1
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------------
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1993
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
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COMMISSION REGISTRANT, STATE OF INCORPORATION, I.R.S. EMPLOYER
FILE NUMBER ADDRESS AND TELEPHONE NUMBER IDENTIFICATION NO.
----------- ---------------------------------- -----------------
1-3526 THE SOUTHERN COMPANY 58-0690070
(A Delaware Corporation)
64 Perimeter Center East
Atlanta, Georgia 30346
(404) 393-0650
1-3164 ALABAMA POWER COMPANY 63-0004250
(An Alabama Corporation)
600 North 18th Street
Birmingham, Alabama 35291
(205) 250-1000
1-6468 GEORGIA POWER COMPANY 58-0257110
(A Georgia Corporation)
333 Piedmont Avenue, N.E.
Atlanta, Georgia 30308
(404) 526-6526
0-2429 GULF POWER COMPANY 59-0276810
(A Maine Corporation)
500 Bayfront Parkway
Pensacola, Florida 32501
(904) 444-6111
0-6849 MISSISSIPPI POWER COMPANy 64-0205820
(A Mississippi Corporation)
2992 West Beach
Gulfport, Mississippi 39501
(601) 864-1211
1-5072 SAVANNAH ELECTRIC AND POWER COMPANY 58-0418070
(A Georgia Corporation)
600 Bay Street, East
Savannah, Georgia 31401
(912) 232-7171
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SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Each of the following securities registered pursuant to Section 12(b) of the
Act are registered on the New York Stock Exchange.
TITLE OF EACH CLASS Registrant
- ------------------- ----------
COMMON STOCK, $5 PAR VALUE THE SOUTHERN COMPANY
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CLASS A PREFERRED, CUMULATIVE, $25 STATED CAPITAL ALABAMA POWER COMPANY
7.60% (First 1992 Series) 6.80% Series
7.60% (Second 1992 Series) 6.40% Series
Adjustable Rate (1993 Series)
FIRST MORTGAGE BONDS
10 5/8% Series due 2017
9 1/4% Series due 2021
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PREFERRED STOCK, CUMULATIVE, $100 STATED VALUE GEORGIA POWER COMPANY
$7.72 Series
$7.80 Series
CLASS A PREFERRED, CUMULATIVE, $25 STATED VALUE
$2.125 Series $1.9375 Series
$1.90 Series Adjustable Rate (First 1993 Series)
$1.9875 Series Adjustable Rate (Second 1993 Series)
$1.925 Series
FIRST MORTGAGE BONDS
4 3/4% Series due 1996 6 7/8% Series due 2002
6 1/8% Series due 1999 10% Series due 2016
7% Series due 2000 7.95% Series due 2023
6% Series due 2000 7 5/8% Series due 2023
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PREFERRED STOCK, CUMULATIVE, $100 PAR VALUE MISSISSIPPI POWER COMPANY
Depositary Preferred Shares, each representing one-fourth of a share of:
7.25% Series
6.32% Series
6.65% Series
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PREFERRED STOCK, CUMULATIVE, $25 PAR VALUE SAVANNAH ELECTRIC AND POWER COMPANY
6.64% Series
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SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
TITLE OF EACH CLASS REGISTRANT
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PREFERRED STOCK, CUMULATIVE, $100 PAR VALUE ALABAMA POWER COMPANY
4.20% Series 4.60% Series 4.72% Series 5.96% Series
4.52% Series 4.64% Series 4.92% Series 6.88% Series
CLASS A PREFERRED, CUMULATIVE, $100,000 STATED CAPITAL
Auction (1993 Series)
CLASS A PREFERRED, CUMULATIVE, $100 STATED CAPITAL
Auction (1988 Series)
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PREFERRED STOCK, CUMULATIVE, $100 STATED VALUE GEORGIA POWER COMPANY
$4.60 Series $4.60 Series (1964) $4.96 Series $6.48 Series
$4.60 Series (1962) $4.72 Series $5.00 Series $6.60 Series
$4.60 Series (1963) $4.92 Series $5.64 Series
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PREFERRED STOCK, CUMULATIVE, $100 PAR VALUE GULF POWER COMPANY
4.64% Series 5.44% Series 7.88% Series
5.16% Series 7.52% Series 11.36% Series
CLASS A PREFERRED, CUMULATIVE, $10 PAR, $25 STATED CAPITAL
7.00% Series 7.30% Series 6.72% Series
Adjustable Rate (1993 Series)
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PREFERRED STOCK, CUMULATIVE, $100 PAR VALUE MISSISSIPPI POWER COMPANY
4.40% Series 4.60% Series 4.72% Series 7.00% Series
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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 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. ( )
Aggregate market value of voting stock held by non-affiliates of The
Southern Company at February 28, 1994: $13.4 billion. Each of such other
registrants are wholly-owned subsidiaries of The Southern Company and have no
voting stock other than their common stock. A description of registrants'
common stock follows:
DESCRIPTION OF SHARES OUTSTANDING
REGISTRANT COMMON STOCK AT FEBRUARY 28, 1994
- ---------- ------------ --------------------
The Southern Company Par Value $5 Per Share 648,346,540
Alabama Power Company Par Value $40 Per Share 5,608,955
Georgia Power Company No Par Value 7,761,500
Gulf Power Company No Par Value 992,717
Mississippi Power Company Without Par Value 1,121,000
Savannah Electric and Power Company Par Value $5 Per Share 10,844,635
Documents incorporated by reference: specified portions of The Southern
Company's Proxy Statement relating to the 1994 Annual Meeting of Stockholders
are incorporated by reference into PART III.
This combined Form 10-K is separately filed by The Southern Company,
Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi
Power Company and Savannah Electric and Power Company. 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.
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TABLE OF CONTENTS
Page
PART I ----
Item 1 Business-
The SOUTHERN System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1
New Business Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-2
Certain Factors Affecting the Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-3
Construction Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-3
Financing Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-5
Fuel Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-7
Territory Served . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-9
Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-12
Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-13
Rate Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-15
Long-Term Power Sales Agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-16
Employee Relations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-17
Item 2 Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-18
Item 3 Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-22
Item 4 Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . I-23
Executive Officers of SOUTHERN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-24
PART II
Item 5 Market for Registrants' Common Equity and Related Stockholder MattersII-1
Item 6 Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-2
Item 7 Management's Discussion and Analysis of Results of Operations
and Financial Condition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-2
Item 8 Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3
Item 9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-4
PART III
Item 10 Directors and Executive Officers of the Registrants . . . . . . . . . . . . . . . . . . . . . . III-1
Item 11 Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-13
Item 12 Security Ownership of Certain Beneficial Owners and
Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-30
Item 13 Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . . . . . III-36
PART IV
Item 14 Exhibits, Financial Statement Schedules, and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1
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DEFINITIONS
When used in Items 1 through 5 and Items 10 through 14, the
following terms will have the meanings indicated. Other defined
terms specific only to Item 11 are found on page III-13.
TERM MEANING
AEC . . . . . . . . . . . . . . Alabama Electric Cooperative, Inc.
AFUDC . . . . . . . . . . . . . Allowance for Funds Used During Construction
ALABAMA . . . . . . . . . . . . Alabama Power Company
Alicura . . . . . . . . . . . . Hidroelectrica Alicura, S.A. (Argentina)
AMEA . . . . . . . . . . . . . Alabama Municipal Electric Authority
Clean Air Act . . . . . . . . Clean Air Act Amendments of 1990
Dalton . . . . . . . . . . . . City of Dalton, Georgia
DOE . . . . . . . . . . . . . United States Department of Energy
ECO Plan . . . . . . . . . . . Environmental Compliance Overview Plan
ECR Plan . . . . . . . . . . . Environmental Cost Recovery Plan
Edelnor . . . . . . . . . . . . Empressa, Electrica del Norte Grande, S.A. (Chile)
Energy Act . . . . . . . . . . Energy Policy Act of 1992
EMF . . . . . . . . . . . . . . Electromagnetic field
EPA . . . . . . . . . . . . . . United States Environmental Protection Agency
FERC . . . . . . . . . . . . . Federal Energy Regulatory Commission
FPC . . . . . . . . . . . . . . Florida Power Corporation
FP&L . . . . . . . . . . . . . Florida Power & Light Company
Freeport . . . . . . . . . . . Freeport Power Company (Bahamas)
GEORGIA . . . . . . . . . . . . Georgia Power Company
GULF . . . . . . . . . . . . . Gulf Power Company
Gulf States . . . . . . . . . . Gulf States Utilities Company
Holding Company Act . . . . . . Public Utility Holding Company Act of 1935, as amended
IBEW . . . . . . . . . . . . . International Brotherhood of Electrical Workers
JEA . . . . . . . . . . . . . . Jacksonville Electric Authority
MEAG . . . . . . . . . . . . . Municipal Electric Authority of Georgia
MISSISSIPPI . . . . . . . . . . Mississippi Power Company
NRC . . . . . . . . . . . . . Nuclear Regulatory Commission
OPC . . . . . . . . . . . . . . Oglethorpe Power Corporation
operating affiliates . . . . . ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH
PSC . . . . . . . . . . . . . . Public Service Commission
REA . . . . . . . . . . . . . Rural Electrification Administration
RICO . . . . . . . . . . . . . Racketeer Influenced and Corrupt Organizations Act
SAVANNAH . . . . . . . . . . . Savannah Electric and Power Company
SCS . . . . . . . . . . . . . . Southern Company Services, Inc.
SEC . . . . . . . . . . . . . . Securities and Exchange Commission
SEGCO . . . . . . . . . . . . . Southern Electric Generating Company
SEI . . . . . . . . . . . . . . Southern Electric International, Inc.
SEPA . . . . . . . . . . . . . Southeastern Power Administration
SERC . . . . . . . . . . . . . Southeastern Electric Reliability Council
SMEPA . . . . . . . . . . . . . South Mississippi Electric Power Association
SOUTHERN . . . . . . . . . . . The Southern Company
Southern Nuclear . . . . . . . Southern Nuclear Operating Company, Inc.
SOUTHERN system . . . . . . . . SOUTHERN, the operating affiliates, SEGCO, SEI
Southern Nuclear, SCS and other subsidiaries
TVA . . . . . . . . . . . . . . Tennessee Valley Authority
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PART I
ITEM 1. BUSINESS
SOUTHERN was incorporated under the laws of Delaware on November 9, 1945.
SOUTHERN is domesticated under the laws of Georgia and is qualified to do
business as a foreign corporation under the laws of Alabama. SOUTHERN owns all
the outstanding common stock of ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH, each of which is an operating public utility company. ALABAMA and
GEORGIA each own 50% of the outstanding common stock of SEGCO. The operating
affiliates supply electric service in the states of Alabama, Georgia, Florida,
Mississippi and Georgia, respectively, and SEGCO owns generating units at a
large electric generating station which supplies power to ALABAMA and GEORGIA.
More particular information relating to each of the operating affiliates is as
follows:
ALABAMA is a corporation organized under the laws of the State of Alabama on
November 10, 1927, by the consolidation of a predecessor Alabama Power
Company, Gulf Electric Company and Houston Power Company. The predecessor
Alabama Power Company had had a continuous existence since its incorporation
in 1906.
GEORGIA was incorporated under the laws of the State of Georgia on June 26,
1930, and admitted to do business in Alabama on September 15, 1948.
GULF is a corporation which was organized under the laws of the State of
Maine on November 2, 1925, and admitted to do business in Florida on January
15, 1926, in Mississippi on October 25, 1976 and in Georgia on November 20,
1984.
MISSISSIPPI was incorporated under the laws of the State of Mississippi on
July 12, 1972, was admitted to do business in Alabama on November 28, 1972,
and effective December 21, 1972, by the merger into it of the predecessor
Mississippi Power Company, succeeded to the business and properties of the
latter company. The predecessor Mississippi Power Company was incorporated
under the laws of the State of Maine on November 24, 1924, and was admitted
to do business in Mississippi on December 23, 1924, and in Alabama on
December 7, 1962.
SAVANNAH is a corporation existing under the laws of Georgia; its charter
was granted by the Secretary of State on August 5, 1921.
SOUTHERN also owns all the outstanding common stock of SEI, Southern
Nuclear, SCS (the system service company), and various other subsidiaries
related to foreign operations and domestic non-utility operations (see
Exhibit 21 herein). At this time, the operations of the other subsidiaries
are not material. SEI designs, builds, owns and operates power production
facilities and provides a broad range of technical services to industrial
companies and utilities in the United States and a number of international
markets. A further description of SEI's business and organization follows
later in this section. Southern Nuclear provides services to the Southern
electric system's nuclear plants.
SEGCO owns electric generating units with an aggregate capacity of 1,019,680
kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama, and
ALABAMA and GEORGIA are each entitled to one-half of SEGCO's capacity and
energy. ALABAMA acts as SEGCO's agent in the operation of SEGCO's units and
furnishes coal to SEGCO as fuel for its units. SEGCO also owns three
230,000 volt transmission lines extending from Plant Gaston to the Georgia
state line at which point connection is made with the GEORGIA transmission
line system.
THE SOUTHERN SYSTEM
The transmission facilities of each of the operating affiliates and SEGCO are
connected to the respective company's own generating plants and other sources
of power and are interconnected with the transmission facilities of the other
operating affiliates and SEGCO by means of heavy-duty high voltage lines. (In
the case of GEORGIA's integrated transmission system, see Item 1 - BUSINESS -
"Territory Served" herein.)
Operating contracts covering arrangements in effect with principal
neighboring utility systems provide for capacity exchanges, capacity purchases
and sales, transfers of economy energy and other similar transactions.
Additionally, the operating affiliates have entered into voluntary reliability
agreements with the subsidiaries of Entergy Corporation, Florida Electric Power
Coordinating Group and TVA and with Carolina Power & Light Company, Duke Power
Company, South Carolina Electric & Gas Company and Virginia Electric
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and Power Company, each of which provides for the establishment and periodic
review of principles and procedures for planning and operation of generation
and transmission facilities, maintenance schedules, load retention programs,
emergency operations, and other matters affecting the reliability of bulk power
supply. The operating affiliates have joined with other utilities in the
Southeast (including those referred to above) to form the SERC to augment
further the reliability and adequacy of bulk power supply. Through the SERC,
the operating affiliates are represented on the National Electric Reliability
Council.
An intra-system interchange agreement provides for coordinating operations
of the power producing facilities of the operating affiliates and SEGCO and the
capacities available to such companies from non-affiliated sources and for the
pooling of surplus energy available for interchange. Coordinated operation of
the entire interconnected system is conducted through a central power supply
coordination office maintained by SCS. The available sources of energy are
allocated to the operating affiliates to provide the most economical sources of
power consistent with good operation. The resulting benefits and savings are
apportioned among the operating affiliates.
SCS has contracted with each operating affiliate, SEI, various of the other
subsidiaries, Southern Nuclear and SEGCO to furnish, at cost and upon request,
the following services: general executive and advisory services, power pool
operations, general engineering, design engineering, purchasing, accounting and
statistical, finance and treasury, taxes, insurance and pensions, corporate,
rates, budgeting, public relations, employee relations, systems and procedures
and other services with respect to business and operations. SOUTHERN also has
a contract with SCS for certain of these specialized services.
Southern Nuclear has contracted with ALABAMA to operate its Farley Nuclear
Plant, as authorized by amendments to the plant operating licenses. Southern
Nuclear also has a contract to provide GEORGIA with technical and other
services to support GEORGIA's operation of plants Hatch and Vogtle.
Applications are now pending before the NRC for amendments to the Hatch and
Vogtle operating licenses which would authorize Southern Nuclear to become the
operator. See Item 1 - BUSINESS - "Regulation - Atomic Energy Act of 1954"
herein.
NEW BUSINESS DEVELOPMENT
SOUTHERN continues to consider new business opportunities, particularly those
which allow use of the expertise and resources developed through its regulated
utility experience. These endeavors began in 1981 and are conducted through
SEI and other existing subsidiaries.
SEI's primary business focus is international and domestic cogeneration, the
independent power market, and the privatization of generation facilities in the
international market. SEI currently operates two domestic independent power
production projects totaling 225 megawatts and is one-third owner of one of
these (which produces 180 megawatts). It has a contract to sell electric
energy to Virginia Electric and Power Company from a facility SEI is developing
(through subsidiaries) in King George, Virginia. Upon completion, currently
planned for 1996, SEI will operate the 220 megawatt coal-fired plant and own
50% of the project.
In April 1993, SOUTHERN completed the purchase of a 50% interest in
Freeport, an electric utility on the Island of Grand Bahama, for a purchase
price of $35.5 million. Freeport has generating capacity of about 112
megawatts. In August 1993, SOUTHERN completed the purchase of a 55% interest
in Alicura, an entity that owns the right to use the generation from a 1,000
megawatt hydroelectric generating facility in Argentina, for a net purchase
price of approximately $188 million. In December 1993, SOUTHERN completed the
purchase of a 35% interest in Edelnor for the purchase price of $73 million.
Edelnor is a utility located in Northern Chile that owns and operates a
transmission grid and a 96 megawatt generating facility and is building an
additional 150 megawatt facility.
SEI has continued to render consulting services and market SOUTHERN system
expertise in the United States and throughout the world. It contracts with
other public utilities, commercial concerns and government agencies for the
rendition of services and the licensing of intellectual property. In addition,
SEI engages in energy management-related services and activities.
These continuing efforts to invest in and develop new business opportunities
offer the potential of earning returns which may exceed those of rate-regulated
operations. However, because of the absence of any assured return or rate of
return, they also involve a higher
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degree of risk. SOUTHERN expects to make substantial investments over the
period 1994-1996 in these and other new businesses.
CERTAIN FACTORS AFFECTING THE INDUSTRY
The electric utility industry is expected to become increasingly competitive in
the future as a result of the enactment of the Energy Act (see each
registrant's "Management's Discussion and Analysis - Future Earnings Potential"
in Item 7 herein), deregulation, competing technologies and other factors. In
recent years the electric utility industry in general has experienced problems
in a number of areas including the uncertain cost of capital needed for
construction programs, difficulty in obtaining sufficient return on invested
capital and in securing adequate rate increases when required, high costs and
other issues associated with compliance with environmental and nuclear
regulations, changes in regulatory climate, prudence audits and the effects of
inflation and other factors on the costs of operations and construction
expenditures. The SOUTHERN system has been experiencing certain of these
problems in varying degrees and management is unable to predict the future
effect of these or other factors upon its operations and financial condition.
CONSTRUCTION PROGRAMS
The subsidiary companies of SOUTHERN are engaged in continuous construction
programs to accommodate existing and estimated future loads on their respective
systems. Construction additions or acquisitions of property during 1994
through 1996 by the operating affiliates, SEGCO, SCS and Southern Nuclear are
estimated as follows: (in millions)
- -----------------------------------------------------------
1994 1995 1996
---------------------------------
ALABAMA $ 588 $ 572 $ 531
GEORGIA 688 555 629
GULF 77 55 68
MISSISSIPPI 96 62 98
SAVANNAH 33 32 33
SEGCO 14 16 26
SCS 26 18 14
Southern Nuclear 1 2 2
SOUTHERN system* $1,524 $1,326 $1,411
- -----------------------------------------------------------
*Does not add due to changes made in subsidiaries' construction budget
subsequent to approval of SOUTHERN system construction budget.
Reference is made to Note 4 to the financial statements of each registrant
in Item 8 herein for the amounts of AFUDC included in the above estimates. The
construction estimates for the period 1994 through 1996 do not include amounts
which may be spent by SEI (or the subsidiary(s) created to effect such
project(s)) on future power production projects or the projects discussed
earlier under "New Business Development." (See also Item 1 - BUSINESS -
"Financing Programs" herein.)
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Estimated construction costs in 1994 are expected to be apportioned
approximately as follows: (in millions)
- ---------------------------------------------------------------------------------------------------------------------
SOUTHERN
System* ALABAMA GEORGIA GULF MISSISSIPPI SAVANNAH
------------------------------------------------------------------------------------
Combustion turbines $ 239 $123 $103 $ - $ 5 $ 8
Other generating
facilities including
associated plant
substations 369 102 166 39 44 4
New business 276 114 130 13 11 8
Transmission 150 48 80 2 18 2
Joint line and substation 61 24 34 2 1 -
Distribution 126 50 49 11 9 7
Nuclear fuel 123 61 62 - - -
General plant 179 66 64 10 8 4
------------------------------------------------------------------------------------
$1,524 $588 $688 $77 $96 $33
====================================================================================
*SCS and Southern Nuclear plan capital additions to general plant in 1994 of
$26 million and $1 million, respectively, while SEGCO plans capital additions
of $14 million to generating facilities. Does not add due to changes made in
subsidiaries' construction budget subsequent to approval of SOUTHERN system
construction budget.
The construction programs are subject to periodic review and revision, and
actual construction costs may vary from the above estimates because of numerous
factors. These factors include changes in business conditions; revised load
growth estimates; changes in environmental regulations; changes in existing
nuclear plants to meet new regulatory requirements; increasing cost of labor,
equipment and materials; cost of capital and SEI securing a contract(s) to buy
or build additional generating facilities.
The operating affiliates do not have any baseload generating plants under
construction and current energy demand forecasts do not require any additional
baseload generating facilities before 2011. However, within the service area,
the construction of combustion turbine peaking units with an aggregate capacity
of approximately 1,700 megawatts is planned to be completed by 1996. In
addition, significant construction of transmission and distribution facilities
and upgrading of generating plants will be continuing.
During 1991, the Georgia legislature passed legislation which requires
GEORGIA and SAVANNAH each to file an Integrated Resource Plan for approval by
the Georgia PSC. Under the plan rules, the Georgia PSC must pre-certify the
construction of new power plants. (See Item 1 - BUSINESS - "Rate Matters -
Integrated Resource Planning" herein.)
See Item 1 - BUSINESS - "Regulation - Environmental Regulation" herein for
information with respect to certain existing and proposed environmental
requirements and Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein for
additional information concerning ALABAMA's and GEORGIA's joint ownership of
certain generating units and related facilities with certain non-affiliated
utilities.
ROCKY MOUNTAIN HYDROELECTRIC PROJECT
For information regarding GEORGIA's Rocky Mountain Project, including a joint
ownership agreement with OPC and the uncertain recovery of GEORGIA's costs in
this project, reference is made to Note 4 to SOUTHERN's and to GEORGIA's
financial statements in Item 8 herein.
STOCKHOLDER SUIT
For information concerning a suit against certain current and former directors
and officers of SOUTHERN involving allegations related to Plant Vogtle, the
Rocky Mountain project and other matters, see Item 3 - LEGAL PROCEEDINGS
herein.
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FINANCING PROGRAMS
In early 1994, SOUTHERN sold - through a public offering - common stock for
proceeds totaling approximately $120 million. SOUTHERN may require additional
equity capital during the remainder of 1994. The amount and timing of raising
additional equity capital in 1994, as well as subsequent years, will be
contingent on SOUTHERN's investment opportunities. Equity capital can be
provided from any combination of public offerings, private placements, or its
various stock plans. The operating affiliates' construction programs are
expected to be financed primarily from internal sources. Short-term debt will
be utilized when necessary. The operating affiliates may issue additional
long-term debt and preferred stock primarily for the purposes of debt
maturities and for redeeming higher-cost securities.
In order to issue first mortgage bonds and preferred stock, each of the
operating affiliates must comply with earnings coverage requirements contained
in its respective mortgage and charter. These provisions require, for the
issuance of additional first mortgage bonds, a minimum, before income tax,
earnings coverage of twice the pro forma annual interest charges on first
mortgage bonds and indebtedness secured by prior or equal ranking lien and, for
the issuance of additional preferred stock, a minimum, after income tax,
earnings coverage of one and one-half times pro forma annual interest charges
and preferred stock dividends, in each case for a period of twelve consecutive
calendar months within the fifteen calendar months immediately preceding the
proposed new issue. On the basis of these requirements, the respective
mortgage and preferred stock coverages of the operating affiliates for the
twelve months ended December 31, 1993, are:
- ---------------------------------------------------------
Mortgage Preferred Stock
Coverages Coverages
--------- ---------------
ALABAMA 5.70 2.71
GEORGIA 7.75 2.61
GULF 5.79 2.56
MISSISSIPPI 5.78 2.67
SAVANNAH 3.94 2.20
- ---------------------------------------------------------
The amounts of securities representing short-term unsecured indebtedness
allowable under the respective charters, and the maximum amounts of short-term
indebtedness authorized by the appropriate regulatory authorities, are shown in
the following table:
- ----------------------------------------------------------------------------
Short-term Unsecured Indebtedness
- ----------------------------------------------------------------------------
Allowable
Under Charter
at December 31, 1993
--------------------
Percent of
Secured
Indebtedness
and Other
Amount Capital(2)
------------- ----------------------
(Millions)
ALABAMA $ 542 10%
GEORGIA 1,736 20
GULF 92 10
MISSISSIPPI 133 20
SAVANNAH 70 20
SOUTHERN (1) (1)
- ----------------------------------------------------------------------------
Short-term Indebtedness
Maximum Regulatory
Authorization
-------------
Outstanding
at
Amount December 31, 1993
------------- ----------------------
(Millions)
ALABAMA $530 (3) $ 40
GEORGIA 900 (3) 482
GULF 100 (3) 6
MISSISSIPPI 140 (3) 40
SAVANNAH 70 (3) 3
SOUTHERN 500 (3) 222
Notes:
(1) No limitation.
(2) Under the provisions of the respective charters, GEORGIA's,
MISSISSIPPI's and SAVANNAH's preferred stockholders have approved increases in
the amounts of securities representing short-term unsecured indebtedness which
the companies may have outstanding until July 1 in 2003, 1999 and 1999,
respectively. Such limitations were raised from 10% of secured indebtedness
and other capital to 20% thereof. These approved increases are reflected in
the above table. ALABAMA currently plans to seek approval of its preferred
stockholders to have the charter limitation on short-term indebtedness
increased above its current limitation and
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12
may seek that such increase be made on a permanent basis.
(3) ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SOUTHERN have
received SEC authorization to issue from time to time short-term and/or term
loan notes to banks and commercial paper to dealers in the amounts shown
through March 31, 1996. Each of the operating affiliates (excluding
MISSISSIPPI) must also receive authorization from their respective state PSC to
issue short-term debt. At December 31, 1993, the Alabama PSC authorization
limited ALABAMA's short-term debt to $450 million.
Reference is made to Note 5, 5, 8, 5, 5 and 5 to the financial statements
for SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH, respectively,
in Item 8 herein for information regarding the registrants' credit
arrangements.
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13
FUEL SUPPLY
The operating affiliates' and SEGCO's supply of electricity is derived
predominantly from coal. The sources of generation for the years 1991 through
1993 and the estimates for 1994 are shown below:
Oil
and
ALABAMA Coal Nuclear Hydro Gas Total
---- ------- ----- --- -----
1991 68% 23% 9% *% 100%
1992 70 21 9 * 100
1993 70 22 8 * 100
1994 71 21 8 * 100
GEORGIA
1991 78 19 3 * 100
1992 76 21 3 * 100
1993 77 20 3 * 100
1994 78 19 3 * 100
GULF
1991 100 ** ** * 100
1992 100 ** ** * 100
1993 99 ** ** 1 100
1994 100 ** ** * 100
MISSISSIPPI
1991 89 ** ** 11 100
1992 91 ** ** 9 100
1993 90 ** ** 10 100
1994 83 ** ** 17 100
SAVANNAH
1991 91 ** ** 9 100
1992 81 ** ** 19 100
1993 83 ** ** 17 100
1994 96 ** ** 4 100
SEGCO
1991 100 ** ** * 100
1992 100 ** ** * 100
1993 100 ** ** * 100
1994 100 ** ** * 100
SOUTHERN
SYSTEM
1991 77 17 5 1 100
1992 77 17 5 1 100
1993 78 17 4 1 100
1994 78 17 4 1 100
- -------------------------------------------------------------
*Less than 0.5%
**Not applicable
The average costs of fuel in cents per net kilowatt-hour generated are shown
below:
Oil
and Weighted
ALABAMA Coal Nuclear Gas Average
---- ------- --- --------
1991 2.06 0.57 * 1.69
1992 1.99 0.44 * 1.64
1993 2.11 0.51 * 1.73
GEORGIA
1991 1.77 0.75 * 1.57
1992 1.75 0.63 * 1.52
1993 1.75 0.58 * 1.52
GULF
1991 2.16 ** * 2.17
1992 2.07 ** * 2.07
1993 2.03 ** 4.50 2.05
MISSISSIPPI
1991 1.80 ** 1.71 1.80
1992 1.59 ** 3.05 1.60
1993 1.66 ** 2.97 1.71
SAVANNAH
1991 2.05 ** 3.41 2.18
1992 2.28 ** 3.55 2.53
1993 2.02 ** 4.70 2.49
SEGCO
1991 1.97 ** * 1.97
1992 1.81 ** * 1.81
1993 1.80 ** * 1.81
SOUTHERN
SYSTEM
1991 1.91 0.66 2.84 1.69
1992 1.86 0.54 4.81 1.62
1993 1.90 0.54 4.34 1.67
- ---------------------------------------------------------------
* Not meaningful because of minimal generation from fuel source
** Not applicable
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At March 4, 1994, the operating affiliates and SEGCO had stockpiles of coal
on hand at their respective coal-fired plants which represented an estimated
25-day recoverable supply, based on projected 1994 nameplate burn requirements.
It is estimated that approximately 53 million tons of coal will be consumed in
1994 by the operating affiliates and SEGCO (including those units GEORGIA owns
jointly with OPC, MEAG, Dalton, FP&L and JEA and the units ALABAMA owns jointly
with AEC). The operating affiliates and SEGCO currently have 32 coal
contracts. These contracts cover remaining terms of up to 16 years.
Approximately 30% of 1994 estimated coal requirements will be purchased in the
spot market. Management has set a goal whereby the spot market should be
utilized, absent the transition from coal contract expirations, for 20 to 25%
of the SOUTHERN system's coal supply. Additionally, it has been determined
that approximately 35 days of recoverable supply of coal is the appropriate
level for coal stockpiles. During 1993, the operating affiliates and SEGCO's
average price of coal delivered was approximately $46 per ton. The typical
sulfur content of coal purchased under contracts ranges from approximately 0.7%
to 3.0% sulfur by weight. Fuel sulfur restrictions and other environmental
limitations have increased significantly and may increase further the
difficulty and cost of obtaining an adequate coal supply. See Item 1 -
BUSINESS - "Regulation - Environmental Regulation" herein.
Changes in fuel prices are generally reflected in fuel adjustment clauses
contained in rate schedules. See Item 1 - BUSINESS - "Rate Matters - Rate
Structure".
ALABAMA owns coal lands and mineral rights in the Warrior Coal Field,
located northwest of Birmingham in the vicinity of its Gorgas Steam Plant.
SEGCO also owns coal reserves in the Warrior Coal Field and in the Cahaba Coal
Field, which is located southwest of Birmingham. ALABAMA has an agreement with
a non-affiliated industrial and mining firm to mine coal from ALABAMA's
reserves, as well as its own reserves, for supply to ALABAMA's generating
units.
Should the arrangement between the mining firm and ALABAMA be terminated
pursuant to its provisions, ALABAMA would be obligated to pay the mining firm's
net investment in the mine and take over ownership of equipment and facilities.
On December 31, 1993, the mining firm's investment was approximately $13
million.
The operating affiliates have renegotiated, bought out or otherwise
terminated various coal supply contracts. For more information on certain of
these transactions see Note 5 to the financial statements of SOUTHERN, GULF and
MISSISSIPPI in Item 8 herein.
Reference is made to Item 3 - LEGAL PROCEEDINGS herein for a discussion of
a complaint filed against GULF and SCS regarding the delivery of coal.
In 1974, MISSISSIPPI filed a civil suit against a supplier of natural gas
for violation of the antitrust laws, breach of contract and tortious
interference with its contracts on account of MISSISSIPPI's failure to receive
its full contracted quantities of natural gas. The aggregate amount of damages
sought is approximately $134 million. An internal review of this matter has
determined that the possibility of any recovery is remote.
ALABAMA and GEORGIA have contracts with the United States Enrichment
Corporation for nuclear fuel enrichment services on a total system basis.
These contracts provide that any or all enrichment needs in any fiscal year may
be terminated at no charge upon a 10- year advance notice. To provide
contracting flexibility, all enrichment needs during the period October 1, 1999
- - September 30, 2002 were terminated prior to April 1, 1992. Except for
enrichment requirements during this termination period, all enrichment services
needs of Plants Farley, Hatch and Vogtle until the years cited above may be
accommodated by such contracts.
ALABAMA and GEORGIA have contracts with the DOE that provide for the
permanent disposal of spent nuclear fuel. The service to be provided by the
DOE is scheduled to begin in 1998; however, the actual year this service will
begin is uncertain. Sufficient storage capacity currently is available to
permit operation into 2003 at Plant Hatch, into 2009 at Plant Vogtle, and into
2012 and 2014 at Plant Farley units 1 and 2, respectively. Management believes
that sufficient capacity for nuclear fuel processing exists to preclude the
impairment of normal operations of the SOUTHERN system's nuclear generating
units.
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The Energy Act imposed upon utilities with nuclear plants, including ALABAMA
and GEORGIA, obligations for the decontamination and decommissioning of federal
nuclear fuel enrichment facilities. See Note 1 to SOUTHERN's, ALABAMA's and
GEORGIA's financial statements in Item 8 herein.
TERRITORY SERVED
The territory in which the operating affiliates provide electric service
comprises most of the states of Alabama and Georgia together with the
northwestern portion of Florida and southeastern Mississippi. In this
territory there are non-affiliated electric distribution systems which obtain
some or all of their power requirements either directly or indirectly from the
operating affiliates. The territory has an area of approximately 120,000
square miles and an estimated population of approximately 11 million.
ALABAMA is engaged, within the State of Alabama, in the generation and
purchase of electricity and the distribution and sale of such electricity at
retail in over 1,000 communities (including Anniston, Birmingham, Gadsden,
Mobile, Montgomery and Tuscaloosa), and at wholesale to 15 municipally-owned
electric distribution systems, 11 of which are served indirectly through sales
to AMEA, and two rural distributing cooperative associations. ALABAMA also
supplies steam service in downtown Birmingham. ALABAMA owns coal reserves near
its steam-electric generating plant at Gorgas and uses the output of coal from
these reserves in its generating plants. ALABAMA also sells, and cooperates
with dealers in promoting the sale of, electric appliances.
GEORGIA is engaged in the generation and purchase of electricity and the
distribution and sale of such electricity within the State of Georgia at retail
in over 600 communities (including Athens, Atlanta, Augusta, Columbus, Macon,
Rome and Valdosta), as well as in rural areas, and at wholesale currently to 39
electric cooperative associations through OPC, a corporate cooperative of
electric membership cooperatives in Georgia, and to 50 municipalities, 47 of
which are served through MEAG, a public corporation and an instrumentality of
the State of Georgia.
GULF is engaged, within the northwestern portion of Florida, in the
generation and purchase of electricity and the distribution and sale of such
electricity at retail in 71 communities (including Pensacola, Panama City and
Fort Walton Beach), as well as in rural areas, and at wholesale to a
non-affiliated utility and a municipality. GULF also sells electric
appliances.
MISSISSIPPI is engaged in the generation and purchase of electricity and the
distribution and sale of such energy within the 23 counties of southeastern
Mississippi, at retail in 123 communities (including Biloxi, Gulfport,
Hattiesburg, Laurel, Meridian and Pascagoula), as well as in rural areas, and
at wholesale to one municipality and four rural electric cooperative
associations.
SAVANNAH is engaged, within a five-county area in eastern Georgia, in the
generation and purchase of electricity and the distribution and sale of such
electricity at retail and, as a member of the SOUTHERN system power pool, the
transmission and sale of wholesale energy.
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16
The sources of revenues for the SOUTHERN system and each of SOUTHERN's
operating affiliates are shown in Item 6 herein. For the year ended December
31, 1993, the registrants derived their respective industrial revenues as shown
in the following table.
- --------------------------------------------------------------------------------------------------------------------------
SOUTHERN
System ALABAMA GEORGIA GULF MISSISSIPPI SAVANNAH
---------------------------------------------------------------------------------------------------
Textiles 13% 10% 18% *% 3% -%
Chemical 11 14 7 25 14 32
Paper 11 11 10 11 4 32
Primary metal 8 14 4 * 2 -
Stone, clay,
glass and concrete 6 6 8 2 1 4
Utility services 8 8 9 3 10 6
Food 5 3 6 1 6 8
Government 5 3 5 35 10 -
Transportation
equipment 3 1 4 1 8 9
Lumber and wood
products 4 5 4 2 8 4
Other** 26 25 25 20 34 5
- --------------------------------------------------------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
==========================================================================================================================
* Less than 0.5%
**Other major sources (more than 5%) of industrial revenues were: ALABAMA, coal
mining (5%); GULF, oil and gas extraction (8%); and MISSISSIPPI, petroleum
refining (21%) and electric machinery (5%).
A portion of the area served by SOUTHERN's operating affiliates adjoins
the area served by TVA and its municipal and cooperative distributors. An Act
of Congress limits the distribution of TVA power, unless otherwise authorized
by Congress, to specified areas or customers which generally were those served
on July 1, 1957.
The REA has authority to make loans to cooperative associations or
corporations to enable them to provide electric service to customers in rural
sections of the country. There are 70 electric cooperative organizations
operating in the territory in which the operating affiliates provide electric
service at retail or wholesale.
One of these, AEC, is a generating and transmitting cooperative selling
power to several distributing cooperatives, municipal systems and other
customers in south Alabama and northwest Florida. AEC owns generating units
with approximately 828 megawatts of nameplate capacity, including an undivided
ownership interest in ALABAMA's Plant Miller Units 1 and 2, and associated
transmission lines. AEC's facilities were financed with REA loans secured by
long-term contracts requiring distributing cooperatives to take their
requirements from AEC to the extent such energy is available. Two of the 14
distributing cooperatives operating in ALABAMA's service territory obtain a
portion of their power requirements directly from ALABAMA.
Four electric cooperative associations, financed by the REA, operate
within GULF's service area. These cooperatives purchase their full
requirements from AEC and SEPA. A non-affiliated utility also operates within
GULF's service area and purchases a portion of its requirements from GULF.
ALABAMA and GULF have entered into separate agreements with AEC
involving interconnection between the respective systems and, in the case of
ALABAMA, the delivery of capacity and energy from AEC to certain distributing
cooperatives. The rates for the various services provided by ALABAMA and GULF
to AEC are based on formulary approaches which result in the charges by each
company being updated annually, subject to FERC approval. See Item 2 -
PROPERTIES - "Jointly-Owned Facilities" herein for details of ALABAMA's
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17
joint-ownership with AEC of a portion of Plant Miller.
Another of the 70 electric cooperatives is SMEPA, also a generating and
transmitting cooperative. SMEPA, which began operation in 1970, has a
generating capacity of 739,000 kilowatts and a transmission system estimated to
be 1,357 miles in length. MISSISSIPPI has an interchange agreement with SMEPA
pursuant to which various services are provided, including the furnishing of
protective capacity by MISSISSIPPI to SMEPA.
There are 43 electric cooperative organizations operating in, or in
areas adjoining, territory in the State of Georgia in which GEORGIA provides
electric service at retail or wholesale. Three of these organizations obtain
their power from TVA and one from other sources. Since July 1, 1975, OPC has
supplied the requirements of the remaining 39 of these cooperative
organizations from self-owned generation acquired from GEORGIA and, until
September 1991, through partial requirements purchases from GEORGIA. GEORGIA
entered into an agreement with OPC pursuant to which, effective in September
1991, OPC ceased to be a partial requirements wholesale customer of GEORGIA.
Instead, OPC began the purchase of 1,250 megawatts of capacity from GEORGIA
through 1999, subject to reduction or extension by OPC, and may satisfy the
balance of its needs through purchases from others. This agreement did not
have a material effect on SOUTHERN's or GEORGIA's revenues or earnings.
There are 65 municipally-owned electric distribution systems operating
in the territory in which SOUTHERN's operating affiliates provide electric
service at retail or wholesale.
AMEA was organized under an act of the Alabama legislature and is
comprised of 11 municipalities. In 1986, ALABAMA entered into a firm power
purchase contract with AMEA entitling AMEA to scheduled amounts of capacity (to
a maximum of 100 megawatts) for a period of 15 years commencing September 1,
1986. In October 1991, ALABAMA entered into a second firm power purchase
contract with AMEA entitling AMEA to scheduled amounts of additional capacity
(to a maximum 80 megawatts) for a period of 15 years beginning October 1, 1991.
In both contracts the power is being sold to AMEA for its member municipalities
that previously were served directly by ALABAMA as wholesale customers. Under
the terms of the contracts, ALABAMA received payments from AMEA representing
the net present value of the revenues associated with the respective capacity
entitlements.
Forty-six municipally-owned electric distribution systems formerly
served on a full requirements wholesale basis by GEORGIA and one county-owned
system now receive their requirements through MEAG, which was established by a
state statute in 1975. MEAG serves these requirements from self-owned
generation facilities acquired from GEORGIA and through purchases of capacity
and energy from GEORGIA under partial requirements rates. Similarly, since
1977 Dalton has filled its requirements from generation facilities acquired
from GEORGIA and through partial requirements purchases. The full requirements
of two municipally-owned electric distribution systems are still served at
wholesale by GEORGIA. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities"
herein.) GULF and MISSISSIPPI provide wholesale requirements for one municipal
system each.
GEORGIA has entered into substantially similar agreements with OPC,
MEAG and Dalton providing for the establishment of an integrated transmission
system to carry the power and energy of each. The agreements require an
investment by each party in the integrated transmission system in proportion to
its respective share of the aggregate system load. (See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein.)
ALABAMA, GEORGIA, GULF and MISSISSIPPI also have contracts with SEPA (a
federal power marketing agency) providing for the use of those companies'
facilities at government expense to deliver to certain cooperatives and
municipalities, entitled by federal statute to preference in the purchase of
power from SEPA, quantities of power equivalent to the amounts of power
allocated to them by SEPA from certain United States Government hydroelectric
projects. The operating affiliates also purchase certain amounts of capacity
from SEPA.
The retail service rights of all electric suppliers in the State of
Georgia are regulated by the 1973 State Territorial Electric Service Act.
Pursuant to the provisions of this Act, all areas within existing municipal
limits were assigned to the primary electric supplier
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therein on March 29, 1973 (451 municipalities, including Atlanta, Columbus,
Macon, Augusta, Athens, Rome and Valdosta, to GEORGIA; 115 to electric
cooperatives; and 50 to publicly-owned systems). Areas outside of such
municipal limits were either to be assigned or to be declared open for customer
choice of supplier by action of the Georgia PSC pursuant to standards set forth
in the Act. Consistent with such standards, the Georgia PSC has assigned
substantially all of the land area in the state to a supplier. Notwithstanding
such assignments, the Act provides that any new customer locating outside of
1973 municipal limits and having a connected load in excess of 900 kilowatts
may receive electric service from the supplier of its choice.
Under and subject to the provisions of its franchises and concessions
and the 1973 State Territorial Electric Service Act, SAVANNAH has the full but
nonexclusive right to serve the City of Savannah, the Towns of Bloomingdale,
Pooler, Garden City, Guyton, Newington, Oliver, Port Wentworth, Rincon, Tybee
Island, Springfield, Thunderbolt, Vernonburg, and in conjunction with a
secondary supplier, the Town of Richmond Hill. In addition, SAVANNAH has been
assigned certain unincorporated areas in Chatham, Effingham, Bryan, Bulloch and
Screven Counties by the Georgia PSC. No other electric utility operates in
competition with SAVANNAH in its service area.
Pursuant to the 1956 Utility Act, the Mississippi PSC issued
"Grandfather Certificates" of convenience and necessity to MISSISSIPPI and to
six distribution rural cooperatives operating in southeastern Mississippi, then
served in whole or in part by MISSISSIPPI, authorizing them to distribute
electricity in certain specified geographically described areas of the state.
The six cooperatives serve approximately 271,000 retail customers in a
certificated area of approximately 10,300 square miles. In areas included in a
"Grandfather Certificate", the utility holding such certificate may, without
further certification, extend its lines up to five miles; other extensions
within that area by such utility, or by other utilities, may not be made except
upon a showing of, and a grant of a certificate of, public convenience and
necessity. Areas included in such a certificate which are subsequently annexed
to municipalities may continue to be served by the holder of the certificate,
irrespective of whether it has a franchise in the annexing municipality. On
the other hand, the holder of the municipal franchise may not extend service
into such newly annexed area without authorization by the Mississippi PSC.
COMPETITION
The electric utility industry in general has become, and is expected to
continue to be, increasingly competitive as the result of factors including
regulatory and technological developments. The Energy Act, enacted in 1992,
was intended to foster competition in the wholesale market by, among other
things, facilitating participation by independent power producers. The Energy
Act includes provisions authorizing the FERC under certain conditions to order
utilities owning transmission facilities to provide wholesale transmission
services for other utilities or entities that generate energy.
As a result of the foregoing factors, SOUTHERN may experience
increasing competition for available off-system sales of capacity and energy
from neighboring utilities and alternative sources of energy. Additionally,
the future effect of cogeneration and small-power production facilities on the
SOUTHERN system cannot currently be determined but may be adverse. Reference
is made to each registrant's "Management's Discussion and Analysis - Future
Earnings Potential" in Item 7 herein for further discussion of competition.
ALABAMA currently has cogeneration contracts in effect with nine
industrial customers. Under the terms of these contracts, ALABAMA purchases
excess generation of such companies. During 1993, ALABAMA purchased 48.3
million kilowatt-hours from such companies at a cost of $0.8 million.
GEORGIA currently has cogeneration contracts in effect with seven
industrial customers. Under the terms of these contracts, GEORGIA purchases
excess generation of such companies. During 1993, GEORGIA purchased 4.6
million kilowatt-hours from such companies at a cost of $76,000.
GULF currently has cogeneration agreements for "as available" energy in
effect with two industrial customers. During 1993, GULF purchased 119 million
kilowatt-hours from such companies for $2.3 million.
SAVANNAH currently has cogeneration contracts in
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19
effect with four industrial customers. Under the terms of these contracts,
SAVANNAH purchases excess generation of such companies. During 1993, SAVANNAH
purchased 2.4 million kilowatt-hours from such companies at a cost of $51,000.
The competition for retail energy sales among competing suppliers of
energy is influenced by various factors, including price, availability,
technological advancements and reliability. These factors are, in turn,
affected by, among other influences, political and environmental
considerations, taxation and supply.
The operating affiliates have experienced, and expect to continue to
experience, competition in their respective retail service territories in
varying degrees as the result of self-generation (as described above) and fuel
switching by customers and other factors. (See also Item 1 - BUSINESS -
"Territory Served" herein for information concerning suppliers of electricity
operating within or near the areas served at retail by the operating
affiliates.) In addition, while the Energy Act does not provide for "retail
wheeling" (i.e., the transmission and distribution by an electric utility to
retail customers within its service territory of energy produced by another
entity), applicable legislative and regulatory bodies may consider imposing
such a requirement in the future, the effect of which may be adverse.
REGULATION
STATE COMMISSIONS
The operating affiliates and SEGCO are subject to the jurisdiction of their
respective state regulatory commissions, which have broad powers of supervision
and regulation over public utilities operating in the respective states,
including their rates, service regulations, sales of securities (except for the
Mississippi PSC) and, in the cases of the Georgia PSC and Mississippi PSC, in
part, retail service territories. (See Item 1 - BUSINESS - "Rate Matters" and
"Territory Served" herein.)
HOLDING COMPANY ACT
SOUTHERN is registered as a holding company under the Holding Company Act, and
it and its subsidiary companies are subject to the regulatory provisions of
said Act, including provisions relating to the issuance of securities, sales
and acquisitions of securities and utility assets, services performed by SCS
and Southern Nuclear, and the activities of certain of SOUTHERN's special
purpose subsidiaries.
FEDERAL POWER ACT
The Federal Power Act subjects the operating affiliates and SEGCO to regulation
by the FERC as companies engaged in the transmission or sale at wholesale of
electric energy in interstate commerce, including regulation of accounting
policies and practices.
ALABAMA and GEORGIA are also subject to the provisions of the Federal
Power Act or the earlier Federal Water Power Act applicable to licensees with
respect to their hydroelectric developments. Among the hydroelectric projects
subject to licensing by the FERC are 14 existing ALABAMA generating stations
having an aggregate installed capacity of 1,582,725 kilowatts and 17 existing
GEORGIA generating stations having an aggregate installed capacity of 859,440
kilowatts.
In December 1991, ALABAMA and GEORGIA filed with the FERC their
applications for new licenses on six of their existing hydroelectric projects.
The six projects, ALABAMA's Yates and Thurlow and GEORGIA's Lloyd Shoals,
Langdale, Riverview and North Georgia, with 272,340 kilowatts of capacity, had
licenses that expired December 31, 1993. Although the possibility of
competition existed for these licenses, no competing applications were filed
prior to the filing deadline of December 31, 1991.
The Lloyd Shoals, Langdale and Riverview projects were granted new
30-year licenses that expire 2023. Each of the remaining projects are
operating on annual licenses under the same terms and conditions as their
original licenses. Additionally, the FERC has issued an order granting a
combined, 40-year license for the Yates and Thurlow projects. ALABAMA has
applied to the FERC for rehearing of certain provisions of this license. As a
part of the application for the combined, 40-year license for the Yates and
Thurlow projects, ALABAMA agreed to expand the capacity of these units by a
total of approximately 10.3 megawatts.
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20
GEORGIA and OPC also have a license, expiring in 2027, for the Rocky
Mountain Project, a pure pumped storage facility of 847,800 kilowatt capacity.
In 1988, the FERC approved an amendment to GEORGIA's license for the project,
adding OPC as co-licensee and extending the commercial operation date to 1996.
(See Item 1 - BUSINESS - "Construction Programs - Rocky Mountain Hydroelectric
Project" and Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.)
Licenses for all projects, excluding those discussed above, expire in
the period 2007-2023 in the case of ALABAMA's projects and in the period
1997-2020 in the case of GEORGIA's projects.
Upon or after the expiration of each license, the United States
Government, by act of Congress, may take over the project, or the FERC may
relicense the project either to the original licensee or to a new licensee. In
the event of takeover or relicensing to another, the original licensee is to be
compensated in accordance with the provisions of the Federal Power Act, such
compensation to reflect the net investment of the licensee in the project, not
in excess of the fair value of the property taken, plus reasonable damages to
other property of the licensee resulting from the severance therefrom of the
property taken.
ATOMIC ENERGY ACT OF 1954
ALABAMA, GEORGIA and Southern Nuclear are subject to the provisions of the
Atomic Energy Act of 1954, as amended, which vests jurisdiction in the NRC over
the construction and operation of nuclear reactors, particularly with regard to
certain public health and safety and antitrust matters. The National
Environmental Policy Act has been construed to expand the jurisdiction of the
NRC to consider the environmental impact of a facility licensed under the
Atomic Energy Act of 1954, as amended.
Reference is made to Notes 1 and 13 to SOUTHERN's, Notes 1 and 11 to
ALABAMA's and Notes 1 and 4 to GEORGIA's financial statements in Item 8 herein
for information on nuclear insurance and nuclear decommissioning costs.
Additionally, Note 3 to GEORGIA's financial statements contains information
regarding nuclear performance standards imposed by the Georgia PSC that may
impact retail rates.
ENVIRONMENTAL REGULATION
The operating affiliates and SEGCO are subject to federal, state and local
environmental requirements which, among other things, control emissions of
particulates, sulfur dioxide and nitrogen oxides into the air; the use,
transportation, storage and disposal of hazardous and toxic waste; and
discharges of pollutants, including thermal discharges, into waters of the
United States. The operating affiliates and SEGCO expect to comply with such
requirements, which generally are becoming increasingly stringent, through
technical improvements, the use of appropriate combinations of low-sulfur fuel
and chemicals, addition of environmental control facilities, changes in control
techniques and reduction of the operating levels of generating facilities.
Failure to comply with such requirements could result in the complete shutdown
of individual facilities not in compliance as well as the imposition of civil
and criminal penalties.
Reference is made to each registrant's "Management's Discussion and
Analysis" in Item 7 herein for a discussion of the Clean Air Act and other
environmental legislation and proceedings.
Possible adverse health effects of EMFs from various sources, including
transmission and distribution lines, have been the subject of a number of
studies and increasing public discussion. The scientific research currently is
inconclusive as to whether EMFs may cause adverse health effects. However,
there is the possibility of passage of legislation and promulgation of
rulemaking that would require measures to mitigate EMFs, with resulting
increases in capital and operating costs. In addition, the potential exists for
public liability with respect to lawsuits brought by plaintiffs alleging damages
caused by EMFs.
The operating affiliates' and SEGCO's estimated capital expenditures
for environmental quality control
I-14
21
facilities for the years 1994, 1995 and 1996 are as follows: (in millions)
- -------------------------------------------------------------------------------
Estimated*
----------------------------------------------------------------
1994 1995 1996
---- ---- ----
ALABAMA $ 12.4 $ 12.3 $ 19.3
GEORGIA 87.2 7.8 1.0
GULF 26.0 3.0 7.6
MISSISSIPPI 33.0 2.0 4.0
SAVANNAH 1.9 0.5 0.5
SEGCO 7.2 2.6 7.4
----------------------------------------------------------------
SOUTHERN
system $167.7 $ 28.2 $ 39.8
===============================================================================
*Such estimates are included in the current construction programs. (See
Item 1 - BUSINESS - "Construction Programs" herein.)
Additionally, each operating affiliate (excluding SAVANNAH) and SEGCO have
incurred costs for environmental remediation of various sites. Reference is
made to each applicable registrant's "Management's Discussion and Analysis" in
Item 7 herein for information regarding the registrants' environmental
remediation efforts.
The operating affiliates and SEGCO are unable to predict at this time what
additional steps they may be required to take as a result of the implementation
of existing or future quality control requirements for air, water and hazardous
or toxic materials, but such steps could adversely affect system operations and
result in substantial additional costs.
The outcome of the matters mentioned above under "Regulation" cannot now be
determined, except that these developments may result in delays in obtaining
appropriate licenses for generating facilities, increased construction and
operating costs, or reduced generation, the nature and extent of which, while
not determinable at this time, could be substantial.
RATE MATTERS
RATE STRUCTURE
The rates and service regulations of the operating affiliates are uniform for
each class of service throughout their respective service areas. Rates for
residential electric service are generally of the block type based upon
kilowatt-hours used and include minimum charges.
Residential and other rates contain separate customer charges. Rates for
commercial service are presently of the block type and, for large customers,
the billing demand is generally used to determine capacity and minimum bill
charges. These large customers' rates are generally based upon usage by the
customer (without differentiation between industrial and commercial
classifications) including those with special features to encourage off-peak
usage. With respect to GULF's and MISSISSIPPI's retail rates, fuel and
purchased power costs above base levels included in the various rate schedules
are billed to such customers under the fuel and energy adjustment clauses.
ALABAMA, GEORGIA and SAVANNAH are allowed by state law to recover fuel and net
purchased energy costs through fuel cost recovery provisions which are adjusted
to reflect increases or decreases in such costs. GULF's recovery of such costs
is based upon projections thereof for six-month periods; any over/under
recovery during any such period is reflected in the subsequent six-month
period. The adjustment factors for MISSISSIPPI's retail and wholesale rates
are levelized based on the estimated energy cost for the year, adjusted for any
actual over/under collection from the previous year. Revenues are adjusted for
differences between recoverable fuel costs and amounts actually recovered in
current rates.
INTEGRATED RESOURCE PLANNING
During 1991, the Georgia legislature passed certain legislation under which
both GEORGIA and SAVANNAH must file Integrated Resource Plans for approval by
the Georgia PSC. The plans must specify how GEORGIA and SAVANNAH each intend
to meet the future electrical needs of their customers through a combination of
demand-side and supply-side resources. The Georgia PSC must pre-certify these
new resources. Once certified, all prudently incurred construction costs will
be recoverable through rates.
In July 1992, the Georgia PSC approved Integrated Resource Plans for GEORGIA
and SAVANNAH. In January 1993, the Georgia PSC certified the construction of
two combustion turbine units by SAVANNAH, scheduled to be in service in 1994,
to meet its peaking needs. The Georgia PSC has certified the construction by
I-15
22
GEORGIA of four combustion turbine generating units in 1994 and four units in
1995. GEORGIA has also completed a demonstration competitive bid process for
its supply-side resource requirements expected for 1996. In December 1993,
GEORGIA filed with the Georgia PSC a proposal to purchase from FPC 400
megawatts of capacity in 1996 and 1997 and 200 megawatts of capacity in 1998
and 1999 with options to increase or decrease capacity during those years.
Also, GEORGIA has proposed a joint venture combustion turbine project to be
completed in 1996, also with FPC, which would provide GEORGIA with a 1/3
ownership in a 147 megawatt combustion turbine located at FPC's Intercession
City Plant. GEORGIA would have exclusive rights to all capacity from the unit
for the four summer months and FPC would have the output for the other eight
months of the year. The process is designed to verify the need for capacity
and that the lowest cost alternatives have been selected. In January 1993, the
Georgia PSC also certified certain residential energy conservation programs for
GEORGIA and SAVANNAH and provided for the recovery by GEORGIA and SAVANNAH of
program costs. Depending on the success of these programs, GEORGIA and
SAVANNAH may each receive a reward or, in GEORGIA's case, a penalty. In August
1993, the Georgia PSC also certified certain commercial and industrial energy
conservation programs submitted by GEORGIA and SAVANNAH.
During 1991, the Georgia PSC approved pilot demand-side programs that
encourage conservation for retail customers. Pursuant to an Integrated
Resource Plan approved by the Georgia PSC, GEORGIA has implemented various
demand-side option programs and has been authorized by the Georgia PSC to
recover associated program costs through rate riders. On October 15, 1993, a
superior court judge ruled that recovery of these costs through rate riders is
unlawful. GEORGIA has ceased collection of the rate riders and is deferring
program costs as ordered by the Georgia PSC pending the final outcome of this
matter. See Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8
herein for further information.
ENVIRONMENTAL COST RECOVERY PLANS
In April 1993, the Florida Legislature adopted legislation for an ECR clause,
which allows a utility to petition the Florida PSC for recovery of all prudent
environmental compliance costs that are not being recovered through base rates
or any other rate-adjustment clause. Such environmental costs include
increased operation and maintenance expense, depreciation, and a return on
invested capital.
