - 7 4,729
General 262 5 2 - 265
Construction work in progress 24,576 11,962 - - 36,538
Nuclear fuel 135,285 13,958 42,172 - 107,071
---------- -------- ------- ------- ----------
Total Utility Plant $6,901,462 $102,508 $57,982 $71,388 $7,017,376
========== ======== ======= ======= ==========
___________
Notes:
(1) Additions at cost, as detailed in Column C, consist primarily of construction expenditures, net
of amounts transferred to plant-in-service, and expenditures for ordinary extensions and improvements
of GSU's transmission and distribution system.
(2) In 1992, GSU changed its accounting procedures to include in inventory, power plant materials and
supplies previously expensed or capitalized as plant in service. The effect of the change was to
decrease amounts previously capitalized as plant in service by $35.7 million.
(3) Represents various transfers between functional accounts.
(4) In accordance with a rate order in Louisiana effective March 1, 1991, the LPSC required GSU to
modify its treatment of certain flow through benefits related to Allowance for Funds Used During
Construction recorded on capital expenditures prior to 1986. Accordingly, GSU increased utility plant
by $71.4 million, increased accumulated depreciation by $8.4 million and increased the balance of
accumulated deferred income taxes by $63 million.
(5) Depreciation is computed on the straight-line basis at rates based on the estimated service lives
of the various classes of property. Depreciation provisions on average depreciable property
approximated 2.7% in 1993, 1992, and 1991.
LOUISIANA POWER & LIGHT COMPANY
SCHEDULE V - UTILITY PLANT
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Changes-
Balance at Debits Balance
Classification Beginning Additions Retirements (Credits) at End
(Note 4) of Period at Cost or Sales (Notes 1-2) of Period
- -----------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
Electric Utility Plant:
Intangible $2,222 $968 - - $3,190
Production 3,004,940 20,533 $11,903 $(1) 3,013,569
Transmission 367,794 8,994 1,675 (15) 375,098
Distribution 1,105,360 56,547 10,437 (11) 1,151,459
General 91,834 6,615 1,029 27 97,447
Leased to others 5,144 - - - 5,144
Leased from others (Note 3) 225,083 - - - 225,083
Plant held for future use 114 - - - 114
Construction work in progress 67,535 66,274 - (273) 133,536
Nuclear fuel 66,627 27,894 29,323 - 65,198
Plant acquisition adjustments 2 - - (2) -
---------- -------- ------- ----- ----------
Total Utility Plant $4,936,655 $187,825 $54,367 $(275) $5,069,838
========== ======== ======= ===== ==========
Year Ended December 31, 1992
Electric Utility Plant:
Intangible $811 $1,050 ($239) $122 $2,222
Production 2,957,433 57,501 9,984 (10) 3,004,940
Transmission 349,237 19,233 657 (19) 367,794
Distribution 1,044,647 70,204 9,458 (33) 1,105,360
General 74,513 25,240 7,859 (60) 91,834
Leased to others 5,144 - - - 5,144
Leased from others (Note 3) 223,740 1,343 - - 225,083
Plant held for future use 114 - - - 114
Construction Work in Progress 93,954 (26,214) - (205) 67,535
Nuclear Fuel 64,022 38,540 33,813 (2,122) 66,627
Plant Acquisition Adjustments 12 - - (10) 2
---------- -------- ------- ------- ----------
Total Utility Plant $4,813,627 $186,897 $61,532 $(2,337) $4,936,655
========== ======== ======= ======= ==========
LOUISIANA POWER & LIGHT COMPANY
SCHEDULE V - UTILITY PLANT
(Continued)
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- ------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Changes-
Balance at Debits Balance
Classification Beginning Additions Retirements (Credits) at End
(Note 4) of Period at Cost or Sales (Notes 1-2) of Period
- ------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1991
Electric Utility Plant:
Intangible $1,034 $17 $240 - $811
Production 2,930,598 32,330 5,465 $(30) 2,957,433
Transmission 322,982 26,740 493 8 349,237
Distribution 986,725 66,072 8,153 3 1,044,647
General 69,240 12,121 683 (6,165) 74,513
Leased to others 5,144 - - - 5,144
Leased from others (Note 3) 221,792 1,948 - - 223,740
Plant held for future use 114 - - - 114
Construction work in progress 101,752 (4,105) - (3,693) 93,954
Nuclear fuel 86,869 8,556 32,353 950 64,022
Plant acquisition adjustments 179 - - (167) 12
---------- -------- ------- ------- ----------
Total Utility Plant $4,726,429 $143,679 $47,387 $(9,094) $4,813,627
========== ======== ======= ======= ==========
___________
Notes: 1993 1992 1991
---- ---- ----
(1) Transfers among functional groups of accounts $27 $122 $30
======= ======= ==========
(2) Amortization of plant acquisition adjustments $(2) $(10) $(167)
Transfers to preliminary survey and investigation charges (273) (205) (3,693)
State sales tax and related interest paid under
protest (refunded) - (2,122) 950
Lease reclassifications - - (6,184)
------- ------- ----------
Total $(275) $(2,337) $(9,094)
======= ======= ==========
(3) Includes amounts associated with the portion of Waterford 3 placed under lease
(4) Depreciation is computed on the straight-line basis at rates based on the
estimated service lives of the various classes of property. Depreciation
provisions on average depreciable property approximated 2.9% in 1993, 1992,
and 1991.
MISSISSIPPI POWER & LIGHT COMPANY
SCHEDULE V - UTILITY PLANT
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- ------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Changes-
Balance at Debits Balance
Classification Beginning Additions Retirements (Credits) at End
(Note 3) of Period at Cost or Sales (Notes 1-2) of Period
- ------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
Electric Utility Plant:
Intangible - $475 - - $475
Production $562,883 114 $100 - $562,897
Transmission 336,677 2,874 288 $(4) 339,259
Distribution 392,523 25,006 4,196 1 413,334
General 70,189 2,472 494 - 72,167
Plant held for future use 2,147 - 1,053 3 1,097
Construction work in progress 25,879 36,820 - - 62,699
Plant acquisition adjustments 45 - - (45) -
---------- ------- ------- -------- ----------
Total Utility Plant $1,390,343 $67,761 $6,131 $(45) $1,451,928
========== ======= ======= ======== ==========
Year Ended December 31, 1992
Electric Utility Plant:
Production $559,732 $3,442 $290 $(1) $562,883
Transmission 325,783 11,132 251 13 336,677
Distribution 368,577 28,188 4,232 (10) 392,523
General 67,482 6,649 3,943 1 70,189
Plant held for future use 5,465 - 3,315 (3) 2,147
Construction work in progress 21,219 4,660 - - 25,879
Plant acquisition adjustments 227 - - (182) 45
---------- ------- ------- -------- ----------
Total Utility Plant $1,348,485 $54,071 $12,031 $(182) $1,390,343
========== ======= ======= ======== ==========
Year Ended December 31, 1991
Electric Utility Plant:
Production $572,338 $3,279 $216 $(15,669) $559,732
Transmission 293,788 32,771 742 (34) 325,783
Distribution 352,449 20,408 4,280 - 368,577
General 51,323 9,272 5,211 12,098 67,482
Plant held for future use 4,743 1,053 365 34 5,465
Construction work in progress 25,412 (4,193) - - 21,219
Plant acquisition adjustments 409 - - (182) 227
---------- ------- ------- -------- ----------
Total Utility Plant $1,300,462 $62,590 $10,814 $(3,753) $1,348,485
========== ======= ======= ======== ==========
___________
Notes: 1993 1992 1991
---- ---- ----
(1) Transfers among functional groups of accounts $4 $14 $15,703
======= ======== ==========
(2) Amortization of plant acquisition adjustments $(45) $(182) $(182)
Lease reclassifications - - (3,571)
------- -------- ----------
Total $(45) $(182) $(3,753)
======= ======== ==========
(3) Depreciation is computed on the straight-line basis at rates based on the estimated
service lives of the various classes of property. Depreciation provisions on
average depreciable property approximated 2.4%, 2.5%, and 2.4% in 1993, 1992, and
1991, respectively.
NEW ORLEANS PUBLIC SERVICE INC.
SCHEDULE V - UTILITY PLANT
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Changes-
Balance at Debits Balance
Classification Beginning Additions Retirements (Credits) at End
(Note 2) of Period at Cost or Sales (Note 1) of Period
- -----------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
Electric Utility Plant:
Intangible - $548 - - $548
Production $128,283 481 $74 - 128,690
Transmission 50,467 404 - - 50,871
Distribution 231,208 10,179 1,166 - 240,221
General 32,842 285 - - 33,127
Plant held for future use 23,519 - - - 23,519
Natural Gas:
Intangible 377 69 - - 446
Transmission 6,504 409 1 - 6,912
Distribution 97,324 3,264 489 - 100,099
General 6,194 15 - - 6,209
Construction work in progress 6,906 8,299 - - 15,205
-------- ------- ------ ---- --------
Total Utility Plant $583,624 $23,953 $1,730 - $605,847
======== ======= ====== ==== ========
Year Ended December 31, 1992
Electric Utility Plant:
Production $125,706 $2,650 $73 - $128,283
Transmission 49,798 739 42 $(28) 50,467
Distribution 222,175 10,538 1,533 $28 231,208
General 25,096 8,283 537 - 32,842
Plant held for future use 23,519 - - - 23,519
Natural Gas:
Intangible 377 - - - 377
Transmission 6,488 16 - - 6,504
Distribution 92,465 5,149 290 - 97,324
General 5,630 569 5 - 6,194
Construction work in progress 14,146 (7,240) - - 6,906
-------- ------- ------ ---- --------
Total Utility Plant $565,400 $20,704 $2,480 - $583,624
======== ======= ====== ==== ========
Year Ended December 31, 1991
Electric Utility Plant:
Production $123,134 $2,518 $15 $69 $125,706
Transmission 46,440 3,387 29 - 49,798
Distribution 215,507 7,758 1,090 - 222,175
General 25,426 (195) 66 (69) 25,096
Plant held for future use 23,519 - - - 23,519
Natural Gas:
Intangible 141 236 - - 377
Transmission 6,500 (12) - - 6,488
Distribution 88,435 4,326 296 - 92,465
General 6,078 (316) 132 - 5,630
Construction work in progress 12,552 1,594 - - 14,146
-------- ------- ------ ---- --------
Total Utility Plant $547,732 $19,296 $1,628 - $565,400
======== ======= ====== ==== ========
___________
Notes: 1993 1992 1991
---- ---- ----
(1) Transfers among functional groups of accounts - $28 $69
==== ==== =====
(2) Depreciation is computed on the straight-line basis at rates based on
the estimated service lives of the various classes of property.
Depreciation provisions on average depreciable property approximated
3.1% in 1993 and 1992 and 3.2% in 1991.
SYSTEM ENERGY RESOURCES, INC.
SCHEDULE V - UTILITY PLANT
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Changes-
Balance at Debits Balance
Classification Beginning Additions Retirements (Credits) at End
(Note 3) of Period at Cost or Sales (Note 1) of Period
- -----------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
Electric Utility Plant:
Production $3,002,812 $11,678 $3,363 - $3,011,127
Leased from others (Note 2) 437,317 773 149 - 437,941
Plant held for future use 16,429 - - $(19) 16,410
Construction work in progress 30,658 10,784 - - 41,442
Nuclear fuel 67,991 46,258 34,624 - 79,625
---------- ------- ------- ----- ----------
Total Utility Plant $3,555,207 $69,493 $38,136 $(19) $3,586,545
========== ======= ======= ===== ==========
Year Ended December 31, 1992
Electric Utility Plant:
Production $3,011,223 $28,101 $36,512 - $3,002,812
Leased from others (Note 2) 438,410 2,479 3,572 - 437,317
Plant held for future use 12,119 - - $4,310 16,429
Construction work in progress 34,091 (3,433) - - 30,658
Nuclear fuel 99,575 - 31,584 - 67,991
---------- ------- ------- ------ ----------
Total Utility Plant $3,595,418 $27,147 $71,668 $4,310 $3,555,207
========== ======= ======= ====== ==========
Year Ended December 31, 1991
Electric Utility Plant:
Production $3,011,911 $12,953 $13,641 - $3,011,223
Leased from others (Note 2) 438,499 850 939 - 438,410
Plant held for future use 4,425 - - $7,694 12,119
Construction work in progress 26,491 7,600 - - 34,091
Nuclear fuel 133,908 28,922 63,255 - 99,575
---------- ------- ------- ------ ----------
Total Utility Plant $3,615,234 $50,325 $77,835 $7,694 $3,595,418
========== ======= ======= ====== ==========
___________
Notes:
1993 1992 1991
---- ---- ----
(1) Transfer to construction work in progress $(19) - -
Transfer of reusable salvage to appropriate accounts - $4,310 -
FERC Complaint Case Settlement - - $7,694
------ ------ ----------
Total $(19) $4,310 $7,694
====== ====== ==========
(2) Includes amounts associated with the Grand Gulf 1
sale and leaseback transactions.
(3) Depreciation is computed on the straight-line basis at rates
based on the estimated service lives of the various classes of
property. Depreciation provisions on average depreciable property
approximated 2.9% in 1993, 1992, and 1991.
ENTERGY CORPORATION AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY
Year Ended December 31, 1993
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F Column G
Other
Additions Deductions Changes
---------------------- ------------ ---------
Charged
Balance at to Other Retirements Debits Balance
Beginning Charged to Accounts Renewals and (Credits) Acquisition of at End
Description of Period Income (Note 1) Replacements (Note 2) GSU of Period
- -----------------------------------------------------------------------------------------------------------------------------------
Accumulated Depreciation of
Utility Plant:
Electric:
Intangible $40,521 $10,823 $72 $22,848 $(4,199) - $24,369
Production 2,693,231 260,440 378 21,973 (495) $1,393,679 4,325,260
Transmission 458,957 38,805 - 2,817 - 376,714 871,659
Distribution 1,015,641 96,604 - 32,016 - 424,826 1,505,055
General 123,548 24,258 2,178 179 (35) 45,202 194,972
Leased to others 5,144 - - - - - 5,144
Leased from others (Note 3) 70,529 5,847 14,712 149 - - 90,939
Plant held for future use 5,550 - - - - - 5,550
Depreciation-CWIP in rate base - - - - - (3,504) (3,504)
Regulatory item - - - - - 6,735 6,735
Natural Gas:
Transmission 4,936 41 - 2 - 4,975
Distribution 41,645 2,614 - 895 - 25,423 68,787
General 2,991 322 - - - 426 3,739
Steam Products:
Production - - - - - 49,456 49,456
Distribution - - - - - 4,659 4,659
General - - - - - 188 188
---------- -------- ------- ------- ------- ---------- ----------
Total $4,462,693 $439,754 $17,340 $80,879 $(4,729) $2,323,804 $7,157,983
___________ ========== ======== ======= ======= ======= ========== ==========
Notes:
(1) Provision on basis of usage or estimated life of transportation equipment (automobiles,
trucks and aircraft) charged to clearing accounts and allocated on the basis of the
use of such equipment $1,502
Provision on basis of usage of other tangible property (coal mining equipment)
charged to account(s) and allocated to operating expense as a portion of the cost of
coal burned 608
Amortization of equipment charged to fuel expense 518
Depreciation expense deferrals associated with the Grand Gulf 1 sale and
leaseback transactions consistent with the FERC audit 14,712
----------
Total $17,340
==========
(2) Transfer of net gain on sale of property from reserve $(35)
Reclassify ISES Synchronization costs as a regulatory asset (4,199)
Sale of property (land) in MS credited to Gain on Disposition (495)
----------
Total $(4,729)
==========
(3) Includes amounts associated with the Grand Gulf 1 and Waterford 3 sale and
leaseback transactions.
ENTERGY CORPORATION AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY
Year Ended December 31, 1992
(In Thousands)
- ---------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Additions Deductions Changes
--------------------- ------------ ---------
Charged Retirements
Balance at to Other Renewals and Debits Balance
Beginning Charged to Accounts Replacements (Credits) at End
Description of Period Income (Note 1) (Note 4) (Note 2) of Period
- ----------------------------------------------------------------------------------------------------------------------------
Accumulated Depreciation of
Utility Plant:
Electric:
Intangible $32,550 $7,975 - $4 - $40,521
Production 2,390,095 273,149 $336 48,115 $77,766 2,693,231
Transmission 426,733 34,923 - 2,655 (44) 458,957
Distribution 968,071 89,685 - 42,058 (57) 1,015,641
General 72,009 8,063 1,913 14,723 56,286 123,548
Leased to others 5,144 - - - - 5,144
Leased from others (Note 3) 53,497 5,794 14,810 3,572 - 70,529
Plant held for future use 5,550 - - - - 5,550
Natural Gas:
Transmission 4,897 39 - - - 4,936
Distribution 39,712 2,516 - 583 - 41,645
General 2,709 265 - (17) - 2,991
---------- -------- ------- -------- -------- ----------
Total $4,000,967 $422,409 $17,059 $111,693 $133,951 $4,462,693
========== ======== ======= ======== ======== ==========
___________
Notes:
(1) Provision on basis of usage or or estimated life of transportation equipment (automobiles,
trucks and aircraft) charged to clearing accounts and allocated on the basis of the
use of such equipment $966
Provision on basis of usage of other tangible property (coal mining equipment)
charged to account(s) and allocated to operating expense as a portion of the cost of
coal burned 946
Amortization of equipment charged to fuel expense 688
Removal cost of Ritchie 2 (248)
Salvage on coal mining equipment (103)
Represents depreciation expense deferrals associted with the Grand Gulf 1 sale and
leaseback transactions consistent with the FERC audit 14,810
----------
Total $17,059
==========
(2) Transfer of net gain on sale of property from reserve $(219)
Transfers of depreciation on service company property from other investments and special funds 56,350
ANO Decommissioning Trust Fund transferred to investments 77,820
----------
Total $133,951
==========
(3) Includes amounts associated with the Grand Gulf 1 and Waterford 3 sale and leaseback
transactions.
(4) Includes transfer of reserve related to the sale of Missouri property $18,415
==========
ENTERGY CORPORATION AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY
Year Ended December 31, 1991
(In Thousands)
- ---------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Additions Deductions Changes
---------------------- ----------- --------
Charged
Balance at to Other Retirements Debits Balance
Beginning Charged to Accounts Renewals and (Credits) at End
Description of Period Income (Note 1) Replacements (Note 2) of Period
- ----------------------------------------------------------------------------------------------------------------------------
Accumulated Depreciation of
Utility Plant:
Electric:
Intangible $27,020 $5,530 - - - $32,550
Production 2,176,179 253,828 $(13,111) $27,025 $224 2,390,095
Transmission 395,208 33,705 - 2,115 (65) 426,733
Distribution 905,591 86,370 - 23,951 61 968,071
General 66,502 7,147 1,693 3,336 3 72,009
Leased to others 5,144 - - - - 5,144
Leased from others (Note 3) 36,664 2,883 14,888 938 53,497
Plant held for future use 5,550 - - - - 5,550
Natural Gas:
Transmission 4,859 38 - - - 4,897
Distribution 37,849 2,412 - 549 - 39,712
General 2,721 267 - 279 - 2,709
---------- -------- ------ ------- ---- ----------
Total $3,663,287 $392,180 $3,470 $58,193 $223 $4,000,967
========== ======== ====== ======= ==== ==========
___________
Notes:
(1) Provision on basis of usage or estimated life of transportation equipment (automobiles
trucks and aircraft) charged to clearing accounts and allocated on the basis of the
use of such equipment $806
Provision on basis of usage of other tangible property (coal mining equipment)
charged to account(s) and allocated to operating expense as a portion of the cost of
coal burned 887
Amortization of equipment charged to fuel expense 641
ANO Decommissioning Trust Fund Contribution (13,765)
Removal cost of Ritchie 2 (9)
Salvage on coal mining equipment 22
Depreciation expense deferrals associated with the Grand Gulf 1 sale and
leaseback transactions consistent with the FERC audit 14,888
----------
Total $3,470
==========
(2) Transfer of net gain on sale of property from reserve $(4)
Reclassification of decommissioning amounts pursuant to LPSC order 224
Adjustment to the 1989 retirement of the sold portion of Waterford 3 1
Donation of property 2
----------
Total $223
==========
(3) Includes amounts associated with the Grand Gulf 1 and Waterdford 3 sale and leaseback
transactions.