On January 12, 1994, the Florida PSC approved GULF's petition under ECR for
recovery of environmental costs that were projected to be incurred from July
1993 through September 1994. The order allows the recovery from customers of
such costs amounting to $7.8 million from February through September 1994.
Thereafter, recovery under ECR will be determined semi-annually and will
include a true-up of the prior period and a projection of the ensuing six-month
period.
The Mississippi PSC approved MISSISSIPPI's ECO Plan in 1992. The plan
establishes procedures to facilitate the Mississippi PSC's overview of
MISSISSIPPI's environmental strategy and provides for recovery of costs
associated with environmental projects approved by the Mississippi PSC. Under
the ECO Plan any increase in the annual revenue requirement is limited to 2
percent of retail revenues. However, the plan also provides for carryover of
any amount over the 2 percent limit into the next year's revenue requirement.
The ECO Plan resulted in an annual retail rate increase of $2.6 million
effective April 1993.
RATE INCREASE APPLICATIONS
Reference is made to Note 3 to each registrant's notes to the financial
statements in Item 8 herein for a discussion of retail and wholesale rate
proceedings. Also discussed therein is a review by the FERC concerning the
reasonableness of the Southern electric system's wholesale rate schedules and
contracts that have a return on equity of 13.75% or greater.
LONG-TERM POWER SALES AGREEMENTS
The operating affiliates of the Southern electric system have entered into
long-term contractual agreements for the sale of capacity and energy to certain
non-affiliated utilities located outside the system's service area. Certain of
these agreements are non-firm and are based on capacity of the system in
general. Other agreements are
I-16
23
firm and pertain to capacity related to specific generating units. Because the
energy is generally sold at cost under these agreements, profitability is
affected primarily by revenues from capacity sales. See Note 8, 7, 6, 7, 7 and
6 to the financial statements of SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI
and SAVANNAH, respectively, in Item 8 herein for the amounts of capacity
revenues recorded for each of the past three years.
Long-term non-firm power of 400 megawatts was sold to FPC in 1993. In
January 1994, the amount decreased to 200 megawatts, and the contract will
expire at year-end.
Unit power from specific generating plants is currently being sold to FP&L,
FPC, JEA, and the city of Tallahassee, Florida. Under these agreements, an
average of 1,700 megawatts of capacity is scheduled to be sold during 1994 and
1995. Thereafter, these sales will decline to some 1,600 megawatts and remain
at that approximate level, unless reduced by FP&L, FPC and JEA after 1999,
until the expiration of the contracts in 2010.
GULF STATES DISPUTE SETTLEMENT
Reference is made to Note 8, 7, 3, 7 and 7 to the financial statements of
SOUTHERN, ALABAMA, GEORGIA, GULF and MISSISSIPPI, respectively, in Item 8
herein for a discussion of the Gulf States settlement.
EMPLOYEE RELATIONS
The companies of the SOUTHERN system had a total of 28,743 employees on their
payrolls at December 31, 1993.
- -------------------------------------------------------------------------------
Employees
at
December 31, 1993
-----------------
ALABAMA 8,009
GEORGIA 12,528
GULF 1,565
MISSISSIPPI 1,586
SAVANNAH 655
SCS 2,702
Southern Nuclear 1,453
Other 245
------
Total 28,743
======
The operating affiliates have separate agreements with local unions of the
IBEW generally covering wages, working conditions and procedures for handling
grievances and arbitration. These agreements apply with certain exceptions to
operating, maintenance and construction employees.
ALABAMA has agreements with the IBEW on a three-year contract extending to
August 15, 1995. Upon notice given at least 60 days prior to that date,
negotiations may be initiated with respect to agreement terms to be effective
after such date.
GEORGIA has an agreement with the IBEW covering wages and working conditions
which is in effect through June 30, 1996. GEORGIA also has a contract with the
United Plant Guard Workers of America with respect to Plant Hatch which extends
through September 30, 1995.
GULF has an agreement with a local union of the IBEW on a three-year
contract extending to August 15, 1995.
MISSISSIPPI has agreements with local unions of the IBEW on a contract
extending to August 16, 1995.
Southern Nuclear has an agreement with the IBEW on a three-year contract
extending to August 15, 1995. Upon notice given at least 60 days prior to that
date, negotiations may be initiated with respect to agreement terms to be
effective after such date.
The agreements also subject the terms of the pension plans for the companies
discussed above to collective bargaining with the unions at five-year
intervals.
SAVANNAH has three-year labor agreements with the IBEW and the Office
and Professional Employees International Union that expire April 15, 1996 and
December 1, 1996, respectively.
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24
ITEM 2. PROPERTIES
ELECTRIC PROPERTIES
The operating affiliates and SEGCO, at December 31, 1993, operated 33
hydroelectric generating stations, 31 fossil fuel generating stations and three
nuclear generating stations. The amounts of capacity owned by each company are
shown in the table below.
- ----------------------------------------------------------------------------------
Nameplate
Generating Station Location Capacity
------------------ -------- --------
(Kilowatts)
FOSSIL STEAM
Gadsden Gadsden, AL 120,000
Gorgas Jasper, AL 1,221,250
Barry Mobile, AL 1,525,000
Chickasaw Chickasaw, AL 40,000
Greene County Demopolis, AL 300,000 (1)
Gaston, Unit 5 Wilsonville, AL 880,000
Miller Birmingham, AL 2,532,288 (2)
---------
ALABAMA TOTAL 6,618,538
---------
Arkwright Macon, GA 160,000
Atkinson Atlanta, GA 180,000
Bowen Cartersville, GA 3,160,000
Branch Milledgeville, GA 1,539,700
Hammond Rome, GA 800,000
McDonough Atlanta, GA 490,000
McManus Brunswick, GA 115,000
Mitchell Albany, GA 170,000
Scherer Macon, GA 1,021,682 (3)
Wansley Carrollton, GA 925,550 (4)
Yates Newnan, GA 1,250,000
---------
GEORGIA TOTAL 9,811,932
---------
Crist Pensacola, FL 1,045,000
Lansing Smith Panama City, FL 305,000
Scholz Chattahoochee, FL 80,000
Daniel Pascagoula, MS 500,000 (5)
Scherer Unit 3 Macon, GA 204,500 (3)
---------
GULF TOTAL 2,134,500
---------
Eaton Hattiesburg, MS 67,500
Sweatt Meridian, MS 80,000
Watson Gulfport, MS 1,012,000
Daniel Pascagoula, MS 500,000 (5)
Greene County Demopolis, AL 200,000 (1)
---------
MISSISSIPPI TOTAL 1,859,500
---------
- ----------------------------------------------------------------------------------
Nameplate
Generating Station Location Capacity
------------------ -------- --------------
(Kilowatts)
McIntosh Effingham County, GA 163,117
Kraft Port Wentworth, GA 281,136
Riverside Savannah, GA 102,278
----------
SAVANNAH TOTAL 546,531
----------
Gaston Units 1-4 Wilsonville, AL
(SEGCO) 1,000,000 (6)
----------
TOTAL FOSSIL STEAM 21,971,001
----------
NUCLEAR STEAM
Farley Dothan, AL
(ALABAMA) 1,720,000
----------
Hatch Baxley, GA 816,630 (7)
Vogtle Augusta, GA 1,060,240 (8)
----------
GEORGIA TOTAL 1,876,870
----------
TOTAL NUCLEAR STEAM 3,596,870
----------
COMBUSTION TURBINES
Arkwright Macon, GA 30,580
Atkinson Atlanta, GA 78,720
Bowen Cartersville, GA 39,400
McDonough Atlanta, GA 78,800
McManus Brunswick, GA 481,700
Mitchell Albany, GA 118,200
Wilson Augusta, GA 354,100
Wansley Carrollton, GA 26,322 (4)
----------
GEORGIA TOTAL 1,207,822
----------
Lansing Smith
Unit A (GULF) Panama City, FL 39,400
----------
Chevron Cogenerating
Station Pascagoula, MS 72,720 (9)
Sweatt Meridian, MS 39,400
Watson Gulfport, MS 39,360
----------
MISSISSIPPI TOTAL 151,480
----------
Boulevard Savannah, GA 59,100
Kraft Port Wentworth, GA 22,000
----------
SAVANNAH TOTAL 81,100
----------
Gaston(SEGCO) Wilsonville, AL 19,680 (6)
----------
TOTAL COMBUSTION TURBINES 1,499,482
----------
I-18
25
- -------------------------------------------------------------------------------
Generating Nameplate
Station Location Capacity
------- -------- ----------
(Kilowatts)
HYDROELECTRIC FACILITIES
Weiss Leesburg, AL 87,750
Henry Ohatchee, AL 72,900
Logan Martin Vincent, AL 128,250
Lay Clanton, AL 177,000
Mitchell Verbena, AL 170,000
Jordan Wetumpka, AL 100,000
Bouldin Wetumpka, AL 225,000
Harris Wedowee, AL 135,000
Martin Dadeville, AL 154,200
Yates Tallassee, AL 32,000
Thurlow Tallassee, AL 58,000
Lewis Smith Jasper, AL 157,500
Bankhead Holt, AL 45,125
Holt Holt, AL 40,000
----------
ALABAMA TOTAL 1,582,725
----------
Barnett Shoals
(Leased) Athens, GA 2,800
Bartletts Ferry Columbus, GA 173,000
Goat Rock Columbus, GA 26,000
Lloyd Shoals Jackson, GA 14,400
Morgan Falls Atlanta, GA 16,800
North Highlands Columbus, GA 29,600
Oliver Dam Columbus, GA 60,000
Sinclair Dam Milledgeville, GA 45,000
Tallulah Falls Clayton, GA 72,000
Terrora Clayton, GA 16,000
Tugalo Clayton, GA 45,000
Wallace Dam Eatonton, GA 321,300
Yonah Toccoa, GA 22,500
6 Other Plants 18,080
----------
GEORGIA TOTAL 862,480
----------
TOTAL HYDROELECTRIC FACILITIES 2,445,205
----------
Total Generating Capacity 29,512,558
==========
Notes:
(1) Owned by ALABAMA and MISSISSIPPI as tenants in common in the
proportions of 60% and 40%, respectively.
(2) Excludes the capacity owned by AEC. (See Item 2- PROPERTIES -
"Jointly-Owned Facilities" herein.)
(3) Capacity shown is GEORGIA's or GULF's (Unit 3 only) current portion:
8.4% of Units 1 and 2, 75% (25% for GULF) for Unit 3 and 33.1% for
Unit 4 of total plant capacity. See Item 2 - PROPERTIES - "Proposed
Sales of Property" and "Jointly-Owned Facilities" herein.
(4) Capacity shown is GEORGIA's portion (53.5%) of total plant capacity.
(5) Represents 50% of the plant which is owned as tenants in common by
GULF and MISSISSIPPI.
(6) SEGCO is jointly-owned by ALABAMA and GEORGIA. (See Item 1 - BUSINESS
herein.)
(7) Capacity shown is GEORGIA's portion (50.1%) of total plant capacity.
(8) Capacity shown is GEORGIA's portion (45.7%) of total plant capacity.
(9) Generation is dedicated to a single industrial customer.
Except as discussed below under "Titles to Property", the principal plants
and other important units of the SOUTHERN system are owned in fee by the
operating affiliates and SEGCO. It is the opinion of management of each such
company that its operating properties are adequately maintained and are
substantially in good operating condition.
MISSISSIPPI owns a 79-mile length of 500-kilovolt transmission line which is
leased to Gulf States. The line, completed in 1984, extends from Plant Daniel
to the Louisiana state line. Gulf States is paying a use fee over a forty-year
period covering all expenses and the amortization of the original $57 million
cost of the line.
The all-time maximum demand on the SOUTHERN system was 25,936,900 kilowatts
and occurred in July 1993. This amount excludes demand served by generation
retained by OPC, MEAG and Dalton and excludes demand associated with power
purchased from SEPA by its preference customers. At that time, 27,342,700
kilowatts were supplied by SOUTHERN system generation and 1,405,800 kilowatts
(net) were sold to other parties through net purchased and interchanged power.
The reserve margin for the Southern electric system at that time was 13.2%.
For information on the other registrants' peak demands reference is made to
Item 6 - SELECTED FINANCIAL DATA herein.
ALABAMA and GEORGIA will incur significant costs in decommissioning their
nuclear units at the end of their useful lives. (See Item 1 - BUSINESS -
I-19
26
"Regulation - Atomic Energy Act of 1954" and Note 1 to SOUTHERN's, ALABAMA's
and GEORGIA's financial statements in Item 8 herein.)
OTHER ELECTRIC GENERATION FACILITIES
Through special purpose subsidiaries, SOUTHERN owns a 50% interest in
Freeport, a 35% interest in Edelnor, a 55.3% interest Alicura and a 33.3%
interest in a co-generation facility in Hawaii. For further discussion of
other SEI projects, see Item 1 - BUSINESS - "New Business Development" herein.
The generating capacity of these utilities (or facilities) at December 31,
1993, was as follows:
- -------------------------------------------------------------------------------
Nameplate
Type Facility Location Capacity
------------- -------- --------
(Megawatts)
Combined cycle
co-generation Northern Chile 96
Fossil steam Freeport,
Grand Bahamas 112
Combined cycle Barbers Point,
co-generation Oahu, HI 180
Hydroelectric Argentina 1,000*
* Represents a concession contract that provides SEI with the rights to use
the generation.
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27
JOINTLY-OWNED FACILITIES
ALABAMA has sold an undivided interest in two units of Plant Miller to AEC.
GEORGIA has sold undivided interests in certain generating plants and other
related facilities to OPC, MEAG, Dalton, FP&L and JEA. The percentages of
ownership resulting from these sales are as follows:
- ------------------------------------------------------------------------------------------------------------------------------
Percentage Ownership
Total ----------------------------------------------------------------------------------
Capacity ALABAMA AEC GEORGIA OPC MEAG DALTON FP&L JEA
-------- ------- --- ------- --- ---- ------ ---- ---
(Megawatts)
Plant Miller
Units 1 and 2 1,320 91.8% 8.2% -% -% -% -% -% -%
Plant Hatch 1,630 - - 50.1 30.0 17.7 2.2 - -
Plant Vogtle 2,320 - - 45.7 30.0 22.7 1.6 - -
Plant Scherer -
Units 1 and 2 1,636 - - 8.4 60.0 30.2 1.4 - -
Unit 4 818 - - 33.1 - - - 49.2 17.7
Plant Wansley 1,779 - - 53.5 30.0 15.1 1.4 - -
Rocky Mountain 848 - - 25.0* 75.0 - - - -
*Estimated ownership at completion
- ------------------------------------------------------------------------------------------------------------------------------
ALABAMA and GEORGIA have contracted to operate and maintain the respective
units in which each has an interest (other than Rocky Mountain, as described
below) as agent for the joint owners. See "Proposed Sales of Property" below
for a description of the proposed sale of GEORGIA's remaining unsold ownership
interest in Plant Scherer Unit 4.
In connection with the joint ownership arrangements for Plant Vogtle,
GEORGIA has remaining commitments to purchase declining fractions of OPC's and
MEAG's capacity and energy until 1994 for Unit 1 and 1996 for Unit 2 and, with
regard to a portion of a 5% interest in Plant Vogtle owned by MEAG, until the
latter of the retirement of the plant or the latest stated maturity date of
MEAG's bonds issued to finance such ownership interest. The payments for
capacity are required whether any capacity is available. The energy cost is a
function of each unit's variable operating costs. Except for the portion of
the capacity payments related to the 1987 and 1990 write-offs of Plant Vogtle
costs, the cost of such capacity and energy is included in purchased power in
the Statements of Income in Item 8 herein.
In December 1988, GEORGIA and OPC completed a joint ownership agreement for
the Rocky Mountain project under which GEORGIA will retain its present
investment in the project and OPC will finance, complete and operate the
facility. Upon completion (scheduled for 1995), GEORGIA will own an undivided
interest in the project equal to the proportion its investment bears to the
total investment in the project (excluding each party's cost of funds and ad
valorem taxes). For purposes of the ownership formula, GEORGIA's investment
will be expressed in nominal dollars and OPC's investment will be expressed in
constant 1987 dollars. Based on current cost estimates, GEORGIA's final
ownership is estimated at approximately 25% of the project at completion.
GEORGIA has held preliminary discussions regarding the potential disposition of
its remaining interest in the project.
PROPOSED SALES OF PROPERTY
In 1991 and 1993, GEORGIA completed the first two in a series of four separate
transactions to sell Unit 4 of Plant Scherer to FP&L and JEA for a total price
of approximately $806 million, including any gains on these transactions. FP&L
would eventually own approximately 76.4% of this unit, with JEA owning the
remainder. The capacity from this unit was previously dedicated to off-system
sales contracts with Gulf States that were suspended in 1988. GEORGIA will
continue to operate the unit.
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28
The 1991 and 1993 sales and the remaining transactions are scheduled as
follows:
- -----------------------------------------------------------
Percentage
Closing of Sales
Date Capacity Ownership Price
---- -------- ---------- -----
Megawatts (in millions)
July 1991 290 35.46% $291
June 1993 258 31.44 253
June 1994 135 16.55 132
June 1995 135 16.55 130
- -----------------------------------------------------------
Total 818 100.00% $806
===========================================================
Plant Scherer, a jointly owned coal-fired generating plant, has four
units with a total capacity of 3,272 megawatts. Unit 4 was completed in 1989.
TITLES TO PROPERTY
The operating affiliates' and SEGCO's interests in the principal plants (other
than certain pollution control facilities, one small hydroelectric generating
station leased by GEORGIA and the land on which four combustion turbine
generators of MISSISSIPPI are located, which is held by easement) and other
important units of the respective companies are owned in fee by such companies,
subject only to the liens of applicable mortgage indentures (except for SEGCO)
and to excepted encumbrances as defined therein. The operating affiliates own
the fee interests in certain of their principal plants as tenants in common.
(See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.) Properties such
as electric transmission and distribution lines and steam heating mains are
constructed principally on rights-of-way which are maintained under franchise
or are held by easement only. A substantial portion of lands submerged by
reservoirs is held under flood right easements. In substantially all of its
coal reserve lands, SEGCO owns or will own the coal only, with adequate rights
for the mining and removal thereof.
PROPERTY ADDITIONS AND RETIREMENTS
During the period from January 1, 1989, to December 31, 1993, the operating
affiliates, SEGCO, and other (i.e. SCS, Southern Nuclear and, beginning in
1993, various of the special purpose subsidiaries) gross property additions and
retirements were as follows:
- ------------------------------------------------------------
Gross Property
Additions Retirements
-------------------- -----------
(in millions)
ALABAMA (1) $2,104 $ 375
GEORGIA (2) 3,017 1,519
GULF 341 86
MISSISSIPPI 355 65
SAVANNAH 161 15
SEGCO 90 15
Other (3) 132 53
- ------------------------------------------------------------
SOUTHERN
System $6,200 $2,128
============================================================
(1) Includes approximately $62 million attributable to property sold to AEC in
1992.
(2) Includes approximately $480 million attributable to property sold to OPC,
FP&L and JEA, but excludes $231 million from the write-off of certain Plant
Vogtle costs in 1990.
(3) Net of intercompany eliminations.
ITEM 3. LEGAL PROCEEDINGS
(1) STEPAK V. CERTAIN SOUTHERN OFFICIALS
(U.S. District Court for the Southern District of Georgia)
In April 1991, two SOUTHERN stockholders filed a derivative action suit
against certain current and former directors and officers of SOUTHERN. The
suit alleges violations of RICO by officers and breaches of fiduciary duty
and gross negligence by all defendants resulting from alleged fraudulent
accounting for spare parts, illegal political campaign contributions,
violations of federal securities laws involving misrepresentations and
omissions in SEC filings, and concealment of the foregoing acts. The
complaint seeks damages, including treble damages pursuant to RICO, in an
unspecified amount, which if awarded, would be payable to SOUTHERN. The
plaintiffs' amended complaint was dismissed by the court in March 1992.
The court ruled the plaintiffs had failed to present adequately their
allegation that the
I-22
29
SOUTHERN board of directors' refusal of an earlier demand by the plaintiffs
was wrongful. The plaintiffs appealed the dismissal to the U.S. Court of
Appeals for the Eleventh Circuit.
(2) JOHNSON V. ALABAMA
(Circuit Court of Shelby County, Alabama)
In September 1990, two customers of ALABAMA filed a civil complaint in the
Circuit Court of Shelby County, Alabama, against ALABAMA seeking to
represent all persons who, prior to June 23, 1989, entered into agreements
with ALABAMA for the financing of heat pumps and other merchandise
purchased from vendors other than ALABAMA. The plaintiffs contended that
ALABAMA was required to obtain a license under the Alabama Consumer Finance
Act to engage in the business of making consumer loans. The plaintiffs
were seeking an order declaring these agreements null and void and
requiring ALABAMA to refund all payments, principal and interest, made
under these agreements. The aggregate amount under these agreements,
together with interest paid, currently is estimated to be $40 million.
In June 1993, the court ordered ALABAMA to refund or forfeit interest of
approximately $10 million because of ALABAMA's failure to obtain such
license. However, the court's order did not require any refund or
forfeiture with respect to any principal payments under the agreements
at issue. ALABAMA has appealed the court's order to the Supreme Court of
Alabama.
The final outcome of this matter cannot be determined; however, in
management's opinion, the final outcome will not have a material adverse
effect on SOUTHERN's or ALABAMA's financial statements.
(3) OHIO RIVER COMPANY, ET AL.VS. GULF, ET AL.
(U.S. District Court for Southern District of Ohio, Western Division)
In 1993, a complaint against GULF and SCS was filed in federal district
court in Ohio by two companies with which GULF had contracted for the
transportation by barge for certain GULF coal supplies. The complaint
alleges breach of the contract by GULF and seeks damages estimated by
the plaintiffs to be in excess of $85 million.
The final outcome of this matter cannot now be determined; however, in
management's opinion the final outcome will not have a material adverse
effect on SOUTHERN's or GULF's financial statements.
See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation
- - Federal Power Act" and "Rate Matters", for a description of certain other
administrative and legal proceedings discussed therein.
Additionally, each of the operating affiliates and SEI are, in the normal
course of business, engaged in litigation or administrative proceedings that
include, but are not limited to, acquisition of property, injuries and damages
claims, and complaints by present and former employees. In management's
opinion these various actions will not have a material adverse effect on any of
the registrants' financial statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS
None.
I-23
30
EXECUTIVE OFFICERS OF SOUTHERN
(Inserted in Part I in accordance with Regulation S-K,
Item 401(b), Instruction 3)
EDWARD L. ADDISON
Chairman and CEO
Age 63
Elected in 1983; responsible primarily for the formation
of overall corporate policy. He was elected Chairman
of SOUTHERN effective January 1994.
A. W. DAHLBERG
President and Director
Age 53
Elected in 1985; President and Chief Executive
Officer of GEORGIA from 1988 through 1993. He
was elected Executive Vice President of SOUTHERN
in 1991. He was elected President of SOUTHERN
effective January 1994.
PAUL J. DENICOLA
Executive Vice President and Director
Age 45
Elected in 1989; Executive Vice President of
SOUTHERN since 1991. Elected President and Chief
Executive Officer of SCS effective January 1994. He
previously served as Executive Vice President of SCS
from 1991 to 1993 and President and Chief Executive
Officer of MISSISSIPPI from 1989 to 1991.
H. ALLEN FRANKLIN
Executive Vice President and Director
Age 49
Elected in 1988; President and Chief Executive Officer
of SCS from 1988 through 1993 and, beginning 1991,
Executive Vice President of SOUTHERN. He was
elected President and CEO of GEORGIA effective
January 1994.
ELMER B. HARRIS
Executive Vice President and Director
Age 54
Elected in 1989; President and Chief Executive Officer
of ALABAMA since 1989 and, beginning 1991,
Executive Vice President of SOUTHERN. He previously
served as Senior Executive Vice President of GEORGIA
from 1986 to 1989.
W. L. WESTBROOK
Financial Vice President
Age 54
Elected in 1986; responsible primarily for all aspects of
financing for SOUTHERN. He has served as Executive
Vice President of SCS since 1986.
BILL M. GUTHRIE
Vice President
Age 60 Elected in 1991; serves as Chief Production Officer for
the SOUTHERN system. Senior Executive Vice
President of SCS effective January 1994. He has also
served as Executive Vice President of ALABAMA since
1988.
Each of the above is currently an officer of SOUTHERN, serving a term running
from the last annual meeting of the directors (May 26, 1993) for one year until
the next annual meeting or until his successor is elected and qualified.
I-24
31
PART II
ITEM 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) The common stock of SOUTHERN is listed and traded on the New York
Stock Exchange. The stock is also traded on regional exchanges
across the United States. High and low stock prices, per the New
York Stock Exchange Composite Tape and as adjusted to reflect a
two-for-one stock split in the form of a stock distribution for each
share held as of February 7, 1994, during each quarter for the past
two years were as follows:
---------------------------------------------
High Low
---- ---
1993
First Quarter $21-3/8 $18-3/8
Second Quarter 22-1/2 19-3/8
Third Quarter 23 20-1/2
Fourth Quarter 23-5/8 20-3/4
1992
First Quarter $17-3/8 $15-1/8
Second Quarter 17-5/8 15-5/8
Third Quarter 19 17-3/8
Fourth Quarter 19-1/2 17-5/8
---------------------------------------------
There is no market for the other registrants' common stock, all of
which is owned by SOUTHERN. On February 28, 1994, the closing price
of SOUTHERN's common stock was $20-5/8.
(b) Number of SOUTHERN's common stockholders at December 31, 1993:
237,105
Each of the other registrants have one common stockholder, SOUTHERN.
(c) Common dividends are payable at the discretion of each registrant's
board of directors. The common dividends paid by SOUTHERN and the
operating affiliates to their stockholder(s) for the past two years
were as follows: (in thousands)
=================================================
Registrant Quarter 1993 1992
-------------------------------------------------
SOUTHERN First $180,381 $173,610
Second 180,948 173,610
Third 181,892 173,610
Fourth 182,351 174,052
ALABAMA First 62,900 60,800
Second 63,100 60,900
Third 63,400 60,700
Fourth 63,500 90,900
GEORGIA First 100,100 96,000
Second 100,400 96,200
Third 100,800 95,800
Fourth 101,100 96,000
GULF First 10,400 10,000
Second 10,400 10,000
Third 10,500 9,900
Fourth 10,500 10,000
MISSISSIPPI First 7,200 7,000
Second 7,200 7,000
Third 7,300 7,000
Fourth 7,300 7,000
SAVANNAH First 4,500 5,500
Second 5,500 5,500
Third 5,500 5,500
Fourth 5,500 5,500
-------------------------------------------------
In January 1994, SOUTHERN's board of directors authorized a two-for-one
common stock split in the form of a stock distribution for each share held as
of February 7, 1994. For all reported common stock data, the number of common
shares outstanding and per share amounts for earnings, dividends, and market
price have been adjusted to reflect the stock distribution.
II-1
32
The dividend paid per share by SOUTHERN was 27.5c. for each quarter of 1992
and 28.5c. for each quarter of 1993. SOUTHERN's common dividend for the first
quarter of 1994 was raised to 29.5c. per share.
The amount of common dividends that may be paid by the subsidiary
registrants is restricted in accordance with their respective first mortgage
bond indenture and charter. The amounts of earnings retained in the business
and the amounts restricted against the payment of cash dividends on common
stock at December 31, 1993, were as follows:
Retained Restricted
Earnings Amount
---------- ----------
(in millions)
ALABAMA $ 997 $ 653
GEORGIA 1,316 742
GULF 158 101
MISSISSIPPI 129 86
SAVANNAH 93 55
Consolidated 2,968 1,639
- ------------------------------------------------------
ITEM 6. SELECTED FINANCIAL DATA
SOUTHERN. Reference is made to information under the heading "Selected
Consolidated Financial and Operating Data," contained herein at pages II-38
through II-49.
ALABAMA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-78 through II-91.
GEORGIA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-123 through II-137.
GULF. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II- 166 through
II-179.
MISSISSIPPI. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-207 through II-220.
SAVANNAH. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-245 through II-258.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
SOUTHERN. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-8 through II-15.
ALABAMA. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-53 through II-58.
GEORGIA. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-95 through II-101.
GULF. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-141 through II-147.
MISSISSIPPI. Reference is made to information under the heading
"Management's Discussion and Analysis of Results of Operations and Financial
Condition," contained herein at pages II-183 through II-189.
SAVANNAH. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-224 through II-230.
II-2
33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 1993 FINANCIAL STATEMENTS
PAGE
----
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES:
Report of Independent Public Accountants (in which their opinion on the
financial statements includes an explanatory paragraph which states that
an uncertainty exists with respect to the actions of the regulators
regarding recoverability of the investment in the Rocky Mountain pumped
storage hydroelectric project) II-7
Consolidated Statements of Income for the Years Ended December 31, 1993, 1992 and 1991 II-16
Consolidated Statements of Retained Earnings for the Years Ended December 31, 1993, 1992
and 1991 II-16
Consolidated Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 II-17
Consolidated Balance Sheets at December 31, 1993 and 1992 II-18
Consolidated Statements of Capitalization at December 31, 1993 and 1992 II-20
Consolidated Statements of Paid-In Capital for the Years Ended December 31, 1993, 1992 and 1991 II-21
Notes to Financial Statements II-22
ALABAMA:
Report of Independent Public Accountants II-52
Statements of Income for the Years Ended December 31, 1993, 1992 and 1991 II-59
Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 II-60
Balance Sheets at December 31, 1993 and 1992 II-61
Statements of Capitalization at December 31, 1993 and 1992 II-63
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 II-64
Notes to Financial Statements II-65
GEORGIA:
Report of Independent Public Accountants (in which their opinion on the financial statements
includes an explanatory paragraph which states that an uncertainty exists with respect to the
actions of the regulators regarding the recoverability of Georgia Power's investment in the
Rocky Mountain pumped storage hydroelectric project) II-94
Statements of Income for the Years Ended December 31, 1993, 1992 and 1991 II-102
Balance Sheets at December 31, 1993 and 1992 II-103
Statements of Capitalization at December 31, 1993 and 1992 II-105
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 II-107
Statements of Paid-In Capital for the Years Ended December 31, 1993, 1992 and 1991 II-107
Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 II-108
Notes to Financial Statements II-109
II-3
34
PAGE
----
GULF:
Report of Independent Public Accountants II-140
Statements of Income for the Years Ended December 31, 1993, 1992 and 1991 II-148
Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 II-149
Balance Sheets at December 31, 1993 and 1992 II-150
Statements of Capitalization at December 31, 1993 and 1992 II-152
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 II-154
Statements of Paid-In Capital for the Years Ended December 31, 1993, 1992 and 1991 II-154
Notes to Financial Statements II-155
MISSISSIPPI:
Report of Independent Public Accountants II-182
Statements of Income for the Years Ended December 31, 1993, 1992 and 1991 II-190
Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 II-191
Balance Sheets at December 31, 1993 and 1992 II-192
Statements of Capitalization at December 31, 1993 and 1992 II-194
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 II-195
Statements of Paid-In Capital for the Years Ended December 31, 1993, 1992 and 1991 II-195
Notes to Financial Statements II-196
SAVANNAH:
Report of Independent Public Accountants II-223
Statements of Income for the Years Ended December 31, 1993, 1992 and 1991 II-231
Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 II-232
Balance Sheets at December 31, 1993 and 1992 II-233
Statements of Capitalization at December 31, 1993 and 1992 II-235
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 II-236
Statements of Paid-In Capital for the Years Ended December 31, 1993, 1992 and 1991 II-236
Notes to Financial Statements II-237
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
II-4
35
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-5
36
MANAGEMENT'S REPORT
The Southern Company and Subsidiary Companies 1993 Annual Report
The management of The Southern Company has prepared -- and is responsible for
- -- the consolidated financial statements and related information included in
this report. These statements were prepared in accordance with generally
accepted accounting principles appropriate in the circumstances and necessarily
include amounts that are based on the best estimates and judgments of
management. Financial information throughout this annual report is consistent
with the financial statements.
The company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that books and records
reflect only authorized transactions of the company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The company believes its system of
internal accounting controls maintains an appropriate cost/benefit
relationship.
The company's system of internal accounting controls is evaluated on an
ongoing basis by the company's internal audit staff. The company's independent
public accountants also consider certain elements of the internal control
system in order to determine their auditing procedures for the purpose of
expressing an opinion on the financial statements.
The audit committee of the board of directors, composed of three directors
who are not employees, provides a broad overview of management's financial
reporting and control functions. Periodically, this committee meets with
management, the internal auditors, and the independent public accountants to
ensure that these groups are fulfilling their obligations and to discuss
auditing, internal controls, and financial reporting matters. The internal
auditors and independent public accountants have access to the members of the
audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the consolidated financial statements present
fairly, in all material respects, the financial position, results of
operations, and cash flows of The Southern Company and its subsidiaries in
conformity with generally accepted accounting principles. As discussed in Note
4 to the financial statements, an uncertainty exists with respect to the
actions of regulators regarding recoverability of the investment in the Rocky
Mountain pumped storage hydroelectric project. The outcome of this uncertainty
cannot be determined until regulatory proceedings are concluded. Accordingly,
no provision for any write-down of the costs associated with the Rocky Mountain
project resulting from the potential actions of the Georgia Public Service
Commission has been made in the accompanying financial statements.
/s/ E. L. Addison /s/ W. L. Westbrook
- ------------------------------------ ----------------------------
Edward L. Addison W. L. Westbrook
Chairman and Chief Executive Officer Financial Vice President
II-6
37
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS AND TO THE STOCKHOLDERS OF THE SOUTHERN COMPANY:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of The Southern Company (a Delaware corporation)
and its subsidiaries as of December 31, 1993 and 1992, and the related
consolidated statements of income, retained earnings, 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.
In our opinion, the financial statements (pages II-16 through II-37)
referred to above present fairly, in all material respects, the financial
position of The Southern Company and its subsidiaries as of December 31, 1993
and 1992, and the results of their operations and their cash flows for the
periods stated, in conformity with generally accepted accounting principles.
As explained in Notes 2 and 9 to the financial statements, effective January
1, 1993, The Southern Company changed its methods of accounting for
postretirement benefits other than pensions and for income taxes.
As more fully discussed in Note 4 to the financial statements, an
uncertainty exists with respect to the actions of the regulators regarding
recoverability of the investment in the Rocky Mountain pumped storage
hydroelectric project. The outcome of this uncertainty cannot be determined
until regulatory proceedings are concluded. Accordingly, no provision for any
write-down of the costs associated with the Rocky Mountain project resulting
from the potential actions of the Georgia Public Service Commission has been
made in the accompanying financial statements.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
February 16, 1994
II-7
38
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
The Southern Company and Subsidiary Companies 1993 Annual Report
RESULTS OF OPERATIONS
EARNINGS AND DIVIDENDS
The Southern Company's 1993 financial performance exceeded the strong results
recorded for 1992, and set several new records. The company's financial
strength continued to gain momentum for the third consecutive year. In January
1994, The Southern Company board of directors increased the quarterly dividend
rate by 3.5 percent, and approved a two-for-one common stock split in the form
of a stock distribution. For all reported common stock data, the number of
common shares outstanding and per share amounts for earnings, dividends, and
market price have been adjusted to reflect the stock distribution. For 1993,
The Southern Company's net income of $1.0 billion established a new record high
and the company's common stock reached an all-time high closing price during
the year of 23 3/8 -- surpassing the record of 19 1/2 set in 1992. Also,
return on average common equity reached the highest level since 1986.
Earnings reported for 1993 totaled $1,002 million or $1.57 per share, an
increase of $49 million or 6 cents per share from the previous year. Both 1993
and 1992 earnings were affected by special non-operating or non-recurring
items. After excluding these special items in both years, earnings from
operations of the ongoing business of selling electricity were $1,016 million
or $1.59 per share, an increase of $77 million or 10 cents per share compared
with 1992. The special items that affected 1993 and 1992 earnings were as
follows:
Consolidated Earnings
Net Income Per Share
1993 1992 1993 1992
(in millions)
Earnings as reported $1,002 $953 $1.57 $1.51
Gulf States related (6) (16) (.01) (.03)
Sale of Scherer Unit 4 (18) -- (.03) --
Environmental
cleanup 25 2 .04 .01
Transportation fleet
reductions 13 -- .02 --
Total items excluded 14 (14) .02 (.02)
Earnings from
operations $1,016 $939 $1.59 $1.49
Amount and
percent change $77 8.2% $0.10 6.7%
In 1993, several items -- both positive and negative -- had an impact on
earnings, which resulted in a net reduction of $14 million. These items were:
(1) The conclusion of a settlement agreement -- discussed later -- with Gulf
States Utilities (Gulf States) increased earnings. (2) The second in a series
of four separate transactions to sell Plant Scherer Unit 4 to two Florida
utilities increased earnings. (3) Environmental clean-up costs incurred at
sites located in Alabama and Georgia decreased earnings. (4) Costs associated
with a transportation fleet reduction program decreased earnings. The
improvements in 1993 earnings resulted primarily from increased retail energy
sales and continued emphasis on effective cost controls.
The special items that increased 1992 earnings were primarily related to
additional settlement provisions from Gulf States, and to gains on the sale of
Gulf States common stock received in 1991.
Returns on average common equity were 13.43 percent in 1993, 13.42 percent
in 1992, and 12.74 percent in 1991. Dividends paid on common stock during 1993
were $1.14 per share or 28 1/2 cents per quarter. During 1992 and 1991,
dividends paid per share were $1.10 and $1.07, respectively. In January 1994,
The Southern Company board of directors raised the quarterly dividend to 29 1/2
cents per share or an annual rate of $1.18 per share.
REVENUES
Operating revenues increased in 1993 and 1992 and decreased in 1991 as a result
of the following factors:
Increase (Decrease)
From Prior Year
1993 1992 1991
(in millions)
Retail --
Change in base rates $ 3 $ 137 $ 46
Sales growth 104 138 122
Weather 198 (113) (19)
Fuel cost recovery
and other 199 (55) (36)
Total retail 504 107 113
Sales for resale --
Within service area 38 (8) 5
Outside service area (184) (87) (93)
Total sales for resale (146) (95) (88)
Other operating revenues 58 11 (28)
Total operating revenues $ 416 $ 23 $ (3)
Percent change 5.2% 0.3% 0.0%
II-8
39
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
Retail revenues of $7.3 billion in 1993 increased 7.4 percent from last
year, compared with an increase of 1.6 percent in 1992. Under fuel cost
recovery provisions, fuel revenues generally equal fuel expense -- including
the fuel component of purchased energy -- and do not affect net income.
Sales for resale revenues within the service area were $447 million in 1993,
up 9.2 percent from the prior year. This increase resulted primarily from the
prolonged hot summer weather, which increased the demand for electricity.
Revenues from sales for resale within the service area were $409 million in
1992, down 1.9 percent from the prior year. The decrease resulted from certain
municipalities and cooperatives in the service area retaining more of their own
generation at facilities jointly owned with Georgia Power.
Revenues from sales to utilities outside the service area under long-term
contracts consist of capacity and energy components. Capacity revenues reflect
the recovery of fixed costs and a return on investment under the contracts.
Energy is generally sold at variable cost. The capacity and energy components
were as follows:
1993 1992 1991
(in millions)
Capacity $350 $457 $490
Energy 230 330 366
Total $580 $787 $856
Capacity revenues decreased in 1993 and 1992 because the amount of capacity
under contract declined by some 500 megawatts and 300 megawatts, respectively.
In 1994, the contracted capacity will decline another 400 megawatts.
Changes in revenues are influenced heavily by the amount of energy sold each
year. Kilowatt-hour sales for 1993 and the percent change by year were as
follows:
(billions of Amount Percent Change
kilowatt-hours) 1993 1993 1992 1991
Residential 36.8 9.5% 0.0% 1.5%
Commercial 32.8 5.9 2.1 2.4
Industrial 48.7 1.9 3.8 0.2
Other 0.9 4.6 (4.8) 1.2
Total retail 119.2 5.3 2.1 1.2
Sales for resale --
Within service area 13.3 9.5 (1.7) 10.7
Outside service area 12.4 (25.2) (16.2) (18.7)
Total 144.9 2.1 (0.7) (1.4)
The rate of growth in 1993 retail energy sales was the highest since 1986.
Residential energy sales registered the highest annual increase in two decades
as a result of hotter-than-normal summer weather and the addition of 46,000 new
customers. Commercial sales were also affected by the warm summer. Industrial
energy sales in 1993 and 1992 showed moderate growth, reflecting a recovery in
the business and economic conditions in The Southern Company's service area.
Energy sales to retail customers are projected to grow at an average annual
rate of 1.7 percent during the period 1994 through 2004.
Energy sales for resale outside the service area are predominantly unit
power sales under long-term contracts to Florida utilities. Economy sales and
amounts sold under short-term contracts are also sold for resale outside the
service area. Sales to customers outside the service area have decreased for
the third consecutive year primarily as a result of the scheduled decline in
megawatts of capacity under contract. In addition, the decline in 1992 and
1991 sales was also influenced by fluctuations in prices for oil and natural
gas, the primary fuel sources for utilities with which the company has
long-term contracts. When oil and gas prices fall below a certain level, these
customers can generate electricity to meet their requirements more
economically. However, the fluctuation in these energy sales, excluding the
impact of contractual declines, had minimal effect on earnings because The
Southern Company is paid for dedicating specific amounts of its generating
capacity to these utilities.
EXPENSES
Total operating expenses of $6.7 billion for 1993 were up 6.5 percent compared
with the prior year. The increase was attributable to higher production
expenses of $75 million to meet increased energy demands and an additional $50
million in depreciation expenses and property taxes resulting from additional
utility plant being placed into service. The transportation fleet reduction
program and environmental clean-up costs discussed earlier increased expenses
by some $62 million. Also, a $67 million change in deferred Plant Vogtle
expenses compared with the amount in 1992 contributed to the rise in total
operating expenses.
In 1992, total operating expenses of $6.3 billion were at the same level
reported for 1991. The costs to produce and deliver electricity in 1992
declined by $165 million primarily as a result of less energy being sold and
continued effective cost controls. However, expenses in 1991 were reduced by
proceeds from a settlement
II-9
40
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
agreement with Gulf States that more than offset the decline in 1992 expenses
when compared with 1991. Deferred expenses related to Plant Vogtle in 1992
increased by $47 million when compared with the prior year.
Fuel costs constitute the single largest expense for The Southern Company.
The mix of fuel sources for generation of electricity is determined primarily
by system load, the unit cost of fuel consumed, and the availability of hydro
and nuclear generating units. The amount and sources of generation and the
average cost of fuel per net kilowatt-hour generated were as follows:
1993 1992 1991
Total generation
(billions of kilowatt-hours) 144 140 142
Sources of generation
(percent) --
Coal 78 77 77
Nuclear 17 17 17
Hydro 4 5 5
Oil and gas 1 1 1
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.90 1.86 1.91
Nuclear 0.54 0.54 0.66
Oil and gas 4.34 4.81 2.84
Total 1.67 1.62 1.69
Fuel and purchased power expenses of $2.6 billion in 1993 increased 1.3
percent compared with the prior year because of increased energy demands and
slightly higher average cost of fuel per net kilowatt-hour generated. Fuel and
purchased power costs in 1992 decreased $137 million or 5.0 percent compared
with 1991 primarily because 1.1 billion fewer kilowatt-hours were needed to
meet customer requirements. Also, the decrease in these costs was attributable
to a lower average cost of fuel per net kilowatt-hour generated.
Income taxes for 1993 increased $69 million compared with the prior year.
The increase is attributable to a number of factors, including a 1 percent
increase in the corporate federal income tax rate effective January 1993, the
second sale of additional ownership interest in Plant Scherer Unit 4, and the
increase in taxable income from operations. For 1992, income taxes rose $11
million or 1.7 percent above the amount reported for 1991.
For the fifth consecutive year, total gross interest charges and preferred
stock dividends declined from amounts reported in the previous year. The
declines are attributable to lower interest rates and significant refinancing
activities during the past two years. In 1993, these costs were $831 million
- -- down $21 million or 2.3 percent. These costs for 1992 decreased $71
million. As a result of favorable market conditions during 1993, some $3.0
billion of senior securities was issued for the primary purpose of retiring
higher-cost debt and preferred stock.
EFFECTS OF INFLATION
The Southern Company is subject to rate regulation and income tax laws that are
based on the recovery of historical costs. Therefore, inflation creates an
economic loss because the company is recovering its costs of investments in
dollars that have less purchasing power. While the inflation rate has been
relatively low in recent years, it continues to have an adverse effect on The
Southern Company because of the large investment in long-lived utility plant.
Conventional accounting for historical cost does not recognize this economic
loss nor the partially offsetting gain that arises through financing facilities
with fixed-money obligations such as long-term debt and preferred stock. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
FUTURE EARNINGS POTENTIAL
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends
on numerous factors ranging from growth in energy sales to regulatory matters.
Georgia Power has completed two of four separate transactions to sell Unit 4
of Plant Scherer to two Florida utilities. The remaining transactions are
scheduled to take place in 1994 and 1995. If the sales take place as planned,
Georgia Power could realize an after-tax gain currently estimated to total
approximately $20 million. See Note 7 to the financial statements for
additional information.
In early 1994, Georgia Power and the system service company announced work
force reduction programs that are estimated to reduce 1994 earnings by some $55
million. These actions will assist in efforts to control the growth in
operating expenses.
II-10
41
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
See Note 4 to the financial statements for information on an uncertainty
regarding full recovery of an investment in the Rocky Mountain pumped storage
hydroelectric project.
Future earnings in the near term will depend upon growth in energy sales,
which are subject to a number of factors. Traditionally, these factors have
included changes in contracts with neighboring utilities, energy conservation
practiced by customers, the elasticity of demand, weather, competition, and the
rate of economic growth in the company's service area. However, the Energy
Policy Act of 1992 (Energy Act) will have a profound effect on the future of
the electric utility industry. The Energy Act promotes energy efficiency,
alternative fuel use, and increased competition for electric utilities. The
law also includes provisions to streamline the licensing process for new
nuclear plants. The Southern Company is preparing to meet the challenge of
this major change in the traditional business practices of selling electricity.
The Energy Act allows independent power producers (IPPs) to access a utility's
transmission network in order to sell electricity to other utilities, and this
may enhance the incentive for IPPs to build cogeneration plants for a utility's
large industrial and commercial customers and sell excess energy generation to
other utilities. Although the Energy Act does not require transmission access
to retail customers, pressure for legislation to allow retail wheeling will
continue. If The Southern Company does not remain a low-cost producer and
provide quality service, the company's retail energy sales growth, as well as
new long-term contracts for energy sales outside the service area, could be
limited, and this could significantly erode earnings.
An important part of the Energy Act was to amend the Public Utility Holding
Company Act of 1935 (PUHCA) and allow holding companies to form exempt
wholesale generators and foreign utility companies to sell power largely free
of regulation under PUHCA. These new entities are able to sell power to
affiliates -- under certain restrictions -- and to own and operate power
generating facilities in other domestic and international markets. To take
advantage of these opportunities, Southern Electric International (Southern
Electric) -- founded in 1981 -- is focusing on international and domestic
cogeneration, the independent power market, and the privatization of generating
facilities in the international market. During 1993, investments of some $315
million were made in entities that own and operate generating facilities in
various international markets. In the near term, Southern Electric is expected
to have minimal effect on earnings, but the possibility exists that it could
be a prime contributor to future earnings growth.
Demand-side options -- programs that enable customers to lower or alter
their peak energy requirements -- have been implemented by some of the system
operating companies and are a significant part of integrated resource planning.
See Note 3 to the financial statements under "Georgia Power's Demand-Side
Conservation Programs" for information concerning the recovery of certain
costs. Customers can receive cash incentives for participating in these
programs as well as reduce their energy requirements. Expansion and increased
utilization of these programs will be contingent upon sharing of cost savings
between the customers and the utility. Besides promoting energy efficiency,
another benefit of these programs could be the ability to defer the need to
construct baseload generating facilities further into the future. The ability
to defer major construction projects in conjunction with precertification
approval processes of such projects by the respective state public service
commissions in Alabama, Georgia, and Mississippi will diminish the possible
exposure to prudency disallowances and the resulting impact on earnings. In
addition, Georgia Power has conducted a competitive bidding process for
additional peaking capacity needed in 1996 and 1997. To meet expected
requirements for 1996, Georgia Power has filed a plan with the state public
service commission for certification of a four-year purchase power contract and
for an ownership interest in a combustion turbine peaking unit.
Rates to retail customers served by the system operating companies are
regulated by the respective state public service commissions in Alabama,
Florida, Georgia, and Mississippi. Rates for Alabama Power and Mississippi
Power are adjusted periodically within certain limitations based on earned
retail rate of return compared with an allowed return. See Note 3 to the
financial statements for information about other regulatory matters.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate
schedules and power sales contracts that The Southern Company has with its
sales for resale customers. The FERC currently is reviewing the rate of return
on common equity included in some of these schedules and contracts and may
require such returns to be lowered, possibly retroactively. See Note 3 to the
financial statements under "FERC Reviews Equity Returns" for additional
information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could reduce earnings if such costs are not fully recovered. The Clean
Air Act is discussed later under "Environmental Matters."
II-11
42
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112,
Employers' Accounting for Postemployment Benefits, which must be effective by
1994. The new standard requires that all types of benefits provided to former
or inactive employees and their families prior to retirement be accounted for
on an accrual basis. These benefits include salary continuation, severance
pay, supplemental unemployment benefits, disability-related benefits, job
training, and health and life insurance coverage. In 1993, The Southern
Company adopted Statement No. 112, with no material effect on the financial
statements.
The FASB has issued Statement No. 115, Accounting for Certain Investments in
Debt and Equity Securities, which is effective in 1994. Statement No. 115
supersedes FASB Statement No. 12, Accounting for Certain Marketable Securities.
The Southern Company adopted the new rules January 1, 1994, with no material
effect on the financial statements.
FINANCIAL CONDITION
OVERVIEW
The Southern Company's financial condition is now the strongest since the
mid-1980s. Record levels of performance were set in 1993 related to earnings,
market price of common stock, and energy sold to retail customers. In January
1994, The Southern Company board of directors increased the common stock
dividend for the third consecutive year, and approved a two-for-one common
stock split in the form of a stock distribution.
Another major change in The Southern Company's financial condition was gross
property additions of $1.4 billion to utility plant. The majority of funds
needed for gross property additions since 1990 have been provided from
operating activities, principally from earnings and non-cash charges to income
such as depreciation and deferred income taxes. The Consolidated Statements of
Cash Flows provide additional details.
On January 1, 1993, The Southern Company changed its methods of accounting
for postretirement benefits other than pensions and for income taxes. See
notes 2 and 9 to the financial statements, regarding the impact of these
changes.
CAPITAL STRUCTURE
The company achieved a ratio of common equity to total capitalization --
including short-term debt -- of 43.5 percent in 1993, compared with 42.8
percent in 1992 and 41.5 percent in 1991. The company's goal is to maintain
the common equity ratio generally within a range of 40 percent to 45 percent.
During 1993, the operating companies sold $2.2 billion of first mortgage
bonds and, through public authorities, $385 million of pollution control
revenue bonds, at a combined weighted interest rate of 6.5 percent. Preferred
stock of $426 million was issued at a weighted dividend rate of 5.7 percent.
The operating companies continued to reduce financing costs by retiring
higher-cost bonds and preferred stock. Retirements, including maturities, of
bonds totaled $2.5 billion during 1993, $2.8 billion during 1992, and $1.0
billion during 1991. Retirements of preferred stock totaled $516 million
during 1993, $326 million during 1992, and $125 million during 1991. As a
result, the composite interest rate on long-term debt decreased from 9.2
percent at December 31, 1990, to 7.6 percent at December 31, 1993. During this
same period, the composite dividend rate on preferred stock declined from 8.5
percent to 6.4 percent.
In 1993, The Southern Company raised $205 million from the issuance of new
common stock under the Dividend Reinvestment and Stock Purchase Plan (DRIP) and
the Employee Savings Plan. At the close of 1993, the company's common stock
had a market value of $22.00 per share, compared with a book value of $11.96
per share. The market-to-book value ratio was 184 percent at the end of 1993,
compared with 168 percent at year-end 1992 and 156 percent at year-end 1991.
CAPITAL REQUIREMENTS FOR CONSTRUCTION
The construction program of the operating companies is budgeted at $1.5 billion
for 1994, $1.3 billion for 1995, and $1.5 billion for 1996. The total is $4.3
billion for the three years. Actual construction costs may vary from this
estimate because of factors such as changes in environmental regulations;
changes in existing nuclear plants to meet new regulations; revised load
projections; the cost and efficiency of construction labor, equipment, and
materials; and the cost of capital.
The operating companies do not have any baseload generating plants under
construction, and current energy demand forecasts do not require any additional
baseload facilities until well into the future. However, within the
II-12
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
service area, the construction of combustion turbine peaking units of
approximately 1,700 megawatts of capacity is planned to be completed by 1996 to
meet increased peak-hour demands. In addition, significant construction of
transmission and distribution facilities and upgrading of generating plants
will be continuing.
OTHER CAPITAL REQUIREMENTS
In addition to the funds needed for the construction program, approximately
$789 million will be required by the end of 1996 for present sinking fund
requirements, redemptions announced, and maturities of long-term debt. Also,
the operating subsidiaries plan to continue a program to retire higher-cost
debt and preferred stock and replace these obligations with lower-cost capital.
ENVIRONMENTAL MATTERS
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law -- will have a
significant impact on The Southern Company. Specific reductions in sulfur
dioxide and nitrogen oxide emissions from fossil-fired generating plants will
be required in two phases. Phase I compliance must be implemented in 1995 and
affects eight generating plants -- some 10,000 megawatts of capacity or 35
percent of total capacity -- in the Southern electric system. Phase II
compliance is required in 2000, and all fossil-fired generating plants in the
Southern electric system will be affected.
Beginning in 1995, the Environmental Protection Agency (EPA) will allocate
annual sulfur dioxide emission allowances through the newly established
allowance trading program. An emission allowance is the authority to emit one
ton of sulfur dioxide during a calendar year. The method for allocating
allowances is based on the fossil fuel consumed from 1985 through 1987 for each
affected generating unit. Emission allowances are transferable and can be
bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize the
cost of compliance. The market for emission allowances is developing slower
than expected. However, The Southern Company's sulfur dioxide compliance
strategy is designed to take advantage of allowances as the market develops.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at
the eight affected plants by switching to low-sulfur coal, and this has
required some equipment upgrades. This compliance strategy is expected to
result in unused emission allowances being banked for later use. Additional
construction expenditures are required to install equipment for the control of
nitrogen oxide emissions at these eight plants. Also, continuous emissions
monitoring equipment would be installed on all fossil-fired units. Under this
Phase I compliance approach, additional construction expenditures are estimated
to total approximately $275 million through 1995.
Phase II compliance costs are expected to be higher because requirements are
stricter and all fossil-fired generating plants are affected. For sulfur
dioxide compliance, The Southern Company could use emission allowances banked
during Phase I, increase fuel switching, install flue gas desulfurization
equipment at selected plants, and/or purchase more allowances depending on the
price and availability of allowances. Also, in Phase II, equipment to control
nitrogen oxide emissions will be installed on additional system fossil-fired
plants as required to meet anticipated Phase II limits. Therefore, during the
period 1996 to 2000, compliance could require total construction expenditures
ranging from approximately $450 million to $800 million. However, the full
impact of Phase II compliance cannot now be determined with certainty, pending
the development of a market for emission allowances, the completion of EPA
regulations, and the possibility of new emission reduction technologies.
An average increase of up to 3 percent in revenue requirements from
customers could be necessary to fully recover the cost of compliance for both
Phase I and Phase II of the Clean Air Act. Compliance costs include
construction expenditures, increased costs for switching to low-sulfur coal,
and costs related to emission allowances.
There can be no assurance that all Clean Air Act costs will be recovered.
Metropolitan Atlanta is classified as a non-attainment area with regard to
the ozone ambient air quality standards. Title I of the Clean Air Act requires
the state of Georgia to conduct specific studies and establish new control
rules by November 1994 -- affecting sources of nitrogen oxides and volatile
organic compounds -- to achieve attainment by 1999. As the required first
step, the state has issued rules for the application of reasonably available
control technology to reduce nitrogen oxide emissions by May 31, 1995. The
results of these new rules require nitrogen oxide controls, above Title IV
II-13
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
requirements, on some Georgia Power plants. Final attainment rules, based on
modeling studies, could require installation of additional controls for
nitrogen oxide emissions as early as 1997. Compliance with any new rules could
result in significant additional costs. The impact of new rules will depend on
the development and implementation of such rules.
Title III of the Clean Air Act requires a multi-year EPA study of power
plant emissions of hazardous air pollutants. The study will serve as the basis
for a decision on whether additional regulatory control of these substances is
warranted. Compliance with any new control standards could result in
significant additional costs. The impact of new standards -- if any -- will
depend on the development and implementation of applicable regulations.
The EPA continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study on
the impact of a new standard indicate that a number of plants could be required
to install sulfur dioxide controls. These controls would be in addition to the
controls already required to meet the acid rain provision of the Clean Air Act.
The EPA is expected to take some action on this issue in 1994. The impact of
any new standard will depend on the level chosen for the standard and cannot be
determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air
quality standards for particulate matter, nitrogen oxides, and ozone. The
impact of any new standard will depend on the level chosen for the standard and
cannot be determined at this time.
In 1994 or 1995, the EPA is expected to issue revised rules on air quality
control regulations related to stack height requirements of the Clean Air Act.
The full impact of the final rules cannot be determined at this time, pending
their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of coal
ash. However, the EPA has until 1998 to classify co-managed utility wastes --
coal ash and other utility wastes -- as either non-hazardous or hazardous. If
the EPA classifies the co-managed wastes as hazardous, then substantial
additional costs for the management of such wastes may be required. The full
impact of any change in the regulatory status will depend on the subsequent
development of co-managed waste requirements.
The Southern Company must comply with other environmental laws and
regulations that cover the handling and disposal of hazardous waste. Under
these various laws and regulations, the company could incur costs to clean up
properties currently or previously owned. The company conducts studies to
determine the extent of any required clean-up costs and has recognized in the
financial statements costs to clean up known sites.