ARKANSAS POWER & LIGHT COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- ---------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Additions Deductions Changes
--------------------- ------------ ---------
Charged Retirements
Balance at to Other Renewals and Debits Balance
Beginning Charged to Accounts Replacements (Credits) at End
Description of Period Income (Note 1) (Note 3) (Note 2) of Period
- ----------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
Accumulated Depreciation of
Utility Plant:
Electric:
Intangible $40,353 $10,799 - $22,848 $(4,199) $24,105
Production 858,332 74,487 - 8,520 - 924,299
Transmission 207,115 16,227 - 1,225 - 222,117
Distribution 376,260 36,117 - 13,607 - 398,770
General 25,309 3,525 608 (35) - 29,477
Plant held for future use 5,550 - - - - 5,550
---------- -------- ------- ------- ------- ----------
Total $1,512,919 $141,155 $608 $46,165 $(4,199) $1,604,318
========== ======== ======= ======= ======= ==========
Year Ended December 31, 1992
Accumulated Depreciation of
Utility Plant:
Electric:
Intangible $32,454 $7,903 - $4 - $40,353
Production 713,531 70,322 - 3,287 $77,766 858,332
Transmission 194,749 15,932 - 3,522 (44) 207,115
Distribution 367,363 35,022 - 26,142 17 376,260
General 25,872 3,280 $569 4,348 (64) 25,309
Plant held for future use 5,550 - - - - 5,550
---------- -------- ------- ------- ------- ----------
Total $1,339,519 $132,459 $569 $37,303 $77,675 $1,512,919
========== ======== ======= ======= ======= ==========
Year Ended December 31, 1991
Accumulated Depreciation of
Utility Plant:
Electric:
Intangible $26,999 $5,455 - - - 32,454
Production 665,081 69,553 $(13,765) $7,338 - 713,531
Transmission 179,670 15,800 - 656 ($65) 194,749
Distribution 343,347 34,540 - 10,585 $61 367,363
General 25,055 3,062 574 2,819 - 25,872
Plant held for future use 5,550 - - - - 5,550
---------- -------- ------- ------- ------- ----------
Total $1,245,702 $128,410 $(13,191) $21,398 ($4) $1,339,519
========== ======== ======= ======= ======= ==========
___________
Notes: 1993 1992 1991
(1) Provision on basis of usage or estimated life of transportion
equipment (automobiles, trucks and aircraft) charged to clearing
accounts and allocated on the basis of the use of such equipment - - $61
Provision on basis of usage of other tangible property (coal min-
ing equipment) charged to account 151 - Fuel Stock and allocated
to operating expenses as a portion of the cost of coal burned $608 $569 513
ANO Decommissioning Trust Fund contribution - - (13,765)
------- ------- ----------
Total $608 $569 $(13,191)
======= ======= ==========
(2) Reclassify ISES Synchronization costs as a regulatory asset $(4,199) - -
Transfer of net gain on sale of property from reserve - $(145) $(4)
ANO Decommissioning Trust Fund transferred to investments - 77,820 -
------- ------- ----------
Total $(4,199) $77,675 $(4)
======= ======= ==========
(3) Transfer of reserve related to the sale of Missouri property - $18,415 -
======= ======= ==========
GULF STATES UTILITIES COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- -------------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Additions Deductions Changes
------------------------ ------------ ---------
Balance at Charged Retirements Debits Balance
Beginning Charged to to Other Renewals and (Credits) at End
Description of Period Income Accounts Replacements (Note 1) of Period
- -------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
Accumulated Depreciation of
Utility Plant:
Electric:
Production $1,289,802 $120,845 - $18,287 $1,319 $1,393,679
Transmission 355,238 22,635 - 791 (368) 376,714
Distribution 407,350 30,472 - 15,127 2,131 424,826
General 41,989 3,853 - 639 (1) 45,202
Depreciation-CWIP in rate base (3,124) (380) - - - (3,504)
Regulatory item 4,860 1,875 - - - 6,735
Natural Gas:
Distribution 24,088 1,404 - 41 (28) 25,423
General 412 59 - 45 - 426
Steam Products:
Production 47,344 3,003 - 739 (152) 49,456
Distribution 4,589 78 - 8 - 4,659
General 171 19 - 2 - 188
---------- -------- --- ------- ------ ----------
Total $2,172,719 $183,863 - $35,679 $2,901 $2,323,804
========== ======== === ======= ====== ==========
Year Ended December 31, 1992
Accumulated Depreciation of
Utility Plant:
Electric:
Production $1,191,048 $120,625 - $61,760 $39,889 $1,289,802
Transmission 335,875 22,289 - 1,525 (1,401) 355,238
Distribution 385,964 29,327 - 7,650 (291) 407,350
General 38,850 3,667 - 635 107 41,989
Depreciation-CWIP in rate base (2,744) (380) - - - (3,124)
Regulatory item 2,985 1,875 - - - 4,860
Natural Gas:
Distribution 22,901 1,369 - 169 (13) 24,088
General 365 54 - 7 - 412
Steam Products:
Production 44,441 2,930 - 9 (18) 47,344
Distribution 4,512 77 - - - 4,589
General 154 18 - 1 - 171
---------- -------- --- ------- ------- ----------
Total $2,024,351 $181,851 - $71,756 $38,273 $2,172,719
========== ======== === ======= ======= ==========
GULF STATES UTILITIES COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY
(Continued)
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Additions Deductions Changes
--------------------- ------------ ---------
Balance at Charged Retirements Debits Balance
Beginning Charged to to Other Renewals and (Credits) at End
Description of Period Income Accounts Replacements (Note 1) of Period
- -----------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1991
Accumulated Depreciation of
Utility Plant:
Electric:
Production $1,063,397 $121,558 - $1,098 $7,191 $1,191,048
Transmission 316,684 21,911 - 3,756 1,036 335,875
Distribution 365,962 28,301 - 9,866 1,567 385,964
General 35,722 3,488 - 258 (102) 38,850
Depreciation-CWIP in rate base (2,368) (377) - - 1 (2,744)
Regulatory item (Note 2) - 1,583 - - 1,402 2,985
Natural Gas:
Transmission - - - - - -
Distribution 21,703 1,351 - 89 (64) 22,901
General 321 49 - 5 - 365
Steam Products:
Production 41,891 2,911 - 294 (67) 44,441
Distribution 4,432 76 - - 4 4,512
General 138 18 - 2 - 154
---------- -------- --- ------- ------- ----------
Total $1,847,882 $180,869 - $15,368 $10,968 $2,024,351
========== ======== === ======= ======= ==========
(1) In 1992, GSU changed its accounting procedures to include in inventory, power plant materials and supplies previously
capitalized as plant in service. The effect of the change was to decrease amounts previously capitalized as plant
in service by $35.7 million.
(2) In accordance with the rate order in Louisiana effective March 1, 1991, the LPSC required GSU to modify its treatment
of certain flow through benefits related to Allowance for Funds Used During Construction recorded on capital
expenditures prior to 1986. Accordingly GSU increased utility plant by $71.4 million, increased
accumulated depreciation by $8.4 million and increased the balance of accumulated deferred income taxes by $63
million. In accordance with the March 1991 PUCT rate order, GSU recognized a regulatory asset of $7 million for
depreciation for Big Cajun 2 Unit 3 that was accrued from September 1983 through June 1986.
LOUISIANA POWER & LIGHT COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- ---------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Additions Deductions Changes
--------------------- ------------ ---------
Charged
Balance at to Other Retirements Debits Balance
Beginning Charged to Accounts Renewals and (Credits) at End
Description of Period Income (Note 1) Replacements (Note 2) of Period
- ----------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
Accumulated Depreciation of
Utility Plant:
Electric:
Production $786,278 $79,606 - $13,748 - $852,136
Transmission 135,376 13,408 - 1,128 - 147,656
Distribution 418,988 40,787 - 12,111 - 447,664
General 15,919 2,828 $554 183 $(35) 19,083
Leased to others 5,144 - - - - 5,144
Leased from others (Note 3) 18,577 5,847 - - - 24,424
---------- -------- ---- ------- ---- ----------
Total $1,380,282 $142,476 $554 $27,170 $(35) $1,496,107
========== ======== ==== ======= ==== ==========
Year Ended December 31, 1992
Accumulated Depreciation of
Utility Plant:
Electric:
Production $702,710 $97,058 - $13,490 - $786,278
Transmission 125,143 9,973 - (260) - 135,376
Distribution 392,822 35,760 - 9,520 $(74) 418,988
General 19,393 2,453 $297 6,224 - 15,919
Leased to others 5,144 - - - - 5,144
Leased from others (Note 3) 12,783 5,794 - - - 18,577
---------- -------- ---- ------- ---- ----------
Total $1,257,995 $151,038 $297 $28,974 $(74) $1,380,282
========== ======== ==== ======= ==== ==========
Year Ended December 31, 1991
Accumulated Depreciation of
Utility Plant:
Electric:
Production $629,381 $78,634 - $5,529 $224 $702,710
Transmission 116,401 9,363 - 621 - 125,143
Distribution 366,582 33,840 - 7,600 - 392,822
General 17,451 2,009 $70 140 3 19,393
Leased to others 5,144 - - - - 5,144
Leased from others (Note 3) 9,900 2,883 - - - 12,783
---------- -------- ---- ------- ---- ----------
Total $1,144,859 $126,729 $70 $13,890 $227 $1,257,995
========== ======== ==== ======= ==== ==========
___________
Notes: 1993 1992 1991
(1) Provision on basis of usage or estimate life of transportation
equipment (automobiles, trucks and aircraft) charged to clearing
accounts and allocated on the basis of the use of such equipment $554 $297 $70
======= ===== ==========
(2) Transfer of gain on sale from reserve to other accounts $(35) $(74) -
Donation of property - - 2
Reclassification of decommissioning amounts pursuant to LPSC order - - 224
Adjustment to the 1989 retirement of the sold portions of Waterford 3 - - 1
------- ----- ----------
Total $(35) $(74) $227
======= ===== ==========
(3) Includes amounts associated with the Waterfird 3 sale and
leaseback transactions
MISSISSIPPI POWER & LIGHT COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Additions Deductions Changes
----------------------- ------------ -----------
Balance at Charged
Beginning to Other Retirements Debits Balance
of Period Charged to Accounts Renewals and (Credits) at End
Description (Note 3) Income (Note 1) Replacements (Notes 2-3) of Period
- -----------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
Accumulated Depreciation of
Utility Plant:
Electric:
Intangible - $24 - - - $24
Production $326,821 9,975 $70 $(1,398) $(495) 337,769
Transmission 86,773 7,733 - 453 - 94,053
Distribution 119,375 12,711 - 4,833 - 127,253
General 16,181 1,486 993 31 - 18,629
-------- ------- ------ ------- ------ --------
Total $549,150 $31,929 $1,063 $3,919 $(495) $577,728
======== ======= ====== ======= ====== ========
Year Ended December 31, 1992
Accumulated Depreciation of
Utility Plant:
Electric:
Production $317,093 $9,945 $70 $287 - $326,821
Transmission 78,531 7,592 - (650) - 86,773
Distribution 111,885 12,170 - 4,680 - 119,375
General 17,117 1,426 1,274 3,636 - 16,181
-------- ------- ------ ------- ------ --------
Total $524,626 $31,133 $1,344 $7,953 - $549,150
======== ======= ====== ======= ====== ========
Year Ended December 31, 1991
Accumulated Depreciation of
Utility Plant:
Electric:
Production $307,182 $9,852 $70 $11 - $317,093
Transmission 72,168 7,156 - 793 - 78,531
Distribution 105,116 11,479 - 4,710 - 111,885
General 14,866 1,242 1,234 225 - 17,117
-------- ------- ------ ------- ------ --------
Total $499,332 $29,729 $1,304 $5,739 - $524,626
======== ======= ====== ======= ====== ========
___________
Notes: 1993 1992 1991
(1) Provision on basis of usage or estimated life of transportation
equipment (automobiles, trucks and aircraft) charged to clearing
accounts and allocated on the basis of the use of such equipment $545 $656 $663
Amortization of coal mining equipment charged to fuel expense 448 618 571
Amortization of gas pipeline charged to fuel expense 70 70 70
------- ------ --------
Total $1,063 $1,344 $1,304
======= ====== ========
(2) Sale of property (land) in MS credited to Gain on Disposition
of Property $(495) - -
======= ====== ========
(3) Beginning balances for the year 1991 in Production and General have been changed due
to a reclassification of coal mining equipment from production
function to general plant. This reclassification was not reflected in the original
1991 balances and thereafter. The balances have been revised for the years 1991 and 1992 to update.
NEW ORLEANS PUBLIC SERVICE INC.
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Additions Deductions Changes
----------------------- ------------ ---------
Charged
Balance at to Other Retirements Balance
Beginning Charged to Accounts Renewals and Debits at End
Description of Period Income (Note 1) Replacements (Credits) of Period
- -----------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
Accumulated Depreciation of
Utility Plant:
Electric:
Production $123,512 $4,775 - $86 - $128,201
Transmission 28,972 1,394 - 11 - 30,355
Distribution 101,017 6,989 - 1,465 - 106,541
General 12,365 1,130 $23 - - 13,518
Gas:
Transmission 4,936 41 - 2 - 4,975
Distribution 41,645 2,614 - 895 - 43,364
General 2,992 322 - - - 3,314
-------- ------- --- ------ --- --------
Total $315,439 $17,265 $23 $2,459 - $330,268
======== ======= === ====== === ========
Year Ended December 31, 1992
Accumulated Depreciation of
Utility Plant:
Electric:
Production $119,049 $4,723 - $260 - $123,512
Transmission 27,640 1,375 - 43 - 28,972
Distribution 96,001 6,732 - 1,716 - 101,017
General 11,954 904 $13 506 - 12,365
Gas:
Transmission 4,897 39 - - - 4,936
Distribution 39,712 2,516 - 583 - 41,645
General 2,710 265 - (17) - 2,992
-------- ------- --- ------ --- --------
Total $301,963 $16,554 $13 $3,091 - $315,439
======== ======= === ====== === ========
Year Ended December 31, 1991
Accumulated Depreciation of
Utility Plant:
Electric:
Production $114,443 $4,629 - $23 - $119,049
Transmission 26,350 1,335 - 45 - 27,640
Distribution 90,546 6,511 - 1,056 - 96,001
General 11,221 834 $12 113 - 11,954
Natural Gas:
Transmission 4,859 38 - - - 4,897
Distribution 37,849 2,412 - 549 - 39,712
General 2,722 267 - 279 - 2,710
-------- ------- --- ------ --- --------
Total $287,990 $16,026 $12 $2,065 - $301,963
======== ======= === ====== === ========
___________
Notes: 1993 1992 1991
---- ---- ----
(1) Provision on basis of usage or estimated life of transportation
equipment (automobiles, trucks and aircraft) charged to clearing
accounts and allocated on the basis of the use of such equipment $23 $13 $12
====== ==== ========
SYSTEM ENERGY RESOURCES, INC.
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Additions Deductions Changes
--------------------- ------------ --------
Charged
Balance at to Other Retirements Balance
Beginning Charged to Accounts Renewals and Debits at End
Description of Period Income (Note 1) Replacements (Credits) of Period
- -----------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
Accumulated Depreciation of
Utility Plant:
Electric:
Production $520,350 $85,988 - $3,187 - $603,151
Leased from others (Note 2) 51,952 - $14,712 149 - 66,515
-------- ------- ------- ------- ------- --------
Total $572,302 $85,988 $14,712 $3,336 - $669,666
======== ======= ======= ======= ======= ========
Year Ended December 31, 1992
Accumulated Depreciation of
Utility Plant:
Electric:
Production $465,214 $85,927 - $30,791 - $520,350
Leased from others (Note 2) 40,714 - $14,810 3,572 - 51,952
-------- ------- ------- ------- ------- --------
Total $505,928 $85,927 $14,810 $34,363 - $572,302
======== ======= ======= ======= ======= ========
Year Ended December 31, 1991
Accumulated Depreciation of
Utility Plant:
Electric:
Production $393,159 $85,986 - $13,931 - $465,214
Leased from others (Note 2) 26,764 - $14,888 938 - 40,714
-------- ------- ------- ------- ------- --------
Total $419,923 $85,986 $14,888 $14,869 - $505,928
======== ======= ======= ======= ======= ========
___________
Notes: 1993 1992 1991
---- ---- ----
(1) Represents depreciation expense deferrals associated with the
Grand Gulf 1 sale and leaseback transactions consistent with the
FERC audit $14,712 $14,810 $14,888
======= ======= ========
(2) Includes amounts associated with the Grand Gulf 1 sale and
leaseback transactions
ENTERGY CORPORATION AND SUBSIDIARIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1993, 1992, and 1991
(In Thousands)
- ---------------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
Other
Additions Changes
---------------------- ----------
Charged Deductions
Balance at to Other from Balance
Beginning Charged to Accounts Provisions Acquistion at End
visions Acquistion at End
Description of Period Income (Note 1) (Note 2) of GSU of Period
- ---------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1993
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $6,193 $8,565 - $8,333 $2,383 $8,808
======= ======= ===== ======= ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $25,178 $5,714 - $7,217 $10,872 $34,547
Injuries and damages (Note 3) 14,728 8,952 - 13,303 8,714 19,091
Pensions and benefits (Note 4) 11,196 18,757 - 25,479 - 4,474
Misc. operating reserves (Note 5) 500 - - - - 500
Coal car maintenance - - - - 3,430 3,430
------- ------- ----- ------- ------- -------
Total $51,602 $33,423 - $45,999 $23,016 $62,042
======= ======= ===== ======= ======= =======
Year ended December 31, 1992
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $8,125 $3,654 - $5,586 - $6,193
======= ======= ===== ======= ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance (Note 6) $35,058 $10,820 - $20,700 - $25,178
Injuries and damages (Note 3) 13,364 11,053 $20 9,709 - 14,728
Pensions and benefits (Note 4) 11,196 17,792 (597) 17,195 - 11,196
Misc. operating reserves (Note 5) 500 - - - - 500
------- ------- ----- ------- ------- -------
Total $60,118 $39,665 $(577) $47,604 - $51,602
======= ======= ===== ======= ======= =======
Year ended December 31, 1991
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $8,100 $9,831 - $9,806 - $8,125
======= ======= ===== ======= ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $33,181 $8,594 - $6,717 - $35,058
Injuries and damages (Note 3) 12,664 11,444 $20 10,764 - 13,364
Pensions and benefits (Note 4) 8,683 18,249 732 16,468 - 11,196
Misc. operating reserves (Note 5) - 500 - - - 500
------- ------- ----- ------- ------- -------
Total $54,528 $38,787 $752 $33,949 - $60,118
======= ======= ===== ======= ======= =======
___________
Notes:
(1) Charged to clearing and other accounts.
(2) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for doubtful accounts, such
deductions are reduced by recoveries of amounts previously written off.
(3) Injuries and damages provision is provided to absorb all current expenses
as appropriate and for the estimated cost of settling claims for injuries and damages.
(4) Pension and benefits provision is provided to account for provisions made
by AP&L for group medical insurance coverage on its employees.
(5) Miscellaneous operating reserves represents a reserve provided by MP&L for
environmental exposures.
(6) Property insurance reserves and insurance reimbursements were adequate to
cover expenses associated with Hurricane Andrew.
ARKANSAS POWER & LIGHT COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1993, 1992, and 1991
(In Thousands)
- ----------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Other
Additions Changes
------------------------ ----------
Charged Deductions
Balance at to Other from Balance
Beginning Charged to Accounts Provisions at End
Description of Period Income (Note 1) (Note 2) of Period
- ----------------------------------------------------------------------------------------------------------------
Year ended December 31, 1993
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $1,613 $3,439 - $3,002 $2,050
======= ======= ====== ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $5,182 $1,952 - $4,313 $2,821
Injuries and damages (Note 3) 5,851 4,070 - 6,662 3,259
Pensions and benefits (Note 4) 11,196 18,757 - 25,479 4,474
------- ------- ------ ------- -------
Total $22,229 $24,779 - $36,454 $10,554
======= ======= ====== ======= =======
Year ended December 31, 1992
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $3,430 $(3) - $1,814 $1,613
======= ======= ====== ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $7,827 $4,000 - $6,645 $5,182
Injuries and damages (Note 3) 4,254 7,086 - 5,489 5,851
Pensions and benefits (Note 4) 11,196 17,792 $(597) 17,195 11,196
------- ------- ------ ------- -------
Total $23,277 $28,878 $(597) $29,329 $22,229
======= ======= ====== ======= =======
Year ended December 31, 1991
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $3,430 $2,946 - $2,946 $3,430
======= ======= ====== ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $9,320 $3,274 - $4,767 $7,827
Injuries and damages (Note 3) 3,571 6,017 - 5,334 4,254
Pensions and benefits (Note 4) 8,683 18,249 $732 16,468 11,196
------- ------- ----- ------- -------
Total $21,574 $27,540 $732 $26,569 $23,277
======= ======= ====== ======= =======
___________
Notes:
(1) Charged to clearing and other accounts.
(2) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for doubtful accounts,
such deductions are reduced by recoveries of amounts previously written off.
(3) Injuries and damages provision is provided to absorb all current expenses as appropriate
and for the estimated cost of settling claims for injuries and damages.
(4) Pension and benefits provision is provided to account for provisions made
by AP&L for group medical insurance coverage on its employees.