Several major pieces of environmental legislation are in the process of
being reauthorized or amended by Congress. These include: the Clean Water
Act; the Comprehensive Environmental Response, Compensation, and Liability Act;
and the Resource Conservation and Recovery Act. Changes to these laws could
affect many areas of The Southern Company's operations. The full impact of
these requirements cannot be determined at this time, pending the development
and implementation of applicable regulations.
Compliance with possible new legislation related to global climate change,
electromagnetic fields, and other environmental and health concerns could
significantly affect The Southern Company. The impact of new legislation -- if
any -- will depend on the subsequent development and implementation of
applicable regulations. In addition, the potential for lawsuits alleging
damages caused by electromagnetic fields exists.
SOURCES OF CAPITAL
In early 1994, The Southern Company sold -- through a public offering -- common
stock with proceeds totaling $120 million. The company may require additional
equity capital during the remainder of 1994. The amount and timing of
additional equity capital to be raised in 1994 -- as well as in subsequent
years -- will be contingent on The Southern Company's investment opportunities.
Equity capital can be provided from any combination of public offerings,
private placements, or the company's stock plans. Any portion of the common
stock required during 1994 for the DRIP and the employee stock plans that is
not provided from the issuance of new stock will be acquired on the open market
in accordance with the terms of such plans.
The operating subsidiaries plan to obtain the funds required for
construction and other purposes from sources similar to those used in the past.
However, the type and timing of any financings -- if needed -- will depend on
market conditions and regulatory approval.
II-14
45
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
Completing the sale of Unit 4 of Plant Scherer will provide some $260
million of cash during the years 1994 and 1995.
As required by the Nuclear Regulatory Commission, Alabama Power and Georgia
Power established external sinking funds for nuclear decommissioning costs.
For 1994 through 2000, the combined amount to be funded for both Alabama Power
and Georgia Power totals $36 million annually. The cumulative effect of
funding over this period will diminish internally funded capital and may
require capital from other sources. For additional information concerning
nuclear decommissioning costs, see Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning."
To meet short-term cash needs and contingencies, the system companies had
approximately $178 million of cash and cash equivalents and $1.1 billion of
unused credit arrangements with banks at the beginning of 1994.
To issue additional first mortgage bonds and preferred stock, the operating
companies must comply with certain earnings coverage requirements designated in
their mortgage indentures and corporate charters. The ability to issue
securities in the future will depend on coverages at that time. The coverage
ratios were, at the end of the respective years, as follows:
Mortgage Charter
Coverage Coverage
(2.00* (1.50
Required) Required)
1993 1992 1993 1992
Alabama Power 5.70 5.86 2.71 2.56
Georgia Power 7.75 6.38 2.61 2.23
Gulf Power 5.79 5.27 2.56 2.35
Mississippi Power 5.78 5.68 2.67 2.51
Savannah Electric 3.94 5.01 2.20 2.65
*Savannah Electric's requirement is 2.50.
II-15
46
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1993, 1992, and 1991
The Southern Company and Subsidiary Companies 1993 Annual Report
1993 1992 1991
(in millions)
OPERATING REVENUES $8,489 $8,073 $8,050
OPERATING EXPENSES:
Operation --
Fuel 2,265 2,114 2,237
Purchased power 336 454 468
Proceeds from settlement of disputed contracts (Note 8) (3) (7) (181)
Other 1,448 1,317 1,321
Maintenance 653 613 637
Depreciation and amortization 793 768 763
Amortization of deferred Plant Vogtle expenses, net (Note 1) 36 (31) 16
Taxes other than income taxes 462 436 432
Federal and state income taxes 734 647 618
Total operating expenses 6,724 6,311 6,311
OPERATING INCOME 1,765 1,762 1,739
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction 9 10 13
Deferred return on Plant Vogtle (Note 1) -- -- 35
Interest income 30 32 30
Other, net (41) (50) (57)
Income taxes applicable to other income 57 39 21
INCOME BEFORE INTEREST CHARGES 1,820 1,793 1,781
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest on long-term debt 595 684 757
Allowance for debt funds used during construction (13) (12) (18)
Interest on notes payable 30 16 20
Amortization of debt discount, premium, and expense, net 26 14 9
Other interest charges 87 34 29
Preferred dividends of subsidiary companies 93 104 108
Net interest charges and preferred dividends 818 840 905
CONSOLIDATED NET INCOME $1,002 $ 953 $ 876
COMMON STOCK DATA: (Note 10)
Average number of shares of common stock outstanding (in millions) 637 632 632
Earnings per share of common stock $1.57 $1.51 $ 1.39
Cash dividends paid per share of common stock $1.14 $1.10 $ 1.07
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1993, 1992, and 1991
1993 1992 1991
(in millions)
BALANCE AT BEGINNING OF YEAR $2,721 $2,490 $2,296
Consolidated net income 1,002 953 876
3,723 3,443 3,172
Cash dividends on common stock 726 695 676
Capital and preferred stock transactions, net 29 27 6
BALANCE AT END OF YEAR (Note 14) $2,968 $2,721 $2,490
The accompanying notes are an integral part of these statements.
II-16
47
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1993, 1992, and 1991
The Southern Company and Subsidiary Companies 1993 Annual Report
1993 1992 1991
(in millions)
OPERATING ACTIVITIES:
Consolidated net income $ 1,002 $ 953 $ 876
Adjustments to reconcile consolidated net income
to net cash provided by operating activities --
Depreciation and amortization 1,011 969 968
Deferred income taxes and investment tax credits 189 215 15
Allowance for equity funds used during construction (9) (10) (13)
Deferred Plant Vogtle costs (Note 1) 36 (31) (19)
Non-cash proceeds from settlement of disputed
contracts (Note 8) -- (7) (141)
Gain on asset sales (36) -- (37)
Other, net (9) (25) 82
Changes in certain current assets and liabilities --
Receivables, net (55) (10) 68
Fossil fuel stock 138 53 21
Materials and supplies (2) (76) (1)
Accounts payable 43 35 (13)
Other (61) (71) 61
Net cash provided from operating activities 2,247 1,995 1,867
INVESTING ACTIVITIES:
Gross property additions (1,441) (1,105) (1,123)
Foreign utility operations (465) -- --
Sales of property 262 44 291
Other (37) 61 (45)
Net cash used for investing activities (1,681) (1,000) (877)
FINANCING ACTIVITIES:
Proceeds --
Common stock 205 30 --
Preferred stock 426 410 100
First mortgage bonds 2,185 1,815 380
Other long-term debt 592 256 140
Prepaid capacity revenues -- -- 53
Retirements --
Preferred stock (516) (326) (125)
First mortgage bonds (2,178) (2,575) (881)
Other long-term debt (450) (296) (200)
Increase in notes payable, net 114 525 180
Payment of common stock dividends (726) (695) (676)
Miscellaneous (137) (148) (41)
Net cash used for financing activities (485) (1,004) (1,070)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 81 (9) (80)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 97 106 186
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 178 $ 97 $ 106
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for --
Interest (net of amount capitalized) $ 673 $ 743 $ 802
Income taxes 530 458 428
The accompanying notes are an integral part of these statements.
II-17
48
CONSOLIDATED STATEMENTS OF BALANCE SHEETS
At December 31, 1993, and 1992
The Southern Company and Subsidiary Companies 1993 Annual Report
ASSETS 1993 1992
(in millions)
UTILITY PLANT:
Plant in service (Note 1) $27,687 $27,033
Less accumulated provision for depreciation 8,934 8,280
18,753 18,753
Nuclear fuel, at amortized cost 229 257
Construction work in progress (Note 4) 1,031 665
Total 20,013 19,675
Less property-related accumulated deferred income taxes (Note 9) -- 3,186
Total 20,013 16,489
OTHER PROPERTY AND INVESTMENTS:
Foreign utility operations, being amortized (Note 5) 559 --
Nuclear decommissioning trusts 88 52
Miscellaneous 89 75
Total 736 127
CURRENT ASSETS:
Cash and cash equivalents 178 97
Investment securities -- 199
Receivables, less accumulated provisions for uncollectible accounts
of $9 million in 1993 and $7 million in 1992 1,147 919
Fossil fuel stock, at average cost 254 392
Materials and supplies, at average cost 535 533
Prepayments 148 220
Vacation pay deferred (Note 1) 73 70
Total 2,335 2,430
DEFERRED CHARGES:
Deferred charges related to income taxes (Note 9) 1,546 --
Deferred Plant Vogtle costs (Note 1) 507 383
Debt expense, being amortized 33 28
Premium on reacquired debt, being amortized 288 222
Deferred fuel charges (Note 5) 70 89
Miscellaneous 383 270
Total 2,827 992
TOTAL ASSETS $25,911 $20,038
The accompanying notes are an integral part of these balance sheets.
II-18
49
CONSOLIDATED BALANCE SHEETS (continued)
At December 31, 1993 and 1992
The Southern Company and Subsidiary Companies 1993 Annual Report
CAPITALIZATION AND LIABILITIES 1993 1992
(in millions)
CAPITALIZATION (See accompanying statements):
Common stock equity $7,684 $ 7,234
Preferred stock 1,332 1,351
Preferred stock subject to mandatory redemption 1 8
Long-term debt 7,412 7,241
Total 16,429 15,834
CURRENT LIABILITIES:
Preferred stock due within one year 1 65
Long-term debt due within one year 156 188
Notes payable 941 827
Accounts payable 698 646
Customer deposits 103 99
Taxes accrued --
Federal and state income 34 27
Other 172 145
Interest accrued 186 191
Vacation pay accrued 90 86
Miscellaneous 190 242
Total 2,571 2,516
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes (Note 9) 3,979 --
Deferred credits related to income taxes (Note 9) 1,051 --
Accumulated deferred investment tax credits 900 957
Disallowed Plant Vogtle capacity buyback costs 63 72
Prepaid capacity revenues 144 148
Miscellaneous 774 511
Total 6,911 1,688
COMMITMENTS AND CONTINGENT MATTERS (Notes 1, 3, 4, 5, 6, 7, 8, and 13)
TOTAL CAPITALIZATION AND LIABILITIES $25,911 $20,038
The accompanying notes are an integral part of these balance sheets.
II-19
50
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1993 and 1992
The Southern Company and Subsidiary Companies 1993 Annual Report
1993 1992 1993 1992
(in millions) (percent of total)
COMMON STOCK EQUITY:
Common stock, par value $5 per share --
Authorized -- 1 billion shares
Outstanding -- 1993: 637 million shares, 1992:
632 million shares (Note 10) $ 3,213 $ 1,582
Paid-in capital 1,502 2,929
Premium on preferred stock 1 2
Retained earnings (Note 14) 2,968 2,721
Total common stock equity 7,684 7,234 46.8% 45.7%
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
$100 par or stated value --
4.20% to 5.96% 199 199
6.32% to 7.88% 205 182
8.04% to 8.80% -- 225
$25 par or stated value --
$1.90 to $2.125 295 295
6.40% to 9.50% 323 200
Auction rates -- at January 1, 1994;
2.72% to 2.92% 70 50
Adjustable rates -- at January 1, 1994;
4.80% to 7.57% 240 200
Total (annual dividend requirement -- $85 million) 1,332 1,351 8.1 8.5
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES
SUBJECT TO MANDATORY REDEMPTION:
$100 par value --
11.36% 2 3
$25 stated value --
$2.43 -- 45
$2.50 -- 25
Total 2 73
Less amount due within one year 1 65
Total excluding amount due within one year 1 8 0.0 0.1
II-20
51
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1993 and 1992
The Southern Company and Subsidiary Companies 1993 Annual Report
1993 1992 1993 1992
(in millions) (percent of total)
LONG-TERM DEBT:
First mortgage bonds of subsidiaries --
Maturity Interest Rates
1994 4 5/8% 26 78
1995 4 3/4% to 5 1/8% 141 211
1996 4 1/2% to 6 1/4% 235 100
1997 5 7/8% to 7 1/8% 25 113
1998 5% to 9.2% 249 98
1999 through 2003 6% to 8 3/4% 1,580 1,626
2004 through 2008 6 7/8% to 9% 230 182
2014 through 2018 9 3/8% to 10 3/4% 85 975
2019 through 2023 7.3% to 9 3/8% 1,909 1,040
2020 Variable rates -- 50
2032 Variable rates 200 200
Total first mortgage bonds 4,680 4,673
Other long-term debt (Note 11) 2,962 2,820
Unamortized debt premium (discount), net (74) (64)
Total long-term debt (annual interest
requirement -- $581 million) 7,568 7,429
Less amount due within one year (Note 12) 156 188
Long-term debt excluding amount due within one year 7,412 7,241 45.1 45.7
TOTAL CAPITALIZATION 16,429 $ 15,834 100.0% 100.0%
CONSOLIDATED STATEMENTS OF PAID-IN CAPITAL
For The Years Ended December 31, 1993, 1992, and 1991
1993 1992 1991
(in millions)
BALANCE AT BEGINNING OF YEAR $2,929 $2,906 $2,906
Proceeds from sales of common stock over the par value -- 9.7 million
and 1.6 million shares in 1993 and 1992, respectively 179 23 --
Two-for-one stock split (Note 10) (1,606) -- --
BALANCE AT END OF YEAR $1,502 $2,929 $2,906
The accompanying notes are an integral part of these statements.
II-21
52
NOTES TO FINANCIAL STATEMENTS
The Southern Company and Subsidiary Companies 1993 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
GENERAL
The Southern Company is the parent company of five operating companies, a
system service company, Southern Electric International (Southern Electric),
Southern Nuclear Operating Company (Southern Nuclear), and various other
subsidiaries related to foreign utility operations and domestic non-utility
operations. At this time, the operations of the other subsidiaries are not
material. The operating companies provide electric service in four
Southeastern states. Contracts among the companies -- dealing with jointly
owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) or the Securities and Exchange Commission (SEC). The system
service company provides, at cost, specialized services to The Southern Company
and to the subsidiary companies. Southern Electric designs, builds, owns, and
operates power production facilities and provides a broad range of technical
services to industrial companies and utilities in the United States and a
number of international markets. Southern Nuclear provides services to The
Southern Company's nuclear power plants.
The Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both the company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The
operating companies also are subject to regulation by the FERC and their
respective state regulatory commissions. The companies follow generally
accepted accounting principles and comply with the accounting policies and
practices prescribed by their respective commissions.
All material intercompany items have been eliminated in consolidation.
Consolidated retained earnings at December 31, 1993, include $2.6 billion of
undistributed retained earnings of subsidiaries.
Certain prior years' data presented in the consolidated financial statements
have been reclassified to conform with current year presentation.
REVENUES AND FUEL COSTS
The operating companies accrue revenues for service rendered but unbilled at
the end of each fiscal period. Fuel costs are expensed as the fuel is used.
The operating companies' electric rates include provisions to adjust billings
for fluctuations in fuel and the energy component of purchased power costs.
Revenues are adjusted for differences between recoverable fuel costs and
amounts actually recovered in current rates.
Fuel expense includes the amortization of the cost of nuclear fuel and a
charge, based on nuclear generation, for the permanent disposal of spent
nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted
to $137 million in 1993, $132 million in 1992, and $162 million in 1991.
Alabama Power and Georgia Power have contracts with the U.S. Department of
Energy (DOE) that provide for the permanent disposal of spent nuclear fuel,
which was scheduled to begin in 1998. However, the actual year this service
will begin is uncertain. Sufficient storage capacity currently is available to
permit operation into 2003 at Plant Hatch, into 2009 at Plant Vogtle, and into
2012 and 2014 at Plant Farley units 1 and 2, respectively.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a
Uranium Enrichment Decontamination and Decommissioning Fund, which is to be
funded in part by a special assessment on utilities with nuclear plants. This
assessment will be paid over a 15-year period, which began in 1993. This fund
will be used by the DOE for the decontamination and decommissioning of its
nuclear fuel enrichment facilities. The law provides that utilities will
recover these payments in the same manner as any other fuel expense. Georgia
Power -- based on its ownership interests -- and Alabama Power currently
estimate their liability under this law to be approximately $39 million and $46
million, respectively. These obligations are recorded in the Consolidated
Balance Sheets.
DEPRECIATION AND NUCLEAR DECOMMISSIONING
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.3 percent in 1993, 1992, and 1991. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its cost --
together with the cost of removal, less salvage -- is charged to the
accumulated provision for depreciation. Minor items of property included in
the original cost of the plant are retired when the related property unit is
retired. Depreciation expense includes an amount for the expected costs of
decommissioning nuclear facilities.
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NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
In 1988, the Nuclear Regulatory Commission (NRC) adopted regulations
requiring all licensees operating commercial power reactors to establish a plan
for providing, with reasonable assurance, funds for decommissioning.
Reasonable assurance may be in the form of an external sinking fund, a surety
method, or prepayment. Alabama Power and Georgia Power have established
external sinking funds to comply with the NRC's regulations. Prior to the
enactment of these regulations, Alabama Power and Georgia Power had reserved
nuclear decommissioning costs. The NRC's minimum external funding requirements
are based on a generic estimate of the cost to decommission the radioactive
portions of a nuclear unit based on the size and type of reactor. Alabama
Power and Georgia Power have filed plans with the NRC to ensure that -- over
time -- the deposits and earnings of the external trust funds will provide the
minimum funding amounts prescribed by the NRC.
The estimated cost of decommissioning and the amounts being recovered
through rates at December 31, 1993, for Alabama Power's Plant Farley and
Georgia Power's plants Hatch and Vogtle -- based on its ownership interests --
were as follows:
Plant Plant Plant
Farley Hatch Vogtle
Site study basis (year) 1993 1990 1990
Estimated completion of
decommissioning (year) 2029 2027 2037
(in millions)
Cost of decommissioning:
Radiated structures $409 $184 $155
Non-radiated structures 75 35 62
Other 94 55 54
Total cost $578 $274 $271
(in millions)
Approved for ratemaking $578 $184 $155
Amount expensed in 1993 14 6 6
Balance in external trust fund 50 22 16
Balance in internal reserve 53 33 11
The amounts in the internal reserve are being transferred into the external
trust fund over a set period of time as approved by the respective state public
service commissions.
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of regulatory requirements, changes in
technology, and changes in costs of labor, materials, and equipment.
PLANT VOGTLE PHASE-IN PLANS
In 1987 and 1989, the Georgia Public Service Commission (GPSC) ordered that the
allowed costs of Plant Vogtle, a two-unit nuclear facility of which Georgia
Power owns 45.7 percent, be phased into rates under plans that meet the
requirements of Financial Accounting Standards Board (FASB) Statement No. 92,
Accounting for Phase-In Plans. Under these plans, Georgia Power deferred
financing costs and depreciation expense until the allowed investment was fully
reflected in rates as of October 1991. In 1991, the GPSC modified the Plant
Vogtle phase-in plan to begin earlier amortization of the costs deferred under
the plan. Also, the GPSC levelized capacity buyback expense from co-owners of
Plant Vogtle. See Note 3 for additional information regarding Georgia Power's
1991 rate order. Previously, pursuant to two separate interim accounting
orders by the GPSC, Georgia Power deferred substantially all operating expenses
and financing costs related to Plant Vogtle. Units 1 and 2 began commercial
operation in May 1987 and May 1989, respectively. The accounting orders were
for the periods from the date of each unit's commercial operation until October
1987 and 1989, respectively. Under phase-in plans and accounting orders from
the GPSC, Georgia Power deferred and began amortizing the costs -- recovered
through rates -- related to Plant Vogtle as follows:
Unrecovered
Balance
Year-End
1993 1992 1991 1993
(in millions)
Deferred:
Financing costs $ -- $ -- $ 35 $388
Capacity buyback
expense 38 100 30 168
Other operating
expenses -- -- 7 279
Amortization of
amounts deferred (74) (69) (53) (328)
Net deferred amounts $ (36) $31 $ 19 $507
The unrecovered balance above includes approximately $160 million related
to the adoption in 1993 of FASB Statement No. 109, Accounting for Income Taxes.
See Note 9 for information about Statement No. 109.
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NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
Each GPSC order calls for recovery of deferred costs within 10 years. Also,
the orders authorized Georgia Power to impute a return similar to allowance for
funds used during construction (AFUDC) on its investment in Plant Vogtle units
1 and 2 after the units began commercial operation. These deferred returns are
included in the above amounts, except for the equity component in the case of
the Unit 2 accounting order.
INCOME TAXES
The companies provide deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
In years prior to 1993, income taxes were accounted for and reported under
Accounting Principles Board Opinion No. 11. Effective January 1, 1993, The
Southern Company adopted FASB Statement No. 109, Accounting for Income Taxes.
Statement No. 109 required, among other things, conversion to the liability
method of accounting for accumulated deferred income taxes. See Note 9 for
additional information about Statement No. 109.
AFUDC AND DEFERRED RETURN
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. The composite rates used by the companies to calculate
AFUDC during the years 1991 through 1993 ranged from a before-income-tax rate
of 4.9 percent to 11.4 percent. Deferred income taxes related to capitalized
debt cost were $5 million, $4 million, and $7 million in 1993, 1992, and 1991,
respectively. After Plant Vogtle units 1 and 2 began commercial operation in
1987 and 1989, respectively, Georgia Power imputed a deferred return similar to
AFUDC on its investment in the units under the short-term cost deferrals and
phase-in plans, as discussed earlier. AFUDC and the deferred return, net of
income tax, as a percent of consolidated net income were 1.7 percent in 1993,
1.8 percent in 1992, and 6.0 percent in 1991. The deferred return was
discontinued in October 1991 after the allowed investment in Plant Vogtle was
fully reflected in rates.
UTILITY PLANT
Utility plant is stated at original cost less regulatory disallowances.
Original cost includes: materials; labor; minor items of property; appropriate
administrative and general costs; payroll-related costs such as taxes,
pensions, and other benefits; and the estimated cost of funds used during
construction. The cost of maintenance, repairs, and replacement of minor items
of property is charged to maintenance expense. The cost of replacements of
property (exclusive of minor items of property) is charged to utility plant.
CASH AND CASH EQUIVALENTS
For purposes of the Consolidated Statements of Cash Flows, temporary cash
investments are considered cash equivalents. Temporary cash investments are
securities with original maturities of 90 days or less.
FINANCIAL INSTRUMENTS
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, all financial instruments of The Southern Company -- for
which the carrying amount does not approximate fair value -- are shown in the
table below at December 31:
1993
Carrying Fair
Amount Value
(in millions)
Nuclear decommissioning trusts $ 88 $ 90
Long-term debt 7,321 7,729
Preferred stock subject
to mandatory redemption 2 2
1992
Carrying Fair
Amount Value
(in millions)
Nuclear decommissioning trusts $ 52 $ 53
Investment securities 199 221
Long-term debt 7,165 7,566
Preferred stock subject
to mandatory redemption 73 79
The fair values of nuclear decommissioning trusts and investment securities
were based on listed closing market prices. The fair values for long-term debt
and preferred
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NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
stock subject to mandatory redemption were based on either closing market
prices or closing prices of comparable instruments.
MATERIALS AND SUPPLIES
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to
inventory when purchased and then expensed or capitalized to plant, as
appropriate, when installed. In 1992, Georgia Power converted to the inventory
method of accounting for certain emergency spare parts. This conversion
resulted in a regulatory liability that will be amortized as a credit to income
over approximately four years. This conversion will not have a material effect
on net income.
VACATION PAY
The operating companies' employees earn their vacation in one year and take it
in the subsequent year. However, for ratemaking purposes, vacation pay is
recognized as an allowable expense only when paid. Consistent with this
ratemaking treatment, the companies accrue a current liability for earned
vacation pay and record a current asset representing the future recoverability
of this cost. The amount was $73 million and $70 million at December 31, 1993
and 1992, respectively. In 1994, an estimated 71 percent of the 1993 deferred
vacation cost will be expensed, and the balance will be charged to construction
and other accounts.
2. RETIREMENT BENEFITS
PENSION PLAN
The system companies have defined benefit, trusteed, non-contributory pension
plans that cover substantially all regular employees. Benefits are based on
the greater of amounts resulting from two different formulas: years of service
and final average pay or years of service and a flat-dollar benefit.
Primarily, the companies use the "entry age normal method with a frozen initial
liability" actuarial method for funding purposes, subject to limitations under
federal income tax regulations. Amounts funded to the pension fund are
primarily invested in equity and fixed-income securities. FASB Statement No.
87, Employers' Accounting for Pensions, requires use of the "projected unit
credit" actuarial method for financial reporting purposes.
POSTRETIREMENT BENEFITS
The system companies also provide certain medical care and life insurance
benefits for retired employees. Substantially all employees may become
eligible for these benefits when they retire. A qualified trust for medical
benefits has been established for funding amounts to the extent deductible
under federal income tax regulations. Amounts funded are primarily invested in
debt and equity securities. Accrued costs of life insurance benefits, other
than current cash payments for retirees, currently are not being funded.
Effective January 1, 1993, the system companies adopted FASB Statement No.
106, Employers' Accounting for Postretirement Benefits Other Than Pensions, on
a prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service." In October
1993, the GPSC ordered Georgia Power to phase in the adoption of Statement No.
106 to cost of service over a five-year period, whereby one-fifth of the
additional costs would be expensed in 1993 and the remaining costs would be
deferred. An additional one-fifth of the costs would be expensed each
succeeding year until the costs are fully reflected in cost of service in 1997.
The costs deferred during the five-year period will be amortized to expense
over a 15-year period beginning in 1998. As a result of regulatory treatment
allowed by the operating companies' respective public service commissions, the
adoption of Statement No. 106 did not have a material impact on consolidated
net income.
Prior to 1993, the system companies, except for Georgia Power and Savannah
Electric, recognized these benefit costs on an accrual basis using the
"aggregate cost" actuarial method, which spreads the expected cost of such
benefits over the remaining periods of employees' service as a level percentage
of payroll costs. Consistent with regulatory treatment in these years, Georgia
Power and Savannah Electric recognized these costs on a cash basis as payments
were made. The total costs of such benefits recognized by system companies in
1992 and 1991 were $42 million and $36 million, respectively.
STATUS AND COST OF BENEFITS
Shown in the following tables are actuarial results and assumptions for pension
and postretirement medical and life insurance benefits as computed under the
requirements of FASB Statement Nos. 87 and 106, respectively. Retiree medical
and life insurance information is shown only for 1993 because Statement
II-25
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NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
No. 106 was adopted as of January 1, 1993, on a prospective basis. The funded
status of the plans at December 31 was as follows:
Pension
1993 1992
(in millions)
Actuarial present value of
benefit obligation:
Vested benefits $ 1,534 $ 1,293
Non-vested benefits 76 62
Accumulated benefit obligation 1,610 1,355
Additional amounts related to
projected salary increases 558 638
Projected benefit obligation 2,168 1,993
Less:
Fair value of plan assets 3,337 2,994
Unrecognized net gain (1,060) (891)
Unrecognized prior service cost 72 77
Unrecognized transition asset (152) (164)
Prepaid asset recognized in the
Consolidated Balance Sheets $ 29 $ 23
Postretirement
Medical Life
1993 1993
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $ 243 $ 75
Employees eligible to retire 48 --
Other employees 389 96
Accumulated benefit obligation 680 171
Less:
Fair value of plan assets 95 2
Unrecognized net loss (gain) 76 (13)
Unrecognized transition obligation 419 113
Accrued liability recognized in the
Consolidated Balance Sheets $ 90 $ 69
The weighted average rates assumed in the above
actuarial calculations were:
1993 1992 1991
Discount 7.5% 8.0% 8.0%
Annual salary increase 5.0 6.0 6.0
Long-term return on
plan assets 8.5 8.5 8.5
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend rate
of 11.3 percent for 1993, decreasing gradually to 6.0 percent through the year
2000 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate by 1 percent would increase the accumulated
medical benefit obligation at December 31, 1993, by $129 million and the
aggregate of the service and interest cost components of the net retiree
medical cost by $14 million.
Components of the plans' net cost are shown below:
Pension
1993 1992 1991
(in millions)
Benefits earned during the year $ 76 $ 75 $ 71
Interest cost on projected
benefit obligation 156 146 138
Actual return on plan assets (432) (135) (745)
Net amortization and deferral 186 (85) 551
Net pension cost (income) $ (14) $ 1 $ 15
Of the above net pension amounts, pension income of $9 million in 1993 and
pension expense of $2 million in 1992 and $11 million in 1991 were recorded in
operating expenses, and the remainder was recorded in construction and other
accounts.
Postretirement
Medical Life
1993 1993
(in millions)
Benefits earned during the year $ 21 $ 6
Interest cost on accumulated
benefit obligation 43 13
Amortization of transition
obligation over 20 years 22 6
Actual return on plan assets (12) --
Net amortization and deferral 5 --
Net postretirement cost $ 79 $ 25
Of the above net postretirement medical and life insurance costs recorded in
1993, $64 million was charged to operating expenses, $21 million was deferred,
and the remainder was charged to construction and other accounts.
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NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
WORK FORCE REDUCTION PROGRAMS
The system companies have incurred additional costs for work force reduction
programs. The costs related to these programs were $35 million, $37 million,
and $72 million for the years 1993, 1992, and 1991, respectively. A portion of
the cost of these programs was deferred and is being amortized in accordance
with regulatory treatment. The unamortized balance of these costs was $19
million at December 31, 1993.
3. LITIGATION AND REGULATORY MATTERS
RETAIL RATEPAYERS' SUIT CONCLUDED
In March 1993, several retail ratepayers of Georgia Power filed a civil
complaint in the Superior Court of Fulton County, Georgia, against Georgia
Power, The Southern Company, the system service company, and Arthur Andersen &
Co. The complaint alleged that Georgia Power obtained excessive rate increases
by improper accounting for spare parts and sought actual damages estimated by
the plaintiffs to be in excess of $60 million -- plus treble and punitive
damages -- for alleged violations of the Georgia Racketeer Influenced and
Corrupt Organizations Act and other state statutes, statutory and common law
fraud, and negligence. These state law allegations were substantially the
same as those included in a 1989 suit brought in federal district court in
Georgia. That suit and similar ones filed in Alabama, Florida, and
Mississippi federal courts were subsequently dismissed.
The defendants' motions to dismiss the current complaint were granted by the
Superior Court of Fulton County, Georgia, in July 1993. In January 1994, the
plaintiffs' appeal of the dismissal to the Supreme Court of Georgia was
rejected, and this matter is concluded.
STOCKHOLDER SUIT
In April 1991, two Southern Company stockholders filed a derivative action suit
in the U.S. District Court for the Southern District of Georgia against certain
current and former directors and officers of The Southern Company. The suit
alleges violations of the Federal Racketeer Influenced and Corrupt
Organizations Act (RICO) by officers and breaches of fiduciary duty and gross
negligence by all defendants resulting from alleged fraudulent accounting for
spare parts, illegal political campaign contributions, violations of federal
securities laws involving misrepresentations and omissions in SEC filings, and
concealment of the foregoing acts. The complaint seeks damages -- including
treble damages pursuant to RICO -- in an unspecified amount, which if awarded,
would be payable to The Southern Company. The plaintiffs' amended complaint
was dismissed by the court in March 1992. The court ruled the plaintiffs had
failed to present adequately their allegation that The Southern Company board
of directors' refusal of an earlier demand by the plaintiffs was wrongful. The
plaintiffs have appealed the dismissal to the U.S. Court of Appeals for the
11th Circuit.
ALABAMA POWER HEAT PUMP FINANCING SUIT
In September 1990, two customers of Alabama Power filed a civil complaint in
the Circuit Court of Shelby County, Alabama, against Alabama Power seeking to
represent all persons who, prior to June 23, 1989, entered into agreements with
Alabama Power for the financing of heat pumps and other merchandise purchased
from vendors other than Alabama Power. The plaintiffs contended that Alabama
Power was required to obtain a license under the Alabama Consumer Finance Act
to engage in the business of making consumer loans. The plaintiffs were
seeking an order declaring these agreements null and void and requiring Alabama
Power to refund all payments -- principal and interest -- made under these
agreements. The aggregate amount under these agreements, together with interest
paid, currently is estimated to be $40 million.
In June 1993, the court ordered Alabama Power to refund or forfeit interest
of approximately $10 million because of Alabama Power's failure to obtain such
license. However, the court's order did not require any refund or forfeiture
with respect to any principal payments under the agreements at issue. Alabama
Power has appealed the court's order to the Supreme Court of Alabama.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the company's financial statements.
GULF POWER COAL BARGE TRANSPORTATION SUIT
In 1993, a complaint against Gulf Power and the system service company was
filed in federal district court in Ohio by two companies with which Gulf Power
had contracted for the transportation by barge for certain Gulf Power coal
supplies. The complaint alleges breach of the contract by Gulf Power and seeks
damages estimated by the plaintiffs to be in excess of $85 million.
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NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the company's financial statements.
ALABAMA POWER RATE ADJUSTMENT PROCEDURES
In November 1982, the Alabama Public Service Commission (APSC) adopted rates
that provide for periodic adjustments based upon Alabama Power's earned return
on end-of-period retail common equity. The rates also provide for adjustments
to recognize the placing of new generating facilities in retail service. Both
increases and decreases have been placed into effect since the adoption of
these rates. The rate adjustment procedures allow a return on common equity
range of 13.0 percent to 14.5 percent and limit increases or decreases in rates
to 4 percent in any calendar year.
The APSC issued an order in December 1991 that reduced a scheduled 2.03
percent annual increase in rates to 1.03 percent, effective January 1992. The
1 percent reduction will remain in effect through 1994. The rate reduction was
designed to refund to retail ratepayers a portion of the benefits from a
settled contract dispute with Gulf States Utilities Company (Gulf States). The
present value of this portion of the settlement -- amounting to some $60
million -- is being amortized to income to offset the rate reduction in
accordance with the APSC's rate order. See Note 8 for additional information
concerning the Gulf States settlement.
Also in the December 1991 rate order, the APSC reaffirmed its satisfaction
with the ratemaking mechanism and stated that it did not foresee any further
review or changes in the procedures until after 1994. The ratemaking
procedures will remain in effect after 1994 unless the APSC votes to modify or
discontinue them.
GEORGIA POWER'S DEMAND-SIDE CONSERVATION PROGRAMS
In October 1993, a Superior Court of Fulton County, Georgia, judge ruled that
rate riders previously approved by the GPSC for recovery of Georgia Power's
costs incurred in connection with demand-side conservation programs were
unlawful. The judge held that the GPSC lacked statutory authority to approve
such rate riders except through general rate case proceedings and that those
procedures had not been followed. Georgia Power suspended collection of the
demand-side conservation costs and appealed the court's decision to the Georgia
Court of Appeals. In December 1993, the GPSC approved Georgia Power's request
for an accounting order allowing Georgia Power to defer all current unrecovered
and future costs related to these programs until the superior court's decision
is reversed or until the next general rate case proceedings. An association of
industrial customers has filed a petition for review of the accounting order in
superior court. Georgia Power's costs related to these conservation programs
through 1993 were $60 million, of which $15 million has been collected and the
remainder deferred. The estimated costs, assuming no change in the programs
certified by the GPSC, are $38 million in 1994 and $40 million in 1995.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the company's financial statements.
GEORGIA POWER 1991 RATE ORDER; PHASE-IN PLAN MODIFICATIONS
Georgia Power received a rate order in 1991 from the GPSC that modified the
Plant Vogtle phase-in plans to begin earlier amortization of the costs deferred
under the plans. The amortization period began October 1991 -- rather than
October 1994 as originally scheduled -- and extends through September 1999. In
addition, the GPSC ordered the levelization of capacity buyback expense from
the co-owners of Plant Vogtle over a six-year period beginning October 1991.
This results in net cost deferrals during the first three years and subsequent
amortization of the deferred amounts in the last three years.
MISSISSIPPI POWER RETAIL RATE ADJUSTMENT PLAN
Mississippi Power's retail base rates have been set under a Performance
Evaluation Plan (PEP) since 1986 with various modifications in 1991 and the
latest in 1994. In 1993, the Mississippi Public Service Commission (MPSC)
ordered Mississippi Power to review and propose changes that would enhance the
plan. Mississippi Power filed a revised plan, and the MPSC approved PEP-2 on
January 4, 1994. Under PEP-2, Mississippi Power's rate of return will be
measured on retail net investment rather than on common equity, as previously
calculated. Also, the number of indicators used to evaluate Mississippi
Power's performance was reduced to three with emphasis on price and service to
the customer. In addition, PEP-2 provides for the sharing of rate adjustments
based on low rates and on the performance rating. The evaluation periods for
PEP-2 are semiannual. Any change in rates is limited to 2 percent of retail
revenues per period before a public hearing is required. PEP-2 will remain in
effect until the MPSC modifies or terminates the plan.
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NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
FERC REVIEWS EQUITY RETURNS
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the Southern electric system's wholesale rate schedules and
contracts that have a return on common equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power, and other similar contracts.
Any changes in the rate of return on common equity that may occur as a result
of this proceeding would be effective 60 days after a proper notice of the
proceeding is published. A notice was published on May 10, 1991.
In August 1992, a FERC administrative law judge issued an opinion that
changes in rate schedules and contracts were not necessary and that the FERC
staff failed to show how any changes were in the public interest. The FERC
staff has filed exceptions to the administrative law judge's opinion, and the
matter remains pending before the FERC.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the company's financial statements.
4. CONSTRUCTION PROGRAM
GENERAL
The operating companies are engaged in continuous construction programs,
currently estimated to total some $1.5 billion in 1994, $1.3 billion in 1995,
and $1.5 billion in 1996. These estimates include AFUDC of $34 million in
1994, $41 million in 1995, and $35 million in 1996. The construction programs
are subject to periodic review and revision, and actual construction costs may
vary from the above estimates because of numerous factors. These factors
include changes in business conditions; revised load growth estimates; changes
in environmental regulations; changes in existing nuclear plants to meet new
regulatory requirements; increasing costs of labor, equipment, and materials;
and cost of capital. At December 31, 1993, significant purchase commitments
were outstanding in connection with the construction program. The operating
companies do not have any new baseload generating plants under construction.
However, within the service area, the construction of combustion turbine
peaking units of approximately 1,700 megawatts is planned to be completed by
1996. In addition, significant construction will continue related to
transmission and distribution facilities and the upgrading and extension of the
useful lives of generating plants.
See Management's Discussion and Analysis under "Environmental Matters" for
information on the impact of the Clean Air Act Amendments of 1990 and other
environmental matters.
ROCKY MOUNTAIN PROJECT STATUS
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric project in 1991 was not economically
justifiable and reasonable and withheld authorization for Georgia Power to
spend funds from approved securities issuances on that project. In 1988,
Georgia Power and Oglethorpe Power Corporation (OPC) entered into a joint
ownership agreement for OPC to assume responsibility for the construction and
operation of the project, as discussed in Note 6. However, full recovery of
Georgia Power's costs depends on the GPSC's treatment of the project's cost and
disposition of the project's capacity output. In the event Georgia Power
cannot demonstrate to the GPSC the project's economic viability based on
current ownership, construction schedule, and costs, then part or all of such
costs may have to be written off. At December 31, 1993, Georgia Power's
investment in the project amounted to approximately $197 million. AFUDC
accrued on the Rocky Mountain project has not been credited to income or
included in the project cost since December 1985. If accrual of AFUDC is not
resumed, Georgia Power's portion of the estimated total plant additions at
completion would be approximately $199 million. The plant is currently
scheduled to begin commercial operation in 1995. Georgia Power has held
preliminary discussions with other parties regarding the potential disposition
of its remaining interest in the project.
The ultimate outcome of this matter cannot now be determined.
5. FINANCING, INVESTMENT, AND
COMMITMENTS
GENERAL
In early 1994, The Southern Company sold -- through a public offering -- 5.6
million shares of common stock with proceeds totaling $120 million. The
company may require additional equity capital during the remainder of 1994.
The amount and timing of additional equity capital to be raised in 1994 -- as
well as in subsequent years -- will be contingent on The Southern Company's
investment opportunities. Equity capital can be provided from any combination
of public offerings, private placements, or the company's stock plans.
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NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
To the extent possible, the operating companies' construction programs are
expected to be financed primarily from internal sources. Short-term debt will
be utilized when necessary; the amounts available are discussed below. The
subsidiary companies may issue additional long-term debt and preferred stock
primarily for the purposes of debt maturities and for redeeming higher-cost
securities.
FOREIGN UTILITY OPERATIONS
During 1993, The Southern Company made investments of approximately $315
million in utilities that own and operate generating facilities in various
foreign markets. The consolidated financial statements reflect these
investments in majority-owned subsidiaries on a consolidated basis and other
investments on an equity basis.
BANK CREDIT ARRANGEMENTS
At the beginning of 1994, unused credit arrangements with banks totaled $1.1
billion, of which approximately $500 million expires at various times during
1994 and 1995; $130 million expires at May 1, 1996; $400 million expires at
June 30, 1996; and $70 million expires at December 1, 1996.
Georgia Power's revolving credit agreements of $150 million, of which $130
million remained unused as of December 31, 1993, expire May 1, 1996. During
the term of these agreements, Georgia Power may convert short-term borrowings
into term loans, payable in 12 equal quarterly installments, with the first
installment due at the end of the first calendar quarter after the applicable
termination date or at an earlier date at Georgia Power's option. In
connection with these credit arrangements, Georgia Power agrees to pay
commitment fees based on the unused portions of the commitments or to maintain
compensating balances with the banks.
The $400 million expiring June 30, 1996, is under revolving credit
arrangements with several banks providing The Southern Company, Alabama Power,
and Georgia Power up to the total credit amount of $400 million. To provide
liquidity support to commercial paper programs, $135 million and $165 million
of the $400 million available credit are currently dedicated to the exclusive
use of Alabama Power and Georgia Power, respectively. During the term of these
agreements, short-term borrowings may be converted into term loans, payable in
12 equal quarterly installments, with the first installment due at the end of
the first calendar quarter after the applicable termination date or at an
earlier date at the companies' option. In addition, these agreements require
payment of commitment fees based on the unused portions of the commitments or
the maintenance of compensating balances with the banks.
Mississippi Power has $70 million of revolving credit agreements expiring
December 1, 1996. These agreements allow short-term borrowings to be converted
into term loans, payable in 12 equal quarterly installments, with the first
installment due at the end of the first calendar quarter after the applicable
termination date or at an earlier date at Mississippi Power's option. In
connection with these credit arrangements, Mississippi Power agrees to pay
commitment fees based on the unused portions of the commitments or to maintain
compensating balances with the banks.
Savannah Electric has $20 million of revolving credit arrangements expiring
December 31, 1995. These agreements allow short-term borrowings to be
converted into term loans, payable in 12 equal quarterly installments, with the
first installment due at the end of the first calendar quarter after the
applicable termination date or at an earlier date at Savannah Electric's
option. In connection with these credit arrangements, Savannah Electric agrees
to pay commitment fees based on the unused portions of the commitments.
In connection with all other lines of credit, the companies have the option
of paying fees or maintaining compensating balances, which are substantially
all the cash of the companies except for daily working funds and similar items.
These balances are not legally restricted from withdrawal.
In addition, the companies from time to time borrow under uncommitted lines
of credit with banks, and in the case of Alabama Power and Georgia Power,
through commercial paper programs that have the liquidity support of committed
bank credit arrangements.
ASSETS SUBJECT TO LIEN
The operating companies' mortgages, which secure the first mortgage bonds
issued by the companies, constitute a direct first lien on substantially all of
the companies' respective fixed property and franchises.
FUEL COMMITMENTS
To supply a portion of the fuel requirements of the system's generating plants,
the subsidiary companies have
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NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
entered into various long-term commitments for the procurement of fossil and
nuclear fuel. In most cases, these contracts contain provisions for price
escalations, minimum purchase levels, and other financial commitments. Total
estimated long-term obligations were approximately $15 billion at December 31,
1993. Additional commitments for coal and nuclear fuel will be required in the
future to supply the operating companies' fuel needs.
To take advantage of lower-cost coal supplies, agreements were reached in
1986 for the payment of $121 million to terminate two contracts for the supply
of coal to Plant Daniel, which is jointly owned by Gulf Power and Mississippi
Power. Also, in March 1988, Gulf Power made an advance payment of $60 million
to a coal supplier under an agreement to lower the cost of future coal
purchased under an existing contract. These amounts are being amortized to
expense. The remaining unamortized amount included in deferred charges at
December 31, 1993, was $70 million.
OPERATING LEASES
The operating companies have entered into coal rail car rental agreements with
various terms and expiration dates. Rental expense totaled $11 million, $9
million, and $7 million for 1993, 1992, and 1991, respectively. At December
31, 1993, estimated minimum rental commitments for noncancelable operating
leases were as follows:
Amounts
(in millions)
1994 $ 12
1995 14
1996 12
1997 12
1998 12
1999 and thereafter 226
Total minimum payments $ 288
6. FACILITY SALES AND JOINT OWNERSHIP
AGREEMENTS
In 1992, Alabama Power sold an undivided interest in units 1 and 2 of Plant
Miller and related facilities to Alabama Electric Cooperative, Inc.
Since 1975, Georgia Power has sold undivided interests in plants Vogtle,
Hatch, Scherer, and Wansley in varying amounts, together with transmission
facilities, to OPC, the Municipal Electric Authority of Georgia (MEAG), and the
city of Dalton, Georgia. Georgia Power has completed two of four separate
transactions to sell Unit 4 of Plant Scherer to two Florida utilities. See
Note 7 for additional information concerning these sales. In addition, Georgia
Power has entered into a joint ownership agreement with OPC with respect to the
Rocky Mountain project, as discussed later.
At December 31, 1993, Alabama Power's and Georgia Power's ownership and
investment (exclusive of nuclear fuel) in jointly owned facilities with the
above entities were as follows:
Jointly Owned Facilities
Percent Amount of Accumulated
Ownership Investment Depreciation
(in millions)
Plant Vogtle
(nuclear) 45.7% $3,285 $540
Plant Hatch
(nuclear) 50.1 840 325
Plant Miller
(coal)
Units 1 and 2 91.8 703 247
Plant Scherer
(coal)
Units 1 and 2 8.4 111 33
Unit 4 33.1 236 31
Plant Wansley
(coal) 53.5 286 125
Rocky Mountain
(pumped storage) 25.0* 197 --
*Estimated ownership at date of completion.
Georgia Power and OPC have entered into a joint ownership agreement
regarding the 848-megawatt Rocky Mountain pumped storage hydroelectric project.
Under the agreement, Georgia Power will retain its present investment in the
project and OPC will finance, complete, and operate the facility. Upon
completion, Georgia Power will own an undivided interest in the project equal
to the proportion its investment bears to the total investment in the project
(excluding each party's cost of funds and ad valorem taxes). Based on current
cost estimates, Georgia Power's final ownership is estimated at approximately
25 percent of the project at completion. Georgia Power has held preliminary
discussions with other parties regarding the potential disposition of its
remaining interest in the project.
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NOTES (continued)
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES 1993 ANNUAL REPORT
Alabama Power and Georgia Power have contracted to operate and maintain
the jointly owned facilities -- except for the Rocky Mountain project -- as
agents for their respective co-owners. The companies' proportionate share of
their plant operating expenses is included in the corresponding operating
expenses in the Consolidated Statements of Income.
In connection with a joint ownership arrangement at Plant Vogtle, Georgia
Power has remaining commitments to purchase declining fractions of OPC's and
MEAG's capacity and energy from this plant for periods of up to 10 years
following commercial operation (and, with regard to a portion of the 5 percent
additional interest in Plant Vogtle owned by MEAG, until the latter of the
retirement of the plant or the latest stated maturity date of MEAG's bonds
issued to finance such ownership interest). The payments for such capacity are
required whether any capacity is available. The energy cost of these purchases
is a function of each unit's variable operating costs. Except as noted below,
the cost of such capacity and energy is included in purchased power in the
Consolidated Statements of Income. Capacity payments totaled $183 million,
$289 million, and $320 million, for 1993, 1992, and 1991, respectively.
Projected capacity payments for the next five years are as follows: $132
million in 1994; $77 million in 1995; $70 million in 1996; $59 million in 1997;
and $59 million in 1998. Also, a portion of the above capacity payments
relates to Plant Vogtle costs that were written off after being disallowed for
retail ratemaking purposes.
In 1991, the GPSC ordered that the Plant Vogtle capacity buyback expense be
levelized over a six-year period. The amounts deferred and not expensed in the
year paid totaled $38 million in 1993, $100 million in 1992, and $30 million in
1991. The projected net amount to be deferred in 1994 is $1 million. The
projected net amortization of the deferred expense is $49 million in 1995, $62
million in 1996, and $57 million in 1997.
7. PLANNED SALES OF INTEREST IN PLANT
SCHERER
Georgia Power has completed two of four separate transactions to sell Unit 4 of
Plant Scherer to Florida Power & Light Company (FP&L) and Jacksonville Electric
Authority (JEA) for a total price of approximately $806 million, including any
gains on these transactions. FP&L would eventually own approximately 76.4
percent of the unit, with JEA owning the remainder. The capacity from this
unit was previously dedicated to long-term power sales contracts with Gulf
States that were suspended in 1988. Georgia Power will continue to operate the
unit.
The completed and scheduled remaining transactions are as follows:
Closing Percent
Date Capacity Ownership Amount
(megawatts) (in millions)
July 1991 290 35.46% $291
June 1993 258 31.44 253
June 1994 135 16.55 132
June 1995 135 16.55 130
Total 818 100.00% $806
Plant Scherer -- a jointly owned coal-fired generating plant -- has four
units with a total capacity of 3,272 megawatts. Unit 4 was completed in 1989.
See Note 6 for information regarding current plant ownership.
8. LONG-TERM POWER SALES
AGREEMENTS
GENERAL
The operating subsidiaries of The Southern Company have entered into long-term
contractual agreements for the sale of capacity and energy to certain
non-affiliated utilities located outside the system's service area. Certain of
these agreements are non-firm and are based on capacity of the system in
general. Other agreements are firm and pertain to capacity related to specific
generating units. Because the energy is generally sold at cost under these
agreements, revenues from capacity sales primarily affect profitability. The
capacity revenues have been as follows:
Unit Other
Year Power Long-Term Total
(in millions)
1993 $312 $38 $350
1992 435 22 457
1991 468 22 490
Long-term non-firm power of 400 megawatts was sold in 1993 to Florida Power
Corporation (FPC). In January 1994, this amount decreased to 200 megawatts,
and the contract will expire at year-end.
Unit power from specific generating plants is currently being sold to FP&L,
FPC, JEA, and the city of Tallahassee, Florida. Under these agreements, an
average
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63
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
of 1,700 megawatts of capacity is scheduled to be sold during 1994 and 1995.
Thereafter, these sales will decline to some 1,600 megawatts and remain at that
approximate level -- unless reduced by FP&L, FPC, and JEA for the periods after
1999 -- until the expiration of the contracts in 2010.
GULF STATES SETTLEMENT COMPLETED
On November 7, 1991, subsidiaries of The Southern Company entered into a
settlement agreement with Gulf States that resolved litigation between the
companies that had been pending since 1986 and arose out of a dispute over
certain unit power and other long-term power sales contracts. In 1993, all
remaining terms and obligations of the settlement agreement were satisfied.
Based on the value of the settlement proceeds received -- less the amounts
to be refunded to customers and the amounts previously included in income --
The Southern Company recorded an increase in consolidated net income of $114
million, or 18 cents per share, in November 1991. With respect to Alabama
Power's portion of proceeds received in 1991, see Note 3 concerning the
regulatory treatment of amounts being refunded to retail customers over a
three-year period.
9. INCOME TAXES
Effective January 1, 1993, The Southern Company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption of Statement No. 109 resulted in
cumulative adjustments that had no material effect on consolidated net income.
The adoption also resulted in the recording of additional deferred income taxes
and related assets and liabilities. The related assets of $1.5 billion are
revenues to be received from customers. These assets are attributable to tax
benefits flowed through to customers in prior years and to taxes applicable to
capitalized AFUDC. The related liabilities of $1.1 billion are revenues to be
refunded to customers. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits. Additionally, deferred income taxes
related to accelerated tax depreciation previously shown as a reduction to
utility plant were reclassified.
Details of the federal and state income tax provisions are as follows:
1993 1992 1991
(in millions)
Total provision for income taxes:
Federal --
Currently payable $424 $343 $506
Deferred -- current year 224 225 139
-- reversal of
prior years (51) (41) (121)
Deferred investment tax
credits (20) (6) (11)
577 521 513
State --
Currently payable 64 50 76
Deferred -- current year 39 46 23
-- reversal of
prior years (3) (9) (15)
100 87 84
Total 677 608 597
Less income taxes charged
(credited) to other income (57) (39) (21)
Federal and state income
taxes charged to operations $734 $647 $618
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
1993
(in millions)
Deferred tax liabilities:
Accelerated depreciation $2,496
Property basis differences 1,741
Deferred plant costs 161
Other 289
Total 4,687
Deferred tax assets:
Federal effect of state deferred taxes 102
Other property basis differences 292
Deferred costs 69
Pension and other benefits 46
Other 210
Total 719
Net deferred tax liabilities 3,968
Portion included in current assets, net 11
Accumulated deferred income taxes
in the Consolidated Balance Sheets $3,979
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64
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Consolidated Statements of Income. Credits amortized in
this manner amounted to $29 million in 1993, $41 million in 1992, and $48
million in 1991. At December 31, 1993, all investment tax credits available to
reduce federal income taxes payable had been utilized.
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
1993 1992 1991
Federal statutory rate 35.0% 34.0% 34.0%
State income tax,
net of federal deduction 3.7 3.4 3.5
Non-deductible book
depreciation 1.9 2.2 2.9
Difference in prior years'
deferred and current tax rate (1.3) (1.5) (1.5)
Other (1.1) (1.6) (1.1)
Effective income tax rate 38.2% 36.5% 37.8%
The Southern Company and its subsidiaries file a consolidated federal income
tax return. Under a joint consolidated income tax agreement, each company's
current and deferred tax expense is computed on a stand-alone basis, and
consolidated tax savings are allocated to each company based on its ratio of
taxable income to total consolidated taxable income.
10. COMMON STOCK
STOCK DISTRIBUTION
In January 1994, The Southern Company board of directors authorized a
two-for-one common stock split in the form of a stock distribution for each
share held as of February 7, 1994. For all reported common stock data, the
number of common shares outstanding and per share amounts for earnings,
dividends, and market price have been adjusted to reflect the stock
distribution.
SHARES RESERVED
At December 31, 1993, a total of 24 million shares was reserved for issuance
pursuant to the Dividend Reinvestment and Stock Purchase Plan, the Employee
Savings Plan, and the Executive Stock Option Plan.
EXECUTIVE STOCK OPTION PLAN
The Southern Company's Executive Stock Option Plan authorizes the granting of
non-qualified stock options to key employees of The Southern Company, including
officers. Currently, 34 employees are eligible to participate in the plan. As
of December 31, 1993, 38 current and former employees participated in the plan.
The maximum number of shares of common stock that may be issued under the
Executive Stock Option Plan may not exceed 6 million. The price of options
granted to date has been at the fair market value of the shares on the date of
grant. Options granted to date become exercisable pro rata over a maximum
period of four years from date of grant, such that all options generally are
exercisable by 1997. Options outstanding will expire upon termination of the
plan, which will occur on December 7, 1997, unless terminated earlier by the
board of directors. Stock option activity in 1992 and 1993 is summarized
below:
Shares Average
Subject Option Price
To Option Per Share
Balance at December 31, 1991 1,399,088 $13.02
Options granted 434,840 18.09
Options canceled -- --
Options exercised (644,806) 12.75
Balance at December 31, 1992 1,189,122 15.02
Options granted 359,492 21.22
Options canceled -- --
Options exercised (183,804) 14.14
Balance at December 31, 1993 1,364,810 $16.77
Shares reserved for future grants:
At December 31, 1991 4,508,776
At December 31, 1992 4,073,936
At December 31, 1993 3,714,444
Options exercisable:
At December 31, 1992 243,566
At December 31, 1993 475,795
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65
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
11. OTHER LONG-TERM DEBT
Details of other long-term debt are as follows:
December 31,
1993 1992
(in millions)
Obligations incurred in connection
with the sale by public authorities
of tax-exempt pollution control
revenue bonds:
Collateralized --
5.375% to 10.0% due 2003-2023 $ 708 $ 512
Variable rates (3.05% to 3.40%)
due 2016-2022 63 23
Non-collateralized --
5.9% to 7.25% due 2003-2006 6 32
7.2% to 9.2% due 2007-2010 -- 92
Variable rate (3.7% at 1/1/94)
due 2011 10 10
7.2% to 12.25% due 2013-2014 644 738
6.75% to 10.6% due 2015-2017 890 891
5.8% due 2022 10 --
Variable rate (3.55% at 1/1/94)
due 2019 59 59
Variable rates (3.7% to 6.2% at
1/1/94) due 2021 and 2022 23 23
Less funds on deposit with trustees -- 2
2,413 2,378
Capitalized lease obligations:
Nuclear fuel 96 104
Buildings 146 154
Other 5 6
247 264
Notes payable:
8.25% due 1993-1995 35 51
7.5% due 1993-1995 2 3
9.75% due 1993-2010 10 10
8.0% due 1993 -- 2
4.36% to 8.00% due 1993-1995 101 20
4.62% to 9.4% due 1996-2000 94 25
Adjustable rates (3.45% to
4.41% at 1/1/94) due 1994 60 67
302 178
Total $2,962 $2,820
With respect to the collateralized pollution control revenue bonds, the
operating companies have authenticated and delivered to trustees a like
principal amount of first mortgage bonds as security for obligations under
installment sale or loan agreements. The principal and interest on the first
mortgage bonds will be payable only in the event of default under the
agreements.
Assets acquired under capital leases are recorded as utility plant in
service, and the related obligation is classified as other long-term debt. The
net book value of capitalized leases was $217 million and $236 million at
December 31, 1993 and 1992, respectively. At December 31, 1993, the composite
interest rates for nuclear fuel, buildings, and other were 3.6 percent, 9.7
percent, and 12.0 percent, respectively. Sinking fund requirements and/or
serial maturities through 1998 applicable to other long-term debt are as
follows: $89 million in 1994; $154 million in 1995; $58 million in 1996; $26
million in 1997; and $7 million in 1998.