GULF STATES UTILITIES COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- ----------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Other
Additions Changes
----------------------- ----------
Charged Deductions
Balance at to Other from Balance
Beginning Charged to Accounts Provisions at End
Description of Period Income (Note 1) (Note 2) of Period
- ----------------------------------------------------------------------------------------------------------------
Year ended December 31, 1993
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $2,953 $929 - $1,499 $2,383
======= ======= ====== ====== =======
Accumulated Provisions
Not Deducted from Assets--
Property insurance $9,397 $1,302 - $(173) $10,872
Injuries and damages (Note 3) 6,018 11,317 - 8,621 8,714
Coal car maintenance 2,873 - $1,034 477 3,430
------- ------- ------ ------ -------
Total $18,288 $12,619 $1,034 $8,925 $23,016
======= ======= ====== ====== =======
Year ended December 31, 1992
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $2,796 $2,271 - $2,114 $2,953
======= ======= ====== ====== ======
Accumulated Provisions
Not Deducted from Assets--
Property insurance $10,975 $(1,578) - - $9,397
Injuries and damages (Note 3) 5,102 2,805 - $1,889 6,018
Coal car maintenance 2,459 - $1,006 592 2,873
------- ------- ------ ------ -------
Total $18,536 $1,227 $1,006 $2,481 $18,288
======= ======= ====== ====== =======
Year ended December 31, 1991
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $2,636 $1,731 - $1,571 $2,796
======= ======= ====== ====== =======
Accumulated Provisions
Not Deducted from Assets--
Property insurance $8,891 $2,084 - - $10,975
Injuries and damages (Note 3) 5,812 1,783 - $2,493 5,102
Coal car maintenance 2,894 - $959 1,394 2,459
------- ------- ------ ------ -------
Total $17,597 $3,867 $959 $3,887 $18,536
======= ======= ====== ====== =======
___________
Notes:
(1) Charged to clearing and other accounts.
(2) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for
doubtful accounts, such deductions are reduced by recoveries of amounts
previously written off.
(3) Injuries and damages provision is provided to absorb all current expenses
as appropriate and for the estimated cost of settling claims for injuries
and damages.
LOUISIANA POWER & LIGHT COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1993, 1992, and 1991
(In Thousands)
- ----------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Other
Additions Changes
------------------------ ----------
Deductions
Balance at Charged from Balance
Beginning Charged to to Other Provisions at End
Description of Period Income Accounts (Note 1) of Period
- ----------------------------------------------------------------------------------------------------------------
Year ended December 31, 1993
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $1,956 $337 - $1,218 $1,075
======== ====== ====== ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $2,474 $1,800 - $1,886 $2,388
Injuries and damages (Note 2) 6,153 2,748 - 4,122 4,779
-------- ------ ------ ------- -------
Total $8,627 $4,548 - $6,008 $7,167
======== ====== ====== ======= =======
Year ended December 31, 1992
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $1,956 $1,324 - $1,324 $1,956
======== ====== ====== ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance (Note 3) $9,174 $4,300 - $11,000 $2,474
Injuries and damages (Note 2) 6,153 2,283 - 2,283 6,153
-------- ------ ------ ------- -------
Total $15,327 $6,583 - $13,283 $8,627
======== ====== ====== ======= =======
Year ended December 31, 1991
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $1,956 $2,298 - $2,298 $1,956
======== ====== ====== ======= =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $7,463 $2,800 - $1,089 $9,174
Injuries and damages (Note 2) 6,153 4,421 - 4,421 6,153
-------- ------ ------ ------- -------
Total $13,616 $7,221 - $5,510 $15,327
======== ====== ====== ======= =======
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for
doubtful accounts, such deductions are reduced by recoveries of amounts
previously written off.
(2) Injuries and damages provision is provided to absorb all current expenses
as appropriate and for the estimated cost of settling claims for injuries
and damages.
(3) Property insurance reserves and insurance reimbursements were adequate to
cover expenses associated with Hurricane Andrew.
MISSISSIPPI POWER & LIGHT COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1993, 1992, and 1991
(In Thousands)
- ----------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Other
Additions Changes
----------------------- -----------
Charged Deductions
Balance at to Other from Balance
Beginning Charged to Accounts Provisions at End
Description of Period Income (Note 1) (Note 2) of Period
- ----------------------------------------------------------------------------------------------------------------
Year ended December 31, 1993
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $1,274 $3,629 - $2,433 $2,470
====== ====== === ====== ======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $2,051 $1,521 - $1,018 $2,554
Injuries and damages (Note 3) 395 452 - 619 228
Misc. operating reserves (Note 4) 500 - - - 500
------ ------ --- ------ ------
Total $2,946 $1,973 - $1,637 $3,282
====== ====== === ====== ======
Year ended December 31, 1992
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $1,389 $834 - $949 $1,274
====== ====== === ====== ======
Accumulated Provisions Not
Deducted from Assets:
Property insurance (Note 5) $3,300 $1,520 - $2,769 $2,051
Injuries and damages (Note 3) 613 333 $20 571 395
Misc. operating reserves (Note 4) 500 - - - 500
------ ------ --- ------ ------
Total $4,413 $1,853 $20 $3,340 $2,946
====== ====== === ====== ======
Year ended December 31, 1991
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $1,364 $2,012 - $1,987 $1,389
====== ====== === ====== ======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $2,642 $1,520 - $862 $3,300
Injuries and damages (Note 3) 545 577 $20 529 613
Misc. operating reserves (Note 4) - 500 - - 500
------ ------ --- ------ ------
Total $3,187 $2,597 $20 $1,391 $4,413
====== ====== === ====== ======
___________
Notes:
(1) Charged to clearing and other accounts.
(2) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for doubtful accounts,
such deductions are reduced by recoveries of amounts previously written off.
ductions are reduced by recoveries of amounts previously written off.
(3) Injuries and damages provision is provided to absorb all current expenses
as appropriate and for the estimated cost of settling claims for injuries and damages.
(4) Miscellaneous operating reserves represents a reserve provided by MP&L for
environmental exposures.
(5) Property insurance reserves and insurance reimbursements were adequate to
cover expenses associated with Hurricane Andrew.
NEW ORLEANS PUBLIC SERVICE INC.
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1993, 1992, and 1991
(In Thousands)
- ------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Other
Additions Changes
------------------------ -----------
Deductions
Balance at Charged from Balance
Beginning Charged to to Other Provisions at End
Description of Period Income Accounts (Note 1) of Period
- ------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1993
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $1,350 $1,160 - $1,680 $830
======= ====== ==== ====== =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $15,470 $441 - - $15,911
Injuries and damages (Note 2) 2,329 1,682 - $1,900 2,111
------- ------ ---- ------ -------
Total $17,799 $2,123 - $1,900 $18,022
======= ====== ==== ====== =======
Year ended December 31, 1992
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $1,350 $1,499 - $1,499 $1,350
======= ====== ==== ====== =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $14,755 $1,000 - $285 $15,470
Injuries and damages (Note 2) 2,344 1,351 - 1,366 2,329
------- ------ ---- ------ -------
Total $17,099 $2,351 - $1,651 $17,799
======= ====== ==== ====== =======
Year ended December 31, 1991
Accumulated Provisions
Deducted from Assets--
Doubtful accounts $1,350 $2,575 - $2,575 $1,350
======= ====== ==== ====== =======
Accumulated Provisions Not
Deducted from Assets:
Property insurance $13,755 $1,000 - - $14,755
Injuries and damages (Note 2) 2,395 429 - $480 2,344
------- ------ ---- ------ -------
Total $16,150 $1,429 - $480 $17,099
======= ====== ==== ====== =======
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the
provision for doubtful accounts, such deductions are reduced by recoveries
of amounts previously written off.
(2) Injuries and damages provision is provided to absorb all current expenses
as appropriate and for the estimated cost of settling claims for injuries and damages.
ENTERGY CORPORATION AND SUBSIDIARIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- ------------------------------------------------------------------------------
Column A Column B
Charged to
costs and
expenses
Item (Note 1)
- ------------------------------------------------------------------------------
Year Ended December 31, 1993
Taxes, other than payroll and income taxes:
Ad Valorem $102,898
State and city franchise 45,892
Other 26,948
--------
Total $175,738
========
Year Ended December 31, 1992
Taxes, other than payroll and income taxes:
Ad Valorem $99,337
State and city franchise 47,086
Other 26,114
--------
Total $172,537
========
Year Ended December 31, 1991
Taxes, other than payroll and income taxes:
Ad Valorem $93,036
State and city franchise 44,886
Other 25,311
--------
Total $163,233
========
__________
Notes:
(1) Taxes other than payroll and income taxes include taxes charged to
clearing accounts and distributed from those accounts to appropriate
operating and construction accounts or charged directly to construction
and other appropriate accounts.
ARKANSAS POWER & LIGHT COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- ------------------------------------------------------------------------------
Column A Column B
Charged to
costs and
expenses
Item (Note 1)
- ------------------------------------------------------------------------------
Year Ended December 31, 1993
Taxes, other than payroll and income taxes:
Ad Valorem $19,672
State and city franchise 536
Other 11,168
-------
Total $31,376
=======
Year Ended December 31, 1992
Taxes, other than payroll and income taxes:
Ad Valorem $18,466
State and city franchise 639
Other 10,357
-------
Total $29,462
=======
Year Ended December 31, 1991
Taxes, other than payroll and income taxes:
Ad Valorem $14,972
State and city franchise 675
Other 11,579
-------
Total $27,226
=======
__________
Notes:
(1) Taxes other than payroll and income taxes include taxes charged to
clearing accounts and distributed from those accounts to appropriate
operating and construction accounts or charged directly to construction
and other appropriate accounts.
GULF STATES UTILITIES COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- ------------------------------------------------------------------------------
Column A Column B
Charged to
costs and
expenses
Item (Note 1)
- ------------------------------------------------------------------------------
Year ended December 31, 1993
Taxes, other than payroll and income taxes:
Ad Valorem $31,333
State and city franchise 48,724
Other 5,717
-------
- --
Total $85,774
=======
Year ended December 31, 1992
Taxes, other than payroll and income taxes:
Ad Valorem $27,897
State and city franchise 48,853
Other 5,563
-------
Total $82,313
=======
Year ended December 31, 1991
Taxes, other than payroll and income taxes:
Ad Valorem $27,104
State and city franchise 46,611
Other 4,384
-------
Total $78,099
=======
__________
Notes:
(1) Taxes other than payroll and income taxes include taxes charged to
clearing accounts and distributed from those accounts to appropriate
operating and construction accounts or charged directly to
construction and other appropriate accounts.
LOUISIANA POWER & LIGHT COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- ------------------------------------------------------------------------------
Column A Column B
Charged to
costs and
expenses
Item (Note 1)
- ------------------------------------------------------------------------------
Year Ended December 31, 1993
Taxes, other than payroll and income taxes:
Ad Valorem $24,706
State and city franchise 18,343
Other 7,041
-------
Total $50,090
=======
Year Ended December 31, 1992
Taxes, other than payroll and income taxes:
Ad Valorem $23,045
State and city franchise 17,958
Other 7,842
-------
Total $48,845
=======
Year Ended December 31, 1991
Taxes, other than payroll and income taxes:
Ad Valorem $22,365
State and city franchise 17,922
Other 4,663
-------
Total $44,950
=======
__________
Notes:
(1) Taxes other than payroll and income taxes include taxes charged to
clearing accounts and distributed from those accounts to appropriate
operating and construction accounts or charged directly to
construction and other appropriate accounts.
MISSISSIPI POWER & LIGHT COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- ------------------------------------------------------------------------------
Column A Column B
Charged to
costs and
expenses
Item (Note 1)
- ------------------------------------------------------------------------------
Year Ended December 31, 1993
Taxes, other than payroll and income taxes:
Ad Valorem $25,538
State and city franchise 11,287
Other 5,344
-------
Total $42,169
=======
Year Ended December 31, 1992
Taxes, other than payroll and income taxes:
Ad Valorem $25,101
State and city franchise 10,533
Other 4,562
-------
Total $40,196
=======
Year Ended December 31, 1991
Taxes, other than payroll and income taxes:
Ad Valorem $22,389
State and city franchise 9,810
Other 4,482
-------
Total $36,681
=======
__________
Notes:
(1) Taxes other than payroll and income taxes include taxes charged to
clearing accounts and distributed from those accounts to appropriate
operating and construction accounts or charged directly to
construction and other appropriate accounts.
NEW ORLEANS PUBLIC SERVICE INC.
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- ------------------------------------------------------------------------------
Column A Column B
Charged to
costs and
expenses
Item (Note 1)
- ------------------------------------------------------------------------------
Year Ended December 31, 1993
Taxes, other than payroll and income taxes:
Ad Valorem $10,739
State and city franchise 13,350
Other 2,628
-------
Total $26,717
=======
Year Ended December 31, 1992
Taxes, other than payroll and income taxes:
Ad Valorem $10,480
State and city franchise 13,903
Other 2,083
-------
Total $26,466
=======
Year Ended December 31, 1991
Taxes, other than payroll and income taxes:
Ad Valorem $9,857
State and city franchise 12,965
Other 1,783
-------
Total $24,605
=======
__________
Notes:
(1) Taxes other than payroll and income taxes include taxes charged to
clearing accounts and distributed from those accounts to appropriate
operating and construction accounts or charged directly to
construction and other appropriate accounts.
SYSTEM ENERGY RESOURCES, INC.
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
- ------------------------------------------------------------------------------
Column A Column B
Charged to
costs and
expenses
Item (Note 1)
- ------------------------------------------------------------------------------
Year Ended December 31, 1993
Taxes, other than payroll and income taxes:
Ad Valorem $20,001
State and city franchise 2,918
Other 729
-------
Total $23,648
=======
Year Ended December 31, 1992
Taxes, other than payroll and income taxes:
Ad Valorem $20,002
State and city franchise 3,877
Other 1,235
-------
Total $25,114
=======
Year Ended December 31, 1991
Taxes, other than payroll and income taxes:
Ad Valorem $20,001
State and city franchise 3,697
Other 761
-------
Total $24,459
=======
__________
Notes:
(1) Taxes other than payroll and income taxes include taxes charged to
clearing accounts and distributed from those accounts to appropriate
operating and construction accounts or charged directly to
construction and other appropriate accounts.
EXHIBIT INDEX
The following exhibits indicated by an asterisk preceding the exhibit
number are filed herewith. The balance of the exhibits have heretofore been
filed with the SEC, respectively, as the exhibits and in the file numbers
indicated and are incorporated herein by reference. The exhibits marked with a
(+) are management contracts or compensatory plans or arrangements required to
be filed herewith and required to be identified as such by Item 14 of Form 10-K.
Reference is made to a duplicate list of exhibits being filed as a part of this
Form 10-K, which list, prepared in accordance with Item 102 of Regulation S-T of
the SEC, immediately precedes the exhibits being physically filed with this
Form 10-K.
(3) (i) Articles of Incorporation
Entergy Corporation
(a) 1 -- Certificate of Incorporation of Entergy Corporation (A-1(a) to
Rule 24 Certificate in 70-8059).
System Energy
(b) 1 -- Amended and Restated Articles of Incorporation of System Energy,
as executed April 28, 1989 (A-1(a) to Form U-1 in 70-5399).
AP&L
(c) 1 -- Amended and Restated Articles of Incorporation of AP&L, as
amended (4(c) in 33-50289).
GSU
(d) 1 -- Restated Articles of Incorporation, as amended, of GSU (A-11 in
70-8059).
(d) 2 -- Statement of Resolution amending Restated Articles of
Incorporation, as amended, of GSU (A-11(a) in 70-8059).
LP&L
(e) 1 -- Restated Articles of Incorporation of LP&L, as amended (4(c) in
33-50937).
MP&L
*(f) 1 -- Restated Articles of Incorporation of MP&L, as amended.
NOPSI
(g) 1 -- Restatement of Articles of Incorporation of NOPSI, as executed
September 30, 1969 (A-1 to Form U-1 in 70-6392).
(g) 2 -- Articles of Amendment to Restatement of Articles of Incorporation
of NOPSI, as executed February 27, 1980 (A-2(a) to Rule 24
Certificate in 70-6392).
(g) 3 -- Articles of Amendment to Restatement of Articles of
Incorporation, as amended, of NOPSI, as executed March 19, 1980
(C-1 to Rule 24 Certificate in 70-6404).
(g) 4 -- Articles of Amendment to Restatement of Articles of
Incorporation, as amended, of NOPSI, as executed January 23, 1984
(A-7(d) to Form U-1 in 70-6962).
(g) 5 -- Articles of Amendment to Restatement of Articles of
Incorporation, as amended, of NOPSI, as executed February 21,
1985 (3(f)5 to Form 10-K for the year ended December 31, 1984, in
0-5807).
(g) 6 -- Articles of Amendment to Restatement of Articles of
Incorporation, as amended, of NOPSI, as executed November 21,
1988 (A-2(b) to Rule 24 Certificate in 70-7558).
(g) 7 -- Articles of Amendment to Restatement of Articles of
Incorporation, as amended, of NOPSI, as executed June 12, 1989
(3(a) to Form 10-Q for the quarter ended June 30, 1989 in
0-5807).
(3) (ii) By-Laws
(a) -- By-Laws of Entergy Corporation (A-2(a) to Rule 24 Certificate in
70-8059).
(b) -- By-Laws of System Energy (A-2(a) in 70-5399).
(c) -- By-Laws of AP&L (4(f) in 33-50289).
(d) -- By-Laws of GSU (A-12 in 70-8059).
(e) -- By-Laws of LP&L (A-4 in 70-6962).
*(f) -- By-Laws of MP&L.
(g) -- By-Laws of NOPSI (3(b) to Form 10-Q for the quarter ended
September 30, 1989 in 0-5807).
(4) Instruments Defining Rights of Security Holders, Including Indentures
Entergy Corporation
(a) 1 -- See (4)(b) through (4)(g) below for instruments defining the
rights of holders of long-term debt of System Energy, AP&L, GSU,
LP&L, MP&L and NOPSI.
(a) 2 -- Revolving Credit Agreement, dated as of January 31, 1989 between
System Fuels and Bank of America National Trust and Savings
Association (B-1(c) to Rule 24 Certificate, dated February 1,
1989, in 70-7574), as amended by First Amendment to Revolving
Credit Agreement, dated as of August 28, 1990 (A to Rule 24
Certificate, dated October 31, 1990, in 70-7574).
(a) 3 -- Security Agreement dated as of January 31, 1989 between System
Fuels and Bank of America National Trust and Savings Association
(B-3(c) to Rule 24 Certificate, dated February 1, 1989, in
70-7574).
(a) 4 -- Credit Agreement, dated as of October 3, 1989, between System
Fuels and The Yasuda Trust and Banking Co., Ltd., New York
Branch, as agent (B-1(c) to Rule 24 Certificate, dated October 6,
1989, in 70-7668).
(a) 5 -- First Amendment, dated as of March 1, 1992, to Credit Agreement,
dated as of October 3, 1989, between System Fuels and The Yasuda
Trust and Banking Co., Ltd., New York Branch, as agent (4(a)5 to
Form 10-K for the year ended December 31, 1991 in 1-3517).
(a) 6 -- Second Amendment, dated as of September 30, 1992, to Credit
Agreement dated as of October 3, 1989, between System Fuels and
The Yasuda Trust and Banking Co., Ltd., New York Branch, as agent
(4(a)6 to Form 10-K for the year ended December 31, 1992 in 1-
3517).
(a) 7 -- Security Agreement, dated as of October 3, 1989, as amended,
between System Fuels and The Yasuda Trust and Banking Co., Ltd.,
New York Branch, as agent (B-3(c) to Rule 24 Certificate, dated
October 6, 1989, in 70-7668), as amended by First Amendment to
Security Agreement, dated as of March 14, 1990 (A to Rule 24
Certificate, dated March 7, 1990, in 70-7668).
(a) 8 -- Consent and Agreement, dated as of October 3, 1989, among System
Fuels, The Yasuda Trust and Banking Co., Ltd., New York Branch,
as agent, AP&L, LP&L, and System Energy (B-5(c) to Rule 24
Certificate, dated October 6, 1989, in 70-7668).
System Energy
(b) 1 -- Mortgage and Deed of Trust, as amended by eighteen Supplemental
Indentures (A-1 in 70-5890 (Mortgage); B and C to Rule 24
Certificate in 70-5890 (First); B to Rule 24 Certificate in
70-6259 (Second); 20(a)-5 to Form 10-Q for the quarter ended
June 30, 1981, in 1-3517 (Third); A-1(e)-1 to Rule 24 Certificate
in 70-6985 (Fourth); B to Rule 24 Certificate in 70-7021 (Fifth);
B to Rule 24 Certificate in 70-7021 (Sixth); A-3(b) to Rule 24
Certificate in 70-7026 (Seventh); A-3(b) to Rule 24 Certificate
in 70-7158 (Eighth); B to Rule 24 Certificate in 70-7123 (Ninth);
B-1 to Rule 24 Certificate in 70-7272 (Tenth); B-2 to Rule 24
Certificate in 70-7272 (Eleventh); B-3 to Rule 24 Certificate in
70-7272 (Twelfth); B-1 to Rule 24 Certificate in 70-7382
(Thirteenth); B-2 to Rule 24 Certificate in 70-7382 (Fourteenth);
A-2(c) to Rule 24 Certificate in 70-7946 (Fifteenth); A-2(c) to
Rule 24 Certificate in 70-7946 (Sixteenth); A-2(d) to Rule 24
Certificate in 70-7946 (Seventeenth); and A-2(e) to Rule 24
Certificate dated May 4, 1993 in 70-7946 (Eighteenth)).