12. LONG-TERM DEBT DUE WITHIN ONE YEAR
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year is as follows:
1993 1992
(in millions)
Bond improvement fund requirements $ 51 $ 54
Less:
Portion to be satisfied by certifying
property additions 3 2
Reacquired bonds 25 --
Cash sinking fund requirements 23 52
First mortgage bond maturities
and redemptions 44 57
Other long-term debt maturities
(Note 11) 89 79
Total $156 $188
The first mortgage bond improvement (sinking) fund requirements amount to 1
percent of each outstanding series of bonds authenticated under the indentures
prior to January 1 of each year, other than those issued to collateralize
pollution control and other obligations. The requirements may be satisfied by
depositing cash or reacquiring bonds, or by pledging additional property equal
to 166 2/3 percent of such requirements.
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NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
13. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, Alabama Power and Georgia
Power maintain agreements of indemnity with the NRC that, together with private
insurance, cover third-party liability arising from any nuclear incident
occurring at the companies' nuclear power plants. The act limits to $9.4
billion public liability claims that could arise from a single nuclear
incident. Each nuclear plant is insured against this liability to a maximum of
$200 million by private insurance, with the remaining coverage provided by a
mandatory program of deferred premiums that could be assessed, after a nuclear
incident, against all owners of nuclear reactors. A company could be assessed
up to $79 million per incident for each licensed reactor it operates but not
more than an aggregate of $10 million per incident to be paid in a calendar
year for each reactor. Such maximum assessment, excluding any applicable state
premium taxes, for Alabama Power and Georgia Power -- based on its ownership
and buyback interests -- is $159 million and $171 million, respectively, per
incident but not more than an aggregate of $20 million and $22 million,
respectively, to be paid for each incident in any one year.
Alabama Power and Georgia Power are members of Nuclear Mutual Limited (NML),
a mutual insurer established to provide property damage insurance in an amount
up to $500 million for members' nuclear generating facilities. The members are
subject to a retrospective premium adjustment in the event that losses exceed
accumulated reserve funds. Alabama Power's and Georgia Power's maximum annual
assessments are limited to $14 million and $18 million, respectively, under
current policies.
Additionally, both companies have policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million NML
coverage. This excess insurance is provided by Nuclear Electric Insurance
Limited (NEIL), a mutual insurance company, and American Nuclear
Insurers/Mutual Atomic Energy Liability Underwriters.
NEIL also covers the additional costs that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can be insured against increased costs of replacement power in
an amount up to $3.5 million per week -- starting 21 weeks after the outage --
for one year and up to $2.3 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if
losses each year exceed the accumulated funds available to the insurer under
that policy. The maximum annual assessments under current policies for Alabama
Power and Georgia Power for excess property damage would be $16 million and $15
million, respectively. The replacement power assessments are $9 million for
Alabama Power and $13 million for Georgia Power.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies issued or
renewed on or after April 2, 1991, shall be dedicated first for the sole
purpose of placing the reactor in a safe and stable condition after an
accident. Any remaining proceeds are to be applied next toward the costs of
decontamination and debris removal operations ordered by the NRC, and any
further remaining proceeds are to be paid either to the company or to its bond
trustees as may be appropriate under the policies and applicable trust
indentures.
Alabama Power and Georgia Power participate in an insurance program for
nuclear workers that provides coverage for worker tort claims filed for bodily
injury caused at commercial nuclear power plants. In the event that claims for
this insurance exceed the accumulated reserve funds, Alabama Power and Georgia
Power could be subject to a maximum total assessment of $6 million and $7
million, respectively.
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NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
14. COMMON STOCK DIVIDEND
RESTRICTIONS
The income of The Southern Company is derived primarily from equity in earnings
of its operating subsidiaries. At December 31, 1993, $1.6 billion of
consolidated retained earnings was restricted against the payment by the
operating companies of cash dividends on common stock under terms of bond
indentures or charters.
15. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 1993 and 1992 are as follows:
Per Common Share*
Operating Operating Consolidated Price Range
Quarter Ended Revenues Income Net Income Earnings Dividends High Low
(in millions)
March 1993 $1,840 $377 $177 $0.28 $0.285 21 3/8 18 3/8
June 1993 2,068 426 250 0.39 0.285 22 1/2 19 3/8
September 1993 2,636 637 442 0.70 0.285 23 20 1/2
December 1993 1,945 324 133 0.20 0.285 23 5/8 20 3/4
March 1992 $1,808 $387 $185 $0.29 $0.275 17 3/8 15 1/8
June 1992 2,011 428 223 0.36 0.275 17 5/8 15 5/8
September 1992 2,386 609 404 0.64 0.275 19 17 3/8
December 1992 1,868 338 141 0.22 0.275 19 1/2 17 5/8
*Common stock data have been adjusted to reflect a two-for-one stock split in
the form of a stock distribution for each share held as of February 7, 1994.
The company's business is influenced by seasonal weather conditions and the
timing of rate changes.
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68
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
The Southern Company and Subsidiary Companies 1993 Annual Report
(See Note Below)
1993 1992 1991
OPERATING REVENUES (in millions) $ 8,489 $ 8,073 $ 8,050
CONSOLIDATED NET INCOME (in millions) $ 1,002 $ 953 $ 876
EARNINGS PER SHARE OF COMMON STOCK $ 1.57 $ 1.51 $ 1.39
CASH DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 1.14 $ 1.10 $ 1.07
RETURN ON AVERAGE COMMON EQUITY (percent) 13.43 13.42 12.74
TOTAL ASSETS (in millions) $ 25,911 $ 20,038 $ 19,863
GROSS PROPERTY ADDITIONS (in millions) $ 1,441 $ 1,105 $ 1,123
CAPITALIZATION (in millions):
Common stock equity $ 7,684 $ 7,234 $ 6,976
Preferred stock 1,332 1,351 1,207
Preferred and preference stock subject
to mandatory redemption 1 8 126
Long-term debt 7,412 7,241 7,992
Total excluding amounts due within one year $ 16,429 $ 15,834 $ 16,301
CAPITALIZATION RATIOS (percent):
Common stock equity 46.8 45.7 42.8
Preferred stock 8.1 8.6 8.2
Long-term debt 45.1 45.7 49.0
Total excluding amounts due within one year 100.0 100.0 100.0
OTHER COMMON STOCK DATA:
Book value per share (year-end) $ 11.96 $ 11.43 $ 11.05
Market price per share:
High 23 5/8 19 1/2 17 3/8
Low 18 3/8 15 1/8 12 7/8
Close 22 19 1/4 17 1/8
Market-to-book ratio (year-end) (percent) 183.9 168.4 155.5
Price-earnings ratio (year-end) (times) 14.0 12.7 12.4
Dividends paid (in millions) $ 726 $ 695 $ 676
Dividend yield (year-end) (percent) 5.2 5.7 6.2
Dividend payout ratio (percent) 72.4 72.9 77.1
Cash coverage of dividends (year-end) (times) 2.9 2.8 2.5
Proceeds from sales of stock (in millions) $ 204 $ 30 --
Shares outstanding (in thousands):
Average 637,319 631,844 631,307
Year-end 642,662 632,917 631,307
Stockholders of record (year-end) 237,105 247,378 254,568
FIRST MORTGAGE BONDS (in millions):
Issued $ 2,185 $ 1,815 $ 380
Retired 2,178 2,575 881
PREFERRED STOCK (in millions):
Issued $ 426 $ 410 $ 100
Retired 516 326 125
CUSTOMERS (year-end) (in thousands):
Residential 2,996 2,950 2,903
Commercial 427 414 403
Industrial 18 18 18
Other 4 4 4
Total 3,445 3,386 3,328
EMPLOYEES (year-end) 28,743 29,085 30,402
Note: Common stock data have been adjusted to reflect a two-for-one stock split
in the form of a stock distribution for each share held as of February 7, 1994.
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69
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
The Southern Company and Subsidiary Companies 1993 Annual Report
(See Note Below)
1990 1989 1988 1987 1986 1985 1984 1983
$ 8,053 $ 7,620 $ 7,287 $ 7,204 $ 7,033 $ 6,999 $ 6,350 $ 5,673
$ 604 $ 846 $ 846 $ 577 $ 903 $ 845 $ 735 $ 604
$ 0.96 $ 1.34 $ 1.36 $ 0.96 $ 1.56 $ 1.56 $ 1.47 $ 1.32
$ 1.07 $ 1.07 $ 1.07 $ 1.07 $ 1.0325 $ 0.975 $ 0.915 $ 0.8625
8.85 12.49 13.03 9.27 15.61 16.59 16.55 15.67
$ 19,955 $ 20,092 $ 19,731 $ 19,518 $ 18,483 $ 16,855 $ 15,327 $ 13,790
$ 1,185 $ 1,346 $ 1,754 $ 1,853 $ 2,367 $ 2,242 $ 2,130 $ 1,722
$ 6,783 $ 6,861 $ 6,686 $ 6,307 $ 6,133 $ 5,443 $ 4,741 $ 4,135
1,207 1,209 1,259 1,139 1,214 1,114 1,004 954
151 191 206 224 178 194 206 214
8,458 8,575 8,433 8,333 7,812 7,220 6,774 6,439
$ 16,599 $ 16,836 $ 16,584 $ 16,003 $ 15,337 $ 13,971 $ 12,725 $ 11,742
40.9 40.8 40.3 39.4 40.0 38.9 37.3 35.2
8.2 8.3 8.8 8.5 9.1 9.4 9.5 9.9
50.9 50.9 50.9 52.1 50.9 51.7 53.2 54.9
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
$ 10.74 $ 10.87 $ 10.60 $ 10.28 $ 10.35 $ 9.72 $ 9.08 $ 8.60
14 5/8 14 7/8 12 1/8 14 1/2 13 5/8 11 5/8 9 3/8 8 7/8
11 1/2 11 10 1/8 8 7/8 10 1/8 8 7/8 7 1/8 7 1/4
13 7/8 14 1/2 11 1/8 11 1/8 12 5/8 11 1/8 9 3/8 8 1/8
129.7 134.0 105.5 108.8 122.5 114.5 103.9 95.2
14.6 10.9 8.2 11.7 8.2 7.1 6.4 6.2
$ 676 $ 675 $ 661 $ 628 $ 583 $ 512 $ 444 $ 380
7.7 7.3 9.6 9.6 8.4 9.2 10.2 11.0
111.8 79.8 78.1 108.9 64.6 60.6 60.4 63.0
2.8 2.6 2.3 2.0 2.7 2.6 3.1 3.4
-- $ 4 $ 194 $ 247 $ 379 $ 373 $ 318 $ 333
631,307 631,303 622,292 601,390 580,252 541,244 501,313 456,262
631,307 631,307 630,898 613,565 592,364 560,063 522,018 480,649
263,046 273,751 290,725 296,079 297,302 318,221 336,165 351,012
$ 300 $ 280 $ 335 $ 700 $ 735 $ 20 $ 150 $ 129
146 201 273 369 875 69 71 53
$ -- $ -- $ 120 $ 125 $ 100 $ 150 $ 50 $ 50
96 21 10 160 53 6 6 11
2,865 2,824 2,781 2,733 2,675 2,611 2,541 2,473
396 392 384 374 362 348 336 324
18 18 18 18 17 17 17 17
4 4 4 4 4 4 4 4
3,283 3,238 3,187 3,129 3,058 2,980 2,898 2,818
30,263 30,530 32,523 32,612 32,358 32,354 31,753 31,499
II-39
70
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
1993 1992 1991
OPERATING REVENUES (in millions):
Residential $ 2,696 $ 2,402 $ 2,391
Commercial 2,313 2,181 2,122
Industrial 2,200 2,126 2,088
Other 68 64 65
Total retail 7,277 6,773 6,666
Sales for resale within service area 447 409 417
Sales for resale outside service area 613 797 884
Total revenues from sales of electricity 8,337 7,979 7,967
Other revenues 152 94 83
Total $ 8,489 $ 8,073 $ 8,050
KILOWATT-HOUR SALES (in millions):
Residential 36,807 33,627 33,622
Commercial 32,847 31,025 30,379
Industrial 48,738 47,816 46,050
Other 814 777 817
Total retail 119,206 113,245 110,868
Sales for resale within service area 13,258 12,107 12,320
Sales for resale outside service area 12,445 16,632 19,839
Total 144,909 141,984 143,027
AVERAGE REVENUE PER KILOWATT-HOUR (cents):
Residential 7.32 7.14 7.11
Commercial 7.04 7.03 6.99
Industrial 4.51 4.45 4.53
Total retail 6.10 5.98 6.01
Sales for resale 4.12 4.20 4.05
Total sales 5.75 5.62 5.57
AVERAGE ANNUAL KILOWATT-HOUR USE PER RESIDENTIAL CUSTOMER 12,378 11,490 11,659
AVERAGE ANNUAL REVENUE PER RESIDENTIAL CUSTOMER $ 906.60 $ 820.67 $ 829.18
PLANT NAMEPLATE CAPACITY RATINGS (year-end) (megawatts) 29,513 29,830 29,915
MAXIMUM PEAK-HOUR DEMAND (megawatts):
Winter 19,432 19,121 19,166
Summer 25,937 24,146 25,261
SYSTEM RESERVE MARGIN (at peak) (percent) 13.2 14.3 16.5
ANNUAL LOAD FACTOR (percent) 59.4 60.3 58.3
PLANT AVAILABILITY (percent):
Fossil-steam 87.9 88.6 91.3
Nuclear 85.9 85.2 83.4
SOURCE OF ENERGY SUPPLY (percent):
Coal 72.2 71.7 72.6
Nuclear 16.1 16.2 16.2
Hydro 3.9 4.6 4.4
Oil and gas 0.7 0.5 0.6
Purchased power 7.1 7.0 6.2
Total 100.0 100.0 100.0
TOTAL FUEL ECONOMY DATA:
BTU per net kilowatt-hour generated 9,994 9,976 10,022
Cost of fuel per million BTU (cents) 166.85 162.58 168.28
Average cost of fuel per net kilowatt-hour generated (cents) 1.67 1.62 1.69
II-40
71
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
1990 1989 1988 1987 1986 1985 1984 1983
$ 2,342 $ 2,194 $ 2,103 $ 2,042 $ 1,996 $ 1,825 $ 1,751 $ 1,641
2,062 1,965 1,835 1,692 1,613 1,512 1,410 1,284
2,085 2,011 1,945 1,870 1,845 1,830 1,790 1,600
64 60 56 54 52 50 47 42
6,553 6,230 5,939 5,658 5,506 5,217 4,998 4,567
412 401 480 461 511 436 456 439
977 928 777 1,028 957 1,289 854 619
7,942 7,559 7,196 7,147 6,974 6,942 6,308 5,625
111 61 91 57 59 57 42 48
$ 8,053 $ 7,620 $ 7,287 $ 7,204 $ 7,033 $ 6,999 $ 6,350 $ 5,673
33,118 31,627 31,041 30,583 29,501 27,088 26,163 25,425
29,658 28,454 27,005 25,593 24,166 22,512 20,816 19,512
45,974 45,022 43,675 42,113 40,503 39,804 39,055 35,618
806 787 763 737 723 713 663 645
109,556 105,890 102,484 99,026 94,893 90,117 86,697 81,200
11,134 11,419 14,806 13,282 14,347 11,079 11,193 10,829
24,402 24,228 15,860 22,905 16,909 27,881 21,374 15,509
145,092 141,537 133,150 135,213 126,149 129,077 119,264 107,538
7.07 6.94 6.77 6.68 6.77 6.74 6.69 6.45
6.96 6.91 6.79 6.61 6.67 6.71 6.77 6.58
4.53 4.47 4.45 4.44 4.56 4.60 4.58 4.49
5.98 5.88 5.80 5.71 5.80 5.79 5.76 5.62
3.91 3.73 4.10 4.11 4.69 4.43 4.02 4.02
5.47 5.34 5.40 5.29 5.53 5.38 5.29 5.23
11,637 11,287 11,255 11,307 11,157 10,515 10,434 10,395
$ 822.93 $ 782.90 $ 762.42 $ 754.96 $ 754.93 $ 708.46 $ 698.26 $ 670.76
29,532 29,532 27,552 27,610 26,262 26,262 25,397 25,377
17,629 20,772 18,685 18,185 19,665 19,347 16,353 15,502
25,981 24,399 23,641 23,194 23,255 21,778 20,210 20,999
14.0 21.0 15.0 16.2 11.4 17.6 32.8 27.0
56.6 58.6 59.8 58.7 57.2 57.4 58.9 53.9
91.9 92.2 91.3 91.2 90.3 90.5 90.5 90.5
83.0 87.0 78.4 84.5 74.2 80.3 66.9 75.8
72.1 71.5 77.7 77.8 79.4 78.5 77.3 75.2
15.6 15.7 14.5 13.1 11.5 12.0 11.8 13.2
4.4 5.2 2.3 3.3 2.2 3.1 5.6 6.4
1.3 1.1 0.7 0.6 0.9 0.3 0.2 0.5
6.6 6.5 4.8 5.2 6.0 6.1 5.1 4.7
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
10,065 10,086 10,094 10,122 10,171 10,193 10,208 10,357
172.81 171.00 170.36 176.64 185.89 191.24 191.44 184.25
1.74 1.72 1.72 1.78 1.89 1.95 1.95 1.91
II-41
72
CONSOLIDATED STATEMENTS OF INCOME
The Southern Company and Subsidiary Companies
FOR THE YEARS ENDED DECEMBER 31, 1993 1992 1991
(Millions of Dollars)
OPERATING REVENUES $ 8,489 $ 8,073 $ 8,050
OPERATING EXPENSES:
Operation --
Fuel 2,265 2,114 2,237
Purchased power 336 454 468
Proceeds from settlement of disputed contracts (3) (7) (181)
Other 1,448 1,317 1,321
Maintenance 653 613 637
Depreciation and amortization 793 768 763
Deferred Plant Vogtle expenses, net 36 (31) 16
Taxes other than income taxes 462 436 432
Federal and state income taxes 734 647 618
Total operating expenses 6,724 6,311 6,311
OPERATING INCOME 1,765 1,762 1,739
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction 9 10 13
Deferred return on Plant Vogtle - - 35
Write-off of Plant Vogtle costs - - -
Income tax reduction for write-off of Plant Vogtle costs - - -
Interest income 30 32 30
Other, net (41) (50) (57)
Income taxes applicable to other income 57 39 21
INCOME BEFORE INTEREST CHARGES 1,820 1,793 1,781
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest on long-term debt 595 684 757
Allowance for debt funds used during construction (13) (12) (18)
Interest on interim obligations 30 16 20
Amortization of debt discount, premium, and expense, net 26 14 9
Other interest charges 87 34 29
Preferred and preference dividends of subsidiary companies 93 104 108
Net interest charges and preferred and preference dividends 818 840 905
CONSOLIDATED INCOME BEFORE REFUND OF RETAIL REVENUES
BILLED SUBJECT TO REFUND IN PRIOR YEARS AND CUMULATIVE
EFFECT OF A CHANGE IN METHOD OF RECORDING REVENUES 1,002 953 876
Refund of Retail Revenues Billed Subject to Refund in Prior
Years--Less Income Taxes - - -
Cumulative Effect as of Jan. 1, of Accruing Unbilled
Revenues--Less Income Taxes - - -
CONSOLIDATED NET INCOME AS REPORTED $ 1,002 $ 953 $ 876
EARNINGS PER SHARE OF COMMON STOCK $ 1.57 $ 1.51 $ 1.39
AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING
(THOUSANDS) 637,319 631,844 631,307
II-42
73
CONSOLIDATED STATEMENTS OF INCOME
The Southern Company and Subsidiary Companies
1990 1989 1988 1987 1986 1985 1984 1983
$ 8,053 $ 7,620 $ 7,287 $ 7,204 $ 7,033 $ 6,999 $ 6,350 $ 5,673
2,327 2,241 2,213 2,303 2,316 2,431 2,197 1,944
642 575 562 552 386 456 435 281
- - - - - - - -
1,161 1,103 1,167 1,219 1,045 941 840 759
602 542 547 574 576 562 494 429
749 698 632 563 510 471 444 420
31 (39) (8) (142) - - - -
397 356 362 349 315 303 283 255
520 525 412 517 672 649 576 533
6,429 6,001 5,887 5,935 5,820 5,813 5,269 4,621
1,624 1,619 1,400 1,269 1,213 1,186 1,081 1,052
33 71 138 190 312 269 212 146
83 48 107 115 - - - -
(281) - - (358) - - - -
63 - - 129 - - - -
28 28 46 77 66 70 61 61
(55) (50) (30) (59) (20) - 46 (6)
36 30 23 19 - (19) (42) (20)
1,531 1,746 1,684 1,382 1,571 1,506 1,358 1,233
788 791 784 776 782 755 679 644
(34) (63) (130) (157) (260) (254) (199) (142)
22 12 22 24 4 21 16 2
10 11 10 8 6 3 2 2
26 26 32 29 15 17 15 13
115 123 120 125 121 119 110 106
927 900 838 805 668 661 623 625
604 846 846 577 903 845 735 608
- - - - - - - (11)
- - - - - - - 7
$ 604 $ 846 $ 846 $ 577 $ 903 $ 845 $ 735 $ 604
$ 0.96 $ 1.34 $ 1.36 $ 0.96 $ 1.56 $ 1.56 $ 1.47 $ 1.32
631,307 631,303 622,292 601,390 580,252 541,244 501,313 456,262
II-43
74
CONSOLIDATED STATEMENTS OF CASH FLOWS
The Southern Company and Subsidiary Companies
FOR THE YEARS ENDED DECEMBER 31, 1993 1992 1991
(Millions of Dollars)
OPERATING ACTIVITIES:
Net income $ 1,002 $ 953 $ 876
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 1,011 969 968
Deferred income taxes, net 209 221 26
Deferred investment tax credits, net (20) (6) (11)
Allowance for equity funds used during constuction (9) (10) (13)
Deferred Plant Vogtle costs 36 (31) (19)
Write-off of Plant Vogtle costs - - -
Non-cash proceeds from settlement of disputed contracts - (7) (141)
Other, net (45) (25) 45
Changes in certain current assets and liabilities --
Receivables (55) (10) 68
Inventories 136 (23) 20
Payables 43 35 (13)
Taxes accrued 3 (62) 107
Other (64) (9) (46)
Net cash provided from operating activities 2,247 1,995 1,867
INVESTING ACTIVITIES:
Gross property additions (1,441) (1,105) (1,123)
Foreign utility operations (465) - -
Sales of property 262 44 291
Other (37) 61 (45)
Net cash used for investing activities (1,681) (1,000) (877)
FINANCING ACTIVITIES:
Proceeds:
Common stock 205 30 -
Preferred stock 426 410 100
First mortgage bonds 2,185 1,815 380
Pollution control bonds 386 208 126
Other long-term debt 206 48 14
Prepaid capacity revenues - - 53
Retirements:
Preferred and preference stock (516) (326) (125)
First mortgage bonds (2,178) (2,575) (881)
Pollution control bonds (351) (208) (130)
Other long-term debt (99) (88) (70)
Interim obligations, net 114 525 180
Payment of common stock dividends (726) (695) (676)
Miscellaneous (137) (148) (41)
Net cash provided from (used for) financing activities (485) (1,004) (1,070)
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS 81 (9) (80)
CASH AND EQUIVALENTS AT BEGINNING OF YEAR 97 106 186
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 178 $ 97 $ 106
( ) Denotes use of cash.
II-44
75
CONSOLIDATED STATEMENTS OF CASH FLOWS
The Southern Company and Subsidiary Companies
1990 1989 1988 1987 1986 1985 1984 1983
$ 604 $ 846 $ 846 $ 577 $ 903 $ 845 $ 735 $ 604
982 951 837 742 674 623 581 522
158 225 206 198 465 242 243 280
- (1) 27 20 132 184 245 202
(33) (71) (138) (190) (312) (269) (212) (146)
(52) (87) (115) (257) - - - -
281 - - 358 - - - -
- - - - - - - -
(10) (28) 46 87 15 17 (190) (21)
8 (123) (21) (113) 38 (89) (27) (147)
(82) 6 (47) (62) (37) 127 (69) (31)
(41) (23) (6) 125 48 38 187 65
(5) (15) 29 (34) 24 (65) 32 25
(34) 156 (40) 42 (56) 84 70 19
1,776 1,836 1,624 1,493 1,894 1,737 1,595 1,372
(1,185) (1,346) (1,754) (1,853) (2,367) (2,242) (2,130) (1,722)
- - - - - - - -
35 - - 12 - 1 321 -
14 54 (2) 64 46 126 110 74
(1,136) (1,292) (1,756) (1,777) (2,321) (2,115) (1,699) (1,648)
- 4 194 247 379 373 318 333
- - 120 125 100 150 50 50
300 280 335 700 735 20 150 129
- 104 73 228 386 635 368 59
74 74 68 81 367 68 28 186
- - - - 100 - - -
(96) (21) (10) (160) (53) (6) (6) (11)
(146) (201) (273) (369) (875) (69) (71) (53)
(3) (55) (1) (122) (21) - (4) (1)
(207) (83) (108) (56) (55) (54) (99) (103)
78 27 (300) 313 (37) (77) 118 (2)
(676) (675) (661) (628) (583) (512) (444) (380)
(8) (10) (20) (58) (82) (24) (22) (6)
(684) (556) (583) 301 361 504 386 201
(44) (12) (715) 17 (66) 126 282 (75)
230 242 957 940 1,006 880 598 673
$ 186 $ 230 $ 242 $ 957 $ 940 $ 1,006 $ 880 $ 598
II-45
76
CONSOLIDATED BALANCE SHEETS
The Southern Company and Subsidiary Companies
At December 31, 1993 1992 1991
(Millions of Dollars)
ASSETS
ELECTRIC PLANT:
Production-
Fossil $ 8,006 $ 8,033 $ 7,997
Nuclear 5,930 5,912 5,902
Hydro 1,263 1,253 1,247
Total production 15,199 15,198 15,146
Transmission 3,224 3,093 2,955
Distribution 6,848 6,430 6,092
General 2,395 2,291 2,196
Construction work in progress 1,031 665 603
Nuclear fuel, at amortized cost 229 257 301
Total electric plant 28,926 27,934 27,293
STEAM HEAT PLAINT 21 21 20
Total utility plant 28,947 27,955 27,313
ACCUMULATED PROVISION FOR DEPRECIATION:
Electric 8,924 8,271 7,676
Steam heat 10 9 8
Total accumulated provision for depreciation 8,934 8,280 7,684
Total 20,013 19,675 19,629
Less property-related accumulated deferred income taxes - 3,186 3,020
Total 20,013 16,489 16,609
OTHER PROPERTY AND INVESTMENTS:
Securities received from settlement of disputed contracts - - 202
Foreign utility operations, being amortized 559 - -
Nuclear decommissioning trusts 88 52 26
Miscellaneous 89 75 83
Total 736 127 311
CURRENT ASSETS:
Cash and cash equivalents 178 97 106
Investment securities - 199 -
Receivables, net 962 742 723
Accrued utility revenues 185 177 160
Fossil fuel stock, at average cost 254 392 445
Materials and supplies, at average cost 535 533 457
Prepayments 148 220 222
Vacation pay deferred 73 70 70
Total current assets 2,335 2,430 2,183
DEFERRED CHARGES:
Deferred charges related to income taxes 1,546 - -
Deferred Plant Vogtle costs 507 383 375
Deferred fuel charges 70 89 106
Debt expense, being amortized 33 28 23
Premium on reacquired debt, being amortized 288 222 126
Miscellaneous 383 270 130
Total deferred charges 2,827 992 760
TOTAL ASSETS $25,911 $20,038 $19,863
II-46
77
CONSOLIDATED BALANCE SHEETS
The Southern Company and Subsidiary Companies
1990 1989 1988 1987 1986 1985 1984 1983
$ 7,661 $ 7,565 $ 6,226 $ 6,157 $ 5,415 $ 5,274 $ 4,740 $ 4,606
5,820 5,976 4,995 4,987 2,490 2,341 2,312 2,229
1,222 1,215 1,197 1,192 1,184 1,162 863 854
14,703 14,756 12,418 12,336 9,089 8,777 7,915 7,689
2,824 2,683 2,500 2,388 2,254 2,001 1,878 1,747
5,738 5,365 4,944 4,510 4,131 3,793 3,491 3,225
2,078 2,026 1,865 1,674 1,504 1,243 1,037 876
1,092 1,006 3,071 2,519 5,162 4,278 3,830 2,906
354 402 481 479 520 497 455 422
26,789 26,238 25,279 23,906 22,660 20,589 18,606 16,865
20 20 20 20 35 32 26 26
26,809 26,258 25,299 23,926 22,695 20,621 18,632 16,891
7,079 6,492 5,885 5,355 4,879 4,472 4,056 3,669
8 7 6 6 13 11 11 11
7,087 6,499 5,891 5,361 4,892 4,483 4,067 3,680
19,722 19,759 19,408 18,565 17,803 16,138 14,565 13,211
2,911 2,759 2,559 2,371 2,212 1,976 1,792 1,589
16,811 17,000 16,849 16,194 15,591 14,162 12,773 11,622
- - - - - - - -
- - - - - - - -
2 - - - - - - -
83 85 88 70 69 36 32 12
85 85 88 70 69 36 32 12
186 230 242 957 940 1,006 880 598
- - - - - - - -
793 765 687 687 657 685 613 566
151 189 148 139 83 92 76 96
467 427 490 513 501 503 649 614
456 413 348 278 228 188 169 135
193 192 174 136 70 22 18 34
64 65 63 59 56 53 49 48
2,310 2,281 2,152 2,769 2,535 2,549 2,454 2,091
- - - - - - - -
364 322 270 173 - - - -
126 143 157 112 121 - - -
23 24 24 25 24 24 22 20
99 103 102 95 70 - - -
137 134 89 80 73 84 46 45
749 726 642 485 288 108 68 65
$19,955 $20,092 $19,731 $19,518 $18,483 $16,855 $15,327 $13,790
II-47
78
CONSOLIDATED BALANCE SHEETS
The Southern Company and Subsidiary Companies
At December 31, 1993 1992 1991
(Millions of Dollars)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stock $ 3,213 $ 1,582 $ 1,578
Paid-in capital 1,502 2,929 2,906
Premium on preferred stock 1 2 2
Retained Earnings 2,968 2,721 2,490
Total common equity 7,684 7,234 6,976
Preferred stock 1,332 1,351 1,207
Preferred stock subject to mandatory redemption 1 8 126
Long-term debt 7,412 7,241 7,992
Total capitalization 16,429 15,834 16,301
(excluding amount due within one year)
CURRENT LIABILITIES:
Notes payable to banks 865 567 302
Commercial paper 76 260 -
Preferred stock due within one year 1 65 7
Long-term debt due within one year 156 188 217
Accounts payable 698 646 585
Customer deposits 103 99 95
Taxes accrued 206 172 215
Interest accrued 186 191 221
Vacation pay accrued 90 86 84
Miscellaneous 190 242 229
Total current liabilities 2,571 2,516 1,955
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes 3,979 - -
Deferred credits related to income taxes 1,051 - -
Accumulated deferred investment tax credits 900 957 1,004
Prepaid capacity revenues, net 144 148 149
Disallowed Plant Vogtle capacity buyback costs 63 72 110
Miscellaneous 774 511 344
Total deferred credits and other liabilities 6,911 1,688 1,607
Total Capitalization and Liabilities $25,911 $20,038 $19,863
II-48
79
CONSOLIDATED BALANCE SHEETS
The Southern Company and Subsidiary Companies
1990 1989 1988 1987 1986 1985 1984 1983
$ 1,578 $ 1,578 $ 1,577 $ 1,534 $ 1,481 $ 1,400 $ 1,305 $ 1,202
2,906 2,906 2,903 2,752 2,558 2,259 1,981 1,767
3 3 3 3 5 7 7 6
2,296 2,374 2,203 2,018 2,089 1,777 1,448 1,160
6,783 6,861 6,686 6,307 6,133 5,443 4,741 4,135
1,207 1,209 1,259 1,139 1,214 1,114 1,004 954
151 191 206 224 177 194 205 214
8,458 8,575 8,433 8,333 7,813 7,220 6,775 6,439
16,599 16,836 16,584 16,003 15,337 13,971 12,725 11,742
122 44 17 317 4 41 118 -
- - - - - - - -
7 61 17 9 15 51 6 3
308 169 190 192 251 303 162 140
616 676 728 747 737 689 651 464
91 89 83 86 82 80 83 76
144 181 203 221 259 144 208 196
246 233 240 233 221 226 208 181
75 75 74 68 66 63 58 55
233 252 104 110 111 117 91 73
1,842 1,780 1,656 1,983 1,746 1,714 1,585 1,188
- - - - - - - -
- - - - - - - -
1,063 1,111 1,161 1,180 1,208 1,114 968 767
100 102 81 104 101 - - -
136 73 104 79 - - - -
215 190 145 169 91 56 49 93
1,514 1,476 1,491 1,532 1,400 1,170 1,017 860
$19,955 $20,092 $19,731 $19,518 $18,483 $16,855 $15,327 $13,790
II-49
80
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-50
81
MANAGEMENT'S REPORT
Alabama Power Company 1993 Annual Report
The management of Alabama Power Company has prepared -- and is responsible for
- -- the financial statements and related information included in this report.
These statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts
that are based on the best estimates and judgments of management. Financial
information throughout this annual report is consistent with the financial
statements.
The company maintains a system of internal accounting controls to
provide reasonable assurance that assets are safeguarded and that the books and
records reflect only authorized transactions of the company. Limitations exist
in any system of internal controls based on a recognition that the cost of the
system should not exceed its benefits. The company believes its system of
internal accounting controls maintains an appropriate cost/benefit
relationship.
The company's system of internal accounting controls is evaluated on
an ongoing basis by the company's internal audit staff. The company's
independent public accountants also consider certain elements of the internal
control system in order to determine their auditing procedures for the purpose
of expressing an opinion on the financial statements.
The audit committee of the board of directors, composed of directors
who are not employees, provides a broad overview of management's financial
reporting and control functions. Periodically, this committee meets with
management, the internal auditors and the independent public accountants to
ensure that these groups are fulfilling their obligations and to discuss
auditing, internal controls, and financial reporting matters. The internal
auditors and independent public accountants have access to the members of the
audit committee at any time.
Management believes that its policies and procedures provide
reasonable assurance that the company's operations are conducted according to a
high standard of business ethics. In management's opinion, the financial
statements present fairly, in all material respects, the financial position,
results of operations and cash flows of Alabama Power Company in conformity
with generally accepted accounting principles.
/s/ Elmer B. Harris /s/ William B. Hutchins, III
- -------------------------- ------------------------------
Elmer B. Harris William B. Hutchins III
President Senior Vice President
and Chief Executive Officer and Chief Financial Officer
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS
OF ALABAMA POWER COMPANY:
We have audited the accompanying balance sheets and statements of
capitalization of Alabama Power Company (an Alabama corporation and wholly
owned subsidiary of The Southern Company) 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 the company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements (pages II-59 through II-77)
referred to above present fairly, in all material respects, the financial
position of Alabama Power Company as of December 31, 1993 and 1992, and the
results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
As explained in Notes 2 and 8 to the financial statements, effective
January 1, 1993, the company changed its methods of accounting for
postretirement benefits other than pensions, and for income taxes.
/s/ Arthur Andersen & Co.
Birmingham, Alabama
February 16, 1994
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 1993 Annual Report
RESULTS OF OPERATIONS
EARNINGS
The company's 1993 net income after dividends on preferred stock was $346
million, representing a 2.3 percent increase over the prior year. This
improvement can be attributed to higher retail energy sales and lower financing
costs. Retail energy sales increased 5.1 percent from 1992 levels. This was
primarily due to the extreme weather during 1993, especially when compared to
the unusually mild weather of 1992. Long-term debt interest expense and
preferred stock dividends decreased in 1993 reflecting the continued redemption
and refinancing of higher cost debt and preferred stock. These positive
factors were partially offset by higher operating costs and a scheduled
reduction in capacity sales to non-affiliated utilities.
When comparing 1992 earnings with the prior year, it should be noted
that 1991 earnings included an unusual item -- the settlement of litigation
with Gulf States Utilities Company (Gulf States) that resulted in an after-tax
gain of $9 million. A comparison of 1992 to 1991, excluding this unusual
item, would reflect a 1992 increase in earnings of $8 million.
The return on average common equity for 1993 was 13.9 percent compared
to 14.0 percent in 1992, and 14.6 percent in 1991.
REVENUES
The following table summarizes the principal factors that affected operating
revenues for the past three years:
Increase (Decrease)
From Prior Year
1993 1992 1991
(in thousands)
Retail --
Change in
base rates $ -- $ 36,348 $ 16,831
Sales growth 24,960 36,237 47,769
Weather 58,536 (42,709) (7,318)
Fuel cost recovery
and other 96,437 (31,318) 25,719
Total retail 179,933 (1,442) 83,001
Sales for Resale --
Non-affiliates (43,686) (121) (27,084)
Affiliates 23,887 (1,287) 65,902
Total sales for resale (19,799) (1,408) 38,818
Other operating
revenues 635 2,896 2,551
Total operating
revenues $160,769 $ 46 $124,370
Percent change 5.6% -- % 4.6%
Retail revenues of $2.4 billion in 1993 increased $180 million (8.0
percent) over the prior year, compared with no increase in 1992. The extreme
weather during 1993 and sales growth contributed to the increase in retail
revenues over 1992. Fuel revenues increased substantially during 1993.
However, changes in fuel revenues are offset with corresponding changes in
recoverable fuel expenses and have no effect on net income. Gains in 1992
retail revenues, due to higher rates and sales growth, were partially offset by
lower fuel cost recovery revenues.
Revenues from sales to non-affiliated utilities under long-term contracts
consist of capacity and energy components. Capacity revenues reflect the
recovery of fixed costs and a return on investment under the contracts. Energy
is generally sold at variable cost. The capacity and energy components were:
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
Capacity $158,709 $185,689 $179,754
Energy 79,631 111,958 111,971
Total $238,340 $297,647 $291,725
Capacity revenues decreased in 1993 due to a scheduled reduction in
capacity dedicated to unit power sales customers for the first five months of
the year. The major factor contributing to the increase in capacity revenues
in 1992 and 1991 was a new generating unit, Plant Miller Unit 4, that was
placed in commercial service in March 1991 and dedicated to unit power sales.
This unit's fixed costs are higher than those of the unit it replaced, which
previously provided energy to unit power sales customers.
Sales to affiliated companies within the Southern electric system will
vary from year to year depending on demand and the availability and cost of
generating resources at each company. These sales have no material impact on
earnings.
Kilowatt-hour (KWH) sales for 1993 and the percent change by year were
as follows:
KWH Percent Change
1993 1993 1992 1991
(millions)
Residential 13,185 9.2% (2.1)% 2.7%
Commercial 9,185 6.4 1.2 4.0
Industrial 18,595 1.8 4.3 (1.1)
Other 182 2.8 1.2 2.5
Total retail 41,147 5.1 1.6 1.2
Sales for resale-
Non-affiliates 7,144 (14.8) (4.9) (14.3)
Affiliates 8,081 12.1 (7.4) 72.2
Total 56,372 3.0% (0.7)% (4.3)%
EXPENSES
Total operating expenses of $2.4 billion for 1993 were up 7.0 percent
compared with the prior year. The increase was mainly attributable to higher
production expenses of $95 million to meet increased energy demands.
Total operating expenses for 1992 increased moderately over those
recorded in 1991. However, absent the Gulf States settlement, which reduced
1991 operating expenses, total operating expenses would have decreased $6
million.
Fuel costs are the single largest expense for the company. The mix of
fuel sources for generation of electricity is determined primarily by system
load, the unit cost of fuel consumed, and the availability of hydro and nuclear
generating units. Fuel expense increases in 1993 represent $83 million of the
production expense increase mentioned above. Fuel expense decreased in 1992 as
a result of the reduction in the cost of both coal and nuclear fuel, offset
somewhat by a small increase in generation. Fuel cost per kilowatt-hour
generated was 1.73 cents in 1993, 1.64 cents in 1992 and 1.69 cents in 1991.
Purchased power expenses decreased in 1992 primarily due to less purchased
energy and a decrease in the price of such energy.
Other operation expenses increased 6.0 percent in 1993 following a
minimal increase in 1992. The increase in 1993 is primarily the result of
environmental cleanup costs, net expenses of a March snowstorm, and the
one-time cost of a transportation fleet reduction program, which together
totaled $16.1 million.
Depreciation and amortization expense increased 3.4 percent in 1993
and 3.5 percent in 1992. This is principally due to continued growth in
depreciable plant in service. Taxes other than income taxes increased 4.0
percent in 1993 and 1.4 percent in 1992. These increases were the result of
the addition of new facilities and higher revenue-related taxes.
The increase in income tax expense of 2.6 percent for 1993 is
primarily attributable to a one percent increase in the corporate federal
income tax rate effective January 1, 1993.
Interest expense and dividends on preferred stock decreased $7.5
million (2.8 percent) and $7.2 million (2.6 percent) in 1993 and 1992,
respectively. These reductions are due to significant refinancing of long-term
debt and preferred stock.
II - 54
85
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1993 Annual Report
EFFECTS OF INFLATION
The company is subject to rate regulation that is based on the recovery of
historical costs and, therefore is subject to economic losses caused by
inflation. While the inflation rate has been relatively low in recent years,
it continues to have an adverse effect on the company because of the large
investment in long-lived utility plant. Conventional accounting for historical
cost does not recognize this economic loss nor the partially offsetting gain
that arises through financing facilities with fixed-money obligations, such as
long-term debt and preferred stock. Any recognition of inflation by regulatory
authorities is reflected in the rate of return allowed.
FUTURE EARNINGS POTENTIAL
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends
on numerous factors ranging from growth in energy sales to regulatory matters.
Future earnings in the near term will also depend upon growth in
electric sales, which are subject to a number of factors. Traditionally, these
factors have included changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, weather,
competition, and the rate of economic growth in the company's service area. In
addition, the Energy Policy Act of 1992 (Energy Act) will have a profound
effect on the future of the electric utility industry. The Energy Act promotes
energy efficiency, alternative fuel use, and increased competition for electric
utilities. The law also includes provisions to streamline the licensing
process for new nuclear plants. The company is preparing to meet the challenge
of this major change in the traditional business practices of selling
electricity. The Energy Act allows independent power producers (IPPs) to
access a utility's transmission network in order to sell electricity to other
utilities, and this may enhance the incentive for IPPs to build cogeneration
plants for a utility's large industrial and commercial customers and sell
excess energy generation to other utilities. Although the Energy Act does not
require transmission access to retail customers, pressure for legislation to
allow retail wheeling will continue. If the company does not remain a low-cost
producer and provide quality service, the company's retail energy sales growth,
as well as any new long-term contracts for energy sales outside the service
area, could be limited, and this could significantly erode earnings.
Rates to retail customers served by the company are regulated by the
Alabama Public Service Commission (APSC). Rates for the company can be
adjusted periodically within certain limitations based on earned retail rate of
return compared with an allowed return. See Note 3 to the financial statements
for information about other regulatory matters.
The Federal Energy Regulatory Commission (FERC) regulates wholesale
rate schedules and power sales contracts that the company has with its sales
for resale customers. The FERC currently is reviewing the rate of return on
common equity included in these schedules and contracts and may require such
returns to be lowered, possibly retroactively. See Note 3 to the financial
statements under "FERC Reviews Equity Returns" for additional information.
Compliance costs related to the Clean Air Act Amendments of 1990
(Clean Air Act) could reduce earnings if such costs are not fully recovered.
The Clean Air Act is discussed later under "Environmental Matters."
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112,
Employers' Accounting for Postemployment Benefits, which must be effective by
1994. The new standard requires that all types of benefits provided to former
or inactive employees and their families prior to retirement be accounted for
on an accrual basis. These benefits include salary continuation, severance
pay, supplemental unemployment benefits, disability-related benefits, job
training, and health and life insurance coverage. In 1993, the company adopted
Statement No. 112, with no material effect on the financial statements.
The FASB has issued Statement No. 115, Accounting for Certain
Investments in Debt and Equity Securities, which is effective in 1994.
Statement No. 115 supersedes FASB Statement No. 12, Accounting for Certain
Marketable Securities. The company adopted the new rules January 1, 1994, with
no material effect on the financial statements.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1993 Annual Report
FINANCIAL CONDITION
OVERVIEW
The company's financial condition remained stable in 1993. Growth in energy
sales combined with a significant lowering of the cost of capital, achieved
through the refinancing and/or redemption of higher-cost long-term debt and
preferred stock contributed to this stability.
The company had gross property additions of $436 million in 1993. The
majority of funds needed for gross property additions since 1990 have been
provided from operating activities, principally from earnings and non-cash
charges to income such as depreciation and deferred income taxes. The
Statements of Cash Flows provide additional details.
On January 1, 1993, the company changed its methods of accounting for
postretirement benefits other than pensions, and for income taxes. See Notes 2
and 8 to the financial statements, regarding the impact of these changes.
CAPITAL STRUCTURE
The company's ratio of common equity to total capitalization was 47.4 percent
in 1993, compared with 47.6 percent in 1992, and 45.4 percent in 1991.
In 1993, the company issued $860 million of first mortgage bonds, $158
million of preferred stock and, through public authorities, $144 million of
pollution control revenue bonds. The company continued to reduce financing
costs by retiring higher-cost bonds and preferred stock. Retirements,
including maturities, of bonds totaled $835 million, and preferred stock
retirements totaled $207 million. Composite financing rates as of year-end for
1991 through 1993 were as follows:
1993 1992 1991
Composite interest rate on
long-term debt 7.35% 8.00% 8.64%
Composite dividend rate on
preferred stock 5.80% 6.76% 7.10%
The company's current securities ratings are as follows:
Duff & Standard
Phelps Moody's & Poor's
First Mortgage Bonds A+ A1 A
Preferred Stock A- a2 A-
CAPITAL REQUIREMENTS
Capital expenditures are estimated to be $588 million for 1994, $572 million
for 1995, and $531 million for 1996. The total is $1.7 billion for the three
years. Actual capital costs may vary from this estimate because of factors
such as changes in environmental regulations; changes in the existing nuclear
plant to meet new regulations; revised load projections; increasing costs of
labor, equipment, and materials; and the cost of capital.
The company does not have any baseload generating plants under construction,
and current energy demand forecasts do not require any additional baseload
generating units until well into the future. However, the construction of
combustion turbine peaking units of approximately 720 megawatts of capacity is
planned by 1996 to meet increased peak-hour demands. In addition, significant
construction of transmission and distribution facilities and upgrading of
generating plants will continue.
In addition to the funds needed for the capital budget, approximately $80
million will be required by the end of 1996 for present sinking fund
requirements, redemptions announced, and maturities of first mortgage bonds.
Also, the company plans to continue a program to retire higher-cost debt and
preferred stock and replace these obligations with lower-cost capital.
ENVIRONMENTAL MATTERS
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law -- will have a
significant impact on the Southern electric system. Specific reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants
will be required in two phases. Phase I compliance must be implemented in 1995
and affects eight generating plants -- some 10,000
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1993 Annual Report
megawatts of capacity or 35 percent of total capacity -- in the Southern
electric system. Phase II compliance is required in 2000, and all fossil-fired
generating plants in the Southern electric system will be affected.
Beginning in 1995, the Environmental Protection Agency (EPA) will allocate
annual sulfur dioxide emission allowances through the newly established
allowance trading program. An emission allowance is the authority to emit one
ton of sulfur dioxide during a calendar year. The method for allocating
allowances is based on the fossil fuel consumed from 1985 through 1987 for each
affected generating unit. Emission allowances are transferable and can be
bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize the
cost of compliance. The market for emission allowances is developing slower
than expected. However, The Southern Company's sulfur dioxide compliance
strategy is designed to take advantage of allowances as the market develops.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at
the eight affected plants by switching to low-sulfur coal, and this has
required some equipment upgrades. This compliance strategy is expected to
result in unused emission allowances being banked for later use. Additional
construction expenditures are required to install equipment for the control of
nitrogen oxide emissions at these eight plants. Also, continuous emissions
monitoring equipment would be installed on all fossil-fired units. Under this
Phase I compliance approach, additional construction expenditures are estimated
to total approximately $275 million through 1995 for The Southern Company, of
which the company's portion is approximately $30 million.
Phase II compliance costs are expected to be higher because requirements are
stricter and all fossil-fired generating plants are affected. For sulfur
dioxide compliance, The Southern Company could use emission allowances banked
during Phase I, increase fuel switching, install flue gas desulfurization
equipment at selected plants, and/or purchase more allowances depending on the
price and availability of allowances. Also, in Phase II, equipment to control
nitrogen oxide emissions will be installed on additional system fossil-fired
plants as required to meet anticipated Phase II limits. Therefore, during the
period 1996 to 2000, compliance could require total construction expenditures
ranging from approximately $450 million to $800 million for The Southern
Company, of which the company's portion is approximately $225 million to $350
million. However, the full impact of Phase II compliance cannot now be
determined with certainty, pending the development of a market for emission
allowances, the completion of EPA regulations, and the possibility of new
emission reduction technologies.
An increase of up to 2 percent in annual revenue requirements from customers
could be necessary to fully recover the company's cost of compliance for both
Phase I and Phase II of the Clean Air Act. Compliance costs include
construction expenditures, increased costs for switching to low-sulfur coal,
and costs related to emission allowances.
There can be no assurance that all Clean Air Act costs will be recovered.
Title III of the Clean Air Act requires a multi-year EPA study of power plant
emissions of hazardous air pollutants. The study will serve as the basis for a
decision on whether additional regulatory control of these substances is
warranted. Compliance with any new control standards could result in
significant additional costs. The impact of new standards -- if any -- will
depend on the development and implementation of applicable regulations.
The EPA continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study on
the impact of a new standard indicate that a number of plants could be required
to install sulfur dioxide controls. These controls would be in addition to the
controls already required to meet the acid rain provision of the Clean Air Act.
The EPA is expected to take some action on this issue in 1994. The impact of
any new standard will depend on the level chosen for the standard and cannot be
determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air quality
standards for particulate matter, nitrogen oxides, and ozone. The impact of
any new standard will depend on the level chosen for the standard
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1993 Annual Report
and cannot be determined at this time.
In 1994 or 1995, the EPA is expected to issue revised rules on air quality
control regulations related to stack height requirements of the Clean Air Act.
The full impact of the final rules cannot be determined at this time, pending
their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of coal
ash. However, the EPA has until 1998 to classify co-managed utility wastes --
coal ash and other utility wastes -- as either non-hazardous or hazardous. If
the EPA classifies the co-managed wastes as hazardous, then substantial
additional costs for the management of such wastes may be required. The full
impact of any change in the regulatory status will depend on the subsequent
development of co-managed waste requirements.
The company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws
and regulations, the company could incur costs to clean up properties currently
or previously owned. The company conducts studies to determine the extent of
any required clean-up costs and has recognized in the financial statements
costs to clean up known sites.
Several major pieces of environmental legislation are in the process of being
reauthorized or amended by Congress. These include: the Clean Water Act; the
Comprehensive Environmental Response, Compensation, and Liability Act; and the
Resource Conservation and Recovery Act. Changes to these laws could affect
many areas of The Southern Company's operations. The full impact of these
requirements cannot be determined at this time, pending the development and
implementation of applicable regulations.
Compliance with possible new legislation related to global climate change,
electromagnetic fields, and other environmental and health concerns could
significantly affect the Southern electric system. The impact of new
legislation -- if any -- will depend on the subsequent development and
implementation of applicable regulations. In addition, the potential for
lawsuits alleging damages caused by electromagnetic fields exists.
SOURCES OF CAPITAL
It is anticipated that the funds required will be derived from sources in form
and quantity similar to those used in the past. To issue additional first
mortgage bonds and preferred stock, the company must comply with certain
earnings coverage requirements designated in its mortgage indenture and
corporate charter. The company's coverages are at a level that would permit
any necessary amount of security sales at current interest and dividend rates.
As required by the Nuclear Regulatory Commission and as ordered by the APSC,
the company has established external trust funds for nuclear decommissioning
costs. Also, during 1993, the APSC issued a policy statement which will
require external funding of postretirement benefits. The cumulative effect of
funding these items over a long period will diminish internally funded capital
and may require capital from other sources. For additional information
concerning nuclear decommissioning costs, see Note 1 to the financial
statements under "Depreciation and Nuclear Decommissioning."
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89
STATEMENTS OF INCOME
For the Years Ended December 31, 1993, 1992, and 1991
Alabama Power Company
1993 1992 1991
(in thousands)
OPERATING REVENUES (NOTES 1, 3 AND 7):
Revenues $ 2,825,634 $ 2,688,752 $ 2,687,419
Revenues from affiliates 181,975 158,088 159,375
Total operating revenues 3,007,609 2,846,840 2,846,794
OPERATING EXPENSES:
Operation --
Fuel 877,099 794,438 812,667
Purchased power from non-affiliates 15,230 14,242 21,080
Purchased power from affiliates 120,330 107,230 119,602
Proceeds from settlement of disputed contracts (Note 7) (2,568) (641) (14,819)
Other 473,383 446,477 435,908
Maintenance 252,506 237,071 229,114
Depreciation and amortization 290,310 280,881 271,433
Taxes other than income taxes 178,997 172,095 169,639
Federal and state income taxes (Note 8) 207,210 201,925 200,612
Total operating expenses 2,412,497 2,253,718 2,245,236
OPERATING INCOME 595,112 593,122 601,558
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction (Note 1) 3,260 2,071 2,368
Income from subsidiary (Note 6) 4,127 4,635 4,576
Charitable foundation (3,000) (6,887) (6,500)
Interest income 20,775 14,804 14,356
Other, net (24,420) (11,019) (9,926)
Income taxes applicable to other income 10,239 8,947 7,523
INCOME BEFORE INTEREST CHARGES 606,093 605,673 613,955
INTEREST CHARGES:
Interest on long-term debt 184,861 206,871 214,107
Allowance for debt funds used during construction (Note 1) (2,992) (2,416) (6,903)
Interest on interim obligations 3,760 3,704 13,385
Amortization of debt discount, premium, and expense, net 8,937 4,392 2,634
Other interest charges 35,474 19,381 14,927
Net interest charges 230,040 231,932 238,150
NET INCOME 376,053 373,741 375,805
DIVIDENDS ON PREFERRED STOCK 29,559 35,186 36,139
NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 346,494 $ 338,555 $ 339,666
The accompanying notes are an integral part of these statements.
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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1993, 1992, and 1991
Alabama Power Company
1993 1992 1991
(in thousands)
OPERATING ACTIVITIES:
Net income $ 376,053 $ 373,741 $ 375,805
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 356,499 338,421 337,978
Deferred income taxes and investment tax credits 32,994 23,514 (6,868)
Allowance for equity funds used during construction (3,260) (2,071) (2,368)
Non-cash proceeds from settlement of disputed contracts (Note 7) - (641) (13,750)
Other, net 36,493 (2,657) 26,614
Changes in certain current assets and liabilities --
Receivables, net 19,215 (11,010) 9,178
Inventories 51,630 12,704 (17,374)
Payables 31,544 2,158 28,889
Taxes accrued (9,959) (21,120) 24,828
Energy cost recovery, retail (56,128) 45,509 (12,304)
Other (21,110) 10,629 (37,906)
Net cash provided from operating activities 813,971 769,177 712,722
INVESTING ACTIVITIES:
Gross property additions (435,843) (367,463) (397,011)
Sales of property - 43,556 -
Other (741) (13,379) (36,083)
Net cash used for investing activities (436,584) (337,286) (433,094)
FINANCING ACTIVITIES:
Proceeds:
Preferred stock 158,000 150,000 -
First mortgage bonds 860,000 745,000 250,000
Other long-term debt 180,314 48,382 12,906
Prepaid capacity revenues - - 52,900
Retirements:
Preferred stock (207,000) (145,000) (17,500)
First mortgage bonds (699,788) (931,797) (227,695)
Other long-term debt (181,329) (54,223) (48,678)
Interim obligations, net (156,917) 120,917 (13,500)
Payment of preferred stock dividends (32,099) (35,704) (36,829)
Payment of common stock dividends (252,900) (273,300) (232,900)
Miscellaneous (56,064) (53,697) (17,732)
Net cash used for financing activities (387,783) (429,422) (279,028)
NET CHANGE IN CASH (10,396) 2,469 600
CASH AT BEGINNING OF YEAR 13,629 11,160 10,560
CASH AT END OF YEAR $ 3,233 $ 13,629 $ 11,160
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for --
Interest (net of amount capitalized) $ 176,805 $ 219,263 $ 220,154
Income taxes 175,591 197,693 148,721
( ) Denotes use of cash.
The accompanying notes are an integral part of these statements.
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91
BALANCE SHEETS
At December 31, 1993 and 1992
Alabama Power Company
ASSETS 1993 1992
(in thousands)
UTILITY PLANT:
Plant in service, at original cost (Note 1) $9,757,141 $9,491,083
Less accumulated provision for depreciation 3,384,156 3,131,543
6,372,985 6,359,540
Nuclear fuel, at amortized cost 93,551 101,128
Construction work in progress 225,786 164,588
Total 6,692,322 6,625,256
Less property-related accumulated deferred income taxes (Note 8) - 1,170,982
Total 6,692,322 5,454,274
OTHER PROPERTY AND INVESTMENTS:
Southern Electric Generating Company, at equity (Note 6) 29,201 30,703
Nuclear decommissioning trusts (Note 1) 49,550 32,390
Miscellaneous 20,434 19,189
Total 99,185 82,282
CURRENT ASSETS:
Cash 3,233 13,629
Investment securities (Note 7) - 64,832
Receivables-
Customer accounts receivable 312,090 266,670
Other accounts and notes receivable 48,808 34,801
Affiliated companies 40,216 37,128
Accumulated provision for uncollectible accounts (2,632) (1,482)
Refundable income taxes 11,940 7,817
Fossil fuel stock, at average cost 88,481 134,328
Materials and supplies, at average cost 176,728 182,511
Prepayments-
Income taxes 18,980 66,250
Other 60,227 42,004
Vacation pay deferred 22,680 21,879
Total 780,751 870,367
DEFERRED CHARGES:
Deferred charges related to income taxes (Note 8) 469,010 -
Debt expense, being amortized 7,064 6,118
Premium on reacquired debt, being amortized 102,634 74,835
Uranium enrichment decontamination and decommissioning fund (Note 1) 45,554 47,730
Miscellaneous 52,163 58,012
Total 676,425 186,695
TOTAL ASSETS $8,248,683 $6,593,618
The accompanying notes are an integral part of these statements.
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BALANCE SHEETS
At December 31, 1993 and 1992
Alabama Power Company
CAPITALIZATION AND LIABILITIES 1993 1992
(in thousands)
CAPITALIZATION (SEE ACCOMPANYING STATEMENTS):
Common stock equity $2,526,348 $2,443,493
Preferred stock 440,400 489,400
Long-term debt 2,362,852 2,202,473
Total 5,329,600 5,135,366
CURRENT LIABILITIES:
Long-term debt due within one year (Note 10) 58,998 67,379
Notes payable to banks 40,000 71,000
Commercial paper - 125,917
Accounts payable-
Affiliated companies 62,507 64,318
Other 272,491 232,413
Customer deposits 31,198 31,286
Taxes accrued-
Federal and state income 25,730 10,854
Other 14,414 13,519
Interest accrued 52,809 41,675
Vacation pay accrued 22,680 21,879
Miscellaneous 50,426 93,836
Total 631,253 774,076
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes (Note 8) 1,165,127 -
Accumulated deferred investment tax credits 329,909 344,707
Prepaid capacity revenues, net 143,762 147,658
Deferred revenues from settlement of disputed contracts (Note 3) 19,871 46,721
Uranium enrichment decontamination and decommissioning fund (Note 1) 39,644 44,548
Deferred credits related to income taxes (Note 8) 441,240 -
Miscellaneous 148,277 100,542
Total 2,287,830 684,176
COMMITMENTS AND CONTINGENT MATTERS (NOTES 1, 3, 4, 5, 6, 7, AND 11)
TOTAL CAPITALIZATION AND LIABILITIES $8,248,683 $6,593,618
The accompanying notes are an integral part of these statements.
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STATEMENTS OF CAPITALIZATION
At December 31, 1993 and 1992
Alabama Power Company
1993 1992 1993 1992
(thousands) (percent of total)
COMMON STOCK EQUITY:
Common stock, par value $40 per share --
Authorized -- 6,000,000 shares
Outstanding -- 5,608,955 shares in
1993 and 1992 $ 224,358 $ 224,358
Paid-in capital 1,304,645 1,304,645
Premium on preferred stock 146 342
Retained earnings (Note 12) 997,199 914,148
Total common stock equity 2,526,348 2,443,493 47.4 % 47.6 %
CUMULATIVE PREFERRED STOCK:
$1 par value --
Authorized -- 27,500,000 shares
Outstanding -- 12,020,200 shares
$25 stated capital --
6.40% 50,000 -
6.80% 38,000 -
7.60% 150,000 150,000
Adjustable rate
4.95% - at January 1, 1994 50,000 -
6.08% - at January 1, 1993 - 50,000
$100 stated capital --
Auction rate - at January 1, 1994: 2.92% 50,000 50,000
$100,000 stated capital --
Auction rate - at January 1, 1994: 2.72% 20,000 -
$100 par value --
Authorized -- 3,850,000 shares
Outstanding -- 824,000 shares
4.20% to 4.52% 41,400 41,400
4.60% to 4.92% 29,000 29,000
5.96% to 8.04% 12,000 32,000
8.16% to 9.44% - 137,000
Total (annual dividend requirement -- $25,547,000) 440,400 489,400 8.3 9.5
LONG-TERM DEBT:
First mortgage bonds --
Maturity Interest Rates
May 1, 1994 4 5/8% - 24,105
September 1, 1995 4 7/8% - 33,284
March 1, 1996 4 1/2% 60,000 -
October 1, 1996 6 1/4% - 29,374
October 1, 1997 6 1/2% - 28,000
February 1, 1998 5 1/2% 50,000 -
November 1, 1998 7% - 25,000
1999 through 2003 6% to 8 1/4% 670,000 533,500
2004 through 2008 7 1/4% 175,000 175,000
2009 through 2013 - - -
2014 through 2018 9 3/8% to 10 5/8% 15,243 311,768
2019 through 2023 7.30% to 9 1/4% 900,000 550,000
Total first mortgage bonds 1,870,243 1,710,031
Pollution control obligations 476,140 467,019
Other long-term debt 106,414 116,550
Unamortized debt premium (discount), net (30,947) (23,748)
Total long-term debt (annual interest
requirement -- $180,046,000) 2,421,850 2,269,852
Less amount due within one year (Note 10) 58,998 67,379
Long-term debt excluding amount due within one year 2,362,852 2,202,473 44.3 42.9
TOTAL CAPITALIZATION $ 5,329,600 $ 5,135,366 100.0 % 100.0 %
The accompanying notes are an integral part of these statements.
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STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1993, 1992, and 1991
Alabama Power Company
1993 1992 1991
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 914,148 $ 857,734 $ 751,126
Net income after dividends on preferred stock 346,494 338,555 339,666
Cash dividends on common stock (252,900) (273,300) (232,900)
Preferred stock transactions, net (10,587) (8,732) (362)
Other adjustments to retained earnings 44 (109) 204
BALANCE AT END OF PERIOD (NOTE 12) $ 997,199 $ 914,148 $ 857,734
The accompanying notes are an integral part of these statements.
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NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 1993 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
GENERAL
The company is a wholly owned subsidiary of The Southern Company which is the
parent company of five operating companies, a system service company, Southern
Electric International (Southern Electric), Southern Nuclear Operating Company
(Southern Nuclear), and various other subsidiaries related to foreign utility
operations and domestic non-utility operations. At this time, the operations
of the other subsidiaries are not material. The operating companies (Alabama
Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power
Company, and Savannah Electric and Power Company) provide electric service in
four Southeastern states. Contracts among the companies -- dealing with
jointly-owned generating facilities, interconnecting transmission lines, and
the exchange of electric power -- are regulated by the Federal Energy
Regulatory Commission (FERC) or the Securities and Exchange Commission (SEC).
The system service company provides, at cost, specialized services upon request
to The Southern Company and to the subsidiary companies. Southern Electric
designs, builds, owns and operates power production facilities and provides a
broad range of technical services to industrial companies and utilities in the
United States and a number of international markets. Southern Nuclear provides
services to The Southern Company's nuclear power plants.
The Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both The Southern Company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The
company is also regulated by the FERC and the Alabama Public Service Commission
(APSC). The company follows generally accepted accounting principles and
complies with the accounting policies and practices prescribed by the
respective commissions.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
REVENUES AND FUEL COSTS
The company accrues revenues for services rendered but unbilled at the end of
each fiscal period. Fuel costs are expensed as the fuel is used. The
company's electric rates include provisions to adjust billings for fluctuations
in fuel and the energy component of purchased power costs. Revenues are
adjusted for differences between recoverable fuel costs and amounts actually
recovered in current rates.
Fuel expense includes the amortization of the cost of nuclear fuel and a
charge, based on nuclear generation, for the permanent disposal of spent
nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted
to $62 million in 1993, $48 million in 1992, and $69 million in 1991. The
company has a contract with the U.S. Department of Energy (DOE) that provides
for the permanent disposal of spent nuclear fuel, which was scheduled to begin
in 1998. However, the actual year this service will begin is uncertain.
Sufficient storage capacity currently is available to permit operation into
2012 and 2014 at Plant Farley units 1 and 2, respectively.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a
Uranium Enrichment Decontamination and Decommissioning Fund, which is to be
funded in part by a special assessment on utilities with nuclear plants. This
assessment will be paid over a 15-year period, which began in 1993. This fund
will be used by the DOE for the decontamination and decommissioning of its
nuclear fuel enrichment facilities. The law provides that utilities will
recover these payments in the same manner as any other fuel expense. The
company currently estimates its liability under this law to be approximately
$46 million. This obligation is recognized in the accompanying Balance Sheets.
DEPRECIATION AND NUCLEAR DECOMMISSIONING
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates which approximated
3.3 percent in 1993, 1992, and 1991. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its cost --
together with the cost of removal, less salvage -- is charged to the
accumulated provision for depreciation. Minor items of property included in
the original cost of the plant are retired when the related property unit is
retired. Depreciation expense includes an amount for the expected cost of
decommissioning nuclear facilities.
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Alabama Power Company 1993 Annual Report
In 1988, the Nuclear Regulatory Commission (NRC) adopted regulations
requiring all licensees operating commercial power reactors to establish a plan
for providing, with reasonable assurance, funds for decommissioning.
Reasonable assurance may be in the form of an external trust fund, a surety
method, or prepayment. The company has established external trust funds to
comply with the NRC's regulations. Prior to the enactment of these
regulations, the company had reserved nuclear decommissioning costs. The NRC's
minimum external funding requirements are based on a generic estimate of the
cost to decommission the radioactive portions of a nuclear unit based on the
size and type of reactor. The company has filed plans with the NRC to ensure
that -- over time -- the deposits and earnings of the external trust funds will
provide the minimum funding amount prescribed by the NRC.
The estimated cost of decommissioning and the amounts being recovered
through rates at December 31, 1993, for Plant Farley were as follows:
Plant
Farley
Site study basis (year) 1993
Estimated completion of
decommissioning (year) 2029
(in millions)
Cost of decommissioning:
Radiated structures $409
Non-radiated structures 75
Other 94
Total cost $578
(in millions)
Approved for ratemaking $578
Amount expensed in 1993 14
Balance in external trust funds 50
Balance in internal reserve 53
The amount in the internal reserve is being transferred into the external
trust funds over the remaining life of the license for Plant Farley as approved
by the APSC.
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of regulatory requirements, changes in
technology, and changes in costs of labor, materials, and equipment.
INCOME TAXES
The company provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
In years prior to 1993, income taxes were accounted for and reported under
Accounting Principles Board Opinion No. 11. Effective January 1, 1993, the
company adopted Financial Accounting Standards Board (FASB) Statement No. 109,
Accounting for Income Taxes. Statement No. 109 required, among other things,
conversion to the liability method of accounting for accumulated deferred
income taxes. See Note 8 for additional information about Statement No. 109.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
(AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. The composite rate used to determine the amount of
allowance, net of deferred income tax, was 6.2 percent in 1991. Such method of
computing AFUDC ceased upon the commercial operation of Plant Miller Unit 4 in
March 1991. For construction projects begun after 1986, deferral of taxes
related to capitalized interest is no longer permitted. For those projects,
the composite rate used to determine the amount of allowance was 7.8 percent in
1993, 7.9 percent in 1992, and 8.3 percent in 1991. AFUDC, net of income tax,
as a percent of net income after dividends on preferred stock was 1.5 percent
in 1993, 1.1 percent in 1992, and 2.0 percent in 1991.
UTILITY PLANT
Utility plant is stated at original cost. Original cost includes: materials;
labor; minor items of property; appropriate administrative and general costs;
payroll-related costs such as taxes, pensions, and other benefits; and the
estimated cost of funds used during construction. The cost of maintenance,
repairs and replacements of minor items of property is charged to maintenance
expense. The cost of replacements of property (exclusive
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Alabama Power Company 1993 Annual Report
of minor items of property) is charged to utility plant.
FINANCIAL INSTRUMENTS
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, all financial instruments of the company -- for which
the carrying amount does not approximate fair value -- are shown in the table
below as of December 31:
1993
Carrying Fair
Amount Value
(in millions)
Nuclear decommissioning trusts $ 49.6 $ 50.4
Long-term debt 2,315.4 2,439.4
1992
Carrying Fair
Amount Value
(in millions)
Nuclear decommissioning trusts $ 32.4 $ 32.4
Investment securities 64.8 69.5
Long-term debt 2,154.7 2,255.8
The fair values of nuclear decommissioning trusts and investment securities
were based on listed closing market prices. The fair values for long-term debt
were based on either closing market prices or closing prices of comparable
instruments.
MATERIALS AND SUPPLIES
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to
inventory when purchased and then expensed or capitalized to plant, as
appropriate, when installed.
VACATION PAY
The company's employees earn their vacation in one year and take it in the
subsequent year. However, for ratemaking purposes, vacation pay is recognized
as an allowable expense only when paid. Consistent with this ratemaking
treatment, the company accrues a current liability for earned vacation pay and
records a current asset representing future recoverability of this cost. The
amount was $23 million and $22 million at December 31, 1993 and 1992,
respectively. In 1994, an estimated 65 percent of the 1993 deferred vacation
cost will be expensed and the balance will be charged to construction and other
accounts.
2. RETIREMENT BENEFITS
PENSION PLAN
The company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. Benefits are based on the greater
of amounts resulting from two different formulas: years of service and final
average pay or years of service and a flat-dollar benefit. The company uses
the "entry age normal method with a frozen initial liability" actuarial method
for funding purposes, subject to limitations under federal income tax
regulations. Amounts funded to the pension fund are primarily invested in
equity and fixed-income securities. FASB Statement No. 87, Employers'
Accounting for Pensions, requires use of the "projected unit credit" actuarial
method for financial reporting purposes.
POSTRETIREMENT BENEFITS
The company also provides certain medical care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits when they retire. A qualified trust for medical benefits has been
established for funding amounts to the extent deductible under federal income
tax regulations. Amounts funded are primarily invested in debt and equity
securities. Accrued costs of life insurance benefits, other than current cash
payments for retirees, currently are not being funded. However, in December
1993, the APSC issued an accounting policy statement which requires the company
to externally fund all postretirement benefits. It is expected that an
external funding program will begin in 1994.
Effective January 1, 1993, the company adopted FASB Statement No. 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions, on a
prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service."
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Alabama Power Company 1993 Annual Report
Because the adoption of Statement No. 106 was reflected in rates, it did not
have a material impact on net income.
Prior to 1993, the company recognized these benefit costs on an accrual basis
using the "aggregate cost" actuarial method, which spreads the expected cost of
such benefits over the remaining periods of employees' service as a level
percentage of payroll costs. The total costs of such benefits recognized by
the company in 1992 and 1991 were $15.2 million and $15.4 million,
respectively.
Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension
and postretirement medical and life insurance benefits as computed under the
requirements of Statement Nos. 87 and 106, respectively. Retiree medical and
life insurance information is shown only for 1993 because Statement No. 106 was
adopted as of January 1, 1993, on a prospective basis. The funded status of
the plans at December 31 was as follows:
Pension
1993 1992
(in millions)
Actuarial present value of
benefit obligations:
Vested benefits $ 523 $ 449
Non-vested benefits 20 19
Accumulated benefit obligation 543 468
Additional amounts related to
projected salary increases 153 183
Projected benefit obligation 696 651
Less:
Fair value of plan assets 1,121 1,014
Unrecognized net gain (349) (295)
Unrecognized prior service cost 25 27
Unrecognized transition asset (56) (62)
Prepaid asset recognized in the
Balance Sheets $ 45 $ 33
Postretirement
Medical Life
1993 1993
(in millions)
Actuarial present value of
benefit obligations:
Retirees and dependents $ 67 $ 27
Employees eligible to retire 21 -
Other employees 95 29
Accumulated postretirement
benefit obligation 183 56
Less:
Fair value of plan assets 39 1
Unrecognized net loss (gain) 18 (4)
Unrecognized transition
obligation 102 26
Accrued liability recognized
in the Balance Sheets $ 24 $ 33
The weighted average rates assumed in the actuarial calculations were:
1993 1992 1991
Discount 7.5% 8.0% 8.0%
Annual salary increase 5.0 6.0 6.0
Long-term return on
plan assets 8.5 8.5 8.5
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend rate
of 11.3 percent for 1993, decreasing gradually to 6.0 percent through the year
2000 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate by 1.0 percent would increase the accumulated
medical benefit obligation as of December 31, 1993, by $32.8 million and the
aggregate of the service and interest cost components of the net retiree
medical cost by $3.4 million.
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Alabama Power Company 1993 Annual Report
Components of the plans' net cost are shown below:
Pension
1993 1992 1991
(in millions)
Benefits earned during
the year $ 20.6 $ 20.6 $ 21.7
Interest cost on projected
benefit obligation 50.4 48.2 47.5
Actual return on plan assets (146.3) (45.8) (260.5)
Net amortization and deferral 63.3 (29.3) 193.2
Net pension cost (income) $ (12.0) $ (6.3) $ 1.9
Of the above net pension amounts, $(8.9) million in 1993, $(5.1) million in
1992, and $0.7 million in 1991 were recorded in operating expenses, and the
remainder was recorded in construction and other accounts.
Postretirement
Medical Life
1993 1993
(in millions)
Benefits earned during the year $ 5 $ 2
Interest cost on accumulated
benefit obligation 12 4
Amortization of transition
obligation over 20 years 5 1
Actual return on plan assets (5) -
Net amortization and deferral 2 -
Net postretirement cost $ 19 $ 7
Of the above net postretirement medical and life insurance costs recorded in
1993, $22 million was charged to operating expenses and the remainder was
charged to construction and other accounts.
WORK FORCE REDUCTION PROGRAM
The company has incurred additional costs for work force reduction programs.
The costs related to these programs were $16.1 million, $13.4 million and $6.7
million for the years 1993, 1992 and 1991, respectively. A portion of the cost
of these programs was deferred and is being amortized in accordance with
regulatory treatment. The unamortized balance of these costs was $15.3 million
at December 31, 1993.
3. LITIGATION AND REGULATORY MATTERS
RETAIL RATE ADJUSTMENT PROCEDURES
In November 1982, the APSC adopted rates that provide for periodic adjustments
based upon the company's earned return on end-of-period retail common equity.
The rates also provide for adjustments to recognize the placing of new
generating facilities in retail service. Both increases and decreases have been
placed into effect since the adoption of these rates. The rate adjustment
procedures allow a return on common equity range of 13.0 percent to 14.5
percent and limit increases or decreases in rates to 4 percent in any calendar
year.
The APSC issued an order in December 1991 that reduced a scheduled 2.03
percent annual increase in rates to 1.03 percent, effective January 1992. The
1 percent reduction will remain in effect through 1994. The rate reduction was
designed to refund to retail ratepayers a portion of the benefits from a
settled contract dispute with Gulf States Utilities Company (Gulf States). The
present value of this portion of the settlement amounting to approximately $60
million is being amortized to revenues to offset the rate reduction in
accordance with the APSC's rate order. See Note 7 for additional information
concerning the Gulf States settlement.
Also in the December 1991 rate order, the APSC reaffirmed its satisfaction
with the ratemaking mechanism and stated that it did not foresee any further
review or changes in the procedures until after 1994. The ratemaking
procedures will remain in effect after 1994 unless the APSC votes to modify or
discontinue them.
In February 1993, the APSC ordered - at the company's request - a moratorium
on rate increases for the first two quarters of 1993, which facilitated the
transition of an accounting change. This accounting change permitted the
accrual of estimated operation and maintenance expenses related to nuclear
refueling outages during the period between outages rather than at the time the
expenses are incurred.
HEAT PUMP FINANCING SUIT
In September 1990, two customers of the company filed a civil complaint in the
Circuit Court of Shelby County, Alabama, against the company seeking to
represent all
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Alabama Power Company 1993 Annual Report
persons who, prior to June 23, 1989, entered into agreements with the company
for the financing of heat pumps and other merchandise purchased from vendors
other than the company. The plaintiffs contended that the company was required
to obtain a license under the Alabama Consumer Finance Act to engage in the
business of making consumer loans. The plaintiffs were seeking an order
declaring these agreements null and void and requiring the company to refund
all payments -- principal and interest -- made under these agreements. The
aggregate amount under these agreements, together with interest paid, currently
is estimated to be $40 million.
In June, 1993, the court ordered the company to refund or forfeit interest
of approximately $10 million because of the company's failure to obtain such
license. However, the court's order did not require any refund or forfeiture
with respect to any principal payments under the agreements at issue. The
company has appealed the court's order to the Supreme Court of Alabama.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material effect on the
company's financial statements.
FERC REVIEWS EQUITY RETURNS
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the Southern electric system's wholesale rate schedules and
contracts that have a return on common equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power and other similar contracts. Any
changes in the rate of return on common equity that may occur as a result of
this proceeding would be effective 60 days after a proper notice of the
proceeding is published. A notice was published on May 10, 1991.
In August 1992, a FERC administrative law judge issued an opinion that
changes in rate schedules and contracts were not necessary and that the FERC
staff failed to show how any changes were in the public interest. The FERC
staff has filed exceptions to the administrative law judge's opinion, and the
matter remains pending before the FERC.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material effect on the
company's financial statements.
4. CAPITAL BUDGET
The company's capital expenditures are currently estimated to total $588
million in 1994, $572 million in 1995 and $531 million in 1996. The estimates
include AFUDC of $10 million in 1994, $11 million in 1995 and $12 million in
1996. The estimates for property additions for the three-year period includes
$36.5 million committed to meeting the requirements of the Clean Air Act. The
capital budget is subject to periodic review and revision, and actual capital
cost incurred may vary from the above estimates because of numerous factors.
These factors include changes in business conditions; revised load growth
projections; changes in environmental regulations; changes in the existing
nuclear plant to meet new regulatory requirements; increasing costs of labor,
equipment, and materials; and cost of capital. At December 31, 1993,
significant purchase commitments were outstanding in connection with the
construction program. The company does not have any new baseload generating
plants under construction. However, the construction of combustion turbine
peaking units of approximately 720 megawatts is planned to be completed by
1996. In addition, significant construction will continue related to
transmission and distribution facilities and the upgrading and extension of the
useful lives of generating plants.
5. FINANCING, INVESTMENT, AND COMMITMENTS
GENERAL
To the extent possible, the company's construction program is expected to be
financed primarily from internal sources. Short-term debt will be utilized
when necessary; the amounts available are discussed below. The company may
issue additional long-term debt and preferred stock primarily for the purposes
of debt maturities and for redeeming higher-cost securities.
FINANCING
The ability of the company to finance its capital budget depends on the amount
of funds generated internally and the funds it can raise by external financing.
The
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Alabama Power Company 1993 Annual Report
company's primary sources of external financing are sales of first mortgage
bonds and preferred stock to the public, receipt of additional paid-in capital
from The Southern Company, and leasing of nuclear material. In order to issue
additional first mortgage bonds and preferred stock, the company must comply
with certain earnings coverage requirements contained in its mortgage indenture
and corporate charter. The most restrictive of these provisions requires, for
the issuance of additional first mortgage bonds, that before-income-tax
earnings, as defined, cover pro forma annual interest charges on outstanding
first mortgage bonds at least twice; and for the issuance of additional
preferred stock, that gross income available for interest cover pro forma
annual interest charges and preferred stock dividends at least one and one-half
times. These coverages, for first mortgage bonds and for preferred stock for
the year ended December 31, 1993, were 5.70 and 2.71, respectively.
BANK CREDIT ARRANGEMENTS
The company, along with The Southern Company and Georgia Power Company, has
entered into agreements with several banks outside the service area to provide
$400 million of revolving credit to the companies through June 30, 1996. To
provide liquidity support for commercial paper programs, the company and
Georgia Power Company have exclusive right to $135 million and $165 million,
respectively, of the available credit. The companies have the option of
converting the short-term borrowings into term loans, payable in 12 equal
quarterly installments, with the first installment due at the end of the first
calendar quarter after the applicable termination date or at an earlier date at
the companies' option. In addition, these agreements provide for payment of
commitment fees based on the unused portions of the commitments or the
maintenance of compensating balances with the banks.
Additionally, the company maintains committed lines of credit in the amount
of $350 million which expire at various times during 1994 and, in certain
cases, provide for average annual compensating balances. Because the
arrangements are based on an average balance, the company does not consider any
of its cash balances to be restricted as of any specific date. Moreover, the
company borrows from time to time pursuant to arrangements with banks for
uncommitted lines of credit.
In connection with all other lines of credit, the company has the option of
paying fees or maintaining compensating balances, which are substantially all
the cash of the company except for daily working funds and similar items.
These balances are not legally restricted from withdrawal.
At December 31, 1993, the company had regulatory approval to have
outstanding up to $450 million of short-term borrowings.
ASSETS SUBJECT TO LIEN
The company's mortgage, as amended and supplemented, securing the first
mortgage bonds issued by the company, constitutes a direct lien on
substantially all of the company's fixed property and franchises.
FUEL COMMITMENTS
To supply a portion of the fuel requirements of its generating plants, the
company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels and other financial commitments.
Total estimated long-term obligations through the year 2013 were approximately
$8 billion at December 31, 1993.
In addition, a contract with a certain coal contractor requires
reimbursement or purchase, at net book value, of the investment in the mine or
equipment upon termination of the contract. At December 31, 1993, such net
book value was approximately $13 million. Additional commitments for coal and
for nuclear fuel will be required in the future to supply the company's fuel
needs.
6. FACILITY SALES AND JOINT OWNERSHIP
AGREEMENTS
The company and Georgia Power Company own equally all of the outstanding
capital stock of Southern Electric Generating Company (SEGCO), which owns
electric generating units with a total rated capacity of 1,019,680 kilowatts,
together with associated transmission facilities. The capacity of these units
is sold equally to the company and Georgia Power Company under a contract
expiring in 1994 which, in substance, requires payments sufficient to provide
for the operating expenses, taxes, interest expense
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Alabama Power Company 1993 Annual Report
and a return on equity, whether or not SEGCO has any capacity and energy
available. The company's share of expenses totaled $86 million in 1993, $73
million in 1992 and $82 million in 1991, and is included in "Purchased power
from affiliates" in the Statements of Income. An amended contract has been
filed with the FERC with substantially the same provisions, but the term
thereof would be extended automatically for two year periods, subject to any
party's right to cancel upon two years' notice.
In addition, the company has guaranteed unconditionally the obligation of
SEGCO under an installment sale agreement for the purchase of certain pollution
control facilities at SEGCO's generating units, pursuant to which $24.5 million
principal amount of pollution control revenue bonds are outstanding. Georgia
Power Company has agreed to reimburse the company for the pro rata portion of
such obligation corresponding to its then proportionate ownership of stock of
SEGCO if the company is called upon to make such payment under its guaranty.
At December 31, 1993, the capitalization of SEGCO consisted of $58 million
of equity and $84 million of long-term debt on which the annual interest
requirement is $3.8 million. SEGCO paid dividends totaling $11.3 million in
1993, $12.0 million in 1992, and $4.5 million in 1991, of which one-half of
each was paid to the company. SEGCO's net income was $8.3 million, $9.3
million and $9.2 million for 1993, 1992 and 1991, respectively.
In June 1992 the company completed the sale of a portion of Plant Miller
Units 1 and 2 to Alabama Electric Cooperative, Inc. (AEC). The company's
percentage ownership and investment in jointly-owned generating plants at
December 31, 1993, follows:
Total
Megawatt Company
Facility (Type) Capacity Ownership
Greene County 500 60.00%(1)
(coal)
Plant Miller
Units 1 and 2 1,320 91.84%(2)
(coal)
(1) Jointly owned with an affiliate, Mississippi Power Company.
(2) Jointly owned with AEC.
Company Accumulated
Facility (Type) Investment Depreciation
(in millions)
Greene County $ 81 $ 37
(coal)
Plant Miller
Units 1 and 2 $ 703 $ 247
(coal)
7. LONG-TERM POWER SALES AGREEMENTS
GENERAL
The operating subsidiaries of The Southern Company, including the company, have
entered into long-term and short-term contractual agreements for the sale of
capacity and energy to certain non-affiliated utilities located outside the
system's service area. Certain of these agreements are non-firm and are based
on capacity of the system in general. Other agreements are firm and pertain to
capacity related to specific generating units. Because the energy is generally
sold at cost under these agreements, revenues from capacity sales primarily
affect profitability. The company's portion of off-system capacity revenues
has been as follows:
Other
Long-Term
and
Unit Short-Term
Year Power Non-Firm Total
(in millions)
1993 $144 $15 $159
1992 177 9 186
1991 172 8 180
Long-term non-firm power of 400 megawatts was sold by the Southern electric
system in 1993 to Florida Power Corporation (FPC). In January 1994, this
amount decreased to 200 megawatts, and the contract will expire at year-end.
Unit power from Plant Miller is being sold to FPC, Florida Power & Light
Company (FP&L), Jacksonville Electric Authority (JEA) and the City of
Tallahassee, Florida (Tallahassee). Under these agreements, an average of
1,100 megawatts of capacity is scheduled to be
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NOTES(continued)
Alabama Power Company 1993 Annual Report
sold during 1994. Thereafter, these sales will increase to some 1,200
megawatts and remain at that approximate level -- unless reduced by FP&L, FPC,
and JEA for the periods after 1999 -- until the expiration of the contracts in
2010.
GULF STATES SETTLEMENT COMPLETED
On November 7, 1991, subsidiaries of The Southern Company entered into a
settlement agreement with Gulf States that resolved litigation between the
companies that had been pending since 1986 and arose out of a dispute over
certain unit power and other long-term power sales contracts. In 1993, all
remaining terms and obligations of the settlement agreement were satisfied.
With respect to the company's portion of proceeds received in 1991, see Note
3 concerning the regulatory treatment of amounts being refunded to retail
customers over a three-year period.
ALABAMA MUNICIPAL ELECTRIC AUTHORITY (AMEA)
CAPACITY CONTRACTS
In August 1986, the company entered into a firm power purchase contract with
AMEA entitling AMEA to scheduled amounts of capacity (to a maximum 100
megawatts) for a period of 15 years commencing September 1, 1986 (1986
Contract). In October 1991, the company entered into a second firm power
purchase contract with AMEA entitling AMEA to scheduled amounts of additional
capacity (to a maximum 80 megawatts) for a period of 15 years commencing
October 1, 1991 (1991 Contract). In both contracts the power will be sold to
AMEA for its member municipalities that previously were served directly by the
company as wholesale customers. Under the terms of the contracts, the company
received payments from AMEA representing the net present value of the revenues
associated with the respective capacity entitlements, discounted at effective
annual rates of 9.96 percent and 11.19 percent for the 1986 and 1991 Contracts,
respectively. These payments are being recognized as operating revenues and
the discounts are being amortized to other interest expense as scheduled
capacity is made available over the terms of the contracts.
In order to secure AMEA's advance payments and the company's performance
obligation under the contracts, the company issued and delivered to an escrow
agent first mortgage bonds representing the maximum amount of liquidated
damages payable by the company in the event of a default under the contracts.
No principal or interest is payable on such bonds unless and until a default by
the company occurs. As the liquidated damages decline under the contracts, a
portion of the bonds equal to the decreases are returned to the company. At
December 31, 1993, $153 million of such bonds were held by the escrow agent
under the contracts.
8. INCOME TAXES
Effective January 1, 1993, the company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption of Statement No. 109 resulted in
cumulative adjustments that had no material effect on net income. The adoption
also resulted in the recording of additional deferred income taxes and related
assets and liabilities. The related assets of $469 million are revenues to be
received from customers. These assets are attributable to tax benefits flowed
through to customers in prior years and to taxes applicable to capitalized
AFUDC. The related liabilities of $441 million are revenues to be refunded to
customers. These liabilities are attributable to deferred taxes previously
recognized at rates higher than current enacted tax law and to unamortized
investment tax credits. Additionally, deferred income taxes related to
accelerated tax depreciation previously shown as a reduction to utility plant
were reclassified.
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NOTES (continued)
Alabama Power Company 1993 Annual Report
Details of the federal and state income tax provisions are as follows:
1993 1992 1991
(in thousands)
Federal --
Currently payable $149,680 $152,481 $181,070
Deferred --
current year 9,636 27,760 28,382
reversal of prior years 19,653 (7,827) (34,911)
Deferred investment tax
credits (2,106) - (1,089)
176,863 172,414 173,452
State --
Currently payable 14,297 16,983 18,887
Deferred --
current year 1,898 6,387 2,256
reversal of prior years 3,913 (2,806) (1,506)
20,108 20,564 19,637
Total 196,971 192,978 193,089
Less income taxes charged
(credited) to other income (10,239) (8,947) (7,523)
Federal and state income
taxes charged to operations $207,210 $201,925 $200,612
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities are as follows:
1993
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 697
Property basis differences 536
Premium on reacquired debt 38
Fuel clause underrecovered 11
Other 17
Total 1,299
Deferred tax assets:
Capacity prepayments 44
Other deferred costs 8
Pension and other benefits 15
Accrued nuclear outage costs 7
Unbilled revenue 7
Other 39
Total 120
Net deferred tax liabilities 1,179
Portion included in current liabilities, net (14)
Accumulated deferred income taxes
in the Balance Sheets $ 1,165
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $13 million in 1993, $18 million in 1992, and $16 million in 1991.
At December 31, 1993, all investment tax credits available to reduce federal
income taxes payable had been utilized.
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
1993 1992 1991
Effective tax rate 34.4% 34.1% 34.0%
State income tax, net of
federal income tax benefit (2.3) (2.4) (2.3)
Non-deductible book
depreciation (1.6) (1.6) (1.8)
Differences in prior years'
deferred and current tax rates 1.6 1.9 1.8
Other 2.9 2.0 2.3
Statutory federal tax rate 35.0% 34.0% 34.0%
The Southern Company and its subsidiaries file a consolidated federal income
tax return. Under a joint consolidated income tax agreement, each company's
current and deferred tax expense is computed on a stand-alone basis, and
consolidated tax savings are allocated to each company based on its ratio of
taxable income to total consolidated taxable income.
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NOTES (continued)
Alabama Power Company 1993 Annual Report
9. OTHER LONG-TERM DEBT
Details of other long-term debt are as follows:
December 31,
1993 1992
(in thousands)
Obligations incurred in
connection with the
sale of tax-exempt
pollution control
revenue bonds by
public authorities-
2003-2013 6% to
9-3/8% $ 27,050 $162,365
2014-2023 3.05%
to 10-7/8% 449,090 306,200
Less funds on deposit
with trustees - 1,546
476,140 467,019
Capitalized lease obligations
and other long-term debt:
Nuclear fuel 95,943 104,058
Office buildings 7,710 8,069
Street light and other 2,761 4,423
106,414 116,550
Total $582,554 $583,569
Pollution control obligations represent installment purchases of pollution
control facilities financed by funds derived from sales by public authorities
of revenue bonds. The company is required to make payments sufficient for the
authorities to meet principal and interest requirements of such bonds. With
respect to $154.5 million of such pollution control obligations, the company
has authenticated and delivered to the trustees a like principal amount of
first mortgage bonds as security for its obligations under the installment
purchase agreements. No principal or interest on these first mortgage bonds is
payable unless and until a default occurs on the installment purchase
agreements.
The company has capitalized leased nuclear material and recorded the related
lease obligations. The arrangement provides for the payment of interest at
varying rates and times dependent on options selected by the company from types
of loans available under the arrangement. At the end of 1993 the effective
rate of this lease arrangement, including applicable fees, was 3.58 percent.
Principal payments are required under the arrangement based on the cost of fuel
burned.
The company has also capitalized certain office building leases and a street
light lease. Monthly principal payments plus interest are required, and at
December 31, 1993, the interest rate was 9.5 percent for office buildings and
13.0 percent for street lights.
The net book value of capitalized leases included in utility plant in service
was $94.7 million and $103.0 million at December 31, 1993 and 1992,
respectively. The estimated aggregate annual maturities of other long-term
debt through 1998 are as follows: $38.9 million in 1994, $33.3 million in 1995,
$18.7 million in 1996, $6.4 million in 1997 and $3.0 million in 1998.
10. LONG-TERM DEBT DUE WITHIN ONE YEAR
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year is as follows:
1993 1992
(in thousands)
Cash sinking fund requirements $20,135 $18,525
Other long-term debt maturities
(Note 9) 38,863 48,854
Total $58,998 $67,379
The annual first mortgage bond improvement fund requirement is one percent
of the aggregate principal amount of bonds of each series authenticated, so
long as a portion of that series is outstanding, and may be satisfied by the
deposit of cash and/or reacquired bonds, the certification of unfunded property
additions or a combination thereof. The 1994 requirement of $20.1 million was
satisfied by the deposit of cash in 1994, which was used for the partial
redemption of various series of outstanding bonds. In addition, maturing in
1994 are other long-term debt of $38.9 million consisting primarily of
capitalized nuclear fuel obligations.
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NOTES (continued)
Alabama Power Company 1993 Annual Report
11. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988 (Act), the company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at
Plant Farley. The Act limits to $9.4 billion, public liability claims that
could arise from a single nuclear incident. Plant Farley is insured against
this liability to a maximum of $200 million by private insurance, with the
remaining coverage provided by a mandatory program of deferred premiums which
could be assessed, after a nuclear incident, against all owners of nuclear
reactors. A company could be assessed up to $79 million per incident for each
licensed reactor it operates but not more than an aggregate of $10 million per
incident to be paid in a calendar year for each reactor. Such maximum
assessment, excluding any applicable state premium taxes, for the company is
$159 million per incident but not more than an aggregate of $20 million to be
paid for each incident in any one year.
The company is a member of Nuclear Mutual Limited (NML), a mutual insurer
established to provide property damage insurance in an amount up to $500
million for members' nuclear generating facilities. The members are subject to
a retrospective premium adjustment in the event that losses exceed accumulated
reserve funds. The company's maximum annual assessment per incident is limited
to $14 million under the current policy.
Additionally, the company has policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million NML
coverage. This excess insurance is provided by Nuclear Electric Insurance
Limited (NEIL), a mutual insurance company, and American Nuclear
Insurers/Mutual Atomic Energy Liability Underwriters.
NEIL also covers the additional cost that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can be insured against increased cost of replacement power in
an amount up to $3.5 million per week (starting 21 weeks after the outage) for
one year and up to $2.3 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if losses
each year exceed the accumulated funds available to the insurer under that
policy. The maximum annual assessments per incident under current policies for
the company would be $16 million for excess property damage and $9 million for
replacement power.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies issued or
renewed on or after April 2, 1991, shall be dedicated first for the sole
purpose of placing the reactor in a safe and stable condition after an
accident. Any remaining proceeds are to be applied next toward the costs of
decontamination and debris removal operations ordered by the NRC, and then, any
further remaining proceeds are to be paid either to the company or to its bond
trustees as may be appropriate under applicable trust indentures.
The company participates in an insurance program for nuclear workers that
provides coverage for worker tort claims filed for bodily injury caused at
commercial nuclear power plants. In the event that claims for this insurance
exceed the accumulated reserve funds, the company could be subject to a maximum
total assessment of $6.4 million.
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NOTES (continued)
Alabama Power Company 1993 Annual Report
12. COMMON STOCK DIVIDEND
RESTRICTIONS
The company's first mortgage bond indenture contains various common stock
dividend restrictions that remain in effect as long as the bonds are
outstanding. At December 31, 1993, $653 million of retained earnings was
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture. Supplemental indentures in connection with future
first mortgage bond issues may contain more stringent common stock dividend
restrictions than those currently in effect.
13. QUARTERLY FINANCIAL INFORMATION
(UNAUDITED)
Summarized quarterly financial data for 1993 and 1992 are as follows:
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
(in thousands)
MARCH 1993 $635,559 $124,356 $ 57,856
JUNE 1993 733,589 159,023 91,448
SEPTEMBER 1993 919,934 205,151 150,818
DECEMBER 1993 718,527 106,582 46,372
March 1992 $649,554 $140,574 $ 75,044
June 1992 720,661 146,488 83,545
September 1992 821,469 200,262 136,744
December 1992 655,156 105,798 43,222
The company's business is influenced by seasonal weather conditions and the
timing of rate adjustments.
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108
SELECTED FINANCIAL AND OPERATING DATA
Alabama Power Company
1993 1992 1991
OPERATING REVENUES (IN THOUSANDS) $3,007,609 $2,846,840 $2,846,794
NET INCOME AFTER DIVIDENDS
ON PREFERRED STOCK (IN THOUSANDS) $346,494 $338,555 $339,666
CASH DIVIDENDS ON COMMON STOCK (IN THOUSANDS) $252,900 $273,300 $232,900
RETURN ON AVERAGE COMMON EQUITY (PERCENT) 13.94 14.02 14.55
TOTAL ASSETS (IN THOUSANDS) $8,248,683 $6,593,618 $6,549,462
GROSS PROPERTY ADDITIONS (IN THOUSANDS) $435,843 $367,463 $397,011
CAPITALIZATION (IN THOUSANDS):
Common stock equity $2,526,348 $2,443,493 $2,387,198
Preferred stock 440,400 489,400 484,400
Preferred stock subject to mandatory redemption - - -
Long-term debt 2,362,852 2,202,473 2,382,635
Total (excluding amounts due within one year) $5,329,600 $5,135,366 $5,254,233
CAPITALIZATION RATIOS (PERCENT):
Common stock equity 47.4 47.6 45.4
Preferred stock 8.3 9.5 9.2
Long-term debt 44.3 42.9 45.4
Total (excluding amounts due within one year) 100.0 100.0 100.0
FIRST MORTGAGE BONDS (IN THOUSANDS):
Issued 860,000 745,000 250,000
Retired 699,788 931,797 227,695
PREFERRED STOCK (IN THOUSANDS):
Issued 158,000 150,000 -
Retired 207,000 145,000 17,500
SECURITY RATINGS:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A A A
Duff & Phelps A+ A A
Preferred Stock -
Moody's a2 a2 a2
Standard and Poor's A- A- A-
Duff & Phelps A- A- A-
CUSTOMERS (YEAR-END):
Residential 1,027,130 1,012,294 997,585
Commercial 157,337 152,530 148,228
Industrial 5,391 5,434 5,496
Other 713 704 697
Total 1,190,571 1,170,962 1,152,006
EMPLOYEES (YEAR-END) 8,009 8,116 8,513
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109
SELECTED FINANCIAL AND OPERATING DATA
Alabama Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$2,722,424 $2,629,354 $2,476,626 $2,574,634 $2,549,574 $2,518,699 $2,236,560 $2,030,649
$ 312,803 $ 311,146 $ 283,475 $ 257,239 $ 273,456 $ 264,562 $ 233,252 $ 229,011
$ 220,800 $ 217,300 $ 212,700 $ 201,100 $ 191,300 $ 185,700 $ 161,900 $ 145,200
14.00 14.53 14.03 13.56 15.12 15.41 14.74 16.12
$6,362,293 $6,279,431 $6,180,945 $5,912,000 $5,570,653 $5,722,263 $5,496,197 $5,120,607
$ 444,680 $ 459,199 $ 643,892 $ 600,589 $ 553,767 $ 568,073 $ 575,173 $ 522,140
$2,280,590 $2,188,811 $2,094,815 $1,946,747 $1,847,608 $1,770,156 $1,664,295 $1,499,909
484,400 484,400 484,400 384,400 384,400 384,400 424,400 424,400
12,500 17,500 22,500 27,500 30,000 35,000 37,224 38,034
2,397,931 2,435,129 2,496,492 2,386,258 2,210,108 2,349,373 2,402,713 2,404,565
$5,175,421 $5,125,840 $5,098,207 $4,744,905 $4,472,116 $4,538,929 $4,528,632 $4,366,908
44.1 42.7 41.1 41.0 41.3 39.0 36.7 34.3
9.6 9.8 9.9 8.7 9.3 9.3 10.2 10.6
46.3 47.5 49.0 50.3 49.4 51.7 53.1 55.1
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
- - 150,000 200,000 125,000 - - -
33,122 75,650 42,445 108,082 405,765 39,460 21,250 16,189
- - 100,000 - - - - 50,000
5,000 5,000 2,500 5,000 42,224 - 810 4,200
A1 A1 A1 A1 A1 A1 A2 A3
A A A A A A A- BBB+
A A 6 6 6 6 7 8
a2 a2 a2 a2 a2 a2 a3 baa2
A- A- A- A- A- A- BBB+ BBB
A- A- 7 7 7 7 8 9
985,566 974,622 964,581 950,101 934,798 918,777 905,239 889,372
144,340 141,265 137,955 134,533 130,540 126,644 123,561 120,749
5,322 5,200 5,120 4,955 4,725 4,619 4,467 4,325
690 684 678 713 697 755 759 757
1,135,918 1,121,771 1,108,334 1,090,302 1,070,760 1,050,795 1,034,026 1,015,203
9,473 9,698 10,302 10,457 10,367 10,212 10,144 9,917
II-79
110
SELECTED FINANCIAL AND OPERATING DATA (continued)
Alabama Power Company
1993 1992 1991
OPERATING REVENUES (IN THOUSANDS):
Residential $ 947,277 $ 845,660 $ 864,347
Commercial 634,895 589,816 582,730
Industrial 832,938 800,311 790,224
Other 13,344 12,734 12,662
Total retail 2,428,454 2,248,521 2,249,963
Sales for resale - non-affiliates 364,105 407,791 407,912
Sales for resale - affiliates 181,975 158,088 159,375
Total revenues from sales of electricity 2,974,534 2,814,400 2,817,250
Other revenues 33,075 32,440 29,544
Total $ 3,007,609 $ 2,846,840 $ 2,846,794
KILOWATT-HOUR SALES (IN THOUSANDS):
Residential 13,185,062 12,069,268 12,324,898
Commercial 9,185,462 8,629,869 8,526,131
Industrial 18,595,237 18,260,274 17,511,579
Other 181,673 176,798 174,760
Total retail 41,147,434 39,136,209 38,537,368
Sales for resale - non-affiliates 7,143,672 8,382,571 8,810,442
Sales for resale - affiliates 8,081,324 7,210,697 7,784,285
Total 56,372,430 54,729,477 55,132,095
AVERAGE REVENUE PER KILOWATT-HOUR (CENTS):
Residential 7.18 7.01 7.01
Commercial 6.91 6.83 6.83
Industrial 4.48 4.38 4.51
Total retail 5.90 5.75 5.84
Sales for resale 3.59 3.63 3.42
Total sales 5.28 5.14 5.11
RESIDENTIAL AVERAGE ANNUAL KILOWATT-HOUR
USE PER CUSTOMER 12,936 12,017 12,435
RESIDENTIAL AVERAGE ANNUAL REVENUE
PER CUSTOMER $ 929.36 $ 842.00 $ 872.04
PLANT NAMEPLATE CAPACITY RATINGS (NOTE 1)
(year-end) (megawatts) 10,431 10,431 10,539
TERRITORIAL PEAK-HOUR DEMAND (MEGAWATTS) (NOTE 2):
Winter 7,152 7,077 6,586
Summer 9,457 8,801 8,627
ANNUAL LOAD FACTOR (PERCENT) (NOTE 2) 58.6 59.6 59.9
PLANT AVAILABILITY (PERCENT):
Fossil-steam 89.7 88.9 93.1
Nuclear 86.6 80.2 87.0
SOURCE OF ENERGY SUPPLY (PERCENT):
Coal 63.9 64.3 61.5
Nuclear 20.1 19.0 20.8
Hydro 6.9 8.5 8.2
Oil and gas * * *
Purchased power -
From non-affiliates 1.1 1.2 1.6
From affiliates 8.0 7.0 7.9
Total 100.0 100.0 100.0
TOTAL FUEL ECONOMY DATA (NOTE 1):
BTU per net kilowatt-hour generated 10,003 10,000 9,985
Cost of fuel per million BTU (cents) 173.66 164.57 170.49
Average cost of fuel per net kilowatt-hour generated (cents) 1.74 1.65 1.70
Notes:
(1) Generating capacity and fuel data includes Alabama Power Company's 50%
portion of SEGCO.
(2) Includes Southeastern Power Administration allotment.
* Less than one-tenth of one percent.
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111
SELECTED FINANCIAL AND OPERATING DATA (continued)
Alabama Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 825,645 $ 781,982 $ 761,805 $ 759,957 $ 738,864 $ 684,970 $ 664,286 $ 629,478
551,634 533,487 510,910 501,088 481,676 453,651 430,400 398,827
777,580 762,274 738,755 721,298 705,395 717,078 692,177 631,440
12,103 11,743 11,255 10,968 10,811 10,129 9,615 8,914
2,166,962 2,089,486 2,022,725 1,993,311 1,936,746 1,865,828 1,796,478 1,668,659
434,996 409,202 355,362 443,880 472,938 539,343 317,890 225,535
93,473 104,488 76,691 118,746 120,911 95,733 108,812 119,610
2,695,431 2,603,176 2,454,778 2,555,937 2,530,595 2,500,904 2,223,180 2,013,804
26,993 26,178 21,848 18,697 18,979 17,795 13,380 16,845
$ 2,722,424 $ 2,629,354 $ 2,476,626 $ 2,574,634 $ 2,549,574 $ 2,518,699 $ 2,236,560 $ 2,030,649
11,996,794 11,346,736 11,332,285 11,149,225 10,606,698 9,814,814 9,634,285 9,176,413
8,201,534 7,915,685 7,711,092 7,476,924 7,015,589 6,593,645 6,270,899 5,816,678
17,713,153 17,360,791 16,881,342 15,969,075 15,025,806 15,215,276 15,134,188 13,688,096
170,420 166,485 165,122 159,422 153,282 146,119 143,785 138,901
38,081,901 36,789,697 36,089,841 34,754,646 32,801,375 31,769,854 31,183,157 28,820,088
10,277,060 10,292,329 7,905,750 10,523,554 9,064,049 12,158,464 8,587,936 6,473,574
4,519,275 5,048,743 3,551,142 4,963,997 4,456,360 3,588,338 4,270,493 3,904,285
52,878,236 52,130,769 47,546,733 50,242,197 46,321,784 47,516,656 44,041,586 39,197,947
6.88 6.89 6.72 6.82 6.97 6.98 6.90 6.86
6.73 6.74 6.63 6.70 6.87 6.88 6.86 6.86
4.39 4.39 4.38 4.52 4.69 4.71 4.57 4.61
5.69 5.68 5.60 5.74 5.90 5.87 5.76 5.79
3.57 3.35 3.77 3.63 4.39 4.03 3.32 3.33
5.10 4.99 5.16 5.09 5.46 5.26 5.05 5.14
12,256 11,717 11,839 11,848 11,457 10,781 10,755 10,400
$ 843.50 $ 807.50 $ 795.84 $ 807.61 $ 798.09 $ 752.43 $ 741.58 $ 713.40
9,879 9,879 9,279 9,337 9,337 9,337 8,580 8,629
6,293 7,264 6,377 6,138 6,257 6,191 5,696 5,456
8,878 8,256 7,991 7,886 7,892 7,570 6,946 7,147
57.4 59.5 59.6 58.3 56.2 57.2 59.8 55.0
92.2 90.7 91.3 90.2 88.5 90.5 91.2 90.4
86.5 83.1 91.9 83.3 83.8 81.0 86.5 82.9
57.0 54.1 53.9 52.5 58.8 55.7 51.5 49.1
21.6 21.0 26.1 21.7 23.8 22.4 26.1 26.9
8.7 11.0 4.8 6.3 4.2 6.2 11.0 12.9
0.1 0.1 0.1 0.2 0.1 0.1 * *
0.9 1.8 0.5 0.2 2.0 1.7 0.2 0.5
11.7 12.0 14.6 19.1 11.1 13.9 11.2 10.6
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
10,072 10,061 10,137 10,214 10,209 10,229 10,367 10,610
171.55 172.20 168.21 176.72 179.65 185.74 179.40 164.30
1.73 1.73 1.71 1.80 1.83 1.90 1.86 1.74
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STATEMENTS OF INCOME
Alabama Power Company
FOR THE YEARS ENDED DECEMBER 31 1993* 1992* 1991*
(Thousands of Dollars)
OPERATING REVENUES:
Revenues $ 2,825,634 $ 2,688,752 $ 2,687,419
Revenues from affiliates 181,975 158,088 159,375
Total operating revenues 3,007,609 2,846,840 2,846,794
OPERATING EXPENSES:
Operation --
Fuel 877,099 794,438 812,667
Purchased power from non-affiliates 15,230 14,242 21,080
Purchased power from affiliates 120,330 107,230 119,602
Proceeds from settlement of disputed contracts (2,568) (641) (14,819)
Other 473,383 446,477 435,908
Maintenance 252,506 237,071 229,114
Depreciation and amortization 290,310 280,881 271,433
Taxes other than income taxes 178,997 172,095 169,639
Federal and state income taxes 207,210 201,925 200,612
Total operating expenses 2,412,497 2,253,718 2,245,236
OPERATING INCOME 595,112 593,122 601,558
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction 3,260 2,071 2,368
Income from subsidiary 4,127 4,635 4,576
Charitable foundation (3,000) (6,887) (6,500)
Interest income 20,775 14,804 14,356
Other, net (24,420) (11,019) (9,926)
Income taxes applicable to other income 10,239 8,947 7,523
INCOME BEFORE INTEREST CHARGES 606,093 605,673 613,955
INTEREST CHARGES:
Interest on long-term debt 184,861 206,871 214,107
Allowance for debt funds used during construction (2,992) (2,416) (6,903)
Interest on interim obligations 3,760 3,704 13,385
Amortization of debt discount, premium, and expense, net 8,937 4,392 2,634
Other interest charges 35,474 19,381 14,927
Net interest charges 230,040 231,932 238,150
NET INCOME 376,053 373,741 375,805
DIVIDENDS ON PREFERRED STOCK 29,559 35,186 36,139
NET INCOME AFTER DIVIDENDS ON PREFERRED $ 346,494 $ 338,555 $ 339,666
* Includes the effect of recognizing, beginning in 1987, retail service
rendered but not yet billed to customers.
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STATEMENTS OF INCOME
Alabama Power Company
1990* 1989* 1988* 1987* 1986 1985 1984 1983
$ 2,628,951 $ 2,524,866 $ 2,399,935 $ 2,455,888 $ 2,428,663 $ 2,422,966 $ 2,127,748 $ 1,911,039
93,473 104,488 76,691 118,746 120,911 95,733 108,812 119,610
2,722,424 2,629,354 2,476,626 2,574,634 2,549,574 2,518,699 2,236,560 2,030,649
756,501 712,453 676,423 696,763 738,367 743,463 657,183 542,760
11,185 28,272 8,407 6,703 23,889 25,990 4,592 6,297
165,982 163,267 185,390 257,052 156,091 187,041 156,180 121,205
- - - - - - - -
411,559 380,536 400,879 410,575 350,671 308,437 287,647 262,354
215,304 202,633 197,225 199,617 203,972 210,143 182,957 164,391
262,817 247,973 225,123 212,072 201,803 183,779 174,514 169,231
163,567 154,398 148,681 141,422 135,248 128,648 122,928 107,445
185,954 188,507 143,614 190,575 255,400 248,774 224,726 220,245
2,172,869 2,078,039 1,985,742 2,114,779 2,065,441 2,036,275 1,810,727 1,593,928
549,555 551,315 490,884 459,855 484,133 482,424 425,833 436,721
25,487 29,515 39,047 27,663 27,455 32,985 45,704 35,103
4,182 3,750 3,302 3,440 2,967 3,417 3,181 3,088
(17,500) (25,000) - - - - - -
12,006 10,871 9,914 7,044 11,422 20,874 12,432 8,729
(8,235) (4,313) (13,694) (816) (3,738) (4,447) (666) (1,368)
11,081 13,629 8,034 849 185 (4,941) (3,088) (1,213)
576,576 579,767 537,487 498,035 522,424 530,312 483,396 481,060
221,527 230,046 225,522 205,824 226,110 248,073 245,684 246,246
(23,339) (27,627) (31,830) (24,235) (24,334) (29,048) (42,868) (38,558)
10,252 9,098 5,714 7,221 1,159 - - 1,261
3,706 4,469 4,411 4,405 3,313 1,145 996 985
13,115 13,112 13,715 14,662 8,695 4,234 4,291 4,179
225,261 229,098 217,532 207,877 214,943 224,404 208,103 214,113
351,315 350,669 319,955 290,158 307,481 305,908 275,293 266,947
38,512 39,523 36,480 32,919 34,025 41,346 42,041 37,936
$ 312,803 $ 311,146 $ 283,475 $ 257,239 $ 273,456 $ 264,562 $ 233,252 $ 229,011
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STATEMENTS OF CASH FLOWS
Alabama Power Company
For the Years Ended December 31, 1993 1992 1991
(Thousands of Dollars)
Operating Activities:
Net income $ 376,053 $ 373,741 $ 375,805
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 356,499 338,421 337,978
Deferred income taxes, net 35,100 23,514 (5,779)
Deferred investment tax credits, net (2,106) - (1,089)
Allowance for equity funds used during construction (3,260) (2,071) (2,368)
Non-cash proceeds from settlement of disputed contracts - (641) (13,750)
Other, net 36,493 (2,657) 26,614
Changes in certain current assets and liabilities --
Receivables, net 19,215 (11,010) 9,178
Inventories 51,630 12,704 (17,374)
Payables 31,544 2,158 28,889
Taxes accrued (9,959) (21,120) 24,828
Energy cost recovery, retail (56,128) 45,509 (12,304)
Other (21,110) 10,629 (37,906)
Net cash provided from operating activities 813,971 769,177 712,722
Investing Activities:
Gross property additions (435,843) (367,463) (397,011)
Sales of property - 43,556 -
Other (741) (13,379) (36,083)
Net cash used for investing activities (436,584) (337,286) (433,094)
Financing Activities and Capital Contributions:
Proceeds:
Preferred stock 158,000 150,000 -
First mortgage bonds 860,000 745,000 250,000
Pollution control bonds - - -
Other long-term debt 180,314 48,382 12,906
Capital contributions from parent company - - -
Prepaid capacity revenues - - 52,900
Redemptions:
Preferred stock (207,000) (145,000) (17,500)
First mortgage bonds (699,788) (931,797) (227,695)
Pollution control bonds (135,315) (335) (250)
Other long-term debt (46,014) (53,888) (48,428)
Interim obligations, net (156,917) 120,917 (13,500)
Payment of preferred stock dividends (32,099) (35,704) (36,829)
Payment of common stock dividends (252,900) (273,300) (232,900)
Miscellaneous (56,064) (53,697) (17,732)
Net cash provided from (used for) financing activities (387,783) (429,422) (279,028)
Net Change in Cash (10,396) 2,469 600
Cash at Beginning of Year 13,629 11,160 10,560
Cash at End of Year $ 3,233 $ 13,629 $ 11,160
( ) Denotes use of cash.