(b) 2 -- Facility Lease No. 1, dated as of December 1, 1988, between
Meridian Trust Company and Stephen M. Carta (Steven Kaba,
successor), as Owner Trustees, and System Energy (B-2(c)(1) to
Rule 24 Certificate dated January 9, 1989 in 70-7561), as
supplemented by Lease Supplement No. 1 dated as of April 1, 1989
(B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-
7561) and Lease Supplement No. 2 dated as of January 1, 1994 (B-
3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215).
(b) 3 -- Facility Lease No. 2, dated as of December 1, 1988 between
Meridian Trust Company and Stephen M. Carta (Steven Kaba,
successor), as Owner Trustees, and System Energy (B-2(c)(2) to
Rule 24 Certificate dated January 9, 1989 in 70-7561), as
supplemented by Lease Supplement No. 1 dated as of April 1, 1989
(B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-
7561) and Lease Supplement No. 2 dated as of January 1, 1994 (B-
4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215).
(b) 4 -- Installment Sale Agreement, dated as of December 1, 1983 between
System Energy and Claiborne County, Mississippi (B-1 to First
Rule 24 Certificate in 70-6913).
(b) 5 -- Indenture of Trust, dated as of December 1, 1983, between
Claiborne County, Mississippi and Deposit Guaranty National Bank
(A-1 to First Rule 24 Certificate in 70-6913).
(b) 6 -- Installment Sale Agreement, dated as of June 1, 1984, between
System Energy and Claiborne County, Mississippi (B-2 to Second
Rule 24 Certificate in 70-6913).
(b) 7 -- Indenture of Trust dated as of June 1, 1984, between Claiborne
County, Mississippi and Deposit Guaranty National Bank (A-2 to
Second Rule 24 Certificate in 70-6913).
(b) 8 -- Installment Sale Agreement, dated as of December 1, 1984, between
System Energy and Claiborne County, Mississippi (B-1 to First
Rule 24 Certificate in 70-7026).
(b) 9 -- Indenture of Trust, dated as of December 1, 1984, between
Claiborne County, Mississippi and Deposit Guaranty National Bank
(B-2 to First Rule 24 Certificate in 70-7026).
(b) 10 -- Installment Sale Agreement, dated as of June 15, 1985, between
System Energy and Claiborne County, Mississippi (B-1(b) to Third
Rule 24 Certificate in 70-7026).
(b) 11 -- Indenture of Trust, dated as of June 15, 1985, between Claiborne
County, Mississippi and Deposit Guaranty National Bank (B-2(b) to
Third Rule 24 Certificate in 70-7026).
(b) 12 -- Installment Sale Agreement, dated as of May 1, 1986, between
System Energy and Claiborne County, Mississippi (B-1(b) to Rule
24 Certificate in 70-7158).
(b) 13 -- Indenture of Trust, dated as of May 1, 1986, between Claiborne
County, Mississippi and Deposit Guaranty National Bank (B-2(b) to
Rule 24 Certificate in 70-7158).
AP&L
(c) 1 -- Mortgage and Deed of Trust, as amended by fifty-one
Supplemental Indentures (7(d) in 2-5463 (Mortgage); 7(b) in
2-7121 (First); 7(c) in 2-7605 (Second); 7(d) in 2-8100 (Third);
7(a)-4 in 2-8482 (Fourth); 7(a)-5 in 2-9149 (Fifth); 4(a)-6 in
2-9789 (Sixth); 4(a)-7 in 2-10261 (Seventh); 4(a)-8 in 2-11043
(Eighth); 2(b)-9 in 2-11468 (Ninth); 2(b)-10 in 2-15767 (Tenth);
D in 70-3952 (Eleventh); D in 70-4099 (Twelfth); 4(d) in 2-23185
(Thirteenth); 2(c) in 2-24414 (Fourteenth); 2(c) in 2-25913
(Fifteenth); 2(c) in 2-28869 (Sixteenth); 2(d) in 2-28869
(Seventeenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646
(Nineteenth); 2(c) in 2-39253 (Twentieth); 2(c) in 2-41080
(Twenty-first); C-1 to Rule 24 Certificate in 70-5151
(Twenty-second); C-1 to Rule 24 Certificate in 70-5257
(Twenty-third); C to Rule 24 Certificate in 70-5343
(Twenty-fourth); C-1 to Rule 24 Certificate in 70-5404
(Twenty-fifth); C to Rule 24 Certificate in 70-5502
(Twenty-sixth); C-1 to Rule 24 Certificate in 70-5556
(Twenty-seventh); C-1 to Rule 24 Certificate in 70-5693
(Twenty-eighth); C-1 to Rule 24 Certificate in 70-6078
(Twenty-ninth); C-1 to Rule 24 Certificate in 70-6174
(Thirtieth); C-1 to Rule 24 Certificate in 70-6246
(Thirty-first); C-1 to Rule 24 Certificate in 70-6498
(Thirty-second); A-4b-2 to Rule 24 Certificate in 70-6326
(Thirty-third); C-1 to Rule 24 Certificate in 70-6607
(Thirty-fourth); C-1 to Rule 24 Certificate in 70-6650
(Thirty-fifth); C-1 to Rule 24 Certificate, dated December 1,
1982, in 70-6774 (Thirty-sixth); C-1 to Rule 24 Certificate,
dated February 17, 1983, in 70-6774 (Thirty-seventh); A-2(a) to
Rule 24 Certificate, dated December 5, 1984, in 70-6858
(Thirty-eighth); A-3(a) to Rule 24 Certificate in 70-7127
(Thirty-ninth); A-7 to Rule 24 Certificate in 70-7068 (Fortieth);
A-8(b) to Rule 24 Certificate dated July 6, 1989 in 70-7346
(Forty-first); A-8(c) to Rule 24 Certificate, dated February 1,
1990 in 70-7346 (Forty-second); 4 to Form 10-Q for the quarter
ended September 30, 1990 in 1-10764 (Forty-third); A-2(a) to Rule
24 Certificate, dated November 30, 1990, in 70-7802
(Forty-fourth); A-2(b) to Rule 24 Certificate, dated January 24,
1991, in 70-7802 (Forty-fifth); 4(d)(2) in 33-54298
(Forty-sixth); 4(c)(2) to Form 10-K for the year ended December
31, 1992 in 1-10764 (Forty-seventh); 4(b) to Form 10-Q for the
quarter ended June 30, 1993 in 1-10764 (Forty-eighth); 4(c) to
Form 10-Q for the quarter ended June 30, 1993 in 1-10764
(Forty-ninth); 4(b) to Form 10-Q for the quarter ended September
30, 1993 in 1-10764 (Fiftieth); and 4(c) to Form 10-Q for the
quarter ended September 30, 1993 in 1-10764 (Fifty-first)).
GSU
(d) 1 -- Indenture of Mortgage, as amended by certain Supplemental
Indentures (B-a-I-1 in Registration No. 2-2449 (Mortgage); 7-A-9
in Registration No. 2-6893 (Seventh); B to Form 8-K dated
September 1, 1959 (Eighteenth); B to Form 8-K dated February 1,
1966 (Twenty-second); B to Form 8-K dated March 1, 1967 (Twenty-
third); C to Form 8-K dated March 1, 1968 (Twenty-fourth); B to
Form 8-K dated November 1, 1968 (Twenty-fifth); B to Form 8-K
dated April 1, 1969 (Twenty-sixth); 2-A-8 in Registration No. 2-
66612 (Thirty-eighth); 4-2 to Form 10-K for the year ended
December 31, 1984 in 1-2703 (Forty-eighth); 4-2 to Form 10-K for
the year ended December 31, 1988 in 1-2703 (Fifty-second); 4 to
Form 10-K for the year ended December 31, 1991 in 1-2703 (Fifty-
third); 4 to Form 8-K dated July 29, 1992 in 1-2703 (Fifth-
fourth); 4 to Form 10-K dated December 31, 1992 in 1-2703 (Fifty-
fifth); 4 to Form 10-Q for the quarter ended March 31, 1993 in 1-
2703 (Fifty-sixth); and 4-2 to Amendment No. 9 to Registration
No. 2-76551 (Fifty-seventh)).
(d) 2 -- Indenture, dated March 21, 1939, accepting resignation of The
Chase National Bank of the City of New York as trustee and
appointing Central Hanover Bank and Trust Company as successor
trustee (B-a-1-6 in Registration No. 2-4076).
(d) 3 -- Trust Indenture for 9.72% Debentures due July 1, 1998 (4 in
Registration No. 33-40113).
LP&L
(e) 1 -- Mortgage and Deed of Trust, as amended by forty-eight
Supplemental Indentures (7(d) in 2-5317 (Mortgage); 7(b) in
2-7408 (First); 7(c) in 2-8636 (Second); 4(b)-3 in 2-10412
(Third); 4(b)-4 in 2-12264 (Fourth); 2(b)-5 in 2-12936 (Fifth);
D in 70-3862 (Sixth); 2(b)-7 in 2-22340 (Seventh); 2(c) in
2-24429 (Eighth); 4(c)-9 in 2-25801 (Ninth); 4(c)-10 in 2-26911
(Tenth); 2(c) in 2-28123 (Eleventh); 2(c) in 2-34659 (Twelfth);
C to Rule 24 Certificate in 70-4793 (Thirteenth); 2(b)-2 in
2-38378 (Fourteenth); 2(b)-2 in 2-39437 (Fifteenth); 2(b)-2 in
2-42523 (Sixteenth); C to Rule 24 Certificate in 70-5242
(Seventeenth); C to Rule 24 Certificate in 70-5330 (Eighteenth);
C-1 to Rule 24 Certificate in 70-5449 (Nineteenth); C-1 to
Rule 24 Certificate in 70-5550 (Twentieth); A-6(a) to Rule 24
Certificate in 70-5598 (Twenty-first); C-1 to Rule 24 Certificate
in 70-5711 (Twenty-second); C-1 to Rule 24 Certificate in 70-5919
(Twenty-third); C-1 to Rule 24 Certificate in 70-6102
(Twenty-fourth); C-1 to Rule 24 Certificate in 70-6169
(Twenty-fifth); C-1 to Rule 24 Certificate in 70-6278
(Twenty-sixth); C-1 to Rule 24 Certificate in 70-6355
(Twenty-seventh); C-1 to Rule 24 Certificate in 70-6508
(Twenty-eighth); C-1 to Rule 24 Certificate in 70-6556
(Twenty-ninth); C-1 to Rule 24 Certificate in 70-6635
(Thirtieth); C-1 to Rule 24 Certificate in 70-6834
(Thirty-first); C-1 to Rule 24 Certificate in 70-6886
(Thirty-second); C-1 to Rule 24 Certificate in 70-6993
(Thirty-third); C-2 to Rule 24 Certificate in 70-6993
(Thirty-fourth); C-3 to Rule 24 Certificate in 70-6993
(Thirty-fifth); A-2(a) to Rule 24 Certificate in 70-7166
(Thirty-sixth); A-2(a) in 70-7226 (Thirty-seventh); C-1 to
Rule 24 Certificate in 70-7270 (Thirty-eighth); 4(a) to Quarterly
Report on Form 10-Q for the quarter ended June 30, 1988, in
1-8474 (Thirty-ninth); A-2(b) to Rule 24 Certificate in 70-7553
(Fortieth); A-2(d) to Rule 24 Certificate in 70-7553
(Forty-first); A-3(a) to Rule 24 Certificate in 70-7822
(Forty-second); A-3(b) to Rule 24 Certificate in 70-7822
(Forty-third); A-2(b) to Rule 24 Certificate in File No. 70-7822
(Forty-fourth); A-3(c) to Rule 24 Certificate in 70-7822
(Forty-fifth); A-2(c) to Rule 24 Certificate dated April 7, 1993
in 70-7822 (Forty-sixth); A-3(d) to Rule 24 Certificate dated
June 4, 1993 in 70-7822 (Forth-seventh); and A-3(e) to Rule 24
Certificate dated December 21, 1993 in 70-7822 (Forty-eighth)).
(e) 2 -- Facility Lease No. 1, dated as of September 1, 1989, between
First National Bank of Commerce, as Owner Trustee, and LP&L
(4(c)-1 in Registration No. 33-30660).
(e) 3 -- Facility Lease No. 2, dated as of September 1, 1989, between
First National Bank of Commerce, as Owner Trustee, and LP&L
(4(c)-2 in Registration No. 33-30660).
(e) 4 -- Facility Lease No. 3, dated as of September 1, 1989, between
First National Bank of Commerce, as Owner Trustee, and LP&L
(4(c)-3 in Registration No. 33-30660).
MP&L
(f) 1 -- Mortgage and Deed of Trust, as amended by twenty-five
Supplemental Indentures (7(d) in 2-5437 (Mortgage); 7(b) in
2-7051 (First); 7(c) in 2-7763 (Second); 7(d) in 2-8484 (Third);
4(b)-4 in 2-10059 (Fourth); 2(b)-5 in 2-13942 (Fifth); A-11 to
Form U-1 in 70-4116 (Sixth); 2(b)-7 in 2-23084 (Seventh); 4(c)-9
in 2-24234 (Eighth); 2(b)-9(a) in 2-25502 (Ninth); A-11(a) to
Form U-1 in 70-4803 (Tenth); A-12(a) to Form U-1 in 70-4892
(Eleventh); A-13(a) to Form U-1 in 70-5165 (Twelfth); A-14(a) to
Form U-1 in 70-5286 (Thirteenth); A-15(a) to Form U-1 in 70-5371
(Fourteenth); A-16(a) to Form U-1 in 70-5417 (Fifteenth); A-17 to
Form U-1 in 70-5484 (Sixteenth); 2(a)-19 in 2-54234
(Seventeenth); C-1 to Rule 24 Certificate in 70-6619
(Eighteenth); A-2(c) to Rule 24 Certificate in 70-6672
(Nineteenth); A-2(d) to Rule 24 Certificate in 70-6672
(Twentieth); C-1(a) to Rule 24 Certificate in 70-6816
(Twenty-first); C-1(a) to Rule 24 Certificate in 70-7020
(Twenty-second); C-1(b) to Rule 24 Certificate in 70-7020
(Twenty-third); C-1(a) to Rule 24 Certificate in 70-7230
(Twenty-fourth); and A-2(a) to Rule 24 Certificate in 70-7419
(Twenty-fifth)).
(f) 2 -- Mortgage and Deed of Trust, dated as of February 1, 1988, as
amended by eight Supplemental Indentures (A-2(a)-2 to Rule 24
Certificate in 70-7461 (Mortgage); A-2(b)-2 in 70-7461 (First);
A-5(b) to Rule 24 Certificate in 70-7419 (Second); A-4(b) to
Rule 24 Certificate in 70-7554 (Third); A-1(b)-1 to Rule 24
Certificate in 70-7737 (Fourth); A-2(b) to Rule 24 Certificate
dated November 24, 1992 in 70-7914 (Fifth); A-2(e) to Rule 24
Certificate dated January 22, 1993 in 70-7914 (Sixth); A-2(g) to
Form U-1 in 70-7914 (Seventh); and A-2(i) to Rule 24 Certificate
dated November 10, 1993 in 70-7914 (Eighth)).
NOPSI
(g) 1 -- Mortgage and Deed of Trust, as amended by eleven Supplemental
Indentures (B-3 in 2-5411 (Mortgage); 7(b) in 2-7674 (First);
4(a)-2 in 2-10126 (Second); 4(b) in 2-12136 (Third); 2(b)-4 in
2-17959 (Fourth); 2(b)-5 in 2-19807 (Fifth); D to Rule 24
Certificate in 70-4023 (Sixth); 2(c) in 2-24523 (Seventh); 4(c)-9
in 2-26031 (Eighth); 2(a)-3 in 2-50438 (Ninth); 2(a)-3 in 2-62575
(Tenth); and A-2(b) to Rule 24 Certificate in 70-7262
(Eleventh)).
(g) 2 -- Mortgage and Deed of Trust, dated as of May 1, 1987, as amended
by four Supplemental Indentures (A-2(c) to Rule 24 Certificate in
70-7350 (Mortgage); A-5(b) to Rule 24 Certificate in 70-7350
(First); A-4(b) to Rule 24 Certificate in 70-7448 (Second); 4(f)4
to Form 10-K for the year ended December 31, 1992 in 0-5807
(Third); and 4(a) to Form 10-Q for the quarter ended September
30, 1993 in 0-5807 (Fourth)).
(10) Material Contracts
Entergy Corporation
(a) 1 -- Agreement, dated April 23, 1982, among certain System companies,
relating to System Planning and Development and Intra-System
Transactions (10(a)1 to Form 10-K for the fiscal year ended
December 31, 1982, in 1-3517).
(a) 2 -- Middle South Utilities System Agency Agreement, dated
December 11, 1970 (5(a)-2 in 2-41080).
(a) 3 -- Amendment, dated February 10, 1971, to Middle South Utilities
System Agency Agreement, dated December 11, 1970 (5(a)-4 in
2-41080).
(a) 4 -- Middle South Utilities System Agency Coordination Agreement,
dated December 11, 1970 (5(a)-3 in 2-41080).
(a) 5 -- Service Agreement with Entergy Services, dated as of April 1,
1963 (5(a)-5 in 2-41080).
(a) 6 -- Amendment, dated January 1, 1972, to Service Agreement with
Entergy Services (5(a)-6 in 2-43175).
(a) 7 -- Amendment, dated April 27, 1984, to Service Agreement with
Entergy Services (10(a)-7 to Form 10-K for the fiscal year ended
December 31, 1984, in 1-3517).
(a) 8 -- Amendment, dated August 1, 1988, to Service Agreement with
Entergy Services (10(a)-8 to Form 10-K for the fiscal year ended
December 31, 1988, in 1-3517).
(a) 9 -- Amendment, dated January 1, 1991, to Service Agreement with
Entergy Services (10(a)-9 to Form 10-K for the fiscal year ended
December 31, 1990, in 1-3517).
(a) 10 -- Availability Agreement, dated June 21, 1974, among System Energy
and certain other System companies (B to Rule 24 Certificate,
dated June 24, 1974, in 70-5399).
(a) 11 -- First Amendment to Availability Agreement, dated as of June 30,
1977 (B to Rule 24 Certificate, dated June 24, 1977, in 70-5399).
(a) 12 -- Second Amendment to Availability Agreement, dated as of June 15,
1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592).
(a) 13 -- Third Amendment to Availability Agreement, dated as of June 28,
1984 (B-13(a) to Rule 24 Certificate, dated July 6, 1984, in
70-6985).
(a) 14 -- Fourth Amendment to Availability Agreement, dated as of June 1,
1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399).
(a) 15 -- Fourteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(a) 16 -- Fifteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated June 5, 1986, in 70-7158).
(a) 17 -- Sixteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (C to
Rule 24 Certificate, dated June 4, 1986, in 70-7123).
(a) 18 -- Eighteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-2
to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(a) 19 -- Nineteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-3
to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(a) 20 -- Twentieth Assignment of Availability Agreement, Consent and
Agreement, dated as of November 15, 1987, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-1
to Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(a) 21 -- Twenty-first Assignment of Availability Agreement, Consent and
Agreement, dated as of December 1, 1987, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (C-2 to
Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(a) 22 -- Twenty-third Assignment of Availability Agreement, Consent and
Agreement, dated as of January 11, 1991, with Chemical Bank, as
Agent (B-3(a) to Rule 24 Certificate, dated January 23, 1991, in
70-7561).
(a) 23 -- Twenty-fourth Assignment of Availability Agreement, Consent and
Agreement, dated as of July 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to
Rule 24 Certificate, dated July 14, 1992, in 70-7946).
(a) 24 -- Twenty-fifth Assignment of Availability Agreement, Consent and
Agreement, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to
Rule 24 Certificate, dated November 2, 1992, in 70-7946).
(a) 25 -- Twenty-sixth Assignment of Availability Agreement, Consent and
Agreement, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(c) to
Rule 24 Certificate, dated November 2, 1992, in 70-7946).
(a) 26 -- Twenty-seventh Assignment of Availability Agreement, Consent and
Agreement, dated as of April 1, 1993, with United States Trust
Company of New York and Gerard F. Ganey as Trustees (B-2(d) to
Rule 24 Certificate dated May 4, 1993 in 70-7946).
(a) 27 -- Twenty-eighth Assignment of Availability Agreement, Consent and
Agreement, dated as of December 17, 1993, with Chemical Bank, as
Agent (B-2(a) to Rule 24 Certificate dated December 22, 1993 in
70-7561).
(a) 28 -- Capital Funds Agreement, dated June 21, 1974, between Entergy
Corporation and System Energy (C to Rule 24 Certificate, dated
June 24, 1974, in 70-5399).
(a) 29 -- First Amendment to Capital Funds Agreement, dated as of June 1,
1989 (B to Rule 24 Certificate, dated June 8, 1989, in 70-5399).
(a) 30 -- Fourteenth Supplementary Capital Funds Agreement and Assignment,
dated as of June 15, 1985, with Deposit Guaranty National Bank,
United States Trust Company of New York and Malcolm J. Hood, as
Trustees (B-4(b) to Rule 24 Certificate, dated July 31, 1985, in
70-7026).
(a) 31 -- Fifteenth Supplementary Capital Funds Agreement and Assignment,
dated as of May 1, 1986, with Deposit Guaranty National Bank,
United States Trust Company of New York and Malcolm J. Hood, as
Trustees (B-4(b) to Rule 24 Certificate, dated June 5, 1986, in
70-7158).
(a) 32 -- Sixteenth Supplementary Capital Funds Agreement and Assignment,
dated as of May 1, 1986, with United States Trust Company of New
York and Malcolm J. Hood, as Trustees (D to Rule 24 Certificate,
dated June 4, 1986, in 70-7123).
(a) 33 -- Eighteenth Supplementary Capital Funds Agreement and Assignment,
dated as of September 1, 1986, with United States Trust Company
of New York and Gerard F. Ganey, as Trustees (D-2 to Rule 24
Certificate, dated October 1, 1986, in 70-7272).
(a) 34 -- Nineteenth Supplementary Capital Funds Agreement and Assignment,
dated as of September 1, 1986, with United States Trust Company
of New York and Gerard F. Ganey, as Trustees (D-3 to Rule 24
Certificate, dated October 1, 1986, in 70-7272).
(a) 35 -- Twentieth Supplementary Capital Funds Agreement and Assignment,
dated as of November 15, 1987, with United States Trust Company
of New York and Gerard F. Ganey, as Trustees (D-1 to Rule 24
Certificate, dated December 1, 1987, in 70-7382).
(a) 36 -- Twenty-first Supplementary Capital Funds Agreement and
Assignment, dated as of December 1, 1987, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (D-2
to Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(a) 37 -- Twenty-third Supplementary Capital Funds Agreement and
Assignment, dated as of January 11, 1991, with Chemical Bank, as
agent (B-4(a) to Rule 24 Certificate, dated January 23, 1991, in
70-7561).
(a) 38 -- Twenty-fourth Supplementary Capital Funds Agreement and
Assignment, dated as of July 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-3(b) to
Rule 24 Certificate dated July 14, 1992 in 70-7946).
(a) 39 -- Twenty-fifth Supplementary Capital Funds Agreement and
Assignment, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-3(b) to
Rule 24 Certificate dated November 2, 1992 in 70-7946).
(a) 40 -- Twenty-sixth Supplementary Capital Funds Agreement and
Assignment, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-3(c) to
Rule 24 Certificate dated November 2, 1992 in 70-7946).
(a) 41 -- Twenty-seventh Supplementary Capital Funds Agreement and
Assignment, dated as of April 1, 1993, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-3(d) to
Rule 24 Certificate dated May 4, 1993 in 70-7946).
(a) 42 -- Twenty-eighth Supplementary Capital Funds Agreement and
Assignment, dated as of December 17, 1993, with Chemical Bank, as
Agent (B-3(a) to Rule 24 Certificate dated December 22, 1993 in
70-7561).
(a) 43 -- First Amendment to Supplementary Capital Funds Agreements and
Assignments, dated as of June 1, 1989, by and between Entergy
Corporation, System Energy, Deposit Guaranty National Bank,
United States Trust Company of New York and Gerard F. Ganey (C
to Rule 24 Certificate, dated June 8, 1989, in 70-7026).
(a) 44 -- First Amendment to Supplementary Capital Funds Agreements and
Assignments, dated as of June 1, 1989, by and between Entergy
Corporation, System Energy, United States Trust Company of New
York and Gerard F. Ganey (C to Rule 24 Certificate, dated June
8, 1989, in 70-7123).
(a) 45 -- First Amendment to Supplementary Capital Funds Agreement and
Assignment, dated as of June 1, 1989, by and between Entergy
Corporation, System Energy and Chemical Bank (C to Rule 24
Certificate, dated June 8, 1989, in 70-7561).
+(a) 46 -- Agreement between Entergy Corporation and Edwin Lupberger
(10(a)-42 to Form 10-K for the fiscal year ended December 31,
1985, in 1-3517).
(a) 47 -- Reallocation Agreement, dated as of July 28, 1981, among System
Energy and certain other System companies (B-1(a) in 70-6624).
(a) 48 -- Joint Construction, Acquisition and Ownership Agreement, dated as
of May 1, 1980, between System Energy and SMEPA (B-1(a) in
70-6337), as amended by Amendment No. 1, dated as of May 1, 1980
(B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31,
1980 (1 to Rule 24 Certificate, dated October 30, 1981, in
70-6337).
(a) 49 -- Operating Agreement dated as of May 1, 1980, between System
Energy and SMEPA (B(2)(a) in 70-6337).
(a) 50 -- Assignment, Assumption and Further Agreement No. 1, dated as of
December 1, 1988, among System Energy, Meridian Trust Company and
Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate,
dated January 9, 1989, in 70-7561).
(a) 51 -- Assignment, Assumption and Further Agreement No. 2, dated as of
December 1, 1988, among System Energy, Meridian Trust Company and
Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate,
dated January 9, 1989, in 70-7561).
(a) 52 -- Substitute Power Agreement, dated as of May 1, 1980, among MP&L,
System Energy and SMEPA (B(3)(a) in 70-6337).
(a) 53 -- Grand Gulf Unit No. 2 Supplementary Agreement, dated as of
February 7, 1986, between System Energy and SMEPA (10(aaa) in
33-4033).
(a) 54 -- Compromise and Settlement Agreement, dated June 4, 1982, between
Texaco, Inc. and LP&L (28(a) to Form 8-K, dated June 4, 1982, in
1-3517).
+(a) 55 -- Post-Retirement Plan (10(a)37 to Form 10-K for the fiscal year
ended December 31, 1983, in 1-3517).
(a) 56 -- Unit Power Sales Agreement, dated as of June 10, 1982, between
System Energy and AP&L, LP&L, MP&L and NOPSI (10(a)-39 to Form
10-K for the fiscal year ended December 31, 1982, in 1-3517).
(a) 57 -- First Amendment to Unit Power Sales Agreement, dated as of June
28, 1984, between System Energy and AP&L, LP&L, MP&L and NOPSI
(19 to Form 10-Q for the quarter ended September 30, 1984, in
1-3517).
(a) 58 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(a) 59 -- Middle South Utilities Inc. and Subsidiary Companies Intercompany
Income Tax Allocation Agreement, dated April 28, 1988 (Exhibit
D-1 to Form U5S for the year ended December 31, 1987).
(a) 60 -- First Amendment to Tax Allocation Agreement, dated January 1,
1990 (D-2 to Form U5S for the year ended December 31, 1989).
(a) 61 -- Guaranty Agreement between Entergy Corporation and AP&L, dated as
of September 20, 1990 (B-1(a) to Rule 24 Certificate, dated
September 27, 1990, in 70-7757).
(a) 62 -- Guarantee Agreement between Entergy Corporation and LP&L, dated
as of September 20, 1990 (B-2(a) to Rule 24 Certificate, dated
September 27, 1990, in 70-7757).
(a) 63 -- Guarantee Agreement between Entergy Corporation and System
Energy, dated as of September 20, 1990 (B-3(a) to Rule 24
Certificate, dated September 27, 1990, in 70- 7757).
(a) 64 -- Loan Agreement between Entergy Operations and Entergy
Corporation, dated as of September 20, 1990 (B-12(b) to Rule 24
Certificate, dated June 15, 1990, in 70-7679).
(a) 65 -- Loan Agreement between Entergy Power and Entergy Corporation,
dated as of August 28, 1990 (A-4(b) to Rule 24 Certificate, dated
September 6, 1990, in 70-7684).
(a) 66 -- Loan Agreement between Entergy Corporation and Entergy Systems
and Service, Inc., dated as of December 29, 1992 (A-4(b) to Rule
24 Certificate in 70-7947).
+(a) 67 -- Executive Financial Counseling Program of Entergy Corporation and
Subsidiaries (10(a) 52 to Form 10-K for the year ended
December 31, 1989, in 1-3517).
+(a) 68 -- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form 10-K
for the year ended December 31, 1989, in 1-3517).
+(a) 69 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries
(A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831).
+(a) 70 -- Retired Outside Director Benefit Plan (10(a)63 to Form 10-K for
the year ended December 31, 1991, in 1-3517).
+(a) 71 -- Agreement between Entergy Corporation and Jerry D. Jackson.
(10(a) 67 to Form 10-K for the year ended December 31, 1992 in 1-
3517).
+(a) 72 -- Agreement between Entergy Services, Inc., a subsidiary of
Entergy Corporation, and Gerald D. McInvale (10(a) 68 to Form
10-K for the year ended December 31, 1992 in 1-3517).
+(a) 73 -- Supplemental Retirement Plan (10(a) 69 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(a) 74 -- Defined Contribution Restoration Plan of Entergy Corporation and
Subsidiaries (10(a)53 to Form 10-K for the year ended
December 31, 1989 in 1-3517).
+(a) 75 -- Amendment No. 1 to the Equity Ownership Plan of Entergy
Corporation and Subsidiaries (10(a) 71 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(a) 76 -- Executive Disability Plan of Entergy Corporation and Subsidiaries
(10(a) 72 to Form 10-K for the year ended December 31, 1992 in 1-
3517).
+(a) 77 -- Executive Medical Plan of Entergy Corporation and Subsidiaries
(10(a) 73 to Form 10-K for the year ended December 31, 1992 in 1-
3517).
+(a) 78 -- Stock Plan for Outside Directors of Entergy Corporation and
Subsidiaries, as amended (10(a) 74 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(a) 79 -- Summary Description of Private Ownership Vehicle Plan of Entergy
Corporation and Subsidiaries (10(a) 75 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
(a) 80 -- Agreement and Plan of Reorganization Between Entergy Corporation
and Gulf States Utilities Company, dated June 5, 1992 (1 to
Current Report on Form 8-K dated June 5, 1992 in 1-3517).
+*(a)81 -- Amendment to Defined Contribution Restoration Plan of
Entergy Corporation and Subsidiaries.
+*(a)82 -- System Executive Retirement Plan.
System Energy
(b) 1 -- Availability Agreement, dated June 21, 1974, among System Energy
and certain other System companies (B to Rule 24 Certificate,
dated June 24, 1974, in 70-5399).
(b) 2 -- First Amendment to Availability Agreement, dated as of June 30,
1977 (B to Rule 24 Certificate, dated June 24, 1977, in 70-5399).
(b) 3 -- Second Amendment to Availability Agreement, dated as of June 15,
1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592).
(b) 4 -- Third Amendment to Availability Agreement, dated as of June 28,
1984 (B-13(a) to Rule 24 Certificate, dated July 6, 1984, in
70-6985).
(b) 5 -- Fourth Amendment to Availability Agreement, dated as of June 1,
1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399).
(b) 6 -- Fourteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(b) 7 -- Fifteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York, Malcolm J. Hood, and Deposit Guaranty
National Bank, as Trustees (B-3(b) to Rule 24 Certificate, dated
June 5, 1986, in 70-7158).
(b) 8 -- Sixteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (C to
Rule 24 Certificate, dated June 4, 1986, in 70-7123).
(b) 9 -- Eighteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-2
to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(b) 10 -- Nineteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-3
to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(b) 11 -- Twentieth Assignment of Availability Agreement, Consent and
Agreement, dated as of November 15, 1987, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-1
to Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(b) 12 -- Twenty-first Assignment of Availability Agreement, Consent and
Agreement, dated as of December 1, 1987, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (C-2 to
Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(b) 13 -- Twenty-third Assignment of Availability Agreement, Consent and
Agreement, dated as of January 11, 1991, with Chemical Bank as
Agent (B-3(a) to Rule 24 Certificate, dated January 23, 1991, in
70-7561).
(b) 14 -- Twenty-fourth Assignment of Availability Agreement, Consent and
Agreement, dated as of July 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to
Rule 24 Certificate, dated July 14, 1992, in 70-7946).
(b) 15 -- Twenty-fifth Assignment of Availability Agreement, Consent and
Agreement, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to
Rule 24 Certificate, dated November 2, 1992, in 70-7946).
(b) 16 -- Twenty-sixth Assignment of Availability Agreement, Consent and
Agreement, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(c) to
Rule 24 Certificate, dated November 2, 1992, in 70-7946).
(b) 17 -- Twenty-seventh Assignment of Availability Agreement, Consent and
Agreement, dated as of April 1, 1993, with United States Trust
Company of New York and Gerard F. Ganey as Trustees (B-2(d) to
Rule 24 Certificate dated May 4, 1993 in 70-7946).
(b) 18 -- Twenty-eighth Assignment of Availability Agreement, Consent and
Agreement, dated as of December 17, 1993, with Chemical Bank, as
Agent (B-2(a) to Rule 24 Certificate dated December 22, 1993 in
70-7561).
(b) 19 -- Capital Funds Agreement, dated June 21, 1974, between Entergy
Corporation and System Energy (C to Rule 24 Certificate, dated
June 24, 1974, in 70-5399).
(b) 20 -- First Amendment to Capital Funds Agreement, dated as of June 1,
1989 (B to Rule 24 Certificate, dated June 8, 1989, in 70-5399).
(b) 21 -- Fourteenth Supplementary Capital Funds Agreement and Assignment,
dated as of June 15, 1985, with Deposit Guaranty National Bank,
United States Trust Company of New York and Malcolm J. Hood, as
Trustees (B-4(b) to Rule 24 Certificate, dated July 31, 1985, in
70-7026).
(b) 22 -- Fifteenth Supplementary Capital Funds Agreement and Assignment,
dated as of May 1, 1986, with Deposit Guaranty National Bank,
United States Trust Company of New York and Malcolm J. Hood, as
Trustees (B-4(b) to Rule 24 Certificate, dated June 5, 1986, in
70-7158).
(b) 23 -- Sixteenth Supplementary Capital Funds Agreement and Assignment,
dated as of May 1, 1986, with United States Trust Company of New
York and Malcolm J. Hood, as Trustees (D to Rule 24 Certificate,
dated June 4, 1986, in 70-7123).
(b) 24 -- Eighteenth Supplementary Capital Funds Agreement and Assignment,
dated as of September 1, 1986, with United States Trust Company
of New York and Gerard F. Ganey, as Trustees (D-2 to Rule 24
Certificate, dated October 1, 1986, in 70-7272).
(b) 25 -- Nineteenth Supplementary Capital Funds Agreement and Assignment,
dated as of September 1, 1986, with United States Trust Company
of New York and Gerard F. Ganey, as Trustees (D-3 to Rule 24
Certificate, dated October 1, 1986, in 70-7272).
(b) 26 -- Twentieth Supplementary Capital Funds Agreement and Assignment,
dated as of November 15, 1987, with United States Trust Company
of New York and Gerard F. Ganey, as Trustees (D-1 to Rule 24
Certificate, dated December 1, 1987, in 70-7382).
(b) 27 -- Twenty-first Supplementary Capital Funds Agreement and
Assignment, dated as of December 1, 1987, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (D-2
to Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(b) 28 -- Twenty-third Supplementary Capital Funds Agreement and
Assignment, dated as of January 11, 1991, with Chemical Bank as
Agent (B-4(a) to Rule 24 Certificate, dated January 23, 1991, in
70-7561).
(b) 29 -- Twenty-fourth Supplementary Capital Funds Agreement and
Assignment, dated as of July 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-3(b) to
Rule 24 Certificate dated July 14, 1992, in 70-7946).
(b) 30 -- Twenty-fifth Supplementary Capital Funds Agreement and
Assignment, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-3(b) to
Rule 24 Certificate dated November 2, 1992, in 70-7946).
(b) 31 -- Twenty-sixth Supplementary Capital Funds Agreement and
Assignment, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-3(c) to
Rule 24 Certificate dated November 2, 1992, in 70-7946).
(b) 32 -- Twenty-seventh Supplementary Capital Funds Agreement and
Assignment, dated as of April 1, 1993, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-3(d) to
Rule 24 Certificate dated May 4, 1993 in 70-7946).
(b) 33 -- Twenty-eighth Supplementary Capital Funds Agreement and
Assignment, dated as of December 17, 1993, with Chemical Bank, as
Agent (B-3(a) to Rule 24 Certificate dated December 22, 1993 in
70-7561).
(b) 34 -- First Amendment to Supplementary Capital Funds Agreements and
Assignments, dated as of June 1, 1989, by and between Entergy
Corporation, System Energy, Deposit Guaranty National Bank,
United States Trust Company of New York and Gerard F. Ganey, as
Trustees (C to Rule 24 Certificate, dated June 8, 1989, in
70-7026).
(b) 35 -- First Amendment to Supplementary Capital Funds Agreements and
Assignments, dated as of June 1, 1989, by and between Entergy
Corporation, System Energy, United States Trust Company of New
York and Gerard F. Ganey, as Trustees (C to Rule 24 Certificate,
dated June 8, 1989, in 70-7123).
(b) 36 -- First Amendment to Supplementary Capital Funds Agreement and
Assignment, dated as of June 1, 1989, by and between Entergy
Corporation, System Energy and Chemical Bank (C to Rule 24
Certificate, dated June 8, 1989, in 70-7561).
(b) 37 -- Reallocation Agreement, dated as of July 28, 1981, among System
Energy and certain other System companies (B-1(a) in 70-6624).
(b) 38 -- Joint Construction, Acquisition and Ownership Agreement, dated as
of May 1, 1980, between System Energy and SMEPA (B-1(a) in
70-6337), as amended by Amendment No. 1, dated as of May 1, 1980
(B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31,
1980 (1 to Rule 24 Certificate, dated October 30, 1981, in
70-6337).
(b) 39 -- Operating Agreement, dated as of May 1, 1980, between System
Energy and SMEPA (B(2)(a) in 70-6337).
(b) 40 -- Assignment, Assumption and Further Agreement No. 1, dated as of
December 1, 1988, among System Energy, Meridian Trust Company and
Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate,
dated January 9, 1989, in 70-7561).
(b) 41 -- Assignment, Assumption and Further Agreement No. 2, dated as of
December 1, 1988, among System Energy, Meridian Trust Company and
Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate,
dated January 9, 1989, in 70-7561).
(b) 42 -- Substitute Power Agreement, dated as of May 1, 1980, among MP&L,
System Energy and SMEPA (B(3)(a) in 70-6337).
(b) 43 -- Grand Gulf Unit No. 2 Supplementary Agreement, dated as of
February 7, 1986, between System Energy and SMEPA (10(aaa) in
33-4033).
(b) 44 -- Unit Power Sales Agreement, dated as of June 10, 1982, between
System Energy and AP&L, LP&L, MP&L and NOPSI (10(a)-39 to
Form 10-K for the fiscal year ended December 31, 1982, in
1-3517).
(b) 45 -- First Amendment to the Unit Power Sales Agreement, dated as of
June 28, 1984, between System Energy and AP&L, LP&L, MP&L and
NOPSI (19 to Form 10-Q for the quarter ended September 30, 1984,
in 1-3517).
(b) 46 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(b) 47 -- Fuel Lease, dated as of March 3, 1989, between River Fuel Funding
Company #3, Inc. and System Energy (B-1(b) to Rule 24
Certificate, dated March 3, 1989, in 70-7604).
(b) 48 -- Sales Agreement, dated as of June 21, 1974, between System Energy
and MP&L (D to Rule 24 Certificate, dated June 26, 1974, in
70-5399).
(b) 49 -- Service Agreement, dated as of June 21, 1974, between System
Energy and MP&L (E to Rule 24 Certificate, dated June 26, 1974,
in 70-5399).
(b) 50 -- Partial Termination Agreement, dated as of December 1, 1986,
between System Energy and MP&L (A-2 to Rule 24 Certificate, dated
January 8, 1987, in 70-5399).
(b) 51 -- Middle South Utilities, Inc. and Subsidiary Companies
Intercompany Income Tax Allocation Agreement, dated April 28,
1988 (D-1 to Form U5S for the year ended December 31, 1987).
(b) 52 -- First Amendment to Tax Allocation Agreement, dated January 1,
1990 (D-2 to Form U5S for the year ended December 31, 1989).
(b) 53 -- Service Agreement with Entergy Services, dated as of July 16,
1974, as amended (10(b)-43 to Form 10-K for the fiscal year ended
December 31, 1988, in 1-9067).
(b) 54 -- Amendment, dated January 1, 1991, to Service Agreement with
Entergy Services (10(b)-45 to Form 10-K for the fiscal year ended
December 31, 1990, in 1-9067).
(b) 55 -- Operating Agreement between Entergy Operations and System Energy,
dated as of June 6, 1990 (B-3(b) to Rule 24 Certificate, dated
June 15, 1990, in 70-7679).
(b) 56 -- Guarantee Agreement between Entergy Corporation and System
Energy, dated as of September 20, 1990 (B-3(a) to Rule 24
Certificate, dated September 27, 1990, in 70-7757).
+(b) 57 -- Agreement between System Energy and Donald C. Hintz (10(b)47 to
Form 10-K for the year ended December 31, 1991, in 1-9067).
+(b) 58 -- Agreement between Entergy Corporation and Edwin Lupberger
(10(a)-42 to Form 10-K for the year ended December 31, 1985 in
1-3517).