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STATEMENTS OF CASH FLOWS
Alabama Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 351,315 $ 350,669 $ 319,955 $ 290,158 $ 307,481 $ 305,908 $ 275,293 $ 266,947
331,858 322,042 296,234 270,492 292,569 266,657 266,479 224,656
64,480 31,715 37,952 107,824 135,364 104,259 85,426 115,343
132 6,917 15,019 23,477 19,736 57,096 165,020 105,200
(25,487) (29,515) (39,047) (27,663) (27,455) (32,985) (45,704) (35,103)
- - - - - - - -
19,899 (5,297) 16,106 67,445 4,251 (18,971) (4,573) (60,712)
12,005 (10,436) 8,822 (133,468) 15,238 (13,531) (16,403) (16,534)
(40,901) 20,408 (23,182) (26,255) (2,040) 29,823 25,159 (58,678)
6,597 16,259 (12,957) 39,645 (56,720) 26,360 39,964 84,139
(6,167) 1,547 (7,754) 516 (1,487) (6,325) (8,198) 8,847
(42,535) 39,164 - - - - - -
14,144 28,701 (18,658) 4,464 (35,293) 4,358 29,836 (8,675)
685,340 772,174 592,490 616,635 651,644 722,649 812,299 625,430
(444,680) (459,199) (643,892) (600,589) (553,767) (568,073) (575,173) (522,140)
- - - - - - - -
6,935 3,768 23,161 17,010 10,115 22,028 26,175 17,334
(437,745) (455,431) (620,731) (583,579) (543,652) (546,045) (548,998) (504,806)
- - 100,000 - - - - 50,000
- - 150,000 200,000 125,000 - - -
- 53,700 - 432 26,232 115,577 161,134 10,640
54,831 55,176 62,515 69,786 95,017 12,998 25,654 139,031
- - 79,500 43,000 - 27,000 93,000 76,000
- - - - 100,000 - - -
(5,000) (5,000) (2,500) (5,000) (42,224) - (810) (4,200)
(33,122) (75,650) (42,445) (108,082) (405,765) (39,460) (21,250) (16,189)
(250) (53,950) - - (21,000) - (3,500) (500)
(56,895) (57,316) (56,748) (32,500) (43,561) (35,023) (128,060) (73,154)
59,500 30,000 (15,000) 15,000 - - - -
(38,245) (40,105) (35,362) (32,837) (36,014) (41,566) (42,061) (36,579)
(220,800) (217,300) (212,700) (201,100) (191,300) (185,700) (161,900) (145,200)
(293) (4,576) (5,581) (2,581) (38,052) (4,438) (2,727) (1,869)
(240,274) (315,021) 21,679 (53,882) (431,667) (150,612) (80,520) (2,020)
7,321 1,722 (6,562) (20,826) (323,675) 25,992 182,781 118,604
3,239 1,517 8,079 28,905 352,580 326,588 143,807 25,203
$ 10,560 $ 3,239 $ 1,517 $ 8,079 $ 28,905 $ 352,580 $ 326,588 $ 143,807
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116
BALANCE SHEETS
Alabama Power Company
AT DECEMBER 31, 1993* 1992* 1991*
(Thousands of Dollars)
ASSETS
ELECTRIC PLANT:
Production-
Fossil $ 2,987,010 $ 2,953,683 $ 2,991,876
Nuclear 1,860,842 1,860,832 1,851,317
Hydro 819,848 818,363 814,301
Total production 5,667,700 5,632,878 5,657,494
Transmission 1,051,130 1,013,464 977,239
Distribution 2,206,834 2,072,165 1,947,972
General 810,551 751,652 713,948
Construction work in progress 225,743 164,555 148,564
Nuclear fuel, at amortized cost 93,551 101,128 109,259
Total electric plant 10,055,509 9,735,842 9,554,476
STEAM HEAT PLANT:
Plant in service 20,926 20,924 20,214
Construction work in progress 43 33 181
Total steam heat plant 20,969 20,957 20,395
Total utility plant 10,076,478 9,756,799 9,574,871
ACCUMULATED PROVISION FOR DEPRECIATION:
Electric 3,374,310 3,122,332 2,913,385
Steam heat 9,846 9,211 8,492
Total accumulated provision for depreciation 3,384,156 3,131,543 2,921,877
Total 6,692,322 6,625,256 6,652,994
Less property-related accumulated deferred income taxes - 1,170,982 1,140,303
Total 6,692,322 5,454,274 5,512,691
OTHER PROPERTY AND INVESTMENTS:
Securities received from settlement of disputed contracts - - 69,550
Nuclear decommissioning trusts 49,550 32,390 15,864
Miscellaneous 49,635 49,892 48,254
Total 99,185 82,282 133,668
CURRENT ASSETS:
Cash and cash equivalents 3,233 13,629 11,160
Investment securities - 64,832 -
Receivables, net 410,422 344,934 349,599
Fossil fuel stock, at average cost 88,481 134,328 154,798
Materials and supplies, at average cost 176,728 182,511 174,745
Prepayments 79,207 108,254 95,832
Vacation pay deferred 22,680 21,879 21,691
Total current assets 780,751 870,367 807,825
DEFERRED CHARGES:
Deferred charges related to income taxes 469,010 - -
Debt expense, being amortized 7,064 6,118 5,957
Premium on reacquired debt, being amortized 102,634 74,835 40,174
Uranium enrichment decontamination and decommissioning fund 45,554 47,730 -
Miscellaneous 52,163 58,012 49,147
Total deferred charges 676,425 186,695 95,278
TOTAL ASSETS $ 8,248,683 $ 6,593,618 $ 6,549,462
*Includes the effect of recognizing, beginning in 1987, retail service
rendered but not yet billed to customers.
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117
BALANCE SHEETS
Alabama Power Company
1990* 1989* 1988* 1987* 1986 1985 1984 1983
$ 2,462,100 $ 2,428,146 $ 1,820,966 $ 1,787,979 $ 1,748,226 $ 1,678,117 $ 1,203,447 $ 1,167,707
1,794,540 1,786,877 1,769,093 1,765,854 1,749,981 1,687,766 1,664,849 1,642,869
809,578 803,901 789,617 788,046 784,445 773,682 559,696 556,528
5,066,218 5,018,924 4,379,676 4,341,879 4,282,652 4,139,565 3,427,992 3,367,104
925,368 882,933 844,003 817,065 773,142 699,980 642,968 616,098
1,815,265 1,692,426 1,587,690 1,481,845 1,384,576 1,295,930 1,221,003 1,136,277
660,217 646,523 613,498 535,148 506,228 349,249 300,043 247,080
654,055 557,150 1,023,019 750,907 497,491 502,455 972,832 760,910
143,711 147,997 174,130 191,493 205,768 243,468 223,818 217,793
9,264,834 8,945,953 8,622,016 8,118,337 7,649,857 7,230,647 6,788,656 6,345,262
20,091 20,083 20,076 20,217 19,508 17,056 9,780 9,754
74 71 58 89 123 64 901 209
20,165 20,154 20,134 20,306 19,631 17,120 10,681 9,963
9,284,999 8,966,107 8,642,150 8,138,643 7,669,488 7,247,767 6,799,337 6,355,225
2,676,957 2,458,747 2,257,696 2,068,176 1,877,124 1,697,547 1,525,893 1,378,094
7,861 7,154 6,456 5,938 5,261 3,874 3,619 3,346
2,684,818 2,465,901 2,264,152 2,074,114 1,882,385 1,701,421 1,529,512 1,381,440
6,600,181 6,500,206 6,377,998 6,064,529 5,787,103 5,546,346 5,269,825 4,973,785
1,106,664 1,051,877 1,001,173 933,932 857,081 758,150 664,591 584,322
5,493,517 5,448,329 5,376,825 5,130,597 4,930,022 4,788,196 4,605,234 4,389,463
- - - - - - - -
- - - - - - - -
40,604 34,710 29,677 31,402 30,735 24,849 22,288 22,190
40,604 34,710 29,677 31,402 30,735 24,849 22,288 22,190
10,560 3,239 1,517 8,079 28,905 352,580 326,588 143,807
- - - - - - - -
346,473 355,107 344,671 353,493 220,025 235,263 221,732 205,329
144,960 131,942 173,858 164,671 152,640 163,899 206,232 251,440
167,209 139,326 117,818 103,823 89,599 76,300 63,790 43,741
50,364 54,613 28,412 10,595 12,320 9,741 8,801 24,333
22,845 22,021 21,871 21,317 20,002 18,859 17,599 18,123
742,411 706,248 688,147 661,978 523,491 856,642 844,742 686,773
- - - - - - - -
6,083 6,491 6,831 6,695 6,308 6,607 6,774 6,847
26,504 28,778 27,329 30,767 34,170 524 109 59
- - - - - - - -
53,174 54,875 52,136 50,561 45,927 45,445 17,050 15,275
85,761 90,144 86,296 88,023 86,405 52,576 23,933 22,181
$ 6,362,293 $ 6,279,431 $ 6,180,945 $ 5,912,000 $ 5,570,653 $ 5,722,263 $ 5,496,197 $ 5,120,607
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118
BALANCE SHEETS
Alabama Power Company
AT DECEMBER 31, 1993* 1992* 1991*
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stock $ 224,358 $ 224,358 $ 224,358
Other paid-in capital 1,304,645 1,304,645 1,304,645
Premium on preferred stock 146 342 461
Earnings retained in the business 997,199 914,148 857,734
Total common equity 2,526,348 2,443,493 2,387,198
Preferred stock 440,400 489,400 484,400
Preferred stock subject to mandatory redemption - - -
Long-term debt 2,362,852 2,202,473 2,382,635
Total Capitalization 5,329,600 5,135,366 5,254,233
(excluding amount due within one year)
CURRENT LIABILITIES:
Notes payable to banks 40,000 71,000 76,000
Commercial paper - 125,917 -
Preferred stock due within one year - - -
Long-term debt due within one year 58,998 67,379 85,077
Accounts payable 334,998 296,731 295,333
Customer deposits 31,198 31,286 30,165
Taxes accrued 40,144 24,373 45,493
Interest accrued 52,809 41,675 49,288
Vacation pay accrued 22,680 21,879 21,691
Miscellaneous 50,426 93,836 37,699
Total current liabilities 631,253 774,076 640,746
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes 1,165,127 - -
Accumulated deferred investment tax credit s 329,909 344,707 362,672
Prepaid capacity revenues, net 143,762 147,658 149,534
Deferred revenues from settlement of disputed contracts 19,871 46,721 59,937
Uranium enrichment decontamination and decommissioning fund 39,644 44,548 -
Deferred credits related to income taxes 441,240 - -
Miscellaneous 148,277 100,542 82,340
Total deferred credits and other liabilities 2,287,830 684,176 654,483
TOTAL CAPITALIZATION AND LIABILITIES $ 8,248,683 $ 6,593,618 $ 6,549,462
*Includes the effect of recognizing, beginning in 1987, retail service
rendered but not yet billed to customers.
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119
BALANCE SHEETS
Alabama Power Company
1990* 1989* 1988* 1987* 1986 1985 1984 1983
$ 224,358 $ 224,358 $ 224,358 $ 224,358 $ 224,358 $ 224,358 $ 224,358 $ 224,358
1,304,645 1,304,645 1,304,645 1,225,145 1,182,145 1,182,145 1,155,145 1,062,145
461 461 461 461 461 1,937 1,938 1,904
751,126 659,347 565,351 496,783 440,644 361,716 282,854 211,502
2,280,590 2,188,811 2,094,815 1,946,747 1,847,608 1,770,156 1,664,295 1,499,909
484,400 484,400 484,400 384,400 384,400 384,400 424,400 424,400
12,500 17,500 22,500 27,500 30,000 35,000 37,224 38,034
2,397,931 2,435,129 2,496,492 2,386,258 2,210,108 2,349,373 2,402,713 2,404,565
5,175,421 5,125,840 5,098,207 4,744,905 4,472,116 4,538,929 4,528,632 4,366,908
89,500 30,000 - 15,000 - - - -
- - - - - - - -
5,000 5,000 5,000 2,500 5,000 42,224 - -
83,989 81,031 96,242 95,140 142,394 224,918 120,077 85,550
271,776 267,645 259,443 273,613 238,606 295,326 268,966 229,002
29,571 28,450 25,964 32,220 30,333 29,436 28,498 26,224
20,665 26,832 25,285 72,118 50,757 27,368 36,788 47,724
49,820 49,926 50,174 49,489 47,648 66,193 66,201 65,906
22,845 22,021 21,871 21,317 20,002 18,859 17,599 18,123
64,547 91,022 28,944 24,660 25,567 42,622 38,474 26,759
637,713 601,927 512,923 586,057 560,307 746,946 576,603 499,288
- - - - - - - -
379,990 399,097 412,771 418,370 418,275 418,222 379,433 243,399
99,835 102,346 104,211 103,947 101,143 - - -
- - - - - - - -
- - - - - - - -
- - - - - - - -
69,334 50,221 52,833 58,721 18,812 18,166 11,529 11,012
549,159 551,664 569,815 581,038 538,230 436,388 390,962 254,411
$ 6,362,293 $ 6,279,431 $ 6,180,945 $ 5,912,000 $ 5,570,653 $ 5,722,263 $ 5,496,197 $ 5,120,607
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ALABAMA POWER COMPANY
OUTSTANDING SECURITIES
AT DECEMBER 31, 1993
FIRST MORTGAGE BONDS
Amount Interest Amount
Series Issued Rate Outstanding Maturity
(Thousands) (Thousands)
1993 $ 60,000 4-1/2% $ 60,000 3/1/96
1993 50,000 5-1/2% 50,000 2/1/98
1992 170,000 6-3/8% 170,000 8/1/99
1993 100,000 6% 100,000 3/1/00
1992 100,000 6.85% 100,000 8/1/02
1993 125,000 7% 125,000 1/1/03
1993 175,000 6-3/4% 175,000 2/1/03
1992 175,000 7-1/4% 175,000 8/1/07
1987 200,000 10-5/8% 15,243 11/1/17
1991 100,000 9-1/4% 100,000 5/1/21
1991 150,000 8-3/4% 150,000 12/1/21
1992 200,000 8-1/2% 200,000 5/1/22
1992 100,000 8.3% 100,000 7/1/22
1993 100,000 7-3/4% 100,000 2/1/23
1993 150,000 7.45% 150,000 7/1/23
1993 100,000 7.30% 100,000 11/1/23
$ 2,055,000 $1,870,243
POLLUTION CONTROL BONDS
Amount Interest Amount
Series Issued Rate Outstanding Maturity
(Thousands) (Thousands)
1978 $ 5,600 7.25% $ 5,600 5/1/03
1974 19,600 6% 18,550 2/1/04
1976 3,000 7.20% 2,900 2/1/06
1989 35,000 7.20% 35,000 7/1/14
1984 100,000 10.875% 100,000 11/1/14
1985 50,000 9.375% 50,000 6/1/15
1985 81,500 9.25% 81,500 12/1/15
1989 18,700 7.20% 18,700 6/1/16
1986 21,000 7.40% 21,000 11/1/16
1993 12,100 Variable 12,100 8/1/17
1993 12,000 Variable 12,000 8/1/17
1993 12,000 Variable 12,000 8/1/17
1993 96,990 6.05% 96,990 5/1/23
1993 9,800 5.80% 9,800 6/1/22
$ 477,290 $ 476,140
PREFERRED STOCK
Shares Dividend Amount
Series Outstanding Rate Outstanding
(Thousands)
1946-1952 364,000 4.20% $ 36,400
1950 100,000 4.60% 10,000
1961 80,000 4.92% 8,000
1963 50,000 4.52% 5,000
1964 60,000 4.64% 6,000
1965 50,000 4.72% 5,000
1966 70,000 5.96% 7,000
1968 50,000 6.88% 5,000
1988 500,000 Auction 50,000
1992 4,000,000 7.60% 100,000
1992 2,000,000 7.60% 50,000
1993 1,520,000 6.80% 38,000
1993 2,000,000 6.40% 50,000
1993 200 Auction 20,000
1993 2,000,000 Adjustable 50,000
12,844,200 $ 440,400
II-90
121
ALABAMA POWER COMPANY
SECURITIES RETIRED
DURING 1993
FIRST MORTGAGE BONDS
Principal Interest
Series Amount Rate
(Thousands)
1964 $ 24,105 4.625%
1965 33,284 4.875%
1966 29,374 6.25%
1967 28,000 6.50%
1968 25,000 7%
1972 25,500 7.50%
1972 65,000 7.75%
1973 75,000 8.25%
1972 98,000 7.875%
1986 125,000 9.375%
1987 21,525 10.625%
1988 150,000 10%
$ 699,788
POLLUTION CONTROL BONDS
Principal Interest
Series Amount Rate
(Thousands)
1974 $ 300 6%
1976 9,800 7.20%
1976 50 7.20%
1976 10,415 7.25%
1977 40,000 7.20%
1978 48,000 7.375%
1980 4,250 9.20%
1983 22,500 9.375%
$ 135,315
PREFERRED STOCK
Principal Dividend
Series Amount Rate
(Thousands)
1972 $ 38,000 8.28%
1972 20,000 8.04%
1973 50,000 8.16%
1977 49,000 8.72%
1988 50,000 Adjustable
$ 207,000
II-91
122
GEORGIA POWER COMPANY
FINANCIAL SECTION
II-92
123
MANAGEMENT'S REPORT
Georgia Power Company 1993 Annual Report
The management of Georgia Power Company has prepared this annual report and is
responsible for the financial statements and related information. These
statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances, and necessarily include amounts
that are based on the best estimates and judgments of management. Financial
information throughout this annual report is consistent with the financial
statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls based upon the recognition that the cost of the
system should not exceed its benefits. The Company believes that its system of
internal accounting controls maintains an appropriate cost/benefit
relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control
system in order to determine their auditing procedures for the purpose of
expressing an opinion on the financial statements.
The audit committee of the board of directors, which is composed of five
directors who are not employees, provides a broad overview of management's
financial reporting and control functions. At least three times a year this
committee meets with management, the internal auditors, and the independent
public accountants to ensure that these groups are fulfilling their
obligations and to discuss auditing, internal control and financial reporting
matters. The internal auditors and the independent public accountants have
access to the members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted with a high standard of
business ethics.
In management's opinion, the financial statements present fairly the
financial position, results of operations and cash flows of Georgia Power
Company in conformity with generally accepted accounting principles. As
discussed in Note 4 to the financial statements, an uncertainty exists with
respect to the actions of regulators regarding recoverability of the Company's
investment in the Rocky Mountain pumped storage hydroelectric project. The
outcome of this uncertainty cannot be determined until regulatory proceedings
are concluded. Accordingly, no provision for any write-down of the costs
associated with the Rocky Mountain project resulting from the potential actions
of the Georgia Public Service Commission has been made in the accompanying
financial statements.
/s/ H. Allen Franklin /s/ Warren Y. Jobe
- --------------------- --------------------------
H. Allen Franklin Warren Y. Jobe
President and Chief Executive Vice President,
Executive Officer Treasurer and Chief
Financial Officer
II-93
124
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS
OF GEORGIA POWER COMPANY:
We have audited the accompanying balance sheets and statements of
capitalization of Georgia Power Company (a Georgia corporation) as of December
31, 1993 and 1992, and the related statements of income, retained earnings,
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.
In our opinion, the financial statements (pages II-102 through II-122)
referred to above present fairly, in all material respects, the financial
position of Georgia Power Company as of December 31, 1993 and 1992, and the
results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
As explained in Notes 2 and 7 to the financial statements, effective January
1, 1993, the Company changed its methods of accounting for postretirement
benefits other than pensions and for income taxes.
As more fully discussed in Note 4 to the financial statements, an uncertainty
exists with respect to the actions of the regulators regarding the
recoverability of the Company's investment in the Rocky Mountain pumped storage
hydroelectric project. The outcome of this uncertainty cannot be determined
until regulatory proceedings are concluded. Accordingly, no provision for any
write-down of the costs associated with the Rocky Mountain project resulting
from the potential actions of the Georgia Public Service Commission has been
made in the accompanying financial statements.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
February 16, 1994
II-94
125
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1993 Annual Report
RESULTS OF OPERATIONS
EARNINGS
Georgia Power Company's 1993 earnings totaled $570 million, representing a $49
million (9.5 percent) increase over the prior year. This improvement is
primarily a result of higher retail revenues and lower financing costs. Also,
during the period, the Company had an $18 million after-tax gain on the sale of
a portion of Plant Scherer Unit 4. Higher retail revenues reflect growth in
energy sales of 6.1 percent from 1992 levels primarily due to exceptionally hot
summer weather during 1993. Interest expense and preferred stock dividends
decreased in 1993 due to the redemption and refinancing of higher-cost debt and
preferred stock. These positive events were partially offset by higher
operating expenses.
In comparing 1992 earnings to the prior year, it should be noted that 1991
earnings included two unusual items that significantly affect this comparison.
Earnings in 1991 were $89 million higher due to the completion of a settlement
agreement with Gulf States Utilities Company (Gulf States) related to power
sales contracts. This increase was partially offset by an after-tax charge of
$33 million in 1991 for a work force reduction program. A comparison of 1992
to 1991 -- excluding these unusual items -- would reflect a 1992 increase in
earnings of $102 million.
REVENUES
The following table summarizes the factors impacting operating revenues for the
1991-1993 period:
Increase (Decrease)
From Prior Year
1993 1992 1991
(in millions)
Retail -
Change in base rates $ - $ 95 $ 27
Sales growth 45 76 67
Weather 126 (58) (16)
Fuel cost recovery 76 (26) (54)
Demand-side option
programs 15 - -
Total retail 262 87 24
Sales for resale -
Non-affiliates (106) (96) (47)
Affiliates (6) 2 (103)
Total sales for resale (112) (94) (150)
Other operating revenues 4 3 (18)
Total operating revenues $ 154 $ (4) $ (144)
Percent change 3.6% (0.1)% (3.2)%
Retail revenues of $3.8 billion in 1993 increased $262 million (7.4 percent)
over the prior year, compared with an increase of $87 million (2.5 percent) in
1992. The exceptionally hot weather during the summer of 1993 was the primary
factor affecting the increase in retail revenues over 1992. The increase in
retail revenues for 1992 was a result of higher retail rates and sales growth,
partially offset by mild weather and lower fuel revenues. Fuel revenues
generally represent the direct recovery of fuel expense, including the fuel
component of purchased energy, and do not affect net income. Revenues from
demand-side options programs generally represent the direct recovery of program
costs. See Note 3 to the financial statements for further information on these
programs.
Revenues from sales to non-affiliated utilities decreased in both 1993 and
1992. Contractual unit power sales to Florida utilities for 1993 and 1992 are
down compared with prior years, primarily due to scheduled reductions that
corresponded with the sales to these utilities of portions of Plant Scherer
Unit 4 in July 1991 and June
II-95
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1993 Annual Report
1993. Sales to municipalities and cooperatives increased slightly in 1993 due
to the hot summer weather. Generally, these sales have been decreasing as
these customers retain more of their own generation at facilities jointly owned
with the Company.
Revenues from sales to non-affiliated utilities outside the service area under
long-term contracts consist of capacity and energy components. Capacity
revenues reflect the recovery of fixed costs and a return on investment under
the contracts. Energy is generally sold at variable cost. The capacity and
energy components were as follows:
1993 1992 1991
(in millions)
Capacity $152 $233 $274
Energy 113 168 204
Total $265 $401 $478
Revenues from sales to affiliated companies within the Southern electric
system will vary from year to year depending on demand and the availability and
cost of generating resources at each company. Sales to affiliated companies do
not have a significant impact on earnings.
Changes in revenues are a function of the amount of energy sold each year.
Kilowatt-hour (KWH) sales for 1993 and the percent change by year were as
follows:
Percent Change
1993
KWH 1993 1992 1991
(in billions)
Residential 16.7 11.5% 0.8% 0.3%
Commercial 18.3 5.9 2.2 1.6
Industrial 23.6 2.9 3.1 0.8
Other 0.5 5.7 1.7 0.1
Total retail 59.1 6.1 2.2 0.9
Sales for resale -
Non-affiliates 14.3 (9.8) (15.2) (7.1)
Affiliates 3.0 (8.8) (14.6) (53.0)
Total sales for
resale 17.3 (9.7) (15.1) (20.5)
Total sales 76.4 2.1 (2.9) (6.5)
The hot summer weather during 1993 contributed primarily to the sales growth
in the residential and commercial classes. Continued improvement in economic
conditions positively impacted sales growth in the commercial and industrial
classes. Residential energy sales growth in 1992 reflected mild weather.
Commercial and industrial sales growth in 1992 is attributable to improved
economic conditions.
The decrease in energy sales to non-affiliated utilities reflects scheduled
reductions in contractual power sales.
EXPENSES
Fuel expense increased 2.3 percent in 1993 due to higher generation, which was
partially offset by lower nuclear fuel costs. In 1992, fuel expense decreased
6.9 percent due to lower generation and lower fuel costs. Purchased power
expense has decreased significantly since 1991, reflecting declining
contractual capacity purchases from the co-owners of plants Vogtle and Scherer.
Purchased power expense decreased $88 million in 1993 and $43 million in 1992.
The declines in Plant Vogtle contractual capacity purchases did not have a
significant impact on earnings in 1993 or 1992 as these costs are being
levelized over six years under the terms of the 1991 Georgia Public Service
Commission (GPSC) retail rate order. The levelization is reflected in the
amortization of deferred Plant Vogtle expenses in the income statements. See
Note 3 to the financial statements for additional information.
Other Operation and Maintenance (O & M) expenses increased 9.0 percent in
1993 after remaining relatively flat in 1992. The increase in 1993 is
primarily the result of environmental remediation costs at various current and
former operating sites, the one- time costs of an automotive fleet reduction
program and the recognition of higher employee benefit costs under new
accounting rules adopted in 1993. See Note 2 to the financial statements for
additional information concerning these new rules. Also, during 1993, O & M
expenses reflect costs associated with new demand-side option programs. These
costs were offset by increases in retail revenues. See Note 3 to the financial
statements for additional information on the recovery of demand-side option
program costs.
Depreciation and amortization expense increased slightly due to additional
plant investment. The 1992 decrease is due to the effects of lower
depreciation rates effective in October 1991. Taxes other than income taxes
increased 7.4 percent in 1993 and 3.8 percent in 1992.
II-96
127
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1993 Annual Report
These increases reflect higher ad valorem taxes. The 1993 increase also
includes higher taxes paid to municipalities as a result of increased sales.
Income tax expense increased $62 million in 1993 due primarily to higher
earnings and the effect of a one percent increase in the federal tax rate
effective January, 1993. Also, the Company incurred $27 million of tax expense
in connection with the second in a series of four separate transactions to sell
Plant Scherer Unit 4. The sale resulted in an after-tax gain of $18 million.
Interest expense and dividends on preferred stock decreased $19 million (4.0
percent) and $49 million (9.3 percent) in 1993 and 1992, respectively. These
reductions are due to significant refinancing of long-term debt and preferred
stock. The Company refinanced $1.7 billion of securities in both 1993 and
1992. In addition, the Company has retired $544 million of long-term debt with
the proceeds from the 1991 and 1993 Plant Scherer Unit 4 sales. Other interest
charges in 1993 include interest related to the settlement of an Internal
Revenue Service audit. The settlement, in total, did not have an effect on
1993 net income.
The Company has deferred certain expenses and recorded a deferred return
related to Plant Vogtle under phase-in plans. See Note 3 to the financial
statements under "Plant Vogtle Phase-In-Plans" for information regarding the
deferral and subsequent amortization of costs related to Plant Vogtle.
EFFECTS OF INFLATION
The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic
loss because the Company is recovering its costs of investments in dollars that
have less purchasing power. While the inflation rate has been relatively low
in recent years, it continues to have an adverse effect on the Company because
of the large investment in long-lived utility plant. Conventional accounting
for historical cost does not recognize either this economic loss or the
partially offsetting gain that arises through financing facilities with
fixed-money obligations such as long-term debt and preferred stock. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
FUTURE EARNINGS POTENTIAL
The results of operations for the past three years are not necessarily
indicative of future earnings. The level of future earnings depends on
numerous factors ranging from growth in energy sales to regulatory matters.
Growth in energy sales is subject to a number of factors which traditionally
have included changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, weather,
competition, and the rate of economic growth in the Company's service area.
Assuming normal weather, retail sales growth is projected to be approximately 2
percent annually on average during 1994 through 1996.
The scheduled addition of four combustion turbine generating units in 1994,
four units in 1995 and one unit in 1996, as well as the Rocky Mountain pumped
storage hydroelectric project in 1995, will increase related O & M and
depreciation expenses. See Note 4 to the financial statements for information
on regulatory uncertainties related to the Rocky Mountain project. The GPSC
has certified the construction of the 1994 and 1995 combustion turbine
generating units for meeting peak generating needs. In addition, the Company
has completed a demonstration competitive bidding process for its supply-side
requirements expected for 1996. The Company has filed with the GPSC for
certification of a four-year purchase power agreement beginning in 1996, and
for construction of a jointly owned combustion turbine to be completed in 1996
to meet these needs.
As part of efforts to curtail growth in operating expenses, the Company is
reducing its work force through an early-retirement program announced in
January 1994. The program resulted in a first quarter 1994 after-tax charge to
earnings of $39 million. The program has an expected payback period of
approximately two years.
Pursuant to an Integrated Resource Plan approved by the GPSC in 1992, the
Company has implemented various demand-side option programs and has been
authorized by the GPSC to recover associated program costs through rate riders.
On October 15, 1993, a superior court judge ruled that recovery of these costs
through rate riders is unlawful. The Company has ceased collection of the rate
riders and is deferring program costs as ordered by the
II-97
128
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1993 Annual Report
GPSC pending the final outcome of this matter. See Note 3 to the financial
statements for additional information.
The Company has completed two in a series of four separate transactions to
sell Unit 4 of Plant Scherer to two Florida utilities. The remaining
transactions are scheduled to take place in 1994 and 1995. If the sales take
place as planned, the Company would realize an additional after-tax gain
estimated to total approximately $20 million. See Note 5 to the financial
statements for additional information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could reduce earnings if such costs cannot be billed to customers. The
Clean Air Act is discussed later under "Environmental Issues."
The Energy Policy Act of 1992 (Energy Act) will have a profound effect on the
future of the electric utility industry. The Energy Act promotes energy
efficiency, alternative fuel use, and increased competition among electric
utilities. The law also includes provisions to streamline the licensing
process for new nuclear generating plants. The Energy Act marks the beginning
of a major change in the traditional business practices of selling electricity.
The Energy Act allows Independent Power Producers (IPPs) and other electric
suppliers access to a utility's transmission lines to sell their electricity to
other utilities. This may enhance the incentives for IPPs to build
cogeneration plants for the Company's large industrial and commercial
customers. If the Company does not remain a low cost producer and provide
quality service, the Company's sales growth could be limited and this could
significantly erode earnings.
The Company continues to compete with other electric suppliers within the
state. In Georgia, most new retail customers with more than 900 kilowatts of
connected load may choose their electricity supplier. In addition, the bulk
power market has become very competitive as utilities, IPPs and cogenerators
seek to supply future capacity needs. Competition can create new business
opportunities, but it increases risk and has the potential to adversely affect
earnings.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate
schedules and power sales contracts that the Company has with its sales for
resale customers. The FERC currently is reviewing the rate of return on common
equity included in these schedules and contracts and may require such returns
to be lowered, possibly retroactively. See Note 3 to the financial statements
under "FERC Review of Equity Returns" for additional information.
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112,
Employers' Accounting for Postemployment Benefits, which must be adopted by
1994. The new standard requires that all types of benefits provided to former
or inactive employees and their families prior to retirement be accounted for
on an accrual basis. These benefits include salary continuation, severance
pay, supplemental unemployment benefits, disability-related benefits, job
training, and health and life insurance coverage. In 1993, the Company adopted
Statement No. 112, with no material effect on the financial statements.
The FASB has issued Statement No. 115, Accounting for Certain Investments in
Debt and Equity Securities, which will be effective in 1994. Statement No. 115
supersedes FASB Statement No. 12, Accounting for Certain Marketable
Securities. The Company adopted the new rules in January, 1994, with no
material effect on the financial statements.
FINANCIAL CONDITION
OVERVIEW
The principal changes in the Company's financial condition in 1993 were gross
utility plant additions of $674 million and the lowering of the cost of capital
achieved through the refinancing or retirement of $1.7 billion of long-term
debt and preferred stock.
On January 1, 1993, the Company changed its methods of accounting for
postretirement benefits other than pensions and for income taxes. See Notes 2
and 7 to the financial statements regarding the impact of these changes.
The funds needed for gross property additions are currently provided from
operations. The Statements of Cash Flows provide additional details.
II-98
129
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1993 Annual Report
FINANCING ACTIVITIES
In 1993, the Company continued to lower its financing costs by issuing new
securities and other debt, and retiring or repaying high-cost issues. New
issues during 1991 through 1993 totaled $3.0 billion and retirement or
repayment of securities totaled $4.2 billion. The retirements included the
redemption of $253 million and $291 million in 1993 and 1991, respectively, of
first mortgage bonds with the proceeds from the Plant Scherer Unit 4 sales.
Composite financing rates for the years 1991 through 1993, as of year-end,
were as follows:
1993 1992 1991
Composite interest rate
on long-term debt 7.86% 8.49% 9.05%
Composite preferred stock
dividend rate 6.76% 7.52% 7.99%
The Company's current securities ratings are as follows:
Duff & Standard
Phelps Moody's & Poor's
First Mortgage Bonds A+ A3 A-
Preferred Stock A- baa1 BBB+
Unsecured Bonds A Baa1 BBB+
Commercial Paper * P2 A2
* Not rated by Duff & Phelps
LIQUIDITY AND CAPITAL REQUIREMENTS
Cash provided from operations increased by $236 million in 1993, primarily due
to higher retail sales, lower interest costs, decreasing capacity purchases
from the co-owners of plants Vogtle and Scherer and the receipt of cash
payments from Gulf States that completed the settlement of litigation.
The Company estimates that construction expenditures for the years 1994
through 1996 will total $688 million, $555 million and $629 million,
respectively. The Company will continue to invest in transmission and
distribution facilities and enhance existing generating plants. These
expenditures also include amounts for nine combustion turbine generating units
and equipment that will be required to comply with the provisions of the Clean
Air Act.
The Company's contractual capacity purchases will decline by $113 million
over the next three years. Cash requirements for sinking fund requirements,
redemptions announced, and maturities of long-term debt are expected to total
$377 million during 1994 through 1996.
As a result of requirements by the Nuclear Regulatory Commission, the Company
has established external sinking funds for the purpose of funding nuclear
decommissioning costs. For 1994 through 1996, the amount to be funded for the
Company totals $16 million annually. For additional information concerning
nuclear decommissioning costs, see Note 1 to the financial statements under
"Nuclear Decommissioning."
SOURCES OF CAPITAL
The Company expects to meet future capital requirements primarily using funds
generated from operations and, if needed, by the issuance of new debt and
equity securities, term loans, and short-term borrowings. To meet short-term
cash needs and contingencies, the Company had approximately $540 million of
unused credit arrangements with banks at the beginning of 1994. See Note 8 to
the financial statements for additional information.
Completing the remaining two transactions for the sale of Plant Scherer Unit
4 will generate approximately $130 million in both 1994 and in 1995.
The Company is required to meet certain coverage requirements specified in
its mortgage indenture and corporate charter to issue new first mortgage bonds
and preferred stock. The Company's ability to satisfy all coverage
requirements is such that it could issue new first mortgage bonds and preferred
stock to provide sufficient funds for all anticipated requirements.
ENVIRONMENTAL ISSUES
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law -- will have a
significant impact on The Southern Company. Specific reductions in sulfur
dioxide and nitrogen oxide emissions from fossil-fired generating plants will
be required in two phases. Phase I compliance must be implemented in 1995 and
affects eight generating plants -- some 10,000 megawatts
II-99
130
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1993 Annual Report
of capacity or 35 percent of total capacity -- in the Southern electric system.
Phase II compliance is required in 2000, and all fossil-fired generating plants
in the Southern electric system will be affected.
Beginning in 1995, the Environmental Protection Agency (EPA) will allocate
annual sulfur dioxide emission allowances through the newly established
allowance trading program. An emission allowance is the authority to emit one
ton of sulfur dioxide during a calendar year. The method for allocating
allowances is based on the fossil fuel consumed from 1985 through 1987 for each
affected generating unit. Emission allowances are transferable and can be
bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize the
cost of compliance. The market for emission allowances is developing slower
than expected. However, The Southern Company's sulfur dioxide compliance
strategy is designed to take advantage of allowances as the market develops.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at
the eight affected plants by switching to low-sulfur coal, and this has
required some equipment upgrades. This compliance strategy is expected to
result in unused emission allowances being banked for later use. Additional
construction expenditures are required to install equipment for the control of
nitrogen oxide emissions at these eight plants. Also, continuous emissions
monitoring equipment would be installed on all fossil-fired units. Under this
Phase I compliance approach, Georgia Power's construction expenditures are
estimated to total approximately $150 million through 1995.
Phase II compliance costs are expected to be higher because requirements are
stricter and all fossil-fired generating plants are affected. For sulfur
dioxide compliance, The Southern Company could use emission allowances banked
during Phase I, increase fuel switching, install flue gas desulfurization
equipment at selected plants, and/or purchase more allowances depending on the
price and availability of allowances. Also, in Phase II, equipment to control
nitrogen oxide emissions will be installed on additional system fossil-fired
plants as required to meet anticipated Phase II limits. Therefore, during the
period 1996 to 2000, compliance could require total Georgia Power construction
expenditures ranging from approximately $150 million to $325 million. However,
the full impact of Phase II compliance cannot now be determined with certainty,
pending the development of a market for emission allowances, the completion of
EPA regulations, and the possibility of new emission reduction technologies.
An increase of up to 2 percent in Georgia Power's annual revenue
requirements from customers could be necessary to fully recover the cost of
compliance for both Phase I and Phase II of the Clean Air Act. Compliance
costs include construction expenditures, increased costs for switching to
low-sulfur coal, and costs related to emission allowances. There can be no
assurance that all Clean Air Act costs will be recovered.
Metropolitan Atlanta is classified as a non-attainment area with regard to
the ozone ambient air quality standards. Title I of the Clean Air Act requires
the state of Georgia to conduct specific studies and establish new control
rules by November 1994 -- affecting sources of nitrogen oxides and volatile
organic compounds -- to achieve attainment by 1999. As the required first
step, the state has issued rules for the application of reasonably available
control technology to reduce nitrogen oxide emissions by May 31, 1995. The
results of these new rules require nitrogen oxide controls, above Title IV
requirements, on some Company plants. Final attainment rules, based on
modeling studies, could require installation of additional controls for
nitrogen oxide emissions as early as 1997. Compliance with any new rules could
result in significant additional costs. The impact of new rules will depend on
the development and implementation of such rules.
Title III of the Clean Air Act requires a multi-year EPA study of power
plant emissions of hazardous air pollutants. The study will serve as the basis
for a decision on whether additional regulatory control of these substances is
warranted. Compliance with any new control standards could result in
significant additional costs. The impact of new standards -- if any -- will
depend on the development and implementation of applicable regulations.
The EPA continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study on
the impact of a
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131
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1993 Annual Report
new standard indicate that a number of plants could be required to install
sulfur dioxide controls. These controls would be in addition to the controls
already required to meet the acid rain provision of the Clean Air Act. The EPA
is expected to take some action on this issue in 1994. In addition, the EPA is
evaluating the need to revise the ambient air quality standards for particulate
matter, nitrogen oxides, and ozone. The impact of any new standards will
depend on the level chosen for the standards and cannot be determined at this
time.
In 1994 or 1995, the EPA is expected to issue revised rules on air quality
control regulations related to stack height requirements of the Clean Air Act.
The full impact of the final rules cannot be determined at this time, pending
their development and implementation.
In 1993, the EPA issued a ruling confirming the nonhazardous status of coal
ash. However, the EPA has until 1998 to classify co-managed utility wastes --
coal ash and other utility wastes -- as either nonhazardous or hazardous. If
the EPA classifies the co-managed wastes as hazardous, then substantial
additional costs for the management of such wastes may be required. The full
impact of any change in the regulatory status will depend on the subsequent
development of co-managed waste requirements.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. These laws include the
Comprehensive Environmental Response Compensation and Liability Act of 1980
(CERCLA or Superfund). Under these various laws and regulations, the Company
could incur costs to clean up properties currently or previously owned. The
Company conducts studies to determine the extent of any required clean-up costs
and has recognized costs to clean-up known sites in the financial statements.
Several major pieces of environmental legislation are in the process of
being reauthorized or amended by Congress. These include: the Clean Water
Act; the Comprehensive Environmental Response, Compensation, and Liability Act;
and the Resource Conservation and Recovery Act. Changes to these laws could
affect many areas of the Company's operations. The full impact of these
requirements cannot be determined at this time, pending the development and
implementation of applicable regulations.
Compliance with possible new legislation related to global climate change,
electromagnetic fields and other environmental and health concerns could
significantly affect the Company. The impact of new legislation -- if any --
will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential for lawsuits alleging damages caused
by electromagnetic fields exists.
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STATEMENTS OF INCOME
For the Years Ended December 31, 1993, 1992, and 1991
Georgia Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
OPERATING REVENUES:
Revenues (Note 1) $ 4,389,513 $ 4,229,601 4,235,842
Revenues from affiliates 61,668 67,835 65,586
Total operating revenues 4,451,181 4,297,436 4,301,428
OPERATING EXPENSES:
Operation --
Fuel 951,507 929,780 998,701
Purchased power from non-affiliates 313,170 436,761 444,920
Purchased power from affiliates 194,024 158,306 193,114
Provision for separation benefits - 9,778 52,952
Proceeds from settlement of disputed contracts (Note 3) - (4,982) (142,183)
Other 675,284 616,116 596,565
Maintenance 284,521 264,757 295,012
Depreciation and amortization 379,425 375,460 382,549
Amortization of deferred Plant Vogtle expenses, net
(Note 3) 36,284 (30,804) 16,008
Taxes other than income taxes 192,671 179,460 172,893
Federal and state income taxes 452,122 377,542 349,284
Total operating expenses 3,479,008 3,312,174 3,359,815
OPERATING INCOME 972,173 985,262 941,613
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction 3,168 5,855 9,083
Income from subsidiary (Note 5) 4,127 4,635 4,576
Deferred return on Plant Vogtle - - 34,549
Interest income 3,806 12,475 10,563
Other, net 11,902 (30,527) 13,551
Income taxes applicable to other income 37,661 25,163 (7,522)
INCOME BEFORE INTEREST CHARGES 1,032,837 1,002,863 1,006,413
INTEREST CHARGES:
Interest on long-term debt 343,634 402,541 459,184
Allowance for debt funds used during construction (8,271) (8,310) (10,385)
Interest on interim obligations 15,530 9,694 4,906
Amortization of debt discount, premium, and expense, net 14,024 8,033 6,214
Other interest charges 47,393 12,425 9,938
Net interest charges 412,310 424,383 469,857
NET INCOME 620,527 578,480 536,556
DIVIDENDS ON PREFERRED STOCK 50,674 57,942 61,701
NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 569,853 $ 520,538 474,855
The accompanying notes are an integral part of these statements.
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BALANCE SHEETS
At December 31, 1993 and 1992
Georgia Power Company 1993 Annual Report
ASSETS 1993 1992
(in thousands)
UTILITY PLANT:
Plant in service (Note 1) $ 13,743,521 $ 13,613,361
Less accumulated provision for depreciation 3,822,344 3,569,717
9,921,177 10,043,644
Nuclear fuel, at amortized cost (Note 1) 135,742 155,194
Construction work in progress (Note 4) 584,013 405,606
Total 10,640,932 10,604,444
Less property-related accumulated deferred income taxes (Note 7) - 1,589,743
Total 10,640,932 9,014,701
OTHER PROPERTY AND INVESTMENTS:
Southern Electric Generating Company, at equity (Note 5) 29,201 30,703
Nuclear decommissioning trusts (Note 1) 37,937 20,311
Miscellaneous 31,941 24,760
Total 99,079 75,774
CURRENT ASSETS:
Cash and cash equivalents 5,896 22,114
Investment securities - 108,206
Receivables-
Customer accounts receivable 486,947 357,923
Other accounts and notes receivable 117,249 96,915
Affiliated companies 14,832 22,674
Accumulated provision for uncollectible accounts (4,300) (4,121)
Fossil fuel stock, at average cost 111,620 197,332
Materials and supplies, at average cost 287,551 284,272
Prepayments 65,269 91,447
Vacation pay deferred (Note 1) 41,575 40,169
Total 1,126,639 1,216,931
DEFERRED CHARGES:
Deferred charges related to income taxes (Note 7) 992,510 -
Deferred Plant Vogtle costs (Note 3) 506,980 383,025
Debt expense, being amortized 20,730 17,719
Premium on reacquired debt, being amortized 153,146 116,940
Miscellaneous 196,094 139,352
Total 1,869,460 657,036
TOTAL ASSETS $ 13,736,110 $ 10,964,442
The accompanying notes are an integral part of these statements.
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BALANCE SHEETS
At December 31, 1993 and 1992
Georgia Power Company 1993 Annual Report
CAPITALIZATION AND LIABILITIES 1993 1992
(in thousands)
CAPITALIZATION (SEE ACCOMPANYING STATEMENTS):
Common stock equity $ 4,045,458 $ 3,888,237
Preferred stock 692,787 692,792
Preferred stock subject to mandatory redemption - 6,250
Long-term debt 4,031,387 4,131,016
Total 8,769,632 8,718,295
CURRENT LIABILITIES:
Preferred stock due within one year (Note 8) - 63,750
Long-term debt due within one year (Note 8) 10,543 95,823
Notes payable to banks (Note 8) 406,700 400,200
Commercial paper (Note 8) 75,527 133,471
Accounts payable-
Affiliated companies 38,115 33,258
Other 285,929 284,093
Customer deposits 45,922 45,145
Taxes accrued-
Federal and state income 31,639 43,779
Other 121,854 94,510
Interest accrued 110,497 132,319
Vacation pay accrued 40,060 38,694
Miscellaneous 64,527 89,355
Total 1,231,313 1,454,397
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes (Note 7) 2,479,720 -
Accumulated deferred investment tax credits 478,334 515,539
Disallowed Plant Vogtle capacity buyback costs (Note 5) 63,067 72,201
Deferred credits related to income taxes (Note 7) 452,819 -
Miscellaneous 261,225 204,010
Total 3,735,165 791,750
COMMITMENTS AND CONTINGENT MATTERS (NOTES 2, 3, 4, 5, 6)
TOTAL CAPITALIZATION AND LIABILITIES $ 13,736,110 $ 10,964,442
The accompanying notes are an integral part of these statements.
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STATEMENTS OF CAPITALIZATION
AT December 31, 1993 and 1992
Georgia Power Company 1993 Annual Report
1993 1992 1993 1992
(in thousands) (percent of total)
COMMON STOCK EQUITY:
Common stock, without par value --
Authorized -- 15,000,000 shares
Outstanding -- 7,761,500 shares $ 344,250 $ 344,250
Paid-in capital 2,384,348 2,384,140
Premium on preferred stock 413 467
Retained earnings (Note 8) 1,316,447 1,159,380
Total common stock equity 4,045,458 3,888,237 46.1 % 44.6 %
CUMULATIVE PREFERRED STOCK, WITHOUT PAR VALUE:
Authorized -- 55,000,000 shares in 1993;
52,200,000 shares in 1992
Outstanding -- 21,027,923 shares in 1993;
$100 stated value --
4.60% to 5.64% 95,787 95,792
6.48% to 7.80% 127,000 127,000
8.20% to 9.08% - 25,000
$25 stated value --
$1.90 to $2.125 295,000 295,000
Adjustable rate -- at January 1, 1994:
4.98% 100,000 -
5.42% 75,000 -
6.57% - 50,000
7.02% - 50,000
7.57% - 50,000
Total (annual dividend requirement -- $46,851,000) 692,787 692,792 7.9 7.9
CUMULATIVE PREFERRED STOCK SUBJECT TO MANDATORY
REDEMPTION, WITHOUT PAR VALUE:
Authorized and Outstanding -- 2,800,000 shares in 1992
$25 stated value --
$2.43 - 45,000
$2.50 - 25,000
Total - 70,000
Less amount due within one year - 63,750
Total excluding amount due within one year - 6,250 - 0.1
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STATEMENTS OF CAPITALIZATION
At December 31, 1993 and 1992
Georgia Power Company 1993 Annual Report
1993 1992 1993 1992
LONG-TERM DEBT: (in thousands) (percent of total)
First mortgage bonds --
Maturity Interest Rates
October 1, 1994 4 5/8% - 28,000
September 1, 1995 4 7/8% - 36,500
September 1, 1995 5 1/8% 130,000 130,000
March 1, 1996 4 3/4% 150,000 -
July 1, 1996 5 3/4% - 45,368
September 1, 1997 6 1/2% - 50,000
April 1, 1998 5 1/2% 100,000 -
September 1, 1998 6 5/8% - 50,000
1999 through 2003 6 % to 7 7/8% 820,000 929,500
2008 6 7/8% 50,000 -
2016 through 2018 10% to 10 3/4% 69,716 663,170
2019 through 2023 7.55% to 9.23% 760,000 300,000
2020 variable rate - 50,000
2032 variable rates 200,000 200,000
Total first mortgage bonds 2,279,716 2,482,538
Pollution control obligations (Note 8) 1,661,250 1,661,290
Other long-term debt (Note 8) 135,058 117,344
Unamortized debt premium (discount), net (34,094) (34,333)
Total long-term debt (annual interest
requirement -- $320,505,000) 4,041,930 4,226,839
Less amount due within one year (Note 8) 10,543 95,823
Long-term debt excluding amount due within one year 4,031,387 4,131,016 46.0 47.4
TOTAL CAPITALIZATION $ 8,769,632 $ 8,718,295 100.0 % 100.0%
The accompanying notes are an integral part of these statements.
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STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1993, 1992, and 1991
Georgia Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 1,159,380 $ 1,038,012 $ 944,774
Net income after dividends on preferred stock 569,853 520,538 474,855
Cash dividends on common stock (402,400) (384,000) (375,200)
Preferred stock transactions, net (10,386) (15,170) (6,417)
BALANCE AT END OF PERIOD (NOTE 8) $ 1,316,447 $ 1,159,380 $ 1,038,012
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1993, 1992, and 1991
Georgia Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 2,384,140 $ 2,383,800 $ 2,383,800
Contributions to capital by parent company 208 340 -
BALANCE AT END OF PERIOD $ 2,384,348 $ 2,384,140 $ 2,383,800
The accompanying notes are an integral part of these statements.
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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1993, 1992, and 1991
Georgia Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
OPERATING ACTIVITIES:
Net income $ 620,527 $ 578,480 $ 536,556
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 475,152 471,014 480,318
Deferred income taxes and investment tax credits, net 150,735 189,251 43,695
Allowance for equity funds used during construction (3,168) (5,855) (9,083)
Deferred Plant Vogtle costs 36,284 (30,804) (18,541)
Non-cash proceeds from settlement of disputed contracts
(Note 3) - (4,982) (103,846)
Provision for separation benefits - - 52,952
Gain on asset sales (35,514) (12) (36,835)
Other, net (10,713) (9,756) (42,141)
Changes in certain current assets and liabilities --
Receivables, net 27,088 (31,348) 23,920
Inventories 82,433 (65,621) 24,130
Payables 17,364 25,303 (23,075)
Taxes accrued 15,377 (22,828) 76,932
Energy cost recovery, retail (74,260) (46,615) (4,594)
Other (35,691) (16,518) (17,561)
Net cash provided from operating activities 1,265,614 1,029,709 982,827
INVESTING ACTIVITIES:
Gross property additions (674,432) (508,444) (548,051)
Sales of property 261,687 46 291,075
Other (43,154) 42,892 931
Net cash used for investing activities (455,899) (465,506) (256,045)
FINANCING ACTIVITIES AND CAPITAL CONTRIBUTIONS:
Proceeds:
Preferred stock 175,000 195,000 100,000
First mortgage bonds 1,135,000 975,000 -
Pollution control bonds 145,425 161,955 80,420
Long-term notes 37,000 - -
Retirements:
Preferred stock (245,005) (165,004) (100,000)
First mortgage bonds (1,337,822) (1,381,300) (598,384)
Pollution control bonds (145,465) (160,205) (83,265)
Other long-term debt (19,451) (567) (1,130)
Interim obligations, net (51,444) 334,671 199,000
Payment of preferred stock dividends (53,123) (60,475) (60,766)
Payment of common stock dividends (402,400) (384,000) (375,200)
Miscellaneous (63,648) (70,986) (17,613)
Net cash used for financing activities (825,933) (555,911) (856,938)
NET CHANGE IN CASH AND CASH EQUIVALENTS (16,218) 8,292 (130,156)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 22,114 13,822 143,978
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 5,896 $ 22,114 $ 13,822
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for --
Interest (net of amount capitalized) $420,107 $435,203 $488,431
Income taxes 275,867 190,674 214,809
The accompanying notes are an integral part of these statements.
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139
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1993 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
The Company is a wholly owned subsidiary of The Southern Company, which is the
parent company of five operating companies, Southern Company Services (SCS),
Southern Electric International (Southern Electric), and Southern Nuclear
Operating Company (Southern Nuclear), and various other subsidiaries related to
foreign utility operations and domestic non-utility operations. The operating
companies (Alabama Power Company, Georgia Power Company, Gulf Power Company,
Mississippi Power Company, and Savannah Electric and Power Company) provide
electric service in four southeastern states. Intracompany contracts dealing
with jointly owned generating facilities, transmission lines and exchange of
electric power are regulated by the Federal Energy Regulatory Commission (FERC)
or the Securities and Exchange Commission. SCS provides, at cost, specialized
services to The Southern Company and each of the subsidiary companies.
Southern Electric designs, builds, owns, and operates power production
facilities and provides a broad range of technical services to industrial
companies and utilities in the United States and a number of international
markets. Southern Nuclear provides support services for nuclear power plants
in the Southern electric system.
The Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935. Both The Southern Company and its
subsidiaries are subject to the regulatory provisions of this act. The Company
is also subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows generally accepted accounting
principles and complies with the accounting policies and practices prescribed
by the respective regulatory commissions.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
REVENUES AND FUEL COSTS
The Company accrues revenues for services rendered but unbilled at the end of
each fiscal period. Fuel costs are expensed as fuel is used. The Company is
authorized by state law and FERC regulations to recover fuel costs and the fuel
component of purchased energy costs through fuel cost recovery provisions,
which are periodically adjusted to reflect increases or decreases in such
costs. Revenues are adjusted for differences between recoverable fuel costs
and amounts actually recovered in current rates. Fuel costs were under
recovered by $79 million and $4 million at December 31, 1993, and 1992,
respectively. These amounts are included in customer accounts receivable on
the balance sheets. The fuel cost recovery rate was increased effective
December 6, 1993.
The cost of nuclear fuel is amortized to fuel expense based on estimated
thermal units used to generate electric energy and includes a provision for the
disposal of spent fuel. Total charges for nuclear fuel amortized to expense
were $75 million in 1993, $84 million in 1992, and $93 million in 1991. The
Company has contracted with the U.S. Department of Energy (DOE) for permanent
disposal of spent fuel beginning in 1998; however, the actual year this service
will begin is uncertain. Pending permanent disposition of the spent fuel,
sufficient storage capacity is available at Plant Hatch into 2003 and at Plant
Vogtle into 2009. Also, the Energy Policy Act of 1992 required the
establishment in 1993 of a Uranium Enrichment Decontamination and
Decommissioning Fund which is to be funded, in part, by a special assessment on
utilities with nuclear plants. This fund will be used by the DOE for the
decontamination and decommissioning of its nuclear fuel enrichment facilities.
The law provides that utilities will recover these payments in the same manner
as any other fuel expense. The Company -- based on its ownership interest --
estimates its total assessment under this law to be approximately $42 million
to be paid over a 15-year period beginning in 1993. This obligation is
recognized in the accompanying Balance Sheets and is being recovered through
the fuel cost recovery provisions. The remaining liability at December 31,
1993, is $39 million.
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NOTES (continued)
Georgia Power Company 1993 Annual Report
NUCLEAR REFUELING OUTAGE COSTS
Prior to 1992, the Company expensed nuclear refueling outage costs as incurred
during the outage period. Pursuant to the 1991 GPSC retail rate order, the
Company began accounting for these costs on a normalized basis in 1992. Under
this method of accounting, refueling outage costs are deferred and subsequently
amortized to expense over the operating cycle of each unit, which is normally
18 months. Deferred nuclear outage costs were $17 million and $6 million at
December 31, 1993 and 1992, respectively.
DEPRECIATION
Depreciation is provided on the cost of depreciable utility plant in service
and is calculated primarily on the straight-line basis over the estimated
composite service life of the property. The composite rate of depreciation was
3.1 percent in 1993 and 1992, and 3.2 percent in 1991. Effective October 1991,
the Company adopted lower depreciation rates consistent with the 1991 GPSC
retail rate order. When a property unit is retired or otherwise disposed of in
the normal course of business, its costs and the costs of removal, less
salvage, are charged to the accumulated provision for depreciation. Minor
items of property included in the cost of the plant are retired when the
related property unit is retired.
NUCLEAR DECOMMISSIONING
In 1988, the Nuclear Regulatory Commission (NRC) adopted regulations requiring
all licensees operating commercial nuclear power reactors to establish a plan
for providing, with reasonable assurance, funds for decommissioning.
Reasonable assurance may be in the form of an external sinking fund, a surety
method, or prepayment. The Company has established external trust funds to
comply with the NRC's regulations. Prior to the enactment of these
regulations, the Company had internally reserved nuclear decommissioning costs.
The NRC's minimum external funding requirements are based on a generic estimate
of the cost to decommission the radioactive portions of a nuclear unit based on
the size and type of reactor.
The estimated cost of decommissioning and the amounts being recovered through
rates at December 31, 1993, for the Company's ownership interest in plants
Hatch and Vogtle were as follows:
Plant Plant
Hatch Vogtle
Site study basis (year) 1990 1990
Estimated completion of
decommissioning (year) 2027 2037
Cost of decommissioning: (in millions)
Radiated structures $184 $155
Non-radiated structures 35 62
Contingency 55 54
Total costs $274 $271
(in millions)
Approved for ratemaking $184 $155
Amount expensed in 1993 $ 6 $ 6
Balance in external trust fund $ 22 $ 16
Balance in internal reserve $ 33 $ 11
The amounts in the internal reserve are being transferred into the external
trust fund over a period of approximately nine years as approved by the GPSC in
its 1991 retail rate order.
The estimates approved by the GPSC for ratemaking exclude costs of
non-radiated structures and site contingency costs. The actual decommissioning
cost may vary from the above estimates because of regulatory requirements,
changes in technology, and increased costs of labor, materials, and equipment.
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The Company expects the GPSC to
periodically review and adjust, if necessary, the amounts collected in rates
for the anticipated cost of decommissioning.
PLANT VOGTLE PHASE-IN PLANS
In 1987 and 1989, the GPSC ordered that the costs of Plant Vogtle Units 1 and 2
be phased into rates under plans that meet the requirements of Financial
Accounting Standards Board (FASB) Statement No. 92, Accounting for Phase-In
Plans. In 1991, the GPSC modified the phase-in plans. In addition, the
Company deferred certain Plant Vogtle operating expenses and financing costs
under accounting orders issued by the GPSC. See Note 3 for further
information.
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NOTES (continued)
Georgia Power Company 1993 Annual Report
INCOME TAXES
The Company provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
In years prior to 1993, income taxes were accounted for and reported under
Accounting Principles Board Opinion No. 11. Effective January 1, 1993, the
Company adopted FASB Statement No. 109, Accounting for Income Taxes. See Note
7 to the financial statements for further information.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) AND DEFERRED RETURN
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. For the years 1993, 1992 and 1991, the average AFUDC
rates were 4.87 percent, 7.16 percent and 9.90 percent, respectively. The
reduction in the average AFUDC rate since 1991 reflects the Company's greater
use of lower cost short-term debt.
The Company also imputed a return on its investment in Plant Vogtle Units 1
and 2 after they began commercial operation, under short-term cost deferrals
and phase-in plans as described in Note 3. AFUDC and the Vogtle deferred
returns, net of taxes, as a percentage of net income after dividends on
preferred stock, amounted to 1.4 percent, 2.1 percent and 9.2 percent for 1993,
1992 and 1991, respectively.
UTILITY PLANT
Utility plant is stated at original cost with the exception of Plant Vogtle,
which is stated at cost less regulatory disallowances. Original cost includes
materials; labor; appropriate administrative and general costs; payroll-related
costs such as taxes, pensions, and other benefits; and the estimated cost of
funds used during construction.
CASH AND CASH EQUIVALENTS
For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
FINANCIAL INSTRUMENTS
All financial instruments of the Company -- for which the carrying amount does
not approximate fair value -- are shown in the table below at December 31:
1993
Carrying Fair
Amount Value
(in millions)
Nuclear decommissioning trusts $ 38 $ 40
Long-term debt 3,954 4,197
1992
Carrying Fair
Amount Value
(in millions)
Nuclear decommissioning trusts $ 20 $ 21
Investment securities 108 121
Long-term debt 4,130 4,404
Preferred stock subject to
mandatory redemption 70 76
The fair values of nuclear decommissioning trusts and investment securities
were based on listed closing market prices. The fair values for long-term debt
and preferred stock subject to mandatory redemption were based on either
closing market prices or closing prices of comparable instruments.
MATERIALS AND SUPPLIES
Generally, materials and supplies include the cost of transmission,
distribution and generating plant materials. Materials are charged to
inventory when purchased and then expensed or capitalized to plant, as
appropriate, when installed. In December 1992, the Company converted to the
inventory method of accounting for certain emergency spare parts. This
conversion resulted in a regulatory liability that is being amortized as
credits to income over
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NOTES (continued)
Georgia Power Company 1993 Annual Report
approximately four years. This conversion will not have a material effect on
income in any year.
VACATION PAY
Company employees earn vacation in one year and take it in the subsequent year.
However, for ratemaking purposes, vacation pay is recognized as an allowable
expense only when paid. Consistent with this ratemaking treatment, the Company
accrues a current liability for earned vacation pay and records a current asset
representing the future recoverability of this cost. This amount was $42
million at December 31, 1993, and $40 million at December 31, 1992. In 1994,
approximately 72 percent of the 1993 deferred vacation costs will be expensed,
and the balance will be charged to construction and other accounts.
2. RETIREMENT BENEFITS
PENSION PLAN
The Company has a defined benefit, trusteed, non-contributory pension plan
covering substantially all regular employees. Benefits are based on the
greater of amounts resulting from two different formulas: years of service and
final average pay or years of service and a flat dollar benefit. The Company
uses the "entry age normal method with a frozen initial liability" actuarial
method for funding purposes, subject to limitations under federal income tax
regulations. Amounts funded to the pension fund are primarily invested in
equity and fixed-income securities. FASB Statement No. 87, Employers'
Accounting for Pensions, requires use of the projected unit credit actuarial
method for financial reporting purposes.
POSTRETIREMENT BENEFITS
The Company also provides certain medical care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits when they retire. For medical care benefits, a qualified trust has
been established for funding amounts to the extent deductible under federal
income tax regulations. Amounts funded are primarily invested in debt and
equity securities. Accrued costs of life insurance benefits, other than
current cash payments for retirees, currently are not being funded.
Effective January 1, 1993, the Company adopted FASB Statement No. 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions, on a
prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service."
In October 1993, the GPSC ordered the Company to phase in the adoption of
Statement No. 106 to cost of service over a five-year period, whereby one-fifth
of the additional expense was recognized -- approximately $6 million -- in 1993
and the remaining additional expense was deferred. An additional one-fifth of
the costs will be expensed each succeeding year until the costs are fully
reflected in cost of service in 1997. The cost deferred during the five-year
period will be amortized to expense over a 15-year period beginning in 1998.
As a result of the regulatory treatment allowed by the GPSC, the adoption of
Statement No. 106 did not have a material impact on net income.
Prior to 1993, the Company recognized these cost on a cash basis as payments
were made. The total costs of such benefits recognized by the Company in 1993,
1992, and 1991 were $56 million, $13 million, and $9 million, respectively.
STATUS AND COST OF BENEFITS
Shown in the following tables are actuarial results and assumptions for pension
and postretirement medical and life insurance benefits as computed under the
requirements of Statement Nos. 87 and 106, respectively. Retiree medical and
life insurance information is shown only for 1993 because Statement No. 106
was adopted as
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NOTES (continued)
Georgia Power Company 1993 Annual Report
of January 1, 1993, on a prospective basis. The funded status of the plans at
December 31 was as follows:
Pension
1993 1992
(in millions)
Actuarial present value of
benefit obligations:
Vested benefits $ 655 $ 557
Non-vested benefits 35 26
Accumulated benefit obligation 690 583
Additional amounts related
to projected salary increases 257 293
Projected benefit obligation 947 876
Less:
Fair value of plan assets 1,495 1,341
Unrecognized net gain (490) (413)
Unrecognized prior service cost 31 33
Unrecognized transition asset (62) (67)
Prepaid asset recognized in the Balance
Sheets $ 27 $ 18
Postretirement
Medical Life
1993
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $136 $32
Employees eligible to retire 12 -
Other employees 206 40
Accumulated benefit obligation 354 72
Less:
Fair value of plan assets 30 1
Unrecognized net loss (gain) 40 (6)
Unrecognized transition
obligation 251 69
Accrued liability recognized in the
Balance Sheets $ 33 $ 8
Weighted average rates used in actuarial calculations:
1993 1992 1991
Discount 7.5% 8.0% 8.0%
Annual salary increase 5.0 6.0 6.0
Long-term return on plan
assets 8.5 8.5 8.5
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend rate
of 11.3 percent for 1993, decreasing gradually to 6.0 percent through the year
2000 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate by 1.0 percent would increase the accumulated
medical benefit obligation as of December 31, 1993, by $68 million and the
aggregate of the service and interest cost components of the net retiree
medical cost by $7 million.
The components of the plans' net costs are shown below:
Pension
1993 1992 1991
(in millions)
Benefits earned during the $ 33 $ 34 $ 32
year
Interest cost on projected
benefit obligation 69 65 61
Actual return on plan assets (194) (61) (334)
Net amortization and deferral 84 (38) 247
Net pension cost (income) $ (8) $ - $ 6
Of net pension costs (income) recorded, $(6) million in 1993 and $5 million
in 1991, were recorded to operating expense, with the balance being recorded to
construction and other accounts.
Postretirement
Medical Life
1993
(in millions)
Benefits earned during the year $11 $ 3
Interest cost on accumulated
benefit obligation 23 6
Amortization of transition
obligation over 20 years 12 3
Actual return on plan assets (4) -
Net amortization and deferral 2 -
Net postretirement cost $44 $12
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Of the above net postretirement medical and life insurance costs recorded
in 1993, $21 million was charged to operating expenses, $21 million was
deferred, and the remainder was charged to construction and other accounts.
3. LITIGATION AND REGULATORY MATTERS
DEMAND-SIDE CONSERVATION PROGRAMS
In October 1993, a Superior Court of Fulton County, Georgia, judge ruled that
rate riders previously approved by the GPSC for recovery of the Company's costs
incurred in connection with demand-side conservation programs were unlawful.
The judge held that the GPSC lacked statutory authority to approve such rate
riders except through general rate case proceedings and that those procedures
had not been followed. The Company has suspended collection of the demand-side
conservation costs and appealed the court's decision to the Georgia Court of
Appeals. In December 1993, the GPSC approved the Company's request for an
accounting order allowing the Company to defer all current unrecovered and
future costs related to these programs until the court's decision is reversed
or until the next general rate case proceeding. An association of industrial
customers has filed a petition for review of such accounting order in the
Superior Court of Fulton County, Georgia. The Company's costs related to these
conservation programs through 1993 were $60 million of which $15 million has
been collected and the remainder deferred. The estimated costs, assuming no
change in the programs certified by the GPSC, are $38 million in 1994 and $40
million in 1995.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on these financial statements.
RETAIL RATEPAYERS' SUIT CONCLUDED
In March 1993, several retail ratepayers of Georgia Power filed a civil
complaint in the Superior Court of Fulton County, Georgia, against Georgia
Power, The Southern Company, the system service company, and Arthur Andersen &
Co. The complaint alleged that Georgia Power obtained excessive rate increases
by improper accounting for spare parts and sought actual damages estimated by
the plaintiffs to be in excess of $60 million -- plus treble and punitive
damages -- for alleged violations of the Georgia Racketeer Influenced and
Corrupt Organizations Act and other state statutes, statutory and common law
fraud, and negligence. These state law allegations were substantially the same
as those included in a 1989 suit brought in federal district court in Georgia.
That suit and similar ones filed in Alabama, Florida, and Mississippi federal
courts were subsequently dismissed.
The defendants' motions to dismiss the current complaint were granted by the
Superior Court of Fulton County, Georgia, in July 1993. In January 1994, the
plaintiffs' appeal of the dismissal to the Supreme Court of Georgia was
rejected. This matter is now concluded.
GULF STATES SETTLEMENT
On November 7, 1991, subsidiaries of The Southern Company entered into a
settlement agreement with Gulf States that resolved litigation between the
companies that had been pending since 1986 and arose out of a dispute over
certain unit power and long-term power sales contracts. In 1993, all remaining
terms and obligations of the settlement agreement were satisfied.
Based on the value of the settlement proceeds received, the Company recorded
increases of $3 million in 1992 and $89 million in 1991 net income.
FERC REVIEW OF EQUITY RETURNS
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the Southern electric system's wholesale rate schedules and
contracts that have a return on common equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power, and other similar contracts.
Any changes in the rate of return on common equity that may occur as a result
of this proceeding would be effective 60 days after a proper notice of the
proceeding is published. A notice was published on May 10, 1991.
In August 1992, a FERC administrative law judge issued an opinion that
changes in rate schedules and contracts were not necessary and that the FERC
staff failed to show how any changes were in the public interest. The FERC
staff has filed exceptions to the administrative law judge's opinion, and the
matter remains pending before the FERC.
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Georgia Power Company 1993 Annual Report
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the Company's financial statements.
PLANT VOGTLE PHASE-IN PLANS
Pursuant to orders from the GPSC, the Company recorded a deferred return under
phase-in plans for Plant Vogtle Units 1 and 2 until October 1991 when the
allowed investment was fully reflected in rates. In addition, the GPSC issued
two separate accounting orders that required the Company to defer substantially
all operating and financing costs related to both units until rate orders
addressed these costs. These GPSC orders provide for the recovery of deferred
costs within 10 years. The GPSC modified the phase-in plans in 1991 to
accelerate the recognition of costs previously deferred under the Plant Vogtle
Unit 2 phase-in plan and to levelize the remaining Plant Vogtle declining
capacity buyback expenses.
Under these orders, the Company has deferred and begun amortizing these costs
(as recovered through rates) as follows:
1993 1992 1991
(in millions)
Deferred expenses:
Capacity buybacks $(38) $(100) $(30)
Other operating - - (7)
Amortization of previously
deferred return and
expenses 74 69 53
Deferred expenses, net 36 (31) 16
Deferred return - - 35
Less income taxes - 23 8
Net (deferral) amortization 36 (8) (11)
Effect of adoption of FASB
Statement No. 109 160 - -
Deferred costs
at beginning of year 383 375 364
Deferred costs
at end of year $507 $ 383 $375
NUCLEAR PERFORMANCE STANDARDS
In October 1989, the GPSC adopted a nuclear performance standard for the
Company's nuclear generating units under which the performance of plants Hatch
and Vogtle will be evaluated every three years. The performance standard is
based on each unit's capacity factor as compared to the average of all U.S.
nuclear units operating at a capacity factor of 50% or higher during the
three-year period of evaluation. Depending on the performance of the units,
the Company could receive a monetary reward or penalty under the performance
standards criteria. The first evaluation was conducted in 1993 for performance
during the 1990-92 period. During this three-year period, the Company's units
performed at an average capacity factor of 81 percent compared to an industry
average of approximately 73 percent. Based on these results, the GPSC approved
a performance reward of approximately $8.5 million for the Company. This
reward is being collected through the retail fuel cost recovery provision and
recognized in income over a 36- month period beginning November, 1993.
4. COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program and currently
estimates property additions to be approximately $688 million in 1994, $555
million in 1995 and $629 million in 1996. These estimated additions include
AFUDC of $19 million in 1994, $27 million in 1995, and $18 million in 1996.
The estimates for property additions for the three-year period include $88
million committed to meeting the requirements of the Clean Air Act.
While the Company has no new baseload generating plants under construction,
the construction of nine combustion turbine peaking units is planned to be
completed by 1996. In addition, significant construction of transmission and
distribution facilities, and upgrading and extending the useful life of
generating plants will continue. The construction program is subject to
periodic review and revision, and actual construction costs may vary from
estimates because of numerous factors, including, but not limited to, changes
in business conditions, load growth estimates, environmental regulations, and
regulatory requirements.
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Georgia Power Company 1993 Annual Report
FUEL COMMITMENTS
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels and other financial commitments.
Total estimated long-term obligations were approximately $4.8 billion at
December 31, 1993. Additional commitments for coal and for nuclear fuel will
be required in the future to supply the Company's fuel needs.
OPERATING LEASES
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. Rental expense totaled $8 million, $7 million, and $5
million for 1993, 1992, and 1991, respectively. Minimum annual rental
commitments for noncancellable rail car leases are $9 million annually for
years 1994 through 1998, and total approximately $191 million thereafter.
ROCKY MOUNTAIN PROJECT STATUS
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric project in 1991 as then planned was not
economically justifiable and reasonable and withheld authorization for the
Company to spend funds from approved securities issuances on that project. In
1988, the Company and Oglethorpe Power Corporation (OPC) entered into a joint
ownership agreement for OPC to assume responsibility for the construction and
operation of the project, as discussed in Note 5. The joint ownership
agreement significantly reduces the risk of the project being canceled.
However, full recovery of the Company's costs depends on the GPSC's treatment
of the project's cost and disposition of the project's capacity output. In the
event the Company cannot demonstrate to the GPSC the project's economic
viability based on current ownership, construction schedule, and costs, then
part or all of such costs may have to be written off in accordance with FASB
Statement No. 90, Accounting for Abandonments and Disallowed Plant Costs. At
December 31, 1993, the Company's investment in the project amounted to
approximately $197 million. AFUDC accrued on the Rocky Mountain project has not
been credited to income or included in the project cost since December 1985.
If accrual of AFUDC is not resumed, the Company's portion of the estimated
total plant additions at completion would be approximately $199 million. The
plant is currently scheduled to begin commercial operation in 1995.
The Company has held preliminary discussions with other parties regarding the
potential disposition of its remaining interest in the project.
The ultimate outcome of this matter cannot now be determined.
NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at the
Company's nuclear power plants. The act limits to $9.4 billion public
liability claims that could arise from a single nuclear incident. Each nuclear
plant is insured against this liability to a maximum of $200 million by private
insurance, with the remaining coverage provided by a mandatory program of
deferred premiums that could be assessed, after a nuclear incident, against all
owners of nuclear reactors. A company could be assessed up to $79 million per
incident for each licensed reactor it operates but not more than an aggregate
of $10 million per incident to be paid in a calendar year for each reactor.
Such maximum assessment for the Company -- based on its ownership and buyback
interests -- is $171 million per incident but not more than an aggregate of $22
million to be paid for each incident in any one year.
The Company is a member of Nuclear Mutual Limited (NML), a mutual insurer
established to provide property damage insurance in an amount up to $500
million for members' nuclear generating facilities. The members are subject to
a retrospective premium adjustment in the event that losses exceed accumulated
reserve funds. The Company's maximum assessment per incident is limited to $18
million under current policies.
Additionally, the Company has policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million NML
coverage. This excess insurance is provided by Nuclear Electric
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Georgia Power Company 1993 Annual Report
Insurance Limited (NEIL), a mutual insurance company, and American Nuclear
Insurers/Mutual Atomic Energy Liability Underwriters.
NEIL also covers the additional costs that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can be insured against increased costs of replacement power in
an amount up to $3.5 million per week -- starting 21 weeks after the outage --
for one year and up to $2.3 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if losses
each year exceed the accumulated funds available to the insurer under that
policy. The maximum assessments per incident under the current policies for
the Company would be $15 million for excess property damage and $13 million for
replacement power.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies issued or
renewed on or after April 2, 1991, shall be dedicated first for the sole
purpose of placing the reactor in a safe and stable condition after an
accident. Any remaining proceeds are to be applied next toward the costs of
decontamination and debris removal operations ordered by the NRC, and any
further remaining proceeds are to be paid either to the Company or to its bond
trustees as may be appropriate under the policies and applicable trust
indentures.
The Company participates in an insurance program for nuclear workers that
provides coverage for worker tort claims filed for bodily injury caused at
commercial nuclear power plants. In the event that claims for this insurance
exceed the accumulated reserve funds, the Company could be subject to a maximum
total assessment of $7 million.
5. FACILITY SALES AND JOINT OWNERSHIP AGREEMENTS
Since 1975, the Company has sold undivided interests in plants Hatch, Wansley,
Vogtle, and Scherer Units 1 and 2, together with transmission facilities, to
OPC, an electric membership generation and transmission corporation; the
Municipal Electric Authority of Georgia (MEAG), a public corporation and an
instrumentality of the state of Georgia; and the City of Dalton, Georgia. The
Company has sold an interest in Plant Scherer Unit 3 to Gulf Power, an
affiliate.
Additionally, the Company has completed two of four separate transactions to
sell Unit 4 of Plant Scherer to Florida Power & Light Company (FPL) and
Jacksonville Electric Authority (JEA) for a total price of approximately $806
million, including any gains on these transactions. FPL will eventually own
approximately 76.4 percent of the unit, with JEA owning the remainder. Georgia
Power will continue to operate the unit.
The completed and scheduled remaining transactions are as follows:
Closing Percent After-Tax
Date Capacity Ownership Amount Gain
(in megawatts) (in millions)
July 1991 290 35.46% $291 $14
June 1993 258 31.44 253 18
June 1994 135 16.55 132 10
June 1995 135 16.55 130 10
Total 818 100.00% $806 $52
Except as otherwise noted, the Company has contracted to operate and maintain
all jointly owned facilities. The Company includes its proportionate share of
plant operating expenses in the corresponding operating expenses in the
Statements of Income.
As discussed in Note 4, the Company and OPC have a joint ownership
arrangement for the Rocky Mountain pumped storage hydroelectric project under
which the Company will retain its present investment in the project and OPC
will finance and complete the remainder of the project and operate the
completed facility. Based on current cost estimates the Company's ownership
will be approximately 25% of the project (194 megawatts of capacity) at
completion.
The Company will own six of eight 80 megawatt combustion turbine generating
units and 75% of the related common facilities being jointly constructed with
Savannah Electric, an affiliate. The Company's investment in the project at
December 31, 1993, was $100 million and is expected to total approximately $182
million when the project is completed. All units are
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Georgia Power Company 1993 Annual Report
expected to be completed by June, 1995. Savannah Electric will operate these
units.
In connection with the joint ownership arrangements for plants Vogtle and
Scherer, the Company has made commitments to purchase declining fractions of
OPC's and MEAG's capacity and energy from these units. These commitments are
in effect during periods of up to 10 years following commercial operation (and
with regard to a portion of a 5 percent interest in Plant Vogtle owned by MEAG,
until the latter of the retirement of the plant or the latest stated maturity
date of MEAG's bonds issued to finance such ownership interest). The payments
for capacity are required whether or not any capacity is available. The energy
cost is a function of each unit's variable operating costs. Except as noted
below, the cost of such capacity and energy is included in purchased power from
non-affiliates in the Company's Statements of Income. Capacity payments
totaled $183 million, $289 million and $320 million in 1993, 1992 and 1991,
respectively. The Plant Scherer buyback agreements ended in 1993. The current
projected Plant Vogtle capacity payments for the next five years are as
follows: $132 million in 1994, $77 million in 1995, $70 million in 1996, $59
million in 1997 and $59 million in 1998. Portions of the payments noted above
relate to costs in excess of Plant Vogtle's allowed investment for ratemaking
purposes. The present value of these portions was written off in 1987 and
1990. Additionally, the Plant Vogtle declining capacity buyback expense is
being levelized over a six-year period. See Note 3 for further information.
At December 31, 1993, the Company's percentage ownership and investment
(exclusive of nuclear fuel) in jointly owned facilities in commercial
operation, were as follows:
Total Company
Facility (Type) Capacity Ownership
(megawatts)
Plant Vogtle (nuclear) 2,320 45.7%
Plant Hatch (nuclear) 1,630 50.1
Plant Wansley (coal) 1,779 53.5
Plant Scherer (coal)
Units 1 and 2 1,636 8.4
Unit 3 818 75.0
Unit 4 818 33.1
Accumulated
Facility (Type) Investment Depreciation
(in millions)
Plant Vogtle (nuclear) $3,285 (1) $540
Plant Hatch (nuclear) 840 325
Plant Wansley (coal) 286 125
Plant Scherer (coal)
Units 1 and 2 111 33
Unit 3 539 107
Unit 4 236 31
(1) Investment net of write-offs.
The Company and an affiliate, Alabama Power, own equally all of the
outstanding capital stock of Southern Electric Generating Company (SEGCO),
which owns electric generating units with a total rated capacity of 1,020
megawatts, as well as associated transmission facilities. The capacity of the
units has been sold equally to the Company and Alabama Power under a contract
expiring in 1994, which, in substance, requires payments sufficient to provide
for the operating expenses, taxes, debt service and return on investment,
whether or not SEGCO has any capacity and energy available. An amended
contract has been filed with the FERC with substantially the same provisions,
but the term thereof would be extended automatically for two year periods,
subject to any party's right to cancel upon two year's notice. The Company's
share of expenses included in purchased power from affiliates in the Statements
of
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Georgia Power Company 1993 Annual Report
Income, is as follows:
1993 1992 1991
(in millions)
Energy $ 81 $ 66 $ 74
Capacity 9 9 10
Total $ 90 $ 75 $ 84
Kilowatt-hours 3,352 2,664 2,911
At December 31, 1993, the capitalization of SEGCO consisted of $58 million of
equity and $84 million of long-term debt on which the annual interest
requirement is $3.8 million.
6. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating affiliates of The Southern Company have entered
into long-term contractual agreements for the sale of capacity and energy to
certain non-affiliated utilities located outside the system's service
territory. Certain of these agreements are non-firm and are based on the
capacity of the Southern system. Other agreements are firm and pertain to
capacity related to specific generating units. Because energy is generally
sold at cost under these agreements, it is primarily the capacity revenues that
affect the Company's profitability. The capacity revenues have been as
follows:
Unit Power Other
Year Sales Long-Term
(in millions)
1993 $135 $17
1992 223 10
1991 263 11
Long-term non-firm power of 400 megawatts was sold by the Southern electric
system in 1993 to Florida Power Corporation (FPC). This amount decreases to
200 megawatts in 1994 and the contract expires at year-end. Sales under these
long-term non-firm power sales agreements are made from available power pool
energy, and the revenues from the sales are shared by the operating affiliates.
Unit power from specific generating plants is being sold to FPL, JEA, and the
City of Tallahassee, Florida and beginning in 1994 to FPC. Under these
agreements, the Company sold approximately 830 megawatts of capacity in 1993
and is scheduled to sell approximately 403 megawatts of capacity in 1994.
Thereafter, these sales will decline to an estimated 157 megawatts by the end
of 1996 and will remain at that approximate level through 1999. After 2000,
capacity sales will decline to approximately 101 megawatts -- unless reduced by
FPL and JEA -- until the expiration of the contracts in 2010.
7. INCOME TAXES
Effective January 1, 1993, the Company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption of Statement No. 109 resulted in
cumulative adjustments that had no material effect on net income. The adoption
also resulted in the recording of additional deferred income taxes and related
assets and liabilities. The related assets of $993 million are revenues to be
received from customers. These assets are attributable to tax benefits
flowed-through to customers in prior years, and taxes applicable to
capitalized AFUDC. The related liabilities of $453 million are revenues to be
refunded to customers. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits. Additionally, deferred income taxes
related to accelerated tax depreciation previously shown as a reduction to
utility plant were reclassified.
Details of the federal and state income tax provisions are as follows:
1993 1992 1991
Total provision for income taxes: (in millions)
Federal:
Currently payable $223 $139 $267
Deferred -
Current year 181 170 97
Reversal of prior years (40) (6) (52)
Deferred investment tax
credits (18) (6) (10)
346 297 302
State:
Currently payable 41 24 47
Deferred -
Current year 31 35 17
Reversal of prior years (3) (3) (9)
69 56 55
Total 415 353 357
Less:
Income taxes charged
(credited) to other
income (37) (25) 8
Federal and state income
taxes charged to operations $452 $378 $349
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Georgia Power Company 1993 Annual Report
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
basis, which give rise to deferred tax assets and liabilities are as follows:
1993
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,458
Property basis differences 1,163
Deferred Plant Vogtle costs 161
Premium on reacquired debt 63
Fuel clause underrecovered 32
Other 62
Total 2,939
Deferred tax assets:
Other basis differences 263
Federal effect of state deferred taxes 92
Other deferred costs 61
Disallowed plant buybacks 29
Accrued interest 24
Other 12
Total 481
Net deferred tax liabilities (assets) 2,458
Portion included in current assets (22)
Accumulated deferred income taxes
in the Balance Sheets $2,480
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $19 million in 1993, $19 million in 1992, and $27 million in 1991.
At December 31, 1993, all investment tax credits available to reduce federal
income taxes payable had been utilized.
A reconciliation of the federal statutory tax rate to effective income tax
rate is as follows:
1993 1992 1991
Federal statutory rate 35% 34% 34%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 3 3 4
Difference in prior years'
deferred and current tax rate (1) (1) (1)
Other (1) (2) (1)
Effective income tax rate 40% 38% 40%
The Southern Company and its subsidiaries file a consolidated federal income
tax return. Under a joint consolidated income tax agreement, each company's
current and deferred tax expense is computed on a stand-alone basis, and
consolidated tax savings are allocated to each company based on its ratio of
taxable income to total consolidated taxable income.
8. CAPITALIZATION
COMMON STOCK DIVIDEND RESTRICTIONS
The Company's first mortgage bond indenture contains various common stock
dividend restrictions that remain in effect as long as the bonds are
outstanding. At December 31, 1993, $742 million of retained earnings were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture. Supplemental indentures in connection with future
first mortgage bond issues may contain more stringent common stock dividend
restrictions than those currently in effect.
The Company's charter limits cash dividends on common stock to the lesser of
the retained earnings balance or 75 percent of net income available for such
stock during a prior period of 12 months if the ratio of common stock equity to
total capitalization, including retained earnings, adjusted to reflect the
payment of the proposed dividend, is below 25 percent, and to 50 percent of
such net income if such ratio is less than 20 percent. At December 31, 1993,
the ratio as defined was 46.1 percent.
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REMARKETED BONDS
In 1992, the Company issued two series of variable rate first mortgage bonds
each with principal amounts of $100 million due 2032. The current composite
interest rate on the bonds is 6.20 percent and is fixed for the first three
years of the issues.
POLLUTION CONTROL BONDS
The Company has incurred obligations in connection with the sale by public
authorities of tax-exempt pollution control and industrial development revenue
bonds. The Company has authenticated and delivered to trustees an aggregate of
$407.7 million of its first mortgage bonds, which are pledged as security for
its obligations under pollution control and industrial development contracts.
No interest on these first mortgage bonds is payable unless and until a default
occurs on the installment purchase or loan agreements. An aggregate of
approximately $1.3 billion of the pollution control and industrial development
bonds is secured by a subordinated interest in specific property of the
Company.
Details of pollution control bonds are as follows:
Maturity Interest Rates 1993 1992
(in millions)
2003-2007 5.70% to 6.75% $ 90 $ 103
2008-2011 6.375% & Variable 19 32
2014-2018 6.00% to 12.25% 1,237 1,283
2019-2023 5.75% to 7.25% &
Variable 315 243
Total pollution control bonds $ 1,661 $ 1,661
BANK CREDIT ARRANGEMENTS
At the beginning of 1994, the Company had unused credit arrangements with banks
totaling $540 million, of which $10 million expires June 30, 1994, $130
million expires at May 1, 1996, and $400 million expires at June 30, 1996.
The $400 million expiring June 30, 1996, is under revolving credit
arrangements with several banks providing the Company, Alabama Power, and The
Southern Company up to a total credit amount of $400 million. To provide
liquidity support for commercial paper programs and for other short-term cash
needs, $165 million and $135 million of the $400 million available credit are
currently dedicated for the Company and Alabama Power, respectively. However,
the allocations can be changed among the borrowers by notifying the respective
banks.
During the term of the agreements expiring in 1996, short-term borrowings may
be converted into term loans, payable in 12 equal quarterly installments, with
the first installment due at the end of the first calendar quarter after the
applicable termination date or at an earlier date at the companies' option. In
addition, these agreements require payment of commitment fees based on the
unused portions of the commitments or the maintenance of compensating balances
with the banks.
The $10 million credit arrangement expiring in 1994 allows borrowings for up
to 90 days. Commitment fees are based on the unused portion of the commitment.
In addition, the Company borrows under uncommitted lines of credit with banks
and through a $150 million commercial paper program that has the liquidity
support of committed bank credit arrangements. Average compensating balances
held under these committed facilities were not material in 1993.
OTHER LONG-TERM DEBT
Assets acquired under capital leases are recorded in the Balance Sheets as
utility plant in service, and the related obligations are classified as
long-term debt. At December 31, 1993, the Company had a capitalized lease
obligation for its corporate headquarters building of $88 million with an
interest rate of 8.1 percent. Other capitalized lease obligations were $137
thousand with a composite interest rate of 6.8 percent.
The maturities of capital lease obligations through 1998 are approximately as
follows: $423 thousand in 1994, $309 thousand in 1995, $335 thousand in 1996,
$362 thousand in 1997, and $392 thousand in 1998.
The lease agreement for the corporate headquarters building provides for
payments that are minimal in early years and escalate through the first 21
years of the lease. For ratemaking purposes, the GPSC has treated the lease as
an operating lease and has allowed only the lease
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payments in cost of service. The difference between the accrued expense and
the lease payments allowed for ratemaking purposes is being deferred as a cost
to be recovered in the future as ordered by the GPSC. At December 31, 1993,
and 1992, the interest and lease amortization deferred on the Balance Sheets
are $47 million and $48 million, respectively.
In December 1993, the Company borrowed $37 million through a long-term note
due in 1995.
ASSETS SUBJECT TO LIEN
The Company's mortgage dated as of March 1, 1941, as amended and supplemented,
securing the first mortgage bonds issued by the Company, constitutes a direct
lien on substantially all of the Company's fixed property and franchises.
LONG-TERM DEBT DUE WITHIN ONE YEAR
The current portion of the Company's long-term debt is as follows:
1993 1992
(in millions)
First mortgage bonds:
Redemption of 10.75% issue due 2018 $ - $3.7
Redemption of variable rate issue due
2020 - 50.0
Improvement fund requirement - 30.4
Pollution control bonds
5.95% series sinking fund requirement - 0.3
6.4% series sinking fund requirement * 0.2
6.75% series sinking fund requirement * -
6.375% series sinking fund requirement * -
Other long-term debt 10.5 11.2
Total $10.5 $95.8
*Less than .1 million
The indenture's first mortgage bond improvement fund requirement amounts to 1
percent of each outstanding series of bonds authenticated under the indenture
prior to January 1 of each year, other than those issued to collateralize
pollution control obligations. The requirement may be satisfied by depositing
cash or reacquired bonds, or by pledging additional property equal to 1 2/3
times the requirement. The 1993 and 1992 requirements were met in the first
quarter of each year by depositing cash subsequently used to redeem bonds. The
1994 requirement was funded in December 1993.
REDEMPTION OF HIGH-COST SECURITIES
The Company plans to continue a program of redeeming or replacing high-cost
debt and preferred stock in cases where opportunities exist to reduce financing
costs. High-cost issues may be repurchased in the open market or called at
premiums as specified under terms of the issue. They may also be redeemed at
face value to meet improvement fund and sinking fund requirements, to meet
replacement provisions of the mortgage, or by use of proceeds from the sale of
property pledged under the mortgage. In general, for the first five years a
series is outstanding the Company is prohibited from redeeming for improvement
fund purposes more than 1 percent annually of the original issue amount.
9. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial information for 1993 and 1992 is as follows:
Net Income
After
Dividends on
Operating Operating Preferred
Quarter Ended Revenues Income Stock
(in millions)
MARCH 1993 $1,004 $221 $108
JUNE 1993 1,096 219 141
SEPTEMBER 1993 1,376 356 245
DECEMBER 1993 975 176 76
March 1992 $ 957 $211 $ 91
June 1992 1,068 235 116
September 1992 1,280 342 227
December 1992 992 197 87
The Company's business is influenced by seasonal weather conditions and the
timing of rate increases.
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153
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1993 Annual Report
1993 1992 1991
OPERATING REVENUES (IN THOUSANDS) $ 4,451,181 $ 4,297,436 $ 4,301,428
NET INCOME AFTER DIVIDENDS
ON PREFERRED STOCK (IN THOUSANDS) $ 569,853 $ 520,538 $ 474,855
CASH DIVIDENDS ON COMMON STOCK (IN THOUSANDS) $ 402,400 $ 384,000 $ 375,200
RETURN ON AVERAGE COMMON EQUITY (PERCENT) 14.37 13.60 12.76
TOTAL ASSETS (IN THOUSANDS) $13,736,110 $10,964,442 $10,842,538
GROSS PROPERTY ADDITIONS (IN THOUSANDS) $ 674,432 $ 508,444 $ 548,051
CAPITALIZATION (IN THOUSANDS):
Common stock equity $ 4,045,458 $ 3,888,237 $ 3,766,551
Preferred stock 692,787 692,792 607,796
Preferred stock subject to mandatory redemption - 6,250 118,750
Long-term debt 4,031,387 4,131,016 4,553,189
Total (excluding amounts due within one year) $ 8,769,632 $ 8,718,295 $ 9,046,286
CAPITALIZATION RATIOS (PERCENT):
Common stock equity 46.1 44.6 41.7
Preferred stock 7.9 8.0 8.0
Long-term debt 46.0 47.4 50.3
Total (excluding amounts due within one year) 100.0 100.0 100.0
FIRST MORTGAGE BONDS (IN THOUSANDS):
Issued 1,135,000 975,000 -
Retired 1,337,822 1,381,300 598,384
PREFERRED STOCK (IN THOUSANDS):
Issued 175,000 195,000 100,000
Retired 245,005 165,004 100,000
SECURITY RATINGS:
First Mortgage Bonds -
Moody's A3 A3 Baa1
Standard and Poor's A- A- BBB+
Duff & Phelps A+ A- BBB+
Preferred Stock -
Moody's baa1 baa1 baa1
Standard and Poor's BBB+ BBB+ BBB
Duff & Phelps A- BBB BBB-
CUSTOMERS (YEAR-END):
Residential 1,441,972 1,421,175 1,397,682
Commercial 188,820 183,784 179,933
Industrial 11,217 11,479 11,946
Other 2,322 2,269 2,190
Total 1,644,331 1,618,707 1,591,751
EMPLOYEES (YEAR-END) 12,528 12,600 13,700
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154
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1993 Annual Report
1990 1989 1988 1987 1986 1985 1984 1983
$ 4,445,809 $ 4,145,240 $ 3,897,479 $ 3,786,485 $ 3,561,603 $ 3,609,140 $ 3,319,699 $ 2,869,883
$ 208,066 $ 449,099 $ 479,532 $ 240,057 $ 535,003 $ 493,717 $ 421,719 $ 304,555
$ 389,600 $ 394,500 $ 386,600 $ 377,800 $ 325,500 $ 277,500 $ 225,500 $ 189,600
5.52 11.72 13.06 6.85 16.51 17.95 18.43 15.86
$11,176,619 $11,372,346 $11,130,539 $11,197,494 $10,465,063 $ 9,030,618 $ 7,880,072 $ 6,746,247
$ 558,727 $ 727,631 $ 929,019 $ 1,034,059 $ 1,598,309 $ 1,384,182 $ 1,396,846 $ 1,015,274
$ 3,673,913 $ 3,860,657 $ 3,806,070 $ 3,538,182 $ 3,469,201 $ 3,013,707 $ 2,486,172 $ 2,089,171
607,796 607,844 657,844 657,844 732,844 632,844 482,844 432,844
125,000 155,000 162,500 166,250 112,500 120,000 127,500 131,250
5,000,225 5,054,001 4,861,378 4,825,760 4,464,857 3,878,066 3,432,606 3,128,500
$ 9,406,934 $ 9,677,502 $ 9,487,792 $ 9,188,036 $ 8,779,402 $ 7,644,617 $ 6,529,122 $ 5,781,765
39.1 39.9 40.1 38.5 39.5 39.4 38.1 36.1
7.8 7.9 8.6 9.0 9.6 9.9 9.3 9.8
53.1 52.2 51.3 52.5 50.9 50.7 52.6 54.1
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
300,000 250,000 150,000 500,000 500,000 - 150,000 125,000
91,117 91,516 206,677 217,949 377,538 17,738 26,084 18,273
- - - 125,000 100,000 150,000 50,000 -
83,750 7,500 3,750 150,000 7,500 3,750 2,380 4,378
Baa1 Baa2 Baa2 Baa2 Baa1 Baa1 Baa1 Baa1
BBB+ BBB+ BBB BBB BBB+ BBB+ BBB+ BBB+
BBB BBB 9 9 9 9 8 8
baa1 baa2 baa2 baa2 baa1 baa1 baa1 baa1
BBB BBB BBB- BBB- BBB BBB BBB BBB
BBB- BBB- 10 10 10 10 9 9
1,378,888 1,355,211 1,329,173 1,303,721 1,268,983 1,231,140 1,189,670 1,154,953
178,391 177,814 174,147 169,014 162,258 155,399 148,536 142,305
12,115 12,311 12,353 12,307 12,315 12,309 12,276 12,109
2,114 2,050 1,993 1,858 1,816 1,789 1,753 1,696
1,571,508 1,547,386 1,517,666 1,486,900 1,445,372 1,400,637 1,352,235 1,311,063
13,746 13,900 15,110 14,924 14,773 14,947 14,562 14,535
II-124
155
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1993 Annual Report
1993 1992 1991
OPERATING REVENUES (IN THOUSANDS):
Residential $ 1,291,035 $ 1,128,396 $ 1,111,358
Commercial 1,354,130 1,285,681 1,243,067
Industrial 1,113,067 1,083,856 1,057,702
Other 41,399 39,504 37,861
Total retail 3,799,631 3,537,437 3,449,988
Sales for resale - non-affiliates 534,370 640,308 736,643
Sales for resale - affiliates 61,668 67,835 65,586
Total revenues from sales of electricity 4,395,669 4,245,580 4,252,217
Other revenues 55,512 51,856 49,211
Total $ 4,451,181 $ 4,297,436 $ 4,301,428
KILOWATT-HOUR SALES (IN THOUSANDS):
Residential 16,649,859 14,939,172 14,815,089
Commercial 18,278,508 17,260,614 16,885,833
Industrial 23,635,363 22,978,312 22,298,062
Other 460,801 436,144 429,016
Total retail 59,024,531 55,614,242 54,428,000
Sales for resale - non-affiliates 14,307,030 15,870,222 18,719,924
Sales for resale - affiliates 3,027,733 3,320,060 3,885,892
Total 76,359,294 74,804,524 77,033,816
AVERAGE REVENUE PER KILOWATT-HOUR (CENTS):
Residential 7.75 7.55 7.50
Commercial 7.41 7.45 7.36
Industrial 4.71 4.72 4.74
Total retail 6.44 6.36 6.34
Sales for resale 3.44 3.69 3.55
Total sales 5.76 5.68 5.52
RESIDENTIAL AVERAGE ANNUAL KILOWATT-HOUR USE PER
CUSTOMER 11,630 10,603 10,675
RESIDENTIAL AVERAGE ANNUAL REVENUE PER CUSTOMER $ 901.79 $ 800.88 $ 800.78
PLANT NAMEPLATE CAPACITY RATINGS (YEAR-END)
(MEGAWATTS) 13,759 14,076 14,076
MAXIMUM PEAK-HOUR DEMAND (MEGAWATTS) (NOTE):
Winter 9,067 8,938 10,001
Summer 12,573 11,448 13,090
ANNUAL LOAD FACTOR (PERCENT) 58.5 60.5 55.2
PLANT AVAILABILITY (PERCENT):
Fossil-steam 85.9 86.6 93.3
Nuclear 85.5 87.7 81.6
SOURCE OF ENERGY SUPPLY (PERCENT):
Coal 62.1 61.4 63.6
Nuclear 16.2 17.0 15.3
Hydro 2.3 2.5 2.3
Oil and gas 0.2 * *
Purchased power -
From non-affiliates 10.2 12.2 10.3
From affiliates 9.0 6.9 8.5
Total 100.0 100.0 100.0
TOTAL FUEL ECONOMY DATA:
BTU per net kilowatt-hour generated 9,912 9,900 9,960
Cost of fuel per million BTU (cents) 153.62 153.08 157.97
Average cost of fuel per net kilowatt-hour
generated (cents) 1.52 1.52 1.57
Note: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company
are not included in Peak-Hour Demand
* Less than one-tenth of one percent.
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156
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1993 Annual Report
1990 1989 1988 1987 1986 1985 1984 1983
$ 1,109,165 $ 1,022,781 $ 979,047 $ 904,218 $ 874,231 $ 786,500 $ 754,163 $ 686,269
1,218,441 1,143,727 1,054,995 915,540 854,755 797,540 739,035 649,932
1,061,830 1,006,416 983,822 911,933 897,646 873,554 858,536 747,305
36,773 34,775 31,743 29,350 27,948 26,766 24,388 20,972
3,426,209 3,207,699 3,049,607 2,761,041 2,654,580 2,484,360 2,376,122 2,104,478
784,086 760,809 707,076 822,696 780,049 941,743 779,028 666,739
168,251 150,394 86,751 159,998 91,753 149,463 136,047 70,784
4,378,546 4,118,902 3,843,434 3,743,735 3,526,382 3,575,566 3,291,197 2,842,001
67,263 26,338 54,045 42,750 35,221 33,574 28,502 27,882
$ 4,445,809 $ 4,145,240 $ 3,897,479 $ 3,786,485 $ 3,561,603 $3,609,140 $3,319,699 $2,869,883
14,771,648 14,134,195 13,800,038 13,675,730 13,234,248 12,006,462 11,548,787 11,443,257
16,627,128 15,843,181 14,790,561 13,799,379 12,945,926 11,945,938 10,902,163 10,181,953
22,126,604 21,801,404 21,412,845 20,884,454 20,339,235 19,517,543 18,862,531 17,415,441
428,459 414,107 397,669 385,514 381,917 382,238 342,047 331,804
53,953,839 52,192,887 50,401,113 48,745,077 46,901,326 43,852,181 41,655,528 39,372,455
20,158,681 20,479,412 18,544,705 20,910,185 18,198,186 21,526,865 19,138,575 16,197,259
8,272,528 7,489,948 3,327,814 6,032,889 3,160,242 5,999,834 4,970,928 2,938,120
82,385,048 80,162,247 72,273,632 75,688,151 68,259,754 71,378,880 65,765,031 58,507,834
7.51 7.24 7.09 6.61 6.61 6.55 6.53 6.00
7.33 7.22 7.13 6.63 6.60 6.68 6.78 6.38
4.80 4.62 4.59 4.37 4.41 4.48 4.55 4.29
6.35 6.15 6.05 5.66 5.66 5.67 5.70 5.35
3.35 3.26 3.63 3.65 4.08 3.96 3.80 3.85
5.31 5.14 5.32 4.95 5.17 5.01 5.00 4.86
10,795 10,530 10,484 10,623 10,577 9,923 9,855 10,049
$ 810.56 $ 761.96 $ 743.82 $ 702.36 $ 698.72 $ 650.01 $ 643.53 $ 602.66
14,366 14,366 13,018 13,018 11,875 11,875 11,767 11,698
8,977 10,101 9,866 9,446 10,551 10,049 8,462 7,556
13,196 12,735 12,295 12,390 11,910 11,079 10,443 10,933
55.5 56.3 59.1 56.1 57.5 56.3 56.9 51.9
92.5 93.0 94.5 92.7 91.2 91.2 91.0 91.7
81.3 89.2 69.4 85.4 64.7 79.5 47.3 68.6
65.1 64.0 72.0 70.9 74.6 72.7 74.4 72.2
13.7 14.1 9.6 9.1 5.0 6.7 4.0 6.3
2.2 2.1 1.2 1.7 1.2 1.5 2.7 3.1
0.1 0.1 0.1 0.1 0.6 * * 0.1
11.0 10.2 8.2 8.5 8.9 9.4 9.2 8.4
7.9 9.5 8.9 9.7 9.7 9.7 9.7 9.9
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
9,939 10,020 9,969 9,932 10,016 10,089 10,002 10,100
166.22 164.27 166.28 168.81 175.81 178.11 184.63 179.92
1.65 1.65 1.66 1.68 1.76 1.80 1.85 1.82
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157
STATEMENTS OF INCOME
Georgia Power Company
FOR THE YEARS ENDED DECEMBER 31, 1993 1992 1991
(Thousands of Dollars)
OPERATING REVENUES:
Revenues $ 4,389,513 $4,229,601 $4,235,842
Revenues from affiliates 61,668 67,835 65,586
Total operating revenues 4,451,181 4,297,436 4,301,428
OPERATING EXPENSES:
Operation --
Fuel 951,507 929,780 998,701
Purchased power from non-affiliates 313,170 436,761 444,920
Purchased power from affiliates 194,024 158,306 193,114
Provision for separation benefits - 9,778 52,952
Proceeds from settlement of disputed contracts - (4,982) (142,183)
Other 675,284 616,116 596,565
Maintenance 284,521 264,757 295,012
Depreciation and amortization 379,425 375,460 382,549
Deferred Plant Vogtle expenses, net 36,284 (30,804) 16,008
Taxes other than income taxes 192,671 179,460 172,893
Federal and state income taxes 452,122 377,542 349,284
Total operating expenses 3,479,008 3,312,174 3,359,815
OPERATING INCOME 972,173 985,262 941,613
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction 3,168 5,855 9,083
Income from subsidiary 4,127 4,635 4,576
Deferred return on Plant Vogtle - - 34,549
Write-off of Plant Vogtle costs - - -
Income tax reduction for write-off of Plant Vogtle costs - - -
Interest income 3,806 12,475 10,563
Other, net (See note) 11,902 (30,527) 13,551
Income taxes applicable to other income 37,661 25,163 (7,522)
INCOME BEFORE INTEREST CHARGES 1,032,837 1,002,863 1,006,413
INTEREST CHARGES:
Interest on long-term debt 343,634 402,541 459,184
Allowance for debt funds used during construction (8,271) (8,310) (10,385)
Interest on interim obligations 15,530 9,694 4,906
Amortization of debt discount, premium, and expense, net 14,024 8,033 6,214
Other interest charges 47,393 12,425 9,938
Net interest charges 412,310 424,383 469,857
NET INCOME 620,527 578,480 536,556
DIVIDENDS ON PREFERRED STOCK 50,674 57,942 61,701
NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 569,853 $ 520,538 $ 474,855
Note: Reflects major sales of facilities to Jacksonville Electric Authority,
Florida Power & Light Company, OPC, MEAG, and Dalton. Increases in
net income, after total taxes, from these sales were $18,391,000 in
1993, $14,542,000 in 1991, $6,336,000 in 1990, $3,851,000 in 1987,
and $21,250,000 in 1984.
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158
STATEMENTS OF INCOME
Georgia Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 4,277,558 $ 3,994,846 $3,810,728 $ 3,626,487 $3,469,850 $ 3,459,677 $ 3,183,652 $ 2,799,099
168,251 150,394 86,751 159,998 91,753 149,463 136,047 70,784
4,445,809 4,145,240 3,897,479 3,786,485 3,561,603 3,609,140 3,319,699 2,869,883
1,120,933 1,078,586 1,023,173 1,064,552 1,012,949 1,077,092 1,000,434 884,037
626,989 543,448 546,511 530,051 344,708 415,406 427,403 274,643
173,716 195,355 164,873 199,831 192,297 204,848 188,938 204,624
- - - - - - - -
- - - - - - - -
524,665 504,743 541,975 575,182 513,974 482,468 412,803 361,642
280,304 233,680 246,877 274,672 275,533 254,510 228,377 190,266
380,394 346,091 306,492 254,929 215,763 201,524 191,205 176,735
31,146 (39,211) (8,333) (141,977) - - - -
151,124 128,518 146,759 143,289 119,768 120,320 106,908 95,797
270,561 273,287 204,222 250,093 319,374 311,151 268,654 231,565
3,559,832 3,264,497 3,172,549 3,150,622 2,994,366 3,067,319 2,824,722 2,419,309
885,977 880,743 724,930 635,863 567,237 541,821 494,977 450,574
6,985 40,525 96,530 159,414 275,183 227,950 162,057 107,682
4,182 3,750 3,302 3,440 2,967 3,417 3,181 3,088
82,721 48,096 107,310 115,028 - - - -
(281,254) - - (357,821) - - - -
63,231 - - 128,923 - - - -
7,552 10,333 28,445 55,388 44,615 41,546 34,074 37,234
(21,199) (20,603) (3,746) (55,081) (28,464) (6,815) 45,132 (3,983)
20,859 15,573 6,583 17,344 5,154 (9,114) (37,678) (14,928)
769,054 978,417 963,354 702,498 866,692 798,805 701,743 579,667
480,174 475,991 471,897 480,519 472,744 421,764 351,855 315,443
(9,325) (34,244) (95,818) (130,756) (225,897) (216,233) (150,931) (99,845)
8,512 1,059 15,084 16,362 1,954 20,516 13,387 -
6,100 5,865 5,466 3,573 2,681 2,335 1,680 1,485
9,404 8,868 14,556 12,239 4,610 10,593 8,416 2,461
494,865 457,539 411,185 381,937 256,092 238,975 224,407 219,544
274,189 520,878 552,169 320,561 610,600 559,830 477,336 360,123
66,123 71,779 72,637 80,504 75,597 66,113 55,617 55,568
$ 208,066 $ 449,099 $ 479,532 $ 240,057 $ 535,003 $ 493,717 $ 421,719 $ 304,555
II-128
159
STATEMENTS OF CASH FLOWS
Georgia Power Company
For the Years Ended December 31, 1993 1992 1991
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $ 620,527 $ 578,480 $ 536,556
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 475,152 471,014 480,318
Deferred income taxes, net 169,009 194,955 53,219
Deferred investment tax credits, net (18,274) (5,704) (9,524)
Allowance for equity funds used during construction (3,168) (5,855) (9,083)
Deferred Plant Vogtle costs 36,284 (30,804) (18,541)
Write-off of Plant Vogtle costs - - -
Non-cash proceeds from settlement of disputed contracts - (4,982) (103,846)
Other, net (46,227) (9,768) (26,024)
Changes in certain current assets and liabilities:
Receivables, net 27,088 (31,348) 23,920
Inventories 82,433 (65,621) 24,130
Payables 17,364 25,303 (23,075)
Other (94,574) (85,961) 54,777
Net cash provided from operating activities 1,265,614 1,029,709 982,827
INVESTING ACTIVITIES:
Gross property additions (674,432) (508,444) (548,051)
Sales of property 261,687 46 291,075
Other (43,154) 42,892 931
Net cash used for investing activities (455,899) (465,506) (256,045)
FINANCING ACTIVITIES AND CAPITAL CONTRIBUTIONS:
Proceeds:
Preferred stock 175,000 195,000 100,000
First mortgage bonds 1,135,000 975,000 -
Pollution control bonds 145,425 161,955 80,420
Other long-term debt 37,000 - -
Capital contributions from parent company - - -
Retirements:
Preferred stock (245,005) (165,004) (100,000)
First mortgage bonds (1,337,822) (1,381,300) (598,384)
Pollution control bonds (145,465) (160,205) (83,265)
Other long-term debt (19,451) (567) (1,130)
Interim obligations, net (51,444) 334,671 199,000
Payment of preferred stock dividends (53,123) (60,475) (60,766)
Payment of common stock dividends (402,400) (384,000) (375,200)
Miscellaneous (63,648) (70,986) (17,613)
Net cash provided from (used for) financing activities (825,933) (555,911) (856,938)
NET CHANGE IN CASH AND CASH EQUIVALENTS (16,218) 8,292 (130,156)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 22,114 13,822 143,978
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 5,896 $ 22,114 $ 13,822
( ) Denotes use of cash.