+(b) 59 -- Agreement between Entergy Services and Gerald D. McInvale
(10(a)-69 to Form 10-K for the year ended December 31, 1992 in
1-3517).
AP&L
(c) 1 -- Agreement, dated April 23, 1982, among AP&L and certain other
System companies, relating to System Planning and Development and
Intra-System Transactions (10(a) 1 to Form 10-K for the fiscal
year ended December 31, 1982, in 1-3517).
(c) 2 -- Middle South Utilities System Agency Agreement, dated December
11, 1970 (5(a)2 in 2-41080).
(c) 3 -- Amendment, dated February 10, 1971, to Middle South Utilities
System Agency Agreement, dated December 11, 1970 (5(a)-4 in
2-41080).
(c) 4 -- Middle South Utilities System Agency Coordination Agreement,
dated December 11, 1970 (5(a)-3 in 2-41080).
(c) 5 -- Service Agreement with Entergy Services, dated as of April 1,
1963 (5(a)-5 in 2-41080).
(c) 6 -- Amendment, dated January 1, 1972, to Service Agreement with
Entergy Services (5(a)- 6 in 2-43175).
(c) 7 -- Amendment, dated April 27, 1984, to Service Agreement, with
Entergy Services (10(a)- 7 to Form 10-K for the fiscal year ended
December 31, 1984, in 1-3517).
(c) 8 -- Amendment, dated August 1, 1988, to Service Agreement with
Entergy Services (10(c)- 8 to Form 10-K for the fiscal year ended
December 31, 1988, in 1-10764).
(c) 9 -- Amendment, dated January 1, 1991, to Service Agreement with
Entergy Services (10(c)-9 to Form 10-K for the fiscal year ended
December 31, 1990, in 1-10764).
(c) 10 -- Availability Agreement, dated June 21, 1974, among System Energy
and certain other System companies (B to Rule 24 Certificate,
dated June 24, 1974, in 70-5399).
(c) 11 -- First Amendment to Availability Agreement, dated June 30, 1977 (B
to Rule 24 Certificate, dated June 24, 1977, in 70-5399).
(c) 12 -- Second Amendment to Availability Agreement, dated as of June 15,
1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592).
(c) 13 -- Third Amendment to Availability Agreement, dated as of June 28,
1984 (B-13(a) to Rule 24 Certificate, dated July 6, 1984, in
70-6985).
(c) 14 -- Fourth Amendment to Availability Agreement, dated as of June 1,
1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399).
(c) 15 -- Fourteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(c) 16 -- Fifteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with Deposit Guaranty
National Bank, United States Trust Company of New York, and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated June 5, 1986, in 70-7158).
(c) 17 -- Sixteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (C to Rule
24 Certificate, dated June 4, 1986, in 70-7123).
(c) 18 -- Eighteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-2
to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(c) 19 -- Nineteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-3
to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(c) 20 -- Twentieth Assignment of Availability Agreement, Consent and
Agreement, dated as of November 15, 1987, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-1
to Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(c) 21 -- Twenty-first Assignment of Availability Agreement, Consent and
Agreement, dated as of December 1, 1987, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (C-2 to
Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(c) 22 -- Twenty-third Assignment of Availability Agreement, Consent and
Agreement, dated as of January 11, 1991, with Chemical Bank, as
Agent (B-3(a) to Rule 24 Certificate, dated January 23, 1991, in
70-7561).
(c) 23 -- Twenty-fourth Assignment of Availability Agreement, Consent and
Agreement, dated as of July 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to
Rule 24 Certificate, dated July 14, 1992, in 70-7946).
(c) 24 -- Twenty-fifth Assignment of Availability Agreement, Consent and
Agreement, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to
Rule 24 Certificate, dated November 2, 1992, in 70-7946).
(c) 25 -- Twenty-sixth Assignment of Availability Agreement, Consent and
Agreement, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(c) to
Rule 24 Certificate, dated November 2, 1992, in 70-7946).
(c) 26 -- Twenty-seventh Assignment of Availability Agreement, Consent and
Agreement, dated as of April 1, 1993, with United States Trust
Company of New York and Gerard F. Ganey as Trustees (B-2(d) to
Rule 24 Certificate dated May 4, 1993 in 70-7946).
(c) 27 -- Twenty-eighth Assignment of Availability Agreement, Consent and
Agreement, dated as of December 17, 1993, with Chemical Bank, as
Agent (B-2(a) to Rule 24 Certificate dated December 22, 1993 in
70-7561).
(c) 28 -- Agreement, dated August 20, 1954, between AP&L and the United
States of America (SPA)(13(h) in 2-11467).
(c) 29 -- Amendment, dated April 19, 1955, to the United States of America
(SPA) Contract, dated August 20, 1954 (5(d)-2 in 2-41080).
(c) 30 -- Amendment, dated January 3, 1964, to the United States of America
(SPA) Contract, dated August 20, 1954 (5(d)-3 in 2-41080).
(c) 31 -- Amendment, dated September 5, 1968, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-4 in
2-41080).
(c) 32 -- Amendment, dated November 19, 1970, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-5 in
2-41080).
(c) 33 -- Amendment, dated July 18, 1961, to the United States of America
(SPA) Contract, dated August 20, 1954 (5(d)-6 in 2-41080).
(c) 34 -- Amendment, dated December 27, 1961, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-7 in
2-41080).
(c) 35 -- Amendment, dated January 25, 1968, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-8 in
2-41080).
(c) 36 -- Amendment, dated October 14, 1971, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-9 in
2-43175).
(c) 37 -- Amendment, dated January 10, 1977, to the United States of
America (SPA) Contract, dated August 20, 1954 (5(d)-10 in
2-60233).
(c) 38 -- Agreement, dated May 14, 1971, between AP&L and the United States
of America (SPA) (5(e) in 2-41080).
(c) 39 -- Amendment, dated January 10, 1977, to the United States of
America (SPA) Contract, dated May 14, 1971 (5(e)-1 in 2-60233).
(c) 40 -- Contract, dated May 28, 1943, Amendment to Contract, dated July
21, 1949, and Supplement to Amendment to Contract, dated December
30, 1949, between AP&L and McKamie Gas Cleaning Company;
Agreements, dated as of September 30, 1965, between AP&L and
former stockholders of McKamie Gas Cleaning Company; and Letter
Agreement, dated June 22, 1966, by Humble Oil & Refining Company
accepted by AP&L on June 24, 1966 (5(k)-7 in 2-41080).
(c) 41 -- Agreement, dated April 3, 1972, between Entergy Services and Gulf
United Nuclear Fuels Corporation (5(l)-3 in 2-46152).
(c) 42 -- Fuel Lease, dated as of December 22, 1988, between River Fuel
Trust #1 and AP&L (B-1(b) to Rule 24 Certificate in 70-7571).
(c) 43 -- White Bluff Operating Agreement, dated June 27, 1977, among AP&L
and Arkansas Electric Cooperative Corporation and City Water and
Light Plant of the City of Jonesboro, Arkansas (B-2(a) to Rule 24
Certificate, dated June 30, 1977, in 70-6009).
(c) 44 -- White Bluff Ownership Agreement, dated June 27, 1977, among AP&L
and Arkansas Electric Cooperative Corporation and City Water and
Light Plant of the City of Jonesboro, Arkansas (B-1(a) to Rule 24
Certificate, dated June 30, 1977, in 70-6009).
(c) 45 -- Agreement, dated June 29, 1979, between AP&L and City of Conway,
Arkansas (5(r)-3 in 2-66235).
(c) 46 -- Transmission Agreement, dated August 2, 1977, between AP&L and
City Water and Light Plant of the City of Jonesboro, Arkansas
(5(r)-3 in 2-60233).
(c) 47 -- Power Coordination, Interchange and Transmission Service
Agreement, dated as of June 27, 1977, between Arkansas Electric
Cooperative Corporation and AP&L (5(r)-4 in 2-60233).
(c) 48 -- Independence Steam Electric Station Operating Agreement, dated
July 31, 1979, among AP&L and Arkansas Electric Cooperative
Corporation and City Water and Light Plant of the City of
Jonesboro, Arkansas and City of Conway, Arkansas (5(r)-6 in
2-66235).
(c) 49 -- Amendment, dated December 4, 1984, to the Independence Steam
Electric Station Operating Agreement (10(c) 51 to Form 10-K for
the fiscal year ended December 31, 1984, in 1-10764).
(c) 50 -- Independence Steam Electric Station Ownership Agreement, dated
July 31, 1979, among AP&L and Arkansas Electric Cooperative
Corporation and City Water and Light Plant of the City of
Jonesboro, Arkansas and City of Conway, Arkansas (5(r)-7 in
2-66235).
(c) 51 -- Amendment, dated December 28, 1979, to the Independence Steam
Electric Station Ownership Agreement (5(r)-7(a) in 2-66235).
(c) 52 -- Amendment, dated December 4, 1984, to the Independence Steam
Electric Station Ownership Agreement (10(c) 54 to Form 10-K for
the fiscal year ended December 31, 1984, in 1-10764).
(c) 53 -- Owner's Agreement, dated November 28, 1984, among AP&L, MP&L,
other co-owners of the Independence Station (10(c) 55 to Form
10-K for the fiscal year ended December 31, 1984, in 1-10764).
(c) 54 -- Consent, Agreement and Assumption, dated December 4, 1984, among
AP&L, MP&L, other co-owners of the Independence Station and
United States Trust Company of New York, as Trustee (10(c) 56 to
Form 10-K for the fiscal year ended December 31, 1984, in
1-10764).
(c) 55 -- Power Coordination, Interchange and Transmission Service
Agreement, dated as of July 31, 1979, between AP&L and City Water
and Light Plant of the City of Jonesboro, Arkansas (5(r)-8 in
2-66235).
(c) 56 -- Power Coordination, Interchange and Transmission Agreement, dated
as of June 29, 1979, between City of Conway, Arkansas and AP&L
(5(r)-9 in 2-66235).
(c) 57 -- Agreement, dated June 21, 1979, between AP&L and Reeves E.
Ritchie ((10)(b)-90 to Form 10-K for the fiscal year ended
December 31, 1980, in 1-10764).
(c) 58 -- Agreement, dated as of January 30, 1981, between AP&L and MP&L,
relating to the Independence Station (B-3 in 70-6614).
(c) 59 -- Amendment No. 1, dated as of June 30, 1981, to Agreement, dated
as of January 30, 1981, between AP&L and MP&L, relating to the
Independence Station (10(b) in 2-73310).
(c) 60 -- Reallocation Agreement, dated as of July 28, 1981, among System
Energy and certain other System companies (B-1(a) in 70-6624).
+(c) 61 -- Post-Retirement Plan (10(b) 55 to Form 10-K for the fiscal year
ended December 31, 1983, in 1-10764).
(c) 62 -- Unit Power Sales Agreement, dated as of June 10, 1982, between
System Energy and AP&L, LP&L, MP&L, and NOPSI (10(a) 39 to Form
10-K for the fiscal year ended December 31, 1982, in 1-3517).
(c) 63 -- First Amendment to Unit Power Sales Agreement, dated as of June
28, 1984, between System Energy, AP&L, LP&L, MP&L, and NOPSI (19
to Form 10-Q for the quarter ended September 30, 1984, in
1-3517).
(c) 64 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(c) 65 -- Contract For Disposal of Spent Nuclear Fuel and/or High-Level
Radioactive Waste, dated June 30, 1983, among the DOE, System
Fuels and AP&L (10(b)-57 to Form 10-K for the fiscal year ended
December 31, 1983, in 1-10764).
(c) 66 -- Middle South Utilities, Inc. and Subsidiary Companies
Intercompany Income Tax Allocation Agreement, dated April 28,
1988 (D-1 to Form U5S for the year ended December 31, 1987).
(c) 67 -- First Amendment to Tax Allocation Agreement, dated January 1,
1990 (D-2 to Form U5S for the year ended December 31, 1989).
(c) 68 -- Assignment of Coal Supply Agreement, dated December 1, 1987,
between System Fuels and AP&L (B to Rule 24 letter filing, dated
November 10, 1987, in 70-5964).
(c) 69 -- Coal Supply Agreement, dated December 22, 1976, between System
Fuels and Antelope Coal Company (B-1 in 70-5964), as amended by
First Amendment (A to Rule 24 Certificate in 70-5964); Second
Amendment (A to Rule 24 letter filing, dated December 16, 1983,
in 70-5964); and Third Amendment (A to Rule 24 letter filing,
dated November 10, 1987 in 70-5964).
(c) 70 -- Operating Agreement between Entergy Operations and AP&L, dated as
of June 6, 1990 (B-1(b) to Rule 24 Certificate, dated June 15,
1990, in 70-7679).
(c) 71 -- Guaranty Agreement between Entergy Corporation and AP&L, dated as
of September 20, 1990 (B-1(a) to Rule 24 Certificate, dated
September 27, 1990, in 70-7757).
(c) 72 -- Agreement for Purchase and Sale of Independence Unit 2 between
AP&L and Entergy Power, dated as of August 28, 1990 (B-3(c) to
Rule 24 Certificate, dated September 6, 1990, in 70-7684).
(c) 73 -- Agreement for Purchase and Sale of Ritchie Unit 2 between AP&L
and Entergy Power, dated as of August 28, 1990 (B-4(d) to Rule 24
Certificate, dated September 6, 1990, in 70-7684).
(c) 74 -- Ritchie Steam Electric Station Unit No. 2 Operating Agreement
between AP&L and Entergy Power, dated as of August 28, 1990
(B-5(a) to Rule 24 Certificate, dated September 6, 1990, in
70-7684).
(c) 75 -- Ritchie Steam Electric Station Unit No. 2 Ownership Agreement
between AP&L and Entergy Power, dated as of August 28, 1990
(B-6(a) to Rule 24 Certificate, dated September 6, 1990, in
70-7684).
(c) 76 -- Power Coordination, Interchange and Transmission Service
Agreement between Entergy Power and AP&L, dated as of August 28,
1990 (10(c)-71 to Form 10-K for the fiscal year ended
December 31, 1990, in 1-10764).
+(c) 77 -- Executive Financial Counseling Program of Entergy Corporation and
Subsidiaries (10(a)52 to Form 10-K for the year ended December
31, 1989, in 1-3517).
+(c) 78 -- Entergy Corporation Annual Incentive Plan (10(a)54 to Form 10-K
for the year ended December 31, 1989, in 1-3517).
+(c) 79 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries
(A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831).
+(c) 80 -- Agreement between Arkansas Power & Light Company and R.
Drake Keith. (10(c) 78 to Form 10-K for the year ended December
31, 1992 in 1-10764).
+(c) 81 -- Supplemental Retirement Plan (10(a)69 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(c) 82 -- Defined Contribution Restoration Plan of Entergy Corporation and
Subsidiaries (10(a)53 to Form 10-K for the year ended
December 31, 1989 in 1-3517).
+(c) 83 -- Amendment No. 1 to the Equity Ownership Plan of Entergy
Corporation and Subsidiaries (10(a)71 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(c) 84 -- Executive Disability Plan of Entergy Corporation and Subsidiaries
(10(a)72 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(c) 85 -- Executive Medical Plan of Entergy Corporation and Subsidiaries
(10(a)73 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(c) 86 -- Stock Plan for Outside Directors of Entergy Corporation and
Subsidiaries, as amended (10(a)74 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(c) 87 -- Summary Description of Private Ownership Vehicle Plan of Entergy
Corporation and Subsidiaries (10(a)75 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(c) 88 -- Agreement between Entergy Corporation and Edwin Lupberger
(10(a)-42 to Form 10-K for the year ended December 31, 1985 in
1-3517).
+(c) 89 -- Agreement between Entergy Corporation and Jerry D. Jackson
(10(a)-68 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(c) 90 -- Agreement between Entergy Services and Gerald D. McInvale
(10(a)-69 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(c) 91 -- Agreement between System Energy and Donald C. Hintz (10(b)-47 to
Form 10-K for the year ended December 31, 1991 in 1-9067).
+(c) 92 -- Summary Description of Retired Outside Director Benefit Plan.
(10(c) 90 to Form 10-K for the year ended December 31, 1992 in 1-
10764).
+(c) 93 -- Amendment to Defined Contribution Restoration Plan of Entergy
Corporation and Subsidiaries (10(a) 81 to Form 10-K for the year
ended December 31, 1993 in 1-11299).
+(c) 94 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for the
year ended December 31, 1993 in 1-11299).
GSU
(d) 1 -- Guaranty Agreement, dated as of December 1, 1971, relating to
Pollution Control Revenue Bonds of the Industrial Development
Board of the Parish of Calcasieu, Inc. (Louisiana) (5-26 to
Registration No. 2-52878).
(d) 2 -- Guaranty Agreement, dated July 1, 1976, between GSU and the
Parish of Iberville, Louisiana (C and D to Form 8-K, dated August
6, 1976 in 1-2703).
(d) 3 -- Lease of Railroad Equipment, dated as of December 1, 1981,
between The Connecticut Bank and Trust Company as Lessor and GSU
as Lessee and First Supplement, dated as of December 31, 1981,
relating to 605 One Hundred-Ton Unit Train Steel Coal Porter Cars
(4-12 to Form 10-K for the year ended December 31, 1981 in 1-
2703).
(d) 4 -- Guaranty Agreement, dated August 1, 1992, between GSU and
Hibernia National Bank, relating to Pollution Control Revenue
Refunding Bonds of the Industrial Development Board of the Parish
of Calcasieu, Inc. (Louisiana) (10-1 to Form 10-K for the year
ended December 31, 1992 in 1-2703).
(d) 5 -- Guaranty Agreement, dated January 1, 1993, between GSU and
Hancock Bank of Louisiana, relating to Pollution Control Revenue
Refunding Bonds of the Parish of Pointe Coupee (Louisiana) (10-2
to Form 10-K for the year ended December 31, 1992 in 1-2703).
(d) 6 -- Deposit Agreement, dated as of December 1, 1983 between GSU,
Morgan Guaranty Trust Co. as Depositary and the Holders of
Despositary Receipts, relating to the Issue of 900,000 Depositary
Preferred Shares, each representing 1/2 share of Adjustable Rate
Cumulative Preferred Stock, Series E-$100 Par Value (4-17 to Form
10-K for the year ended December 31, 1983 in 1-2703).
(d) 7 -- Letter of Credit Agreement between GSU and Bankers Trust Company
relating to Pollution Control Revenue Bonds of the Parish of West
Feliciana, State of Louisiana, Series 1984A (4-18 to Form 10-K
for the year ended December 31, 1984 in 1-2703).
(d) 8 -- Letter of Credit and Reimbursement Agreement, dated December 27,
1985, between GSU and Westpack Banking Corporation relating to
Variable Rate Demand Pollution Control Revenue Bonds of the
Parish of West Feliciana, State of Louisiana, Series 1985-D (4-26
to Form 10-K for the year ended December 31, 1985 in 1-2703) and
Letter Agreement amending same dated October 20, 1992 (10-3 to
Form 10-K for the year ended December 31, 1992 in 1-2703).
(d) 9 -- Reimbursement and Loan Agreement, dated as of April 23, 1986, by
and between GSU and The Long-Term Credit Bank of Japan, Ltd.,
relating to Multiple Rate Demand Pollution Control Revenue Bonds
of the Parish of West Feliciana, State of Louisiana, Series 1985
(4-26 to Form 10-K, for the year ended December 31, 1986 in 1-
2703) and Letter Agreement amending same, dated February 19, 1993
(10 to Form 10-K for the year ended December 31, 1992 in 1-2703).
(d) 10 -- Agreement effective February 1, 1964, between Sabine River
Authority, State of Louisiana, and Sabine River Authority of
Texas, and GSU, Central Louisiana Electric Company, Inc., and
Louisiana Power & Light Company, as supplemented (B to Form 8-K,
dated May 6, 1964, A to Form 8-K, dated October 5, 1967, A to
Form 8-K, dated May 5, 1969, and A to Form 8-K, dated December 1,
1969, in 1-2708).
(d) 11 -- Joint Ownership Participation and Operating Agreement regarding
River Bend Unit 1 Nuclear Plant, dated August 20, 1979, between
GSU, Cajun, and SRG&T; Power Interconnection Agreement with
Cajun, dated June 26, 1978, and approved by the REA on August 16,
1979, between GSU and Cajun; and Letter Agreement regarding CEPCO
buybacks, dated August 28, 1979, between GSU and Cajun (2, 3, and
4, respectively, to Form 8-K, dated September 7, 1979, in 1-
2703).
(d) 12 -- Ground Lease, dated August 15, 1980, between Statmont Associates
Limited Partnership (Statmont) and GSU, as amended (3 to Form 8-
K, dated August 19, 1980, and A-3-b to Form 10-Q for the quarter
ended September 30, 1983 in 1-2703).
(d) 13 -- Lease and Sublease Agreement, dated August 15, 1980, between
Statmont and GSU, as amended (4 to Form 8-K, dated August 19,
1980, and A-3-c to Form 10-Q for the quarter ended September 30,
1983 in 1-2703).
(d) 14 -- Lease Agreement, dated September 18, 1980, between BLC
Corporation and GSU (1 to Form 8-K, dated October 6, 1980 in 1-
2703).
(d) 15 -- Joint Ownership Participation Agreement for Big Cajun, between
GSU, Cajun Electric Power Cooperative, Inc., and Sam Rayburn G&T,
Inc, dated November 14, 1980 (6 to Form 8-K, dated January 29,
1981 in 1-2703); Amendment No. 1, dated December 12, 1980 (7 to
Form 8-K, dated January 29, 1981 in 1-2703); Amendment No. 2,
dated December 29, 1980 (8 to Form 8-K, dated January 29, 1981 in
1-2703).
(d) 16 -- Agreement of Joint Ownership Participation between SRMPA, SRG&T
and GSU, dated June 6, 1980, for Nelson Station, Coal Unit #6, as
amended (8 to Form 8-K, dated June 11, 1980, A-2-b to Form 10-Q
For the quarter ended June 30, 1982; and 10-1 to Form 8-K, dated
February 19, 1988 in 1-2703).
(d) 17 -- Agreements between Southern Company and GSU, dated February 25,
1982, which cover the construction of a 140-mile transmission
line to connect the two systems, purchase of power and use of
transmission facilities (10-31 to Form 10-K, for the year ended
December 31, 1981 in 1-2703).
+(d) 18 -- GSU Management Incentive Compensation Plan and Administrative
Guideline as restated March, 1981, effective for the fiscal year
commencing January 1, 1981 (10-33 to Form 10-K for the year ended
December 31, 1981 in 1-2703).
+(d) 19 -- GSU Stock Appreciation Plan (10-34 to Form 10-K for the year
ended December 31, 1981 in 1-2703), and Amendment, dated May 5,
1988 (10-20 to Form 10-K for the year ended December 31, 1988 in
1-2703); Amendment, dated December 4, 1990 (10-2 to Form 10-K for
the year ended December 31, 1990 in 1-2703) Amendment, dated
December 4, 1991 (10-1 to Form 10-K for the year ended December
31, 1991 in 1-2703).
+(d) 20 -- Executive Income Security Plan, effective October 1, 1980, as
amended, continued and completely restated effective as of March
1, 1991 (10-2 to Form 10-K for the year ended December 31, 1991
in 1-2703).
(d) 21 -- Joint Ownership Participation Agreement for Big Cajun between
GSU, Cajun, and SRG&T, dated November 14, 1980 (6 to Form 8-K,
dated January 29, 1981 in 1-2703).
(d) 22 -- Amendment No. 1 to the Joint Ownership Participation Agreement
for Big Cajun, between GSU, Cajun, and SRG&T, dated December 12,
1980 (7 to Form 8-K, dated January 29, 1981 in 1-2703).
(d) 23 -- Amendment No. 2 to the Joint Ownership Participation Agreement
for Big Cajun, between GSU, Cajun, and SRG&T, dated December 29,
1980 (8 to Form 8-K, dated January 29, 1981 in 1-2703).
(d) 24 -- Interchange contract between GSU and Alabama Power Company,
Georgia Power & Light Company, Gulf Power Company, Mississippi
Power Company and Southern Company Services, Inc. dated February
25, 1981 (A-2-b to Form 10-Q for the quarter ended March 31, 1982
in 1-2703); and Amendment, dated December 6, 1983 (10-42 to Form
10-K, for the year end December 31, 1983 in 1-2703). GSU's
position is that Schedule E of this contract was terminated in
1986.
(d) 25 -- Transmission Facilities Agreement between GSU and Mississippi
Power Company, dated February 28, 1982, and Amendment, dated May
12, 1982 (A-2-c to Form 10-Q for the quarter ended March 31, 1982
in 1-2703) and Amendment, dated December 6, 1983 (10-43 to Form
10-K, for the year ended December 31, 1983 in 1-2703).
+(d) 26 -- Employment Agreement entered into as of May 1, 1986, by GSU and
E. Linn Draper and Amendments, dated December 22, 1986 (10-42 to
Form 10-K, for the year ended December 31, 1986 in 1-2703), June
4, 1987 (4-14-75 to Form 10-K, for the year ended December 31,
1987 in 1-2703); February 13, 1989 (10-39 to Form 10-K for the
year ended December 31, 1988 in 1-2703), February 28, 1990 (10-4
to Form 10-K for the year ended December 31, 1989 in 1-2703);
Amendment, dated September 5, 1990 (10-4 to Form 10-K for the
year ended December 31, 1990 in 1-2703), and termination
agreement effective February 28, 1992 (10-I to Form 10-K for the
year ended December 31, 1991 in 1-2703).
(d) 27 -- Lease Agreement dated as of June 29, 1983, between GSU and City
National Bank of Baton Rouge, as Owner Trustee, in connection
with the leasing of a Simulator and Training Center for River
Bend Unit 1 (A-2-a to Form 10-Q for the quarter ended June 30,
1983 in 1-2703) and Amendment, dated December 14, 1984 (10-55 to
Form 10-K, for the year ended December 31, 1984 in 1-2703).
(d) 28 -- Participation Agreement, dated as of June 29, 1983, among GSU,
City National Bank of Baton Rouge, PruFunding, Inc. Bank of the
Southwest National Association, Houston and Bankers Life Company,
in connection with the leasing of a Simulator and Training Center
of River Bend Unit 1 (A-2-b to Form 10-Q for the quarter ended
June 30, 1983 in 1-2703).
(d) 29 -- Tax Indemnity Agreement, dated as of June 29, 1983, between GSU
and Prufunding, Inc., in connection with the leasing of a
Simulator and Training Center for River Bend Unit I (A-2-c to
Form 10-Q for the quarter ended June 30, 1993 in 1-2703).
(d) 30 -- Agreement to Lease, dated as of August 28, 1985, among GSU, City
National Bank of Baton Rouge, as Owner Trustee, and Prudential
Interfunding Corp., as Trustor, in connection with the leasing of
improvement to a Simulator and Training Facility for River Bend
Unit I (10-69 to Form 10-K, for the year ended December 31, 1985
in 1-2703).
(d) 31 -- First Amended Power Sales Agreement, dated December 1, 1985
between Sabine River Authority, State of Louisiana, and Sabine
River Authority, State of Texas, and GSU, Central Louisiana
Electric Co., Inc., and Louisiana Power and Light Company (10-72
to Form 10-K for the year ended December 31, 1985 in 1-2703).
+(d) 32 -- Employment Agreement entered into as of November 8, 1985, by GSU
and Joseph L. Donnelly (10-75 to Form 10-K for the year ended
December 31, 1986 in 1-2703) and Amendment, dated March 2, 1990
(10-3 to Form 10-K for the year ended December 31, 1989 in 1-
2703); and superseding agreement, dated February 12, 1992 (10-2
to Form 10-K for the year ended December 31, 1991 in 1-2703).
+(d) 33 -- Deferred Compensation Plan for Directors of GSU and Varibus
Corporation, as amended January 8, 1987, and effective January 1,
1987 (10-77 to Form 10-K for the year ended December 31, 1986 in
1-2703). Amendment dated December 4, 1991 (10-3 to Amendment No.
8 in Registration No. 2-76551).
+(d) 34 -- Trust Agreement for Deferred Payments to be made by GSU pursuant
to the Executive Income Security Plan, by and between GSU and
Bankers Trust Company, effective November 1, 1986 (10-78 to Form
10-K for the year ended December 31, 1986 in 1-2703).
+(d) 35 -- Trust Agreement for Deferred Installments under GSU's Management
Incentive Compensation Plan and Administrative Guidelines by and
between GSU and Bankers Trust Company, effective June 1, 1986
(10-79 to Form 10-K for the year ended December 31, 1986 in
1-2703).
+(d) 36 -- Nonqualified Deferred Compensation Plan for Officers, Nonemployee
Directors and Designated Key Employees, effective December 1,
1985, as amended, continued and completely restated effective as
of March 1, 1991 (10-3 to Amendment No. 8 in Registration No. 2-
76551).
+(d) 37 -- Trust Agreement for GSU's Nonqualified Directors and Designated
Key Employees by and between GSU and First City, Texas-Beaumont,
N.A., effective July 1, 1991 (10-4 to Form 10-K for the year
ended December 31, 1992 in 1-2703).
(d) 38 -- Lease Agreement, dated as of June 29, 1987, among GSG&T, Inc.,
and GSU related to the leaseback of the Lewis Creek generating
station (10-83 to Form 10-K for the year ended December 31, 1988
in 1-2703).
(d) 39 -- Nuclear Fuel Lease Agreement between GSU and River Bend Fuel
Services, Inc. to lease the fuel for River Bend Unit 1, dated
February 7, 1989 (10-64 to Form 10-K for the year ended December
31, 1988 in 1-2703).
(d) 40 -- Credit Agreement between GSU, Morgan Guaranty and Trust Company
of New York, Citibank, First City, Texas-Houston, N.A., The Bank
of New York, Bankers Trust Company and Canadian Imperial Bank for
$100,000,000 line of credit, dated March 17, 1992 (10-5 to
Amendment No. 8 in Registration No. 2-76551).
(d) 41 -- Trust and Investment Management Agreement between GSU and Morgan
Guaranty and Trust Company of New York with respect to
decommissioning funds authorized to be collected by GSU, dated
March 15, 1989 (10-66 to Form 10-K for the year ended December
31, 1988 in 1-2703).
(d) 42 -- Partnership Agreement by and among Conoco Inc., and GSU, CITGO
Petroleum Corporation and Vista Chemical Company, dated April 28,
1988 (10-67 to Form 10-K for the year ended December 31, 1988 in
1-2703).
+(d) 43 -- Gulf States Utilities Company Executive Continuity Plan, dated
January 18, 1991 (10-6 to Form 10-K for the year ended December
31, 1990 in 1-2703).
+(d) 44 -- Trust Agreement for GSU's Executive Continuity Plan, by and
between GSU and First City, Texas-Beaumont, N.A., effective May
20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992
in 1-2703).
+(d) 45 -- Gulf States Utilities Board of Directors' Retirement Plan, dated
February 15, 1991 (10-8 to Form 10-K for the year ended December
31, 1990 in 1-2703).
+(d) 46 -- Gulf States Utilities Company Employees' Trustee Retirement Plan
effective July 1, 1955 as amended, continued and completely
restated effective January 1, 1989; and Amendment No.1 effective
January 1, 1993 (10-6 to Form 10-K for the year ended December
31, 1992 in 1-2703).
(d) 47 -- Agreement and Plan of Reorganization, dated June 5, 1992, between
GSU and Entergy Corporation (2 to Form 8-K, dated June 8, 1992 in
1-2703).
+(d) 48 -- Nonqualified Accrued Contributions Plan for Designated Key
Employees effective January 1, 1989; Amendment No. 1 effective as
of March 1, 1990; and Amendment No. 2 effective as of December 4,
1990 (10-1 to Amendment No. 1 to Registration No. 33-48889).
+(d) 49 -- Gulf States Utilities Company Employee Stock Ownership Plan, as
amended, continued, and completely restated effective January 1,
1984, and January 1, 1985 (A to Form 11-K, dated December 31,
1985 in 1-2703).
+(d) 50 -- Trust Agreement under the Gulf States Utilities Company Employee
Stock Ownership Plan, dated December 30, 1976, between GSU and
the Louisiana National Bank, as Trustee (2-A to Registration No.
2-62395).
+(d) 51 -- Letter Agreement dated September 7, 1977 between GSU and the
Trustee, delegating certain of the Trustee's functions to the
ESOP Committee (2-B to Registration Statement No. 2-62395).
+(d) 52 -- Gulf States Utilities Company Employees Thrift Plan as amended,
continued and completely restated effective as of January 1, 1992
(28-1 to Amendment No. 8 to Registration No. 2-76551).
+(d) 53 -- Restatement of Trust Agreement under the Gulf States Utilities
Company Employees Thrift Plan, reflecting changes made through
January 1, 1989, between GSU and First City, Texas-Beaumont,
N.A., (formerly First Security Bank of Beaumont, N.A.), as
Trustee (2-A to Form 8-K dated October 20, 1989 in 1-2703).
(d) 54 -- Operating Agreement between Entergy Operations and GSU, dated as
of December 31, 1993 (B-2(f) to Rule 24 Certificate in 70-8059).
(d) 55 -- Guarantee Agreement between Entergy Corporation and GSU, dated as
of December 31, 1993 (B-5(a) to Rule 24 Certificate in 70-8059).
(d) 56 -- Service Agreement with Entergy Services, dated as of December 31,
1993 (B-6(c) to Rule 24 Certificate in 70-8059).
+*(d)57 -- Amendment to Employment Agreement between J. L. Donnelly and
GSU, dated December 22, 1993.
*(d) 58 -- Amendment to Letter of Credit and Reimbursement Agreement between
GSU and Westpac Banking Corporation
LP&L
(e) 1 -- Agreement, dated April 23, 1982, among LP&L and certain other
System companies, relating to System Planning and Development and
Intra-System Transactions (10(a) 1 to Form 10-K for the fiscal
year ended December 31, 1982, in 1-3517).
(e) 2 -- Middle South Utilities System Agency Agreement, dated December
11, 1970 (5(a)-2 in 2-41080).
(e) 3 -- Amendment, dated as of February 10, 1971, to Middle South
Utilities System Agency Agreement, dated December 11, 1970
(5(a)-4 in 2-41080).
(e) 4 -- Middle South Utilities System Agency Coordination Agreement,
dated December 11, 1970 (5(a)-3 in 2-41080).
(e) 5 -- Service Agreement with Entergy Services, dated as of April 1,
1963 (5(a)-5 in 2-42523).
(e) 6 -- Amendment, dated as of January 1, 1972, to Service Agreement with
Entergy Services (4(a)-6 in 2-45916).
(e) 7 -- Amendment, dated as of April 27, 1984, to Service Agreement with
Entergy Services (10(a) 7 to Form 10-K for the fiscal year ended
December 31, 1984, in 1-3517).
(e) 8 -- Amendment, dated as of August 1, 1988, to Service Agreement with
Entergy Services (10(d)-8 to Form 10-K for the fiscal year ended
December 31, 1988, in 1-8474).
(e) 9 -- Amendment, dated January 1, 1991, to Service Agreement with
Entergy Services (10(d)-9 to Form 10-K for the fiscal year ended
December 31, 1990, in 1-8474).
(e) 10 -- Availability Agreement, dated June 21, 1974, among System Energy
and certain other System companies (B to Rule 24 Certificate,
dated June 24, 1974, in 70-5399).
(e) 11 -- First Amendment to Availability Agreement, dated as of June 30,
1977 (B to Rule 24 Certificate, dated June 30, 1977, in 70-5399).
(e) 12 -- Second Amendment to Availability Agreement, dated as of June 15,
1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592).
(e) 13 -- Third Amendment to Availability Agreement, dated as of June 28,
1984 (B-13(a) to Rule 24 Certificate, dated July 6, 1984, in
70-6985).
(e) 14 -- Fourth Amendment to Availability Agreement, dated as of June 1,
1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399).
(e) 15 -- Fourteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(e) 16 -- Fifteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York, Malcolm J. Hood, and Deposit Guaranty
National Bank, as Trustees (B-3(b) to Rule 24 Certificate, dated
June 5, 1986, in 70-7158).
(e) 17 -- Sixteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (C to Rule
24 Certificate, dated June 4, 1986, in 70-7123).
(e) 18 -- Eighteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-2
to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(e) 19 -- Nineteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-3
to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(e) 20 -- Twentieth Assignment of Availability Agreement, Consent and
Agreement, dated as of November 16, 1987, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-1
to Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(e) 21 -- Twenty-first Assignment of Availability Agreement, Consent and
Agreement, dated as of December 1, 1987, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (C-2 to
Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(e) 22 -- Twenty-third Assignment of Availability Agreement, Consent and
Agreement, dated as of January 11, 1991, with Chemical Bank, as
Agent (B-3(a) to Rule 24 Certificate, dated January 23, 1991, in
70-7561).
(e) 23 -- Twenty-fourth Assignment of Availability Agreement, Consent and
Agreement, dated as of July 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to
Rule 24 Certificate, dated July 14, 1992, in 70-7946).
(e) 24 -- Twenty-fifth Assignment of Availability Agreement, Consent and
Agreement, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to
Rule 24 Certificate, dated November 2, 1992, in 70-7946).
(e) 25 -- Twenty-sixth Assignment of Availability Agreement, Consent and
Agreement, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(c) to
Rule 24 Certificate, dated November 2, 1992, in 70-7946).
(e) 26 -- Twenty-seventh Assignment of Availability Agreement, Consent and
Agreement, dated as of April 1, 1993, with United States Trust
Company of New York and Gerard F. Ganey as Trustees (B-2(d) to
Rule 24 Certificate dated May 4, 1993 in 70-7946).
(e) 27 -- Twenty-eighth Assignment of Availability Agreement, Consent and
Agreement, dated as of December 17,1993, with Chemical Bank, as
Agent (B-2(a) to Rule 24 Certificate dated December 22, 1993 in
70-7561).
(e) 28 -- Fuel Lease, dated as of January 31, 1989, between River Fuel
Company #2, Inc., and LP&L (B-1(b) to Rule 24 Certificate in
70-7580).
(e) 29 -- Reallocation Agreement, dated as of July 28, 1981, among System
Energy and certain other System companies (B-1(a) in 70-6624).
(e) 30 -- Compromise and Settlement Agreement, dated June 4, 1982, between
Texaco, Inc. and LP&L (28(a) to Form 8-K, dated June 4, 1982, in
1-8474).
+(e) 31 -- Post-Retirement Plan (10(c)23 to Form 10-K for the fiscal year
ended December 31, 1983, in 1-8474).
(e) 32 -- Unit Power Sales Agreement, dated as of June 10, 1982, between
System Energy and AP&L, LP&L, MP&L and NOPSI (10(a) 39 to Form
10-K for the fiscal year ended December 31, 1982, in 1-3517).
(e) 33 -- First Amendment to the Unit Power Sales Agreement, dated as of
June 28, 1984, between System Energy and AP&L, LP&L, MP&L and
NOPSI (19 to Form 10-Q for the quarter ended September 30, 1984,
in 1-3517).
(e) 34 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(e) 35 -- Middle South Utilities, Inc. and Subsidiary Companies
Intercompany Tax Allocation Agreement, dated April 28, 1988 (D-1
to Form U5S for the year ended December 31, 1987).
(e) 36 -- First Amendment to Tax Allocation Agreement, dated January 1,
1990 (D-2 to Form U5S for the year ended December 31, 1989).
(e) 37 -- Contract for Disposal of Spent Nuclear Fuel and/or High-Level
Radioactive Waste, dated February 2, 1984, among DOE, System
Fuels and LP&L (10(d)33 to Form 10-K for the fiscal year ended
December 31, 1984, in 1-8474).
(e) 38 -- Operating Agreement between Entergy Operations and LP&L, dated as
of June 6, 1990 (B-2(c) to Rule 24 Certificate, dated June 15,
1990, in 70-7679).
(e) 39 -- Guarantee Agreement between Entergy Corporation and LP&L, dated
as of September 20, 1990 (B-2(a), to Rule 24 Certificate, dated
September 27, 1990, in 70-7757).
+(e) 40 -- Executive Financial Counseling Program of Entergy Corporation and
Subsidiaries (10(a) 52 to Form 10-K for the year ended
December 31, 1989, in 1-3517).
+(e) 41 -- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form 10-K
for the year ended December 31, 1989, in 1-3517).
+(e) 42 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries
(A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831).
+(e) 43 -- Supplemental Retirement Plan (10(a) 69 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(e) 44 -- Defined Contribution Restoration Plan of Entergy Corporation and
Subsidiaries (10(a) 53 to Form 10-K for the year ended
December 31, 1989 in 1-3517).
+(e) 45 -- Amendment No. 1 to the Equity Ownership Plan of Entergy
Corporation and Subsidiaries (10(a) 71 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(e) 46 -- Executive Disability Plan of Entergy Corporation and Subsidiaries
(10(a) 72 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(e) 47 -- Executive Medical Plan of Entergy Corporation and Subsidiaries
(10(a) 73 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(e) 48 -- Stock Plan for Outside Directors of Entergy Corporation and
Subsidiaries (10(a) 74 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(e) 49 -- Summary Description of Private Ownership Vehicle Plan of Entergy
Corporation and Subsidiaries (10(a) 75 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(e) 50 -- Agreement between Entergy Corporation and Edwin Lupberger (10(a)
42 to Form 10-K for the year ended December 31, 1985 in 1-3517).
+(e) 51 -- Agreement between Entergy Corporation and Jerry D. Jackson
(10(a) 68 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(e) 52 -- Agreement between Entergy Services and Gerald D. McInvale (10(a)
69 to Form 10-K for the year ended December 31, 1992 in 1-3517).
+(e) 53 -- Agreement between System Energy and Donald C. Hintz (10(b) 47 to
Form 10-K for the year ended December 31, 1991 in 1-9067).
+(e) 54 -- Summary Description of Retired Outside Director Benefit Plan
(10(c)90 to Form 10-K for the year ended December 31, 1992 in
1-10764).