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160
STATEMENTS OF CASH FLOWS
Georgia Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 274,189 $ 520,878 $ 552,169 $ 320,561 $ 610,600 $ 559,830 $ 477,336 $ 360,123
502,098 484,870 400,665 336,647 260,945 248,256 219,301 209,733
88,667 184,490 160,774 76,445 236,822 104,102 145,266 143,511
(52) (8,017) 11,605 (5,075) 106,407 115,144 61,252 83,266
(6,985) (40,525) (96,530) (159,414) (275,183) (227,950) (162,057) (107,682)
(51,575) (87,307) (115,643) (257,005) - - - -
281,254 - - 357,821 - - - -
- - - - - - - -
(50,804) (38,046) 6,983 (759) 5,554 34,311 (81,166) (2,543)
1,444 (59,035) 11,225 (6,880) (7,474) (27,928) (68,325) (51,925)
(23,498) (33,123) (10,044) (72,540) (26,863) 77,667 (65,772) 12,275
(43,470) (38,976) (2,065) 74,341 133,044 (9,182) 161,479 (28,993)
(9,991) 36,015 1,161 2,751 19,682 21,289 99,191 9,674
961,277 921,224 920,300 666,893 1,063,534 895,539 786,505 627,439
(558,727) (727,631) (929,019) (1,034,059) (1,598,309) (1,384,182) (1,396,846) (1,015,274)
34,573 - - 12,276 - - 320,708 -
1,937 47,260 35,328 45,801 168,518 92,826 82,741 53,148
(522,217) (680,371) (893,691) (975,982) (1,429,791) (1,291,356) (993,397) (962,126)
- - - 125,000 100,000 150,000 50,000 -
300,000 250,000 150,000 500,000 500,000 - 150,000 125,000
- 50,000 69,526 191,736 350,001 500,962 190,577 28,827
- - - - 113,000 - - -
- - 175,000 228,000 250,000 315,000 202,000 223,000
(83,750) (7,500) (3,750) (150,000) (7,500) (3,750) (2,380) (4,378)
(91,117) (91,516) (206,677) (217,949) (377,538) (17,738) (26,084) (18,273)
(535) (505) (475) (90,000) - - - -
(114,452) (3,806) (2,878) (2,824) (108) (843) (276) 3,617
- - (302,261) 302,261 (36,715) (72,956) 109,356 -
(67,757) (72,259) (72,931) (80,420) (73,665) (62,337) (55,433) (55,946)
(389,600) (394,500) (386,600) (377,800) (325,500) (277,500) (225,500) (189,600)
(7,663) (4,742) (13,440) (51,745) (33,773) (17,503) (17,975) (1,874)
(454,874) (274,828) (594,486) 376,259 458,202 513,335 374,285 110,373
(15,814) (33,975) (567,877) 67,170 91,945 117,518 167,393 (224,314)
159,792 193,767 761,644 694,474 602,529 485,011 317,618 541,932
$ 143,978 $ 159,792 $ 193,767 $ 761,644 $ 694,474 $ 602,529 $ 485,011 $ 317,618
II-130
161
BALANCE SHEETS
Georgia Power Company
At December 31, 1993 1992 1991
(Thousands of Dollars)
ASSETS
ELECTRIC PLANT:
Production-
Fossil $ 2,976,806 $ 3,144,405 $ 3,128,594
Nuclear 4,069,299 4,051,020 4,051,043
Hydro 442,888 434,341 432,674
Total production 7,488,993 7,629,766 7,612,311
Transmission 1,713,122 1,646,904 1,566,173
Distribution 3,600,115 3,413,681 3,252,111
General 941,291 923,010 896,477
Construction work in progress 584,013 405,606 390,437
Nuclear fuel, at amortized cost 135,742 155,194 191,726
Total electric plant 14,463,276 14,174,161 13,909,235
STEAM HEAT PLANT - - -
Total utility plant 14,463,276 14,174,161 13,909,235
ACCUMULATED PROVISION FOR DEPRECIATION:
Electric 3,822,344 3,569,717 3,315,247
Steam heat - - -
Total accumulated provision for depreciation 3,822,344 3,569,717 3,315,247
Total 10,640,932 10,604,444 10,593,988
Less property-related accumulated deferred income taxes - 1,589,743 1,465,408
Total 10,640,932 9,014,701 9,128,580
OTHER PROPERTY AND INVESTMENTS:
Securities received from settlement of disputed contracts - - 107,993
Nuclear decommissioning trusts 37,937 20,311 10,007
Miscellaneous 61,142 55,463 71,880
Total 99,079 75,774 189,880
CURRENT ASSETS:
Cash and cash equivalents 5,896 22,114 13,822
Investment securities - 108,206 -
Receivables, net 515,178 385,227 330,411
Accrued utility revenues 99,550 88,164 79,099
Fossil fuel stock, at average cost 111,620 197,332 200,248
Materials and supplies, at average cost 287,551 284,272 215,735
Prepayments 65,269 91,447 96,750
Vacation pay deferred 41,575 40,169 39,769
Total current assets 1,126,639 1,216,931 975,834
DEFERRED CHARGES:
Deferred charges related to income taxes 992,510 - -
Deferred Plant Vogtle costs 506,980 383,025 375,028
Debt expense, being amortized 20,730 17,719 12,368
Premium on reacquired debt, being amortized 153,146 116,940 70,855
Miscellaneous 196,094 139,352 89,993
Total deferred charges 1,869,460 657,036 548,244
Total Assets $ 13,736,110 $ 10,964,442 $ 10,842,538
II-131
162
BALANCE SHEETS
Georgia Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 3,350,018 $ 3,319,876 $ 2,638,725 $ 2,616,741 $ 2,138,511 $ 2,118,863 $ 2,105,551 $ 2,039,200
4,025,862 4,189,723 3,225,945 3,220,632 739,835 652,756 647,020 585,646
412,157 411,235 407,771 404,291 399,120 388,832 303,334 297,622
7,788,037 7,920,834 6,272,441 6,241,664 3,277,466 3,160,451 3,055,905 2,922,468
1,522,157 1,431,485 1,322,034 1,248,976 1,176,479 1,004,329 949,802 859,656
3,056,825 2,863,011 2,598,714 2,318,185 2,096,498 1,892,127 1,722,546 1,589,387
876,989 859,013 737,621 657,258 578,236 501,477 452,119 425,947
370,243 403,365 1,963,283 1,710,769 4,430,152 3,581,065 2,694,628 2,038,763
210,320 254,101 307,109 287,492 314,225 253,418 231,456 204,162
13,824,571 13,731,809 13,201,202 12,464,344 11,873,056 10,392,867 9,106,456 8,040,383
- - - 7 15,266 14,709 15,419 15,617
13,824,571 13,731,809 13,201,202 12,464,351 11,888,322 10,407,576 9,121,875 8,056,000
3,040,298 2,762,937 2,445,404 2,193,395 2,001,605 1,851,649 1,693,788 1,536,342
- - - (5) 7,841 7,517 7,696 7,347
3,040,298 2,762,937 2,445,404 2,193,390 2,009,446 1,859,166 1,701,484 1,543,689
10,784,273 10,968,872 10,755,798 10,270,961 9,878,876 8,548,410 7,420,391 6,512,311
1,397,647 1,313,626 1,178,291 1,077,747 1,020,271 920,047 873,024 771,671
9,386,626 9,655,246 9,577,507 9,193,214 8,858,605 7,628,363 6,547,367 5,740,640
- - - - - - - -
- - - - - - - -
78,895 69,839 66,677 54,148 50,749 39,357 38,143 22,523
78,895 69,839 66,677 54,148 50,749 39,357 38,143 22,523
143,978 159,792 193,767 761,644 694,474 602,529 485,011 317,618
- - - - - - - -
356,236 347,899 320,018 342,315 374,590 367,226 350,197 270,512
78,067 93,786 66,265 68,370 55,513 55,403 44,504 55,864
225,966 214,487 225,274 262,752 220,206 210,604 289,807 230,758
220,103 208,084 164,174 116,652 86,658 69,397 67,861 61,138
121,646 116,342 121,840 113,381 44,800 8,506 6,697 8,093
33,677 35,238 34,418 30,100 29,800 28,700 26,600 24,800
1,179,673 1,175,628 1,125,756 1,695,214 1,506,041 1,342,365 1,270,677 968,783
- - - - - - - -
364,446 322,116 269,958 172,990 - - - -
12,708 13,032 12,476 12,985 12,860 12,450 11,218 8,837
60,653 61,889 62,352 51,509 26,914 - - -
93,618 74,596 15,813 17,434 9,894 8,083 12,667 5,464
531,425 471,633 360,599 254,918 49,668 20,533 23,885 14,301
$ 11,176,619 $ 11,372,346 $ 11,130,539 $11,197,494 $ 10,465,063 $ 9,030,618 $ 7,880,072 $ 6,746,247
II-132
163
BALANCE SHEETS
Georgia Power Company
At December 31, 1993 1992 1991
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stock $ 344,250 $ 344,250 $ 344,250
Other paid-in capital 2,384,348 2,384,140 2,383,800
Premium on preferred stock 413 467 489
Earnings retained in the business 1,316,447 1,159,380 1,038,012
Total common equity 4,045,458 3,888,237 3,766,551
Preferred stock 692,787 692,792 607,796
Preferred stock subject to mandatory redemption - 6,250 118,750
Long-term debt 4,031,387 4,131,016 4,553,189
Total capitalization 8,769,632 8,718,295 9,046,286
(excluding amount due within one year)
CURRENT LIABILITIES:
Notes payable to banks 406,700 400,200 199,000
Commercial paper 75,527 133,471 -
Preferred stock due within one year - 63,750 6,250
Long-term debt due within one year 10,543 95,823 54,976
Accounts payable 324,044 317,351 275,932
Customer deposits 45,922 45,145 41,623
Taxes accrued 153,493 138,289 161,117
Interest accrued 110,497 132,319 151,171
Vacation pay accrued 40,060 38,694 38,531
Miscellaneous 64,527 89,355 106,810
Total current liabilities 1,231,313 1,454,397 1,035,410
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes 2,479,720 - -
Accumulated deferred investment tax credits 478,334 515,539 540,134
Disallowed Plant Vogtle capacity buyback costs 63,067 72,201 109,537
Deferred credits related to income taxes 452,819 - -
Miscellaneous 261,225 204,010 111,171
Total deferred credits and other liabilities 3,735,165 791,750 760,842
TOTAL CAPITALIZATION AND LIABILITIES $ 13,736,110 $ 10,964,442 $ 10,842,538
II-133
164
BALANCE SHEETS
Georgia Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 344,250 $ 344,250 $ 344,250 $ 344,250 $ 344,250 $ 344,250 $ 344,250 $ 344,250
2,383,800 2,383,800 2,383,800 2,208,800 1,980,800 1,730,800 1,415,800 1,213,800
1,089 1,089 1,089 1,089 3,074 3,074 3,058 2,898
944,774 1,131,518 1,076,931 984,043 1,141,077 935,583 723,064 528,223
3,673,913 3,860,657 3,806,070 3,538,182 3,469,201 3,013,707 2,486,172 2,089,171
607,796 607,844 657,844 657,844 732,844 632,844 482,844 432,844
125,000 155,000 162,500 166,250 112,500 120,000 127,500 131,250
5,000,225 5,054,001 4,861,378 4,825,760 4,464,857 3,878,066 3,432,606 3,128,500
9,406,934 9,677,502 9,487,792 9,188,036 8,779,402 7,644,617 6,529,122 5,781,765
- - - 302,261 - 36,400 109,356 -
- - - - - - - -
- 53,750 3,750 3,750 7,500 7,500 3,750 2,380
204,906 54,712 42,001 65,774 47,683 48,229 21,324 24,100
310,676 372,968 429,807 446,004 488,910 355,866 365,048 203,569
38,144 36,255 34,221 31,106 29,520 29,752 34,838 31,851
84,185 91,424 130,686 114,947 140,968 92,028 151,438 107,753
175,959 162,513 170,090 162,439 150,145 136,279 117,759 89,626
33,677 35,238 34,418 30,100 29,800 28,700 26,600 24,800
135,392 130,546 51,289 62,364 70,595 60,965 37,874 30,204
982,939 937,406 896,262 1,218,745 965,121 795,719 867,987 514,283
- - - - - - - -
576,837 601,248 632,111 640,694 665,447 572,509 471,640 421,821
135,926 73,111 80,585 79,376 - - - -
- - - - - - - -
73,983 83,079 33,789 70,643 55,093 17,773 11,323 28,378
786,746 757,438 746,485 790,713 720,540 590,282 482,963 450,199
$ 11,176,619 $ 11,372,346 $ 11,130,539 $11,197,494 $ 10,465,063 $ 9,030,618 $ 7,880,072 $ 6,746,247
II-134
165
GEORGIA POWER COMPANY
OUTSTANDING SECURITIES
AT DECEMBER 31, 1993
FIRST MORTGAGE BONDS
Amount Interest Amount
Series Issued Rate Outstanding Maturity
(Thousands) (Thousands)
1992 $ 130,000 5-1/8% $ 130,000 9/1/95
1993 150,000 4.75% 150,000 3/1/96
1993 100,000 5.50% 100,000 4/1/98
1992 195,000 6-1/8% 195,000 9/1/99
1993 100,000 6% 100,000 3/1/00
1992 100,000 7% 100,000 10/1/00
1992 150,000 6-7/8% 150,000 9/1/02
1993 200,000 6.625% 200,000 4/1/03
1993 75,000 6.35% 75,000 8/1/03
1993 50,000 6.875% 50,000 4/1/08
1986 250,000 10% 69,716 7/1/16
1989 250,000 9.23% 100,000 12/1/19
1992 100,000 8-3/4% 100,000 4/1/22
1992 100,000 8-5/8% 100,000 6/1/22
1993 160,000 7.95% 160,000 2/1/23
1993 100,000 7.625% 100,000 3/1/23
1993 75,000 7.75% 75,000 4/1/23
1993 125,000 7.55% 125,000 8/1/23
1992 100,000 Variable 100,000 4/1/32
1992 100,000 Variable 100,000 7/1/32
$2,610,000 $2,279,716
POLLUTION CONTROL BONDS
Amount Interest Amount
Series Issued Rate Outstanding Maturity
(Thousands) (Thousands)
1992 $ 38,800 5.70% $ 38,800 9/1/04
1993 46,790 5.375% 46,790 3/1/05
1976 40,800 6.75% 1,960 11/1/06
1977 24,100 6.40% 1,980 6/1/07
1978 21,600 6.375% 8,200 4/1/08
1991 10,450 Variable 10,450 7/1/11
1984 40,000 11.625% 28,065 3/1/14
1984 125,000 12.25% 113,745 8/1/14
1984 125,000 11.625% 123,175 9/1/14
1984 150,000 12% 126,735 10/1/14
1984 100,000 11.75% 75,070 11/1/14
1985 150,000 10.125% 148,535 6/1/15
1985 200,000 10.50% 200,000 9/1/15
1985 100,000 10.60% 100,000 10/1/15
1985 100,000 10.50% 99,585 11/1/15
1986 56,400 8% 56,400 10/1/16
1987 90,000 8.375% 90,000 7/1/17
1987 50,000 9.375% 50,000 12/1/17
1993 26,700 6% 26,700 3/1/18
1989 50,000 Variable 50,000 5/1/19
1991 8,500 Variable 8,500 7/1/19
1991 51,345 7.25% 51,345 7/1/21
1991 10,125 Variable 10,125 7/1/21
1992 13,155 Variable 13,155 5/1/22
1992 75,000 6.20% 75,000 8/1/22
1992 35,000 6.20% 35,000 9/1/22
1993 11,935 5.75% 11,935 9/1/23
1993 60,000 5.75% 60,000 9/1/23
$1,810,700 $1,661,250
II-135
166
GEORGIA POWER COMPANY
OUTSTANDING SECURITIES (Continued)
AT DECEMBER 31, 1993
PREFERRED STOCK
---------------
Shares Dividend Amount
Series Outstanding Rate Outstanding
(Thousands)
(1) 14,090 $5.00 $ 1,409
1953 100,000 $4.92 10,000
1954 411,564 $4.60 41,157
1954 22,214 $4.60 2,221
1961 70,000 $4.96 7,000
1962 70,000 $4.60 7,000
1963 70,000 $4.60 7,000
1964 50,000 $4.60 5,000
1965 60,000 $4.72 6,000
1966 90,000 $5.64 9,000
1967 120,000 $6.48 12,000
1968 100,000 $6.60 10,000
1971 300,000 $7.72 30,000
1972 750,000 $7.80 75,000
1991 4,000,000 $2.125 100,000
1992 2,000,000 $1.90 50,000
1992 2,200,000 $1.9875 55,000
1992 2,400,000 $1.9375 60,000
1992 1,200,000 $1.925 30,000
1993 3,000,000 Adjustable 75,000
1993 4,000,000 Adjustable 100,000
21,027,868 $ 692,787
(1) Issued in exchange for $5.00 preferred outstanding at the time of company
formation.
II-136
167
GEORGIA POWER COMPANY
SECURITIES RETIRED
DURING 1993
FIRST MORTGAGE BONDS
Principal Interest
Series Amount Rate
(Thousands)
1964 $ 28,000 4.625%
1965 36,500 4.875%
1966 45,368 5.75%
1967 50,000 6.50%
1968 50,000 6.625%
1971 49,500 7.375%
1971 95,000 7.625%
1972 75,000 7.50%
1972 150,000 7.50%
1973 115,000 7.875%
1986 172,284 10.00%
1986 200,000 10.00%
1987 176,235 10.75%
1988 44,935 10.75%
1990 50,000 Variable
$1,337,822
POLLUTION CONTROL BONDS
Principal Interest
Series Amount Rate
(Thousands)
1973 $ 37,990 5.95%
1976 20 6.75%
1977 22,120 6.40%
1978 13,400 6.375%
1984 11,050 12.25%
1984 11,935 11.625%
1984 1,500 11.625%
1984 22,550 12.00%
1984 24,900 11.75%
$ 145,465
PREFERRED STOCK
Principal Dividend
Series Amount Rate
(Thousands)
(1) $ * $5.00
1954 5 $4.60
1969 15,000 $8.20
1970 10,000 $8.76
1984 50,000 Adjustable
1985 50,000 Adjustable
1985 50,000 Adjustable
1987 25,000 $2.50
1987 45,000 $2.43
$ 245,005
(1) Issued in exchange for $5.00 preferred outstanding at the time of company
formation.
* Less than $500.
II-137
168
GULF POWER COMPANY
FINANCIAL SECTION
II-138
169
MANAGEMENT'S REPORT
Gulf Power Company 1993 Annual Report
The management of Gulf Power Company has prepared and is responsible for the
financial statements and related information included in this report. These
statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts
that are based on the best estimates and judgments of management. Financial
information throughout this annual report is consistent with the financial
statements.
The Company maintains a system of internal accounting controls to
provide reasonable assurance that assets are safeguarded and that books and
records reflect only authorized transactions of the Company. Limitations exist
in any system of internal controls, however, based on a recognition that the
cost of the system should not exceed its benefits. The Company believes its
system of internal accounting controls maintains an appropriate cost/benefit
relationship.
The Company's system of internal accounting controls is evaluated on
an ongoing basis by the Company's internal audit staff. The Company's
independent public accountants also consider certain elements of the internal
control system in order to determine their auditing procedures for the purpose
of expressing an opinion on the financial statements.
The audit committee of the board of directors, composed of the
directors who are not employees, provides a broad overview of management's
financial reporting and control functions. Periodically, this committee meets
with management, the internal auditors, and the independent public accountants
to ensure that these groups are fulfilling their obligations and to discuss
auditing, internal controls, and financial reporting matters. The internal
auditors and independent public accountants have access to the members of the
audit committee at any time.
Management believes that its policies and procedures provide
reasonable assurance that the Company's operations are conducted according to a
high standard of business ethics.
In management's opinion, the financial statements present fairly, in
all material respects, the financial position, results of operations, and cash
flows of Gulf Power Company in conformity with generally accepted accounting
principles.
/s/ D. L. McCrary /s/ A. E. Scarbrough
- -------------------------- ------------------------
Douglas L. McCrary Arlan E. Scarbrough
Chairman of the Board Vice President - Finance
and Chief Executive Officer
II-139
170
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS
OF GULF POWER COMPANY:
We have audited the accompanying balance sheets and statements of
capitalization of Gulf Power Company (a Maine corporation and a wholly owned
subsidiary of The Southern Company) as of December 31, 1993 and 1992, and the
related statements of income, retained earnings, 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.
In our opinion, the financial statements (pages II-148 through II-165)
referred to above present fairly, in all material respects, the financial
position of Gulf Power Company as of December 31, 1993 and 1992, and the
results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
As explained in Notes 2 and 8 to the financial statements, effective
January 1, 1993, Gulf Power Company changed its methods of accounting for
postretirement benefits other than pensions and for income taxes.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
February 16, 1994
II-140
171
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION Gulf Power Company 1993 Annual Report
RESULTS OF OPERATIONS
EARNINGS
Gulf Power Company's net income after preferred stock dividends was $54.3
million for 1993, a $0.2 million increase over 1992 net income. Earnings
reflect a $2.3 million gain on the sale of Gulf States Utilities Company (Gulf
States) stock and the reversal of a $1.7 million wholesale rate refund as the
result of a court order which is further discussed in Note 3 to the financial
statements under "Recovery of Contract Buyout Costs". The company also
experienced growth in residential and commercial sales and a decrease in
interest expense on long-term debt as a result of security refinancings, offset
by higher operation and maintenance expense, and decreased industrial sales
reflecting the loss of the Company's largest industrial customer, Monsanto,
which began cogeneration in August of 1993.
The Company's 1992 net income after dividends on preferred stock
decreased $3.7 million compared to the prior year. The 1991 earnings included
an after-tax gain of $12.7 million representing the settlement of litigation
with Gulf States. See Note 7 to the financial statements under "Gulf States
Settlement Completed" for further details. Excluding this settlement from
1991, earnings for 1992 increased $8.4 million -- or approximately -- 18.7
percent over 1991. This improvement was due to increased energy sales; lower
interest expense and preferred dividends as a result of security refinancings;
and continued emphasis on cost controls.
The Company's return on average common equity was 13.29 percent for
1993, a slight decrease from the 13.62 percent return earned in 1992, which was
up from the 12.03 percent earned in 1991 (excluding the Gulf States
settlement).
REVENUES
Changes in operating revenues over the last three years are the result of the
following factors:
Increase (Decrease)
From Prior Year
1993 1992 1991
(in thousands)
Retail --
Change in base rates $ 1,571 $ 722 $ 3,137
Sales growth 7,671 12,965 2,387
Weather 4,049 (6,448) 1,845
Regulatory cost
recovery and other (3,079) (1,839) 13,947
Total retail 10,212 5,400 21,316
Sales for resale--
Non-affiliates 2,131* 442 (4,219)
Affiliates (909) (5,268) (9,220)
Total Sales for resale 1,222 (4,826) (13,439)
Other operating
revenues 806 5,121 (10,495)
Total operating
revenues $12,240 $ 5,695 $ (2,618)
Percent change 2.1% 1.0% (0.5)%
* Includes the non-interest portion of the wholesale rate refund
reversal discussed in "Earnings."
Retail revenues of $471.7 million in 1993 increased $10.2 million or
2.2 percent from last year, compared with an increase of 1.2 percent in 1992
and 4.9 percent in 1991. Revenues increased in the residential and commercial
classes primarily due to customer growth, and favorable weather and economic
conditions. Revenues in the industrial class declined due to the loss of the
Company's largest industrial customer, Monsanto, which began operating its
cogeneration facility in August 1993. See "Future Earnings Potential" for
further details. The change in base rates for 1993 and 1992 reflects the
expiration of a retail rate penalty in September 1992.
Sales for resale were $95.4 million in 1993, increasing $1.2 million or
1.3 percent over 1992. Sales to affiliated companies vary from year to year
depending on demand and the availability and cost of generating resources at
each company. The majority of non-affiliated energy sales arise from long-term
contractual agreements. Non-affiliated long-term contracts include capacity
and energy components. Capacity revenues reflect the recovery of
II-141
172
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1993 Annual Report
fixed costs and return on investment. Energy is sold at its variable cost.
The capacity and energy components under these long-term contracts were
as follows:
1993 1992 1991
(in thousands)
Capacity $33,805 $34,180 $32,651
Energy 21,202 22,933 23,311
Total $55,007 $57,113 $55,962
Beginning in June 1992, all the capacity from the Company's ownership
portion of Plant Scherer Unit No. 3 was sold through unit power sales,
resulting in increased capacity revenues.
In 1993, changes in other operating revenues are primarily due to the
recognition of $2.6 million under the Environmental Cost Recovery (ECR) clause
which is fully discussed in Note 3 to the financial statements under
"Environmental Cost Recovery", which is offset by true-ups of other regulatory
cost recovery clauses. The increase in other operating revenues in 1992 was
primarily due to true-ups of regulatory cost recovery clauses and the changes
in franchise fee collections and Florida gross receipts taxes (discussed under
"Expenses") which had no effect on earnings.
Energy sales for 1993 and percent changes in sales since 1991 are
reported below.
Amount Percent Change
(millions of
kilowatt-hours) 1993 1993 1992 1991
Residential 3,713 3.2% 4.1% 2.8%
Commercial 2,433 2.7 4.2 2.5
Industrial 2,030 (6.9) 2.9 (2.8)
Other 17 - (2.7) (9.3)
Total retail 8,193 0.4 3.8 1.1
Sales for resale
Non-affiliates 1,460 2.0 (7.7) (12.7)
Affiliates 1,030 (14.8) (2.2) (13.9)
Total 10,683 (1.1) 1.4 (3.1)
Overall retail sales remained relatively flat in 1993. Increases in
residential and commercial sales -- reflecting customer growth, favorable
weather and an improving economy -- were offset by the decreased sales in the
industrial class reflecting the loss of Monsanto. Retail sales increased 3.8
percent in 1992 primarily due to an increase in the number of customers served
and a moderately improving economy.
Energy sales for resale to non-affiliates increased 2.0 percent and are
predominantly unit power sales under long-term contracts to Florida utilities
which are discussed above. Energy sales to affiliated companies vary from year
to year as mentioned above.
EXPENSES
Total operating expenses for 1993 increased $16.6 million or 3.5 percent over
1992 primarily due to increased operation and maintenance expenses and higher
taxes. Other operation expenses increased $10.9 million or 11.1 percent from
the 1992 level. The increase is attributable to additional costs of $7.4
million related to increases in the buyout of coal supply contracts and $1.4
million of environmental clean-up costs. Also, higher employee benefit costs
and the costs of an automotive fleet reduction program increased expenses by
$2.1 million. Operating expenses for 1992 increased by approximately $16
million over 1991. Excluding the Gulf States settlement, an after-tax
reduction of $0.6 million in 1992 and $12.7 million in 1991, 1992 total
operating expenses increased $4.3 million or 0.9 percent over 1991.
Fuel and purchased power expenses decreased $3.8 million or 1.8 percent
from 1992 reflecting the lower cost of fuel. Total 1992 fuel and purchased
power increased $1.4 million or 0.7 percent from 1991.
Maintenance expense increased $4.1 million or 9.7 percent over 1992 due
to scheduled maintenance of production facilities. The 1992 maintenance
expense was down $3.5 million or 7.7 percent from 1991 due to a decrease in
scheduled maintenance.
Federal income taxes increased $0.7 million primarily due to a
corporate federal income tax rate increase from 34 percent to 35 percent
effective January 1993. Taxes other than income taxes increased $2.3 million
in 1993, an increase of 6.1 percent over the 1992 expense
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1993 Annual Report
primarily due to increases in property taxes and gross receipt taxes. Taxes
other than income taxes decreased $4.5 million, or 10.5 percent in 1992
compared to 1991 due primarily to the Company discontinuing the collection of
franchise fees for two Florida counties which was partially offset by an
increase in gross receipt taxes. Changes in franchise fee collections and
gross receipt taxes had no impact on earnings.
Interest expense decreased $3.2 million or 8.1 percent from the 1992
level and 1992 interest expense decreased $5.6 million or 12.5 percent from
1991. The decrease in both years is primarily attributable to refinancing some
of the Company's higher cost securities.
EFFECTS OF INFLATION
The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic
loss because the Company is recovering its cost of investments in dollars that
have less purchasing power. While the inflation rate has been relatively low
in recent years, it continues to have an adverse effect on the Company because
of the large investment in long-lived utility plant. Conventional accounting
for historical cost does not recognize this economic loss nor the partially
offsetting gain that arises through financing facilities with fixed-money
obligations, such as long-term debt and preferred stock. Any recognition of
inflation by regulatory authorities is reflected in the rate of return allowed.
FUTURE EARNINGS POTENTIAL
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends
on a number of factors. It is expected that higher operating costs and
carrying charges on increased investment in plant, if not offset by
proportionate increases in operating revenues (either by periodic rate
increases or increases in sales), will adversely affect future earnings. Growth
in energy sales will be subject to a number of factors, including the volume of
sales to neighboring utilities, energy conservation practiced by customers, the
elasticity of demand, customer growth, weather, competition, and the rate of
economic growth in the service area.
In addition to the traditional factors discussed above, the Energy
Policy Act of 1992 (Energy Act) will have a profound effect on the future of
the electric utility industry. The Energy Act promotes energy efficiency,
alternative fuel use, and increased competition for electric utilities. The
Company is preparing to meet the challenges of a major change in the
traditional business practices of selling electricity. The Energy Act allows
independent power producers (IPPs) to access the Company's transmission network
in order to sell electricity to other utilities, and this may enhance the
incentive for IPPs to build cogeneration plants for the Company's large
industrial and commercial customers and sell excess energy generation to the
Company or other utilities. Although the Energy Act does not require
transmission access to retail customers, pressure for legislation to allow
retail wheeling will continue. If the Company does not remain a low-cost
producer and provide quality service, the Company's retail energy sales growth,
its ability to retain large industrial and commercial customers, and obtain new
long-term contracts for energy sales outside the Company's service area, could
be limited, and this could significantly erode earnings.
The future effect of cogeneration and small-power production facilities
cannot be fully determined at this time, but may be adverse. One effect of
cogeneration which the Company has experienced is the loss of its largest
industrial customer, Monsanto, in August of 1993. The loss of the Monsanto
load reduced revenues, and will result in a reduction in net income of
approximately $3 million in the first twelve months.
The Federal Energy Regulatory Commission (FERC) regulates wholesale
rate schedules and power sales contracts that the Company has with its sales
for resale customers. The FERC is currently reviewing the rate of return on
common equity included in these schedules and contracts that have a return on
common equity of 13.75 percent or greater, and may require such returns to be
lowered, possibly retroactively. See Note 3 to the financial statements under
"FERC Reviews Equity Returns" for additional information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean
Air Act) could reduce earnings if such costs are not fully recovered. The
Clean Air Act is discussed later under "Environmental Matters".
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1993 Annual Report
Also, recently enacted legislation that provides for recovery of prudent
environmental compliance costs is discussed in Note 3 to the financial
statements under "Environmental Cost Recovery."
The Company filed a notice with the Florida Public Service Commission
(FPSC) of its intent to obtain rate relief in February 1993. On May 4, 1993,
the FPSC approved a stipulation between the Company, the Office of Public
Counsel, and the Florida Industrial Power Users Group to cancel the filing of
the rate case. The stipulation also allowed the Company to retain, for the
next four years, its existing method for calculating accruals for future power
plant dismantlement costs. The existing method provides a more even allocation
of expenses over the life of the plants and results in an avoided increase in
expenses of about $6 million annually over the next four years when compared to
the FPSC method. The stipulation also provided for the reduction of the
Company's allowed return on equity midpoint from 12.55 percent to 12.0 percent.
After the February 1993 filing date, interest rates continued to remain low,
resulting in lower cost of capital. Also, the Florida legislature adopted
legislation which allows utilities to petition the FPSC for recovery of
environmental costs through an adjustment clause if these costs are not being
recovered in base rates. See Note 3 to the financial statements under
"Environmental Cost Recovery" for further details. The combination of the
circumstances discussed above, placed the Company in a better position to
manage its finances without an increase in base rates while still providing a
fair return for the Company's investors. Consequently, the Company agreed, as
a part of this stipulation, to cancel the filing of the rate case.
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112,
Employers' Accounting for Postemployment Benefits, which must be effective by
1994. The new standard requires that all types of benefits provided to former
or inactive employees and their families prior to retirement be accounted for
on an accrual basis. These benefits include salary continuation, severance
pay, supplemental benefits, disability-related benefits, job training, and
health and life insurance coverage. In 1993, the Company adopted Statement No.
112, which resulted in a decrease in earnings of $0.3 million.
The FASB has issued Statement No. 115, Accounting for Certain
Investments in Debt and Equity Securities, which is effective in 1994.
Statement No. 115 supersedes FASB Statement No. 12, Accounting for Certain
Marketable Securities. The Company does not have any investments that qualify
for FASB Statement No. 115 treatment.
FINANCIAL CONDITION
OVERVIEW
The principal changes in the Company's financial condition during 1993 were
gross property additions of $79 million. Funds for these additions were
provided by internal sources. The Company continued to refinance higher cost
securities to lower the Company's cost of capital. See "Financing Activities"
below and the Statements of Cash Flows for further details.
On January 1, 1993, the Company changed its method of calculating the
accruals for postretirement benefits other than pensions and its method of
accounting for income taxes. See Notes 2 and 8 to the financial statements,
regarding the impact of these changes.
FINANCING ACTIVITIES
As mentioned above, the Company continued to lower its financing costs by
issuing new securities and other debt, and retiring higher-cost issues in 1993.
The Company sold $75 million of first mortgage bonds and, through public
authorities, $53.4 million of pollution control revenue bonds, issued $35
million of preferred stock, and obtained $25 million with a long-term bank
note. Retirements, including maturities during 1993, totaled $88.8 million of
first mortgage bonds, $40.7 million of pollution control revenue bonds, and
$21.1 million of preferred stock. (See the Statements of Cash Flows for
further details.)
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1993 Annual Report
Composite financing rates for the years 1991 through 1993 as of year
end were as follows:
1993 1992 1991
Composite interest rate on 7.1% 8.0% 8.4%
long-term debt
Composite preferred stock 6.5% 7.3% 8.0%
dividend rate
CAPITAL REQUIREMENTS FOR CONSTRUCTION
The Company's gross property additions, including those amounts related to
environmental compliance, are budgeted at $200 million for the three years
beginning 1994 ($77 million in 1994, $55 million in 1995, and $68 million in
1996). The estimates of property additions for the three-year period include
$25 million committed to meeting the requirements of the Clean Air Act, the
cost of which is expected to be recovered through the ECR clause which is
discussed in Note 3 to the financial statements under "Environmental Cost
Recovery". Actual construction costs may vary from this estimate because of
factors such as the granting of timely and adequate rate increases; changes in
environmental regulations; revised load projections; the cost and efficiency of
construction labor, equipment, and materials; and the cost of capital.
The Company does not have any baseload generating plants under
construction. However, the Company plans to construct two 80 megawatt
combustion turbine peaking units. The first is scheduled to be completed in
1998, and the second in 1999. Significant construction of transmission and
distribution facilities and upgrading of generating plants will be continuing.
OTHER CAPITAL REQUIREMENTS
In addition to the funds needed for the construction program, approximately $86
million will be required by the end of 1996 in connection with maturities of
long-term debt and preferred stock subject to mandatory redemption. Also, the
Company plans to continue a program to retire higher-cost debt and preferred
stock and replace these obligations with lower-cost capital.
ENVIRONMENTAL MATTERS
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law -- will have a
significant impact on the Company. Specific reductions in sulfur dioxide and
nitrogen oxide emissions from fossil-fired generating plants will be required
in two phases. Phase I compliance must be implemented in 1995 and affects
eight generating plants -- some 10,000 megawatts of capacity or 35 percent of
total capacity -- in the Southern electric system. Phase II compliance is
required in 2000, and all fossil-fired generating plants in the Southern
electric system will be affected.
Beginning in 1995, the Environmental Protection Agency (EPA) will
allocate annual sulfur dioxide emission allowances through the newly
established allowance trading program. An emission allowance is the authority
to emit one ton of sulfur dioxide during a calendar year. The method for
allocating allowances is based on the fossil fuel consumed from 1985 through
1987 for each affected generating unit. Emission allowances are transferable
and can be bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize
the cost of compliance. The market for emission allowances is developing
slower than expected. However, The Southern Company's sulfur dioxide
compliance strategy is designed to take advantage of allowances as the market
develops.
The Southern Company expects to achieve Phase I sulfur dioxide
compliance at the eight affected plants by switching to low-sulfur coal, and
this has required some equipment upgrades. This compliance strategy is
expected to result in unused emission allowances being banked for later use.
Additional construction expenditures are required to install equipment for the
control of nitrogen oxide emissions at these eight plants. Also, continuous
emissions monitoring equipment would be installed on all fossil-fired units.
Under this Phase I compliance approach, additional construction expenditures
are estimated to total approximately $275 million for The Southern Company
including $34 million for Gulf Power Company through 1995.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1993 Annual Report
Phase II compliance costs are expected to be higher because
requirements are stricter and all fossil-fired generating plants are affected.
For sulfur dioxide compliance, The Southern Company could use emission
allowances banked during Phase I, increase fuel switching, install flue gas
desulfurization equipment at selected plants, and/or purchase more allowances
depending on the price and availability of allowances. Also, in Phase II,
equipment to control nitrogen oxide emissions will be installed on additional
system fossil-fired plants as required to meet anticipated Phase II limits.
Therefore, during the period 1996 to 2000, compliance could require total
construction expenditures ranging from approximately $450 million to $800
million for The Southern Company including approximately $30 million to $40
million for Gulf Power Company. However, the full impact of Phase II
compliance cannot now be determined with certainty, pending the development of
a market for emission allowances, the completion of EPA regulations, and the
possibility of new emission reduction technologies.
Following adoption of legislation in April of 1992, allowing electric
utilities in Florida to seek FPSC approval of their Clean Air Act Compliance
Plans, the Company filed its petition for approval. The Commission approved
the Company's plan for Phase I compliance, deferring until a later date
approval of its Phase II Plan.
An average increase of up to 4 percent in annual revenue requirements
from Gulf Power Company customers could be necessary to fully recover the cost
of compliance for both Phase I and Phase II of the Clean Air Act. Compliance
costs include construction expenditures, increased costs for switching to
low-sulfur coal, and costs related to emission allowances.
The Florida Legislature recently adopted legislation that allows a
utility to petition the FPSC for recovery of prudent environmental compliance
costs through an ECR clause without lengthy regulatory full revenue
requirements rate proceedings. The legislation is discussed in Note 3 to the
financial statements under "Environmental Cost Recovery".
Title III of the Clean Air Act requires a multi-year EPA study of power
plant emissions of hazardous air pollutants. The study will serve as the basis
for a decision on whether additional regulatory control of these substances is
warranted. Compliance with any new control standards could result in
significant additional costs. The impact of new standards -- if any -- will
depend on the development and implementation of applicable regulations.
The EPA continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study on
the impact of a new standard indicate that a number of plants could be required
to install sulfur dioxide controls. These controls would be in addition to the
controls already required to meet the acid rain provision of the Clean Air Act.
The EPA is expected to take some action on this issue in 1994. The impact of
any new standard will depend on the level chosen for the standard and cannot be
determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air
quality standards for particulate matter, nitrogen oxides, and ozone. The
impact of any new standard will depend on the level chosen for the standard and
cannot be determined at this time.
In 1994 or 1995, the EPA is expected to issue revised rules on air
quality control regulations related to stack height requirements of the Clean
Air Act. The full impact of the final rules cannot be determined at this time,
pending their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of
coal ash. However, the EPA has until 1998 to classify co-managed utility
wastes -- coal ash and other utility wastes -- as either non-hazardous or
hazardous. If the EPA classifies the co-managed wastes as hazardous, then
substantial additional costs for the management of such wastes may be required.
The full impact of any change in the regulatory status will depend on the
subsequent development of co-managed waste requirements.
Gulf Power Company must comply with other environmental laws and
regulations that cover the handling and disposal of hazardous waste. Under
these various laws and regulations, the Company could incur costs to clean up
properties currently or previously owned. The Company conducts studies to
determine the extent of any required clean-up costs and has recognized in the
financial statements costs to clean up known sites.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1993 Annual Report
Several major pieces of environmental legislation are in the process of
being reauthorized or amended by Congress. These include: the Clean Water
Act; the Comprehensive Environmental Response, Compensation, and Liability Act;
and the Resource Conservation and Recovery Act. Changes to these laws could
affect many areas of Gulf Power Company's operations. The full impact of these
requirements cannot be determined at this time, pending the development and
implementation of applicable regulations.
Compliance with possible new legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect Gulf Power Company. The impact of new legislation
- -- if any -- will depend on the subsequent development and implementation of
applicable regulations. In addition, the potential for lawsuits alleging
damages caused by electromagnetic fields exists.
COAL STOCKPILE DECREASES
To reduce the working capital invested in the coal stockpile inventory, the
Company implemented a coal stockpile reduction program in 1992. The Company's
actual year end inventory at December 31, 1993 was $20.7 million which is
considerably lower than the desired level of $31.4 million. This situation
exists because a limited supply of coal was available at competitive prices
primarily due to the United Mine Workers strike from July to December 1993. In
addition, barge transportation was stranded due to floods in the Midwest. As a
result of these circumstances, management chose to allow the existing coal
inventory to decline until coal prices stabilized. Current market conditions
indicate that substantial coal supplies at competitive prices are now
available. Therefore, the Company plans to increase purchases and return the
coal stockpile inventory to the desired level by the end of the third quarter,
1994.
SOURCES OF CAPITAL
At December 31, 1993, the Company had $5.6 million of cash and cash equivalents
to meet its short-term cash needs.
It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulations, will be derived
from operations; the sale of additional first mortgage bonds, pollution control
bonds, and preferred stock; and capital contributions from The Southern
Company. The Company is required to meet certain coverage requirements
specified in its mortgage indenture and corporate charter to issue new first
mortgage bonds and preferred stock. The Company's coverage ratios are
sufficient to permit, at present interest and preferred dividend levels, any
foreseeable security sales. The amount of securities which the Company will be
permitted to issue in the future will depend upon market conditions and other
factors prevailing at that time.
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STATEMENTS OF INCOME
For the Years Ended December 31, 1993, 1992, and 1991
Gulf Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
OPERATING REVENUES:
Revenues $ 559,976 $ 546,827 $ 535,864
Revenues from affiliates 23,166 24,075 29,343
Total operating revenues 583,142 570,902 565,207
OPERATING EXPENSES:
Operation-
Fuel 170,485 182,754 176,038
Purchased power from non-affiliates 4,386 1,394 896
Purchased power from affiliates 32,273 26,788 32,579
Proceeds from settlement of disputed contracts (Note 7) - (920) (20,385)
Other 109,164 98,230 94,411
Maintenance 46,004 41,947 45,468
Depreciation and amortization 55,309 53,758 52,195
Taxes other than income taxes 40,204 37,898 42,359
Federal and state income taxes (Note 8) 32,730 32,078 33,893
Total operating expenses 490,555 473,927 457,454
OPERATING INCOME 92,587 96,975 107,753
OTHER INCOME (EXPENSE):
Allowance for equity funds used during
construction (Note 1) 512 14 54
Interest income 1,328 2,733 2,427
Other, net (1,238) (1,487) (3,484)
Gain on sale of investment securities 3,820 - -
Income taxes applicable to other income (921) 187 1,104
INCOME BEFORE INTEREST CHARGES 96,088 98,422 107,854
INTEREST CHARGES:
Interest on long-term debt 31,344 35,792 41,665
Allowance for debt funds used during
construction (Note 1) (454) (46) (95)
Interest on notes payable 870 1,041 280
Amortization of debt discount, premium, and expense, net 1,412 1,032 699
Other interest charges 2,877 1,410 2,272
Net interest charges 36,049 39,229 44,821
NET INCOME 60,039 59,193 63,033
DIVIDENDS ON PREFERRED STOCK 5,728 5,103 5,237
NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 54,311 $ 54,090 $ 57,796
The accompanying notes are an integral part of these statements.
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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1993, 1992, and 1991
Gulf Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
OPERATING ACTIVITIES:
Net income $ 60,039 $ 59,193 $ 63,033
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 72,111 68,021 65,584
Deferred income taxes and investment tax credits 5,347 3,322 (3,392)
Allowance for equity funds used during construction (512) (14) (54)
Non-cash proceeds from settlement of disputed contracts (Note 7) - (920) (19,734)
Other, net (864) 185 3,079
Changes in certain current assets and liabilities --
Receivables, net 12,867 (11,041) 12,421
Inventories 5,574 23,560 (2,397)
Payables 5,386 1,580 (2,003)
Other (9,504) (13,637) 8,012
Net cash provided from operating activities 150,444 130,249 124,549
INVESTING ACTIVITIES:
Gross property additions (78,562) (64,671) (64,323)
Other (5,328) 3,970 (8,097)
Net cash used for investing activities (83,890) (60,701) (72,420)
FINANCING ACTIVITIES AND CAPITAL CONTRIBUTIONS:
Proceeds:
Preferred stock 35,000 29,500 -
First mortgage bonds 75,000 25,000 50,000
Pollution control bonds 53,425 8,930 21,200
Capital contributions from parent 11 121 -
Other long-term debt 25,000 - -
Retirements:
Preferred stock (21,060) (15,500) (2,500)
First mortgage bonds (88,809) (117,693) (32,807)
Pollution control bonds (40,650) (9,205) (21,250)
Other long-term debt (7,736) (5,783) (7,981)
Notes payable, net (37,947) 44,000 -
Payment of preferred stock dividends (5,728) (5,103) (5,237)
Payment of common stock dividends (41,800) (39,900) (38,000)
Miscellaneous (6,888) (8,760) (3,715)
Net cash used for financing activities (62,182) (94,393) (40,290)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 4,372 (24,845) 11,839
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 1,204 26,049 14,210
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 5,576 $ 1,204 $ 26,049
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for --
Interest (net of amount capitalized) $28,470 $38,164 $39,814
Income taxes $27,865 $37,569 $26,915
( ) Denotes use of cash.
The accompanying notes are an integral part of these statements.
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BALANCE SHEETS
At December 31, 1993 and 1992
Gulf Power Company 1993 Annual Report
ASSETS 1993 1992
(in thousands)
UTILITY PLANT:
Plant in service (Notes 1 and 6) $ 1,611,704 $ 1,561,491
Less accumulated provision for depreciation 610,542 578,851
1,001,162 982,640
Construction work in progress 34,591 29,564
Total 1,035,753 1,012,204
Less property-related accumulated deferred income taxes (Note 8) - 200,904
Total 1,035,753 811,300
OTHER PROPERTY AND INVESTMENTS 13,242 7,074
CURRENT ASSETS:
Cash and cash equivalents 5,576 1,204
Investment securities (Notes 1 and 7) - 22,322
Receivables-
Customer accounts receivable 57,226 55,103
Other accounts and notes receivable 5,904 3,237
Affiliated companies 1,241 2,063
Accumulated provision for uncollectible accounts (447) (356)
Fossil fuel stock, at average cost 20,652 29,492
Materials and supplies, at average cost 36,390 33,124
Current portion of deferred coal contract costs (Note 5) 12,535 3,071
Regulatory clauses under recovery (Note 1) 3,244 1,680
Prepayments 2,160 1,395
Vacation pay deferred (Note 1) 4,022 3,779
Total 148,503 156,114
DEFERRED CHARGES:
Deferred charges related to income taxes (Note 8) 31,334 -
Debt expense, being amortized 3,693 3,253
Premium on reacquired debt, being amortized 17,554 15,319
Deferred coal contract costs (Note 5) 52,884 63,723
Miscellaneous 4,846 5,916
Total 110,311 88,211
TOTAL ASSETS $ 1,307,809 $ 1,062,699
The accompanying notes are an integral part of these statements.
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181
BALANCE SHEETS (continued)
At December 31, 1993 and 1992
Gulf Power Company 1993 Annual Report
CAPITALIZATION AND LIABILITIES 1993 1992
(in thousands)
CAPITALIZATION (SEE ACCOMPANYING STATEMENTS):
Common stock equity (Note 11) $ 414,196 $ 403,190
Preferred stock 89,602 74,662
Preferred stock subject to mandatory redemption 1,000 2,000
Long-term debt 369,259 382,047
Total 874,057 861,899
CURRENT LIABILITIES:
Preferred stock due within one year 1,000 1,000
Long-term debt due within one year (Note 10) 41,552 13,820
Notes payable 6,053 44,000
Accounts payable-
Affiliated companies 18,560 5,323
Other 20,139 28,138
Customer deposits 15,082 15,532
Taxes accrued-
Federal and state income 10,330 3,326
Other 2,685 8,093
Interest accrued 5,420 6,370
Regulatory clauses over recovery (Note 1) 840 -
Vacation pay accrued (Note 1) 4,022 3,779
Miscellaneous 8,527 3,950
Total 134,210 133,331
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes (Note 8) 151,743 -
Deferred credits related to income taxes (Note 8) 76,876 -
Accumulated deferred investment tax credits 40,770 43,117
Accumulated provision for property damage (Note 1) 10,509 9,692
Accumulated provision for postretirement benefits (Note 2) 10,749 7,662
Miscellaneous 8,895 6,998
Total 299,542 67,469
COMMITMENTS AND CONTINGENT MATTERS (NOTES 1, 2, 3, 4, 5, AND 7)
TOTAL CAPITALIZATION AND LIABILITIES $ 1,307,809 $ 1,062,699
The accompanying notes are an integral part of these statements.
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STATEMENTS OF CAPITALIZATION
At December 31, 1993 and 1992
Gulf Power Company 1993 Annual Report
1993 1992 1993 1992
(in thousands) (percent of total)
COMMON STOCK EQUITY:
Common stock, without par value --
Authorized and outstanding --
992,717 shares in 1993 and 1992 $ 38,060 $ 38,060
Paid-in capital 218,282 218,271
Premium on preferred stock 81 88
Retained earnings (Note 11) 157,773 146,771
Total common stock equity 414,196 403,190 47.4 % 46.8 %
CUMULATIVE PREFERRED STOCK:
$10 par value, authorized 10,000,000 shares,
Outstanding 2,580,000 shares at December 31, 1993
$25 stated capital --
7.00% 14,500 14,500
7.30% 15,000 15,000
6.72% 20,000 -
Adjustable Rate -- at January 1, 1994: 4.80% 15,000 -
$100 par value --
Authorized -- 781,626 shares
Outstanding -- 251,026 shares at December 31, 1993
4.64% 5,102 5,102
5.16% 5,000 5,000
5.44% 5,000 5,000
7.52% 5,000 5,000
7.88% 5,000 5,000
8.28% - 15,000
8.52% - 5,060
Total (annual dividend requirement -- $5,711,000) 89,602 74,662 10.3 8.7
CUMULATIVE PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION:
$100 par value --
Authorized -- 20,000 shares
Outstanding -- 20,000 shares at December 31, 1993
11.36% Series 2,000 3,000
Total (annual dividend requirement -- $227,000) 2,000 3,000
Less amount due within one year 1,000 1,000
Total excluding amount due within one year 1,000 2,000 0.1 0.2
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STATEMENTS OF CAPITALIZATION (CONTINUED)
At December 31, 1993 and 1992
Gulf Power Company 1993 Annual Report
1993 1992 1993 1992
(in thousands) (percent of total)
First mortgage bonds --
Maturity Interest Rates
October 1, 1994 4 5/8% 12,000 12,000
June 1, 1996 6% 15,000 15,000
August 1, 1997 5 7/8% 25,000 25,000
April 1, 1998 9.20% 19,486 22,845
April 1, 1998 5.55% 15,000 -
July 1, 1998 5.00% 30,000 -
1999 through 2003 6.125% to 8.875% 30,000 83,000
September 1, 2008 9% 5,050 7,500
December 1, 2021 8 3/4% 50,000 50,000
Total first mortgage bonds 201,536 215,345
Pollution control obligations (Note 9) 169,855 157,080
Other long-term debt (Note 9) 42,520 25,256
Unamortized debt premium (discount), net (3,100) (1,814)
Total long-term debt (annual interest
requirement -- $29,378,000) 410,811 395,867
Less amount due within one year (Note 10) 41,552 13,820
Long-term debt excluding amount due within one year 369,259 382,047 42.2 44.3
TOTAL CAPITALIZATION $ 874,057 $ 861,899 100.0 % 100.0 %
The accompanying notes are an integral part of these statements.
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STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1993, 1992, and 1991
Gulf Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
BALANCE AT BEGINNING OF YEAR $ 146,771 $ 134,372 $ 114,576
Net income after dividends on preferred stock 54,311 54,090 57,796
Cash dividends on common stock (41,800) (39,900) (38,000)
Preferred stock transactions, net (1,509) (1,791) -
BALANCE AT END OF YEAR (NOTE 11) $ 157,773 $ 146,771 $ 134,372
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1993, 1992, and 1991
Gulf Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
BALANCE AT BEGINNING OF YEAR $ 218,271 $ 218,150 $ 218,150
Contributions to capital by parent company 11 121 -
BALANCE AT END OF YEAR $ 218,282 $ 218,271 $ 218,150
The accompanying notes are an integral part of these statements.
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NOTES TO FINANCIAL STATEMENTS
At December 31, 1993, 1992 and 1991
Gulf Power Company 1993 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
GENERAL
Gulf Power Company is a wholly owned subsidiary of The Southern Company, which
is the parent company of five operating companies, Southern Company Services,
Inc. (SCS), Southern Electric International (Southern Electric), Southern
Nuclear Operating Company (Southern Nuclear) and various other subsidiaries
related to foreign utility operations and domestic non-utility operations. At
this time, the operations of the other subsidiaries are not material. The
operating companies (Alabama Power Company, Georgia Power Company, Gulf Power
Company, Mississippi Power Company, and Savannah Electric and Power Company)
provide electric service in four Southeastern states. Contracts among the
companies -- dealing with jointly owned generating facilities, interconnecting
transmission lines, and the exchange of electric power -- are regulated by the
Federal Energy Regulatory Commission (FERC) or the Securities and Exchange
Commission. SCS provides, at cost, specialized services to The Southern
Company and to the subsidiary companies. Southern Electric designs, builds,
owns and operates power production facilities and provides a broad range of
technical services to industrial companies and utilities in the United States
and a number of international markets. Southern Nuclear provides services to
The Southern Company's nuclear power plants.
The Southern Company is registered as a holding company under the
Public Utility Holding Company Act of 1935 (PUHCA). Both The Southern Company
and its subsidiaries are subject to the regulatory provisions of the PUHCA.
The Company is also subject to regulation by the FERC and the Florida Public
Service Commission (FPSC). The Company follows generally accepted accounting
principles and complies with the accounting policies and practices prescribed
by these commissions.
Certain prior years' data presented in the financial statements have
been reclassified to conform with current year presentation.
REVENUES AND FUEL COSTS
The Company accrues revenues for service rendered but unbilled at the end of
each fiscal period. Fuel costs are expensed as fuel is used. The Company's
electric rates include provisions to periodically adjust billings for
fluctuations in fuel and the energy component of purchased power costs.
Revenues are adjusted for differences between recoverable fuel costs and
amounts actually recovered in current rates. The FPSC has also approved the
recovery of purchased power capacity costs, energy conservation costs, and
environmental compliance costs in cost recovery clauses that are similar to the
method used to recover fuel costs.
DEPRECIATION AND AMORTIZATION
Depreciation of the original cost of depreciable utility plant in service is
provided primarily using composite straight-line rates which approximated 3.8
percent in 1993, 1992, and 1991. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its cost --
together with the cost of removal, less salvage -- is charged to the
accumulated provision for depreciation. Minor items of property included in
the original cost of the plant are retired when the related property unit is
retired.
INCOME TAXES
The Company provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
In years prior to 1993, income taxes were accounted for and reported
under Accounting Principles Board Opinion No. 11. Effective January 1, 1993,
the Company adopted FASB Statement No. 109, Accounting for Income Taxes.
Statement No. 109 required, among other things, conversion to the liability
method of accounting for accumulated deferred income taxes. See Note 8 for
additional information about Statement No. 109. The Company is included in the
consolidated federal income tax return of The Southern Company.
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NOTES (CONTINUED)
Gulf Power Company 1993 Annual Report
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of certain new facilities. While cash is
not realized currently from such allowance, it increases the revenue
requirement over the service life of plant through a higher rate base and
higher depreciation expense. The FPSC-approved composite rate used to
calculate AFUDC was 7.27 percent effective on July 1, 1993 and 8.03 percent for
the first half of 1993, and for 1992, and 1991. AFUDC amounts for 1993, 1992,
and 1991 were $966 thousand, $60 thousand, and $149 thousand, respectively.
The increase in 1993 is due to an increase in construction projects at Plant
Daniel.
UTILITY PLANT
Utility plant is stated at original cost. Original cost includes: materials;
labor; minor items of property; appropriate administrative and general costs;
payroll-related costs such as taxes, pensions, and other benefits; and the
estimated cost of funds used during construction. The cost of maintenance,
repairs, and replacement of minor items of property is charged to maintenance
expense. The cost of replacements of property (exclusive of minor items of
property) is charged to utility plant.
CASH AND CASH EQUIVALENTS
For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
FINANCIAL INSTRUMENTS
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, all financial instruments of the Company -- for which
the carrying amount does not approximate fair value -- are shown in the table
below as of December 31:
1993
Carrying Fair
Amount Value
(in thousands)
Long-term debt $410,811 $431,251
Preferred stock subject to
mandatory redemption 2,000 2,040
1992
Carrying Fair
Amount Value
(in thousands)
Investment securities $ 22,322 $ 26,387
Long-term debt 395,867 410,724
Preferred stock subject to
mandatory redemption 3,000 3,060
The fair values of investment securities were based on listed closing
market prices. The fair values for long-term debt and preferred stock subject
to mandatory redemption were based on either closing market prices or closing
prices of comparable instruments.
MATERIALS AND SUPPLIES
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to
inventory when purchased and then expensed or capitalized to plant, as
appropriate, when installed.
VACATION PAY
The Company's employees earn their vacation in one year and take it in the
subsequent year. However, for ratemaking purposes, vacation pay is recognized
as an allowable expense only when paid. Consistent with this ratemaking
treatment, the Company accrues a current liability for earned vacation pay and
records a current asset representing the future recoverability of this cost.
The amount was $4.0 million and $3.8 million at December 31, 1993 and 1992,
respectively. In 1994, an estimated 84 percent of the 1993 deferred vacation
cost
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NOTES (CONTINUED)
Gulf Power Company 1993 Annual Report
will be expensed and the balance will be charged to construction.
PROVISION FOR INJURIES AND DAMAGES
The Company is subject to claims and suits arising in the ordinary course of
business. As permitted by regulatory authorities, the Company is providing for
the uninsured costs of injuries and damages by charges to income amounting to
$1.2 million annually. The expense of settling claims is charged to the
provision to the extent available. The accumulated provision of $2.2 million
and $2.5 million at December 31, 1993 and 1992, respectively, is included in
miscellaneous current liabilities in the accompanying Balance Sheets.
PROVISION FOR PROPERTY DAMAGE
Due to a significant increase in the cost of traditional insurance, effective
in 1993, the Company became self-insured for the full cost of storm and other
damage to its transmission and distribution property. As permitted by
regulatory authorities, the Company provides for the estimated cost of
uninsured property damage by charges to income amounting to $1.2 million
annually. At December 31, 1993 and 1992, the accumulated provision for
property damage amounted to $10.5 million and $9.7 million, respectively. The
expense of repairing such damage as occurs from time to time is charged to the
provision to the extent it is available.
2. RETIREMENT BENEFITS:
PENSION PLAN
The Company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. Benefits are based on the greater
of amounts resulting from two different formulas: years of service and final
average pay or years of service and a flat-dollar benefit. The Company uses
the "entry age normal method with a frozen initial liability" actuarial method
for funding purposes, subject to limitations under federal income tax
regulations. Amounts funded to the pension trust fund are primarily invested
in equity and fixed-income securities. FASB Statement No. 87, Employers'
Accounting for Pensions, requires use of the "projected unit credit" actuarial
method for financial reporting purposes.
POSTRETIREMENT BENEFITS
The Company also provides certain medical care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits when they retire. A qualified trust for medical benefits has been
established for funding amounts to the extent deductible under federal income
tax regulations. Amounts funded are primarily invested in debt and equity
securities. Accrued costs of life insurance benefits, other than current cash
payments for retirees, currently are not being funded.
Effective January 1, 1993, the Company adopted FASB Statement No. 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions, on a
prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service." Prior to the
adoption of Statement No. 106, Gulf Power Company recognized these benefit
costs on an accrual basis using the "aggregate cost" actuarial method, which
spreads the expected cost of such benefits over the remaining periods of
employees' service as a level percentage of payroll costs. The costs of such
benefits recognized by the Company in 1993, 1992, and 1991 were $3.9 million,
$3.1 million, and $2.7 million, respectively.
STATUS AND COST OF BENEFITS
Shown in the following tables are actuarial results and assumptions for pension
and postretirement medical and life insurance benefits as computed under the
requirements of Statement Nos. 87 and 106, respectively. Retiree medical and
life insurance information is shown only for 1993 because Statement No. 106 was
adopted as of January 1, 1993, on a prospective basis.
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NOTES (CONTINUED)
Gulf Power Company 1993 Annual Report
The funded status of the plans at December 31 was as follows:
Pension
1993 1992
(in thousands)
Actuarial present value of
benefit obligation:
Vested benefits $ 73,925 $ 63,459
Non-vested benefits 3,217 2,900
Accumulated benefit obligation 77,142 66,359
Additional amounts related to
projected salary increases 25,648 28,719
Projected benefit obligation 102,790 95,078
Less:
Fair value of plan assets 159,192 142,614
Unrecognized net gain (49,376) (40,764)
Unrecognized prior service cost 3,152 3,346
Unrecognized transition asset (8,765) (9,495)
Prepaid asset recognized in
the Balance Sheets $ 1,413 $ 623
Postretirement
Medical