+(e) 55 -- Amendment to Defined Contribution Restoration Plan of Entergy
Corporation and Subsidiaries (10(a) 81 to Form 10-K for the year
ended December 31, 1993 in 1-11299).
+(e) 56 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for the
year ended December 31, 1993 in 1-11299).
MP&L
(f) 1 -- Agreement dated April 23, 1982, among MP&L and certain other
System companies, relating to System Planning and Development and
Intra-System Transactions (10(a) 1 to Form 10-K for the fiscal
year ended December 31, 1982, in 1-3517).
(f) 2 -- Middle South Utilities System Agency Agreement, dated December
11, 1970 (5(a)-2 in 2-41080).
(f) 3 -- Amendment, dated February 10, 1971, to Middle South Utilities
System Agency Agreement, dated December 11, 1970 (5(a) 4 in
2-41080).
(f) 4 -- Middle South Utilities System Agency Coordination Agreement,
dated December 11, 1970 (5(a)-3 in 2-41080).
(f) 5 -- Service Agreement with Entergy Services, dated as of April 1,
1963 (D in 37-63).
(f) 6 -- Amendment, dated January 1, 1972, to Service Agreement with
Entergy Services (A to Notice, dated October 14, 1971, in 37-63).
(f) 7 -- Amendment, dated April 27, 1984, to Service Agreement with
Entergy Services (10(a) 7 to Form 10-K for the fiscal year ended
December 31, 1984, in 1-3517).
(f) 8 -- Amendment, dated as of August 1, 1988, to Service Agreement with
Entergy Services (10(e) 8 to Form 10-K for the fiscal year ended
December 31, 1988, in 0-320).
(f) 9 -- Amendment, dated January 1, 1991, to Service Agreement with
Entergy Services (10(e) 9 to Form 10-K for the fiscal year ended
December 31, 1990, in 0-320).
(f) 10 -- Availability Agreement, dated June 21, 1974, among System Energy
and certain other System companies (B to Rule 24 Certificate,
dated June 24, 1974, in 70-5399).
(f) 11 -- First Amendment to Availability Agreement, dated as of June 30,
1977 (B to Rule 24 Certificate, dated June 24, 1977, in 70-5399).
(f) 12 -- Second Amendment to Availability Agreement, dated as of June 15,
1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592).
(f) 13 -- Third Amendment to Availability Agreement, dated as of June 28,
1984 (B-13(a) to Rule 24 Certificate, dated July 6, 1984, in
70-6985).
(f) 14 -- Fourth Amendment to Availability Agreement, dated as of June 1,
1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399).
(f) 15 -- Fourteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(f) 16 -- Fifteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York, Malcolm J. Hood, and Deposit Guaranty
National Bank, as Trustees (B-3(b) to Rule 24 Certificate, dated
June 5, 1986, in 70-7158).
(f) 17 -- Sixteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (C to Rule
24 Certificate, dated June 4, 1986, in 70-7123).
(f) 18 -- Eighteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-2
to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(f) 19 -- Nineteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-3
to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(f) 20 -- Twentieth Assignment of Availability Agreement, Consent and
Agreement, dated as of November 15, 1987, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-1
to Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(f) 21 -- Twenty-first Assignment of Availability Agreement, Consent and
Agreement, dated as of December 1, 1987, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (C-2 to
Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(f) 22 -- Twenty-third Assignment of Availability Agreement, dated as of
January 11, 1991, with Chemical Bank, as Agent (B-3(a) to Rule 24
Certificate, dated January 23, 1991, in 70-7561).
(f) 23 -- Twenty-fourth Assignment of Availability Agreement, Consent and
Agreement, dated as of July 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to
Rule 24 Certificate, dated July 14, 1992, in 70-7946).
(f) 24 -- Twenty-fifth Assignment of Availability Agreement, Consent and
Agreement, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to
Rule 24 Certificate, dated November 2, 1992, in 70-7946).
(f) 25 -- Twenty-sixth Assignment of Availability Agreement, Consent and
Agreement, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(c) to
Rule 24 Certificate, dated November 2, 1992, in 70-7946).
(f) 26 -- Twenty-seventh Assignment of Availability Agreement, Consent and
Agreement, dated as of April 1, 1993, with United States Trust
Company of New York and Gerard F. Ganey as Trustees (B-2(d) to
Rule 24 Certificate dated May 4, 1993 in 70-7946).
(f) 27 -- Twenty-eighth Assignment of Availability Agreement, Consent and
Agreement, dated as of December 17, 1993, with Chemical Bank, as
Agent (B-2(a) to Rule 24 Certificate dated December 22, 1993 in
70-7561).
(f) 28 -- Substitute Power Agreement, dated as of May 1, 1980, among MP&L,
System Energy and SMEPA (B-3(a) in 70-6337).
(f) 29 -- Agreement, dated as of January 30, 1981, between AP&L and MP&L,
relating to the Independence Station (B-3 in 70-6614).
(f) 30 -- Amendment No. 1, dated as of June 30, 1981, to Agreement, dated
as of January 30, 1981, between AP&L and MP&L, relating to the
Independence Station (10(f)(2) in 2-73309).
(f) 31 -- Amendment, dated December 4, 1984, to the Independence Steam
Electric Station Operating Agreement (10(c) 51 to Form 10-K for
the fiscal year ended December 31, 1984, in 0-375).
(f) 32 -- Amendment, dated December 4, 1984, to the Independence Steam
Electric Station Ownership Agreement (10(c) 54 to Form 10-K for
the fiscal year ended December 31, 1984, in 0-375).
(f) 33 -- Owners Agreement, dated November 28, 1984, among AP&L, MP&L and
other co- owners of the Independence Station (10(c) 55 to Form
10-K for the fiscal year ended December 31, 1984, in 0-375).
(f) 34 -- Consent, Agreement and Assumption, dated December 4, 1984, among
AP&L, MP&L, other co-owners of the Independence Station and
United States Trust Company of New York, as Trustee (10(c) 56 to
Form 10-K for the fiscal year ended December 31, 1984, in 0-375).
(f) 35 -- Reallocation Agreement, dated as of July 28, 1981, among System
Energy and certain other System companies (B-1(a) in 70-6624).
+(f) 36 -- Post-Retirement Plan (10(d) 24 to Form 10-K for the fiscal year
ended December 31, 1983, in 0-320).
(f) 37 -- Unit Power Sales Agreement, dated as of June 10, 1982, between
System Energy and AP&L, LP&L, MP&L, and NOPSI (10(a) 39 to Form
10-K for the fiscal year ended December 31, 1982, in 1-3517).
(f) 38 -- First Amendment to the Unit Power Sales Agreement, dated as of
June 28, 1984, between System Energy and AP&L, LP&L, MP&L, and
NOPSI (19 to Form 10-Q for the quarter ended September 30, 1984,
in 1-3517).
(f) 39 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(f) 40 -- Sales Agreement, dated as of June 21, 1974, between System Energy
and MP&L (D to Rule 24 Certificate, dated June 26, 1974, in
70-5399).
(f) 41 -- Service Agreement, dated as of June 21, 1974, between System
Energy and MP&L (E to Rule 24 Certificate, dated June 26, 1974,
in 70-5399).
(f) 42 -- Partial Termination Agreement, dated as of December 1, 1986,
between System Energy and MP&L (A-2 to Rule 24 Certificate dated
January 8, 1987, in 70-5399).
(f) 43 -- Middle South Utilities, Inc. and Subsidiary Companies
Intercompany Income Tax Allocation Agreement, dated April 28,
1988 (D-1 to Form U5S for the year ended December 31, 1987).
(f) 44 -- First Amendment to Tax Allocation Agreement, dated January 1,
1990 (D-2 to Form U5S for the year ended December 31, 1989).
+(f) 45 -- Executive Financial Counseling Program of Entergy Corporation and
Subsidiaries (10(a) 52 to Form 10-K for the year ended
December 31, 1989, in 1-3517).
+(f) 46 -- Entergy Corporation Annual Incentive Plan (10(a) 54 to Form 10-K
for the year ended December 31, 1989, in 1-3517).
+(f) 47 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries
(A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831).
+(f) 48 -- Supplemental Retirement Plan (10(a)69 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(f) 49 -- Defined Contribution Restoration Plan of Entergy Corporation and
Subsidiaries (10(a)53 to Form 10-K for the year ended
December 31, 1989 in 1-3517).
+(f) 50 -- Amendment No. 1 to the Equity Ownership Plan of Entergy
Corporation and Subsidiaries (10(a)71 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(f) 51 -- Executive Disability Plan of Entergy Corporation and Subsidiaries
(10(a)72 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(f) 52 -- Executive Medical Plan of Entergy Corporation and Subsidiaries
(10(a)73 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(f) 53 -- Stock Plan for Outside Directors of Entergy Corporation and
Subsidiaries, as amended (10(a)74 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(f) 54 -- Summary Description of Private Ownership Vehicle Plan of Entergy
Corporation and Subsidiaries (10(a)75 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(f) 55 -- Agreement between Entergy Corporation and Edwin Lupberger
(10(a)-42 to Form 10-K for the year ended December 31, 1985 in
1-3517).
+(f) 56 -- Agreement between Entergy Corporation and Jerry D. Jackson
(10(a)-68 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(f) 57 -- Agreement between Entergy Services and Gerald D. McInvale
(10(a)-69 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(f) 58 -- Agreement between System Energy and Donald C. Hintz (10(b)-47 to
Form 10-K for the year ended December 31, 1991 in 1-9067).
+(f) 59 -- Summary Description of Retired Outside Director Benefit Plan
(10(c)-90 to Form 10-K for the year ended December 31, 1992 in
1-10764).
+(f) 60 -- Amendment to Defined Contribution Restoration Plan of Entergy
Corporation and Subsidiaries (10(a) 81 to Form 10-K for the year
ended December 31, 1993 in 1-11299).
+(f) 61 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for the
year ended December 31, 1993 in 1-11299).
NOPSI
(g) 1 -- Agreement, dated April 23, 1982, among NOPSI and certain other
System companies, relating to System Planning and Development and
Intra-System Transactions (10(a)-1 to Form 10-K for the fiscal
year ended December 31, 1982, in 1-3517).
(g) 2 -- Middle South Utilities System Agency Agreement, dated December
11, 1970 (5(a)-2 in 2-41080).
(g) 3 -- Amendment dated as of February 10, 1971, to Middle South
Utilities System Agency Agreement, dated December 11, 1970
(5(a)-4 in 2-41080).
(g) 4 -- Middle South Utilities System Agency Coordination Agreement,
dated December 11, 1970 (5(a)-3 in 2-41080).
(g) 5 -- Service Agreement with Entergy Services dated as of April 1, 1963
(5(a)-5 in 2-42523).
(g) 6 -- Amendment, dated as of January 1, 1972, to Service Agreement with
Entergy Services (4(a)-6 in 2-45916).
(g) 7 -- Amendment, dated as of April 27, 1984, to Service Agreement with
Entergy Services (10(a)7 to Form 10-K for the fiscal year ended
December 31, 1984, in 1-3517).
(g) 8 -- Amendment, dated as of August 1, 1988, to Service Agreement with
Entergy Services (10(f)-8 to Form 10-K for the fiscal year ended
December 31, 1988, in 0-5807).
(g) 9 -- Amendment, dated January 1, 1991, to Service Agreement with
Entergy Services (10(f)-9 to Form 10-K for the fiscal year ended
December 31, 1990, in 0-5807).
(g) 10 -- Availability Agreement, dated June 21, 1974, among System Energy
and certain other System companies (B to Rule 24 Certificate,
dated June 24, 1974, in 70-5399).
(g) 11 -- First Amendment to Availability Agreement, dated June 30, 1977 (B
to Rule 24 Certificate, dated June 30, 1977, in 70-5399).
(g) 12 -- Second Amendment to Availability Agreement, dated as of June 15,
1981 (E to Rule 24 Certificate, dated July 1, 1981, in 70-6592).
(g) 13 -- Third Amendment to Availability Agreement, dated as of June 28,
1984 (B-13(a) to Rule 24 Certificate, dated July 6, 1984, in
70-6985).
(g) 14 -- Fourth Amendment to Availability Agreement, dated as of June 1,
1989 (A to Rule 24 Certificate, dated June 8, 1989, in 70-5399).
(g) 15 -- Fourteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of June 15, 1985, with Deposit Guaranty
National Bank, United States Trust Company of New York and
Malcolm J. Hood, as Trustees (B-3(b) to Rule 24 Certificate,
dated July 31, 1985, in 70-7026).
(g) 16 -- Fifteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York, Malcolm J. Hood and Deposit Guaranty
National Bank, as Trustees (B-3(b) to Rule 24 Certificate, dated
June 5, 1986, in 70-7158).
(g) 17 -- Sixteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of May 1, 1986, with United States Trust
Company of New York and Malcolm J. Hood, as Trustees (C to Rule
24 Certificate, dated June 4, 1986, in 70-7123).
(g) 18 -- Eighteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-2
to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(g) 19 -- Nineteenth Assignment of Availability Agreement, Consent and
Agreement, dated as of September 1, 1986, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-3
to Rule 24 Certificate, dated October 1, 1986, in 70-7272).
(g) 20 -- Twentieth Assignment of Availability Agreement, Consent and
Agreement, dated as of November 15, 1987, with United States
Trust Company of New York and Gerard F. Ganey, as Trustees (C-1
to Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(g) 21 -- Twenty-first Assignment of Availability Agreement, Consent and
Agreement, dated as of December 1, 1987, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (C-2 to
Rule 24 Certificate, dated December 1, 1987, in 70-7382).
(g) 22 -- Twenty-third Assignment of Availability Agreement, Consent and
Agreement, dated as of January 11, 1991, with Chemical Bank, as
Agent (B-3(a) to Rule 24 Certificate, dated January 23, 1991, in
70-7561).
(g) 23 -- Twenty-fourth Assignment of Availability Agreement, Consent and
Agreement, dated as of July 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to
Rule 24 Certificate, dated July 14, 1992, in 70-7946).
(g) 24 -- Twenty-fifth Assignment of Availability Agreement, Consent and
Agreement, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to
Rule 24 Certificate, dated November 2, 1992, in 70-7946).
(g) 25 -- Twenty-sixth Assignment of Availability Agreement, Consent and
Agreement, dated as of October 1, 1992, with United States Trust
Company of New York and Gerard F. Ganey, as Trustees (B-2(c) to
Rule 24 Certificate, dated November 2, 1992, in 70-7946).
(g) 26 -- Twenty-seventh Assignment of Availability Agreement, Consent and
Agreement, dated as of April 1, 1993, with United States Trust
Company of New York and Gerard F. Ganey as Trustees (B-2(d) to
Rule 24 Certificate dated May 4, 1993 in 70-7946).
(g) 27 -- Twenty-eighth Assignment of Availability Agreement, Consent and
Agreement, dated as of December 17, 1993, with Chemical Bank, as
Agent (B-2(a) to Rule 24 Certificate dated December 22, 1993 in
70-7561).
(g) 28 -- Reallocation Agreement, dated as of July 28, 1981, among System
Energy and certain other System companies (B-1(a) in 70-6624).
+(g) 29 -- Post-Retirement Plan (10(e) 22 to Form 10-K for the fiscal year
ended December 31, 1983, in 1-1319).
(g) 30 -- Unit Power Sales Agreement, dated as of June 10, 1982, between
System Energy and AP&L, LP&L, MP&L and NOPSI (10(a) 39 to Form
10-K for the fiscal year ended December 31, 1982, in 1-3517).
(g) 31 -- First Amendment to the Unit Power Sales Agreement, dated as of
June 28, 1984, between System Energy and AP&L, LP&L, MP&L and
NOPSI (19 to Form 10-Q for the quarter ended September 30, 1984,
in 1-3517).
(g) 32 -- Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(g) 33 -- Transfer Agreement, dated as of June 28, 1983, among the City of
New Orleans, NOPSI and Regional Transit Authority (2(a) to Form
8-K, dated June 24, 1983, in 1-1319).
(g) 34 -- Middle South Utilities, Inc. and Subsidiary Companies
Intercompany Income Tax Allocation Agreement, dated April 28,
1988 (D-1 to Form U5S for the year ended December 31, 1987).
(g) 35 -- First Amendment to Tax Allocation Agreement, dated January 1,
1990 (D-2 to Form U5S for the year ended December 31, 1989).
+(g) 36 -- Executive Financial Counseling Program of Entergy Corporation and
Subsidiaries (10(a)52 to Form 10-K for the year ended December
31, 1989, in 1-3517).
+(g) 37 -- Entergy Corporation Annual Incentive Plan (10(a)54 to Form 10-K
for the year ended December 31, 1989, in 1-3517).
+(g) 38 -- Equity Ownership Plan of Entergy Corporation and Subsidiaries
(A-4(a) to Rule 24 Certificate, dated May 24, 1991, in 70-7831).
+(g) 39 -- Supplemental Retirement Plan (10(a)69 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(g) 40 -- Defined Contribution Restoration Plan of Entergy Corporation and
Subsidiaries (10(a)53 to Form 10-K for the year ended
December 31, 1989 in 1-3517).
+(g) 41 -- Amendment No. 1 to the Equity Ownership Plan of Entergy
Corporation and Subsidiaries (10(a)71 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(g) 42 -- Executive Disability Plan of Entergy Corporation and Subsidiaries
(10(a)72 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(g) 43 -- Executive Medical Plan of Entergy Corporation and Subsidiaries
(10(a)73 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(g) 44 -- Stock Plan for Outside Directors of Entergy Corporation and
Subsidiaries, as amended (10(a)74 to Form 10-K for the year ended
December 31, 1992 in 1-3517).
+(g) 45 -- Summary Description of Private Ownership Vehicle Plan of Entergy
Corporation and Subsidiaries (10(a)75 to Form 10-K for the year
ended December 31, 1992 in 1-3517).
+(g) 46 -- Agreement between Entergy Corporation and Edwin Lupberger
(10(a)-42 to Form 10-K for the year ended December 31, 1985 in
1-3517).
+(g) 47 -- Agreement between Entergy Corporation and Jerry D. Jackson
(10(a)-68 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(g) 48 -- Agreement between Entergy Services and Gerald D. McInvale
(10(a)-69 to Form 10-K for the year ended December 31, 1992 in
1-3517).
+(g) 49 -- Agreement between System Energy and Donald C. Hintz (10(b)-47 to
Form 10-K for the year ended December 31, 1991 in 1-9067).
+(g) 50 -- Summary Description of Retired Outside Director Benefit Plan
(10(c)-90 to Form 10-K for the year ended December 31, 1992 in
1-10764).
+(g) 51 -- Amendment to Defined Contribution Restoration Plan of Entergy
Corporation and Subsidiaries (10(a) 81 to Form 10-K for the year
ended December 31, 1993 in 1-11299).
+(g) 52 -- System Executive Retirement Plan (10(a) 82 to Form 10-K for the
year ended December 31, 1993 in 1-11299).
(12) Statement Re Computation of Ratios
*(a) AP&L's Computation of Ratios of Earnings to Fixed Charges and of
Earnings to Fixed Charges and Preferred Dividends, as defined.
*(b) GSU's Computation of Ratios of Earnings to Fixed Charges and of
Earnings to Fixed Charges and Preferred Dividends, as defined.
*(c) LP&L's Computation of Ratios of Earnings to Fixed Charges and of
Earnings to Fixed Charges and Preferred Dividends, as defined.
*(d) MP&L's Computation of Ratios of Earnings to Fixed Charges and of
Earnings to Fixed Charges and Preferred Dividends, as defined.
*(e) NOPSI's Computation of Ratios of Earnings to Fixed Charges and of
Earnings to Fixed Charges and Preferred Dividends, as defined.
*(f) System Energy's Computation of Ratios of Earnings to Fixed Charges, as
defined.
*(21) Subsidiaries of the Registrants
(23) Consents of Experts and Counsel
*(a) The consent of Deloitte & Touche is contained herein at page 342.
*(b) The consent of Coopers & Lybrand is contained herein at page 343.
*(c) The consent of Friday, Eldredge & Clark is contained herein at page 344.
*(d) The consent of Clark, Thomas & Winters is contained herein at page 345.
*(e) The consent of Sandlin Associates is contained herein at page 346.
*(f) The consent of Monroe & Lemann (A Professional Corporation) is contained
herein at page 347.
*(g) The consent of Wise Carter Child & Caraway, Professional Association, is
contained herein at page 348.
*(24) Power of Attorney
(99) Additional Exhibits
GSU
(a) 1 Opinion of Clark, Thomas & Winters, a professional corporation, dated
September 30, 1992 regarding the effect of the October 1, 1991
judgment in GSU v. PUCT in the District Court of Travis County, Texas
(99-1 in Registration No. 33-48889).
(a) 2 Opinion of Clark, Thomas & Winters, a professional corporation, dated
September 30, 1992 regarding the effect of the Austin Court of
Appeals' ruling on deferred accounting in City of El Paso v. PUCT
(99-2 in Registration No. 33-48889).
*(a) 3 Opinion of Clark, Thomas & Winters, a professional corporation,
confirming its opinions dated September 30, 1992.
_________________
* Filed herewith.
+ Management contracts or compensatory plans or arrangements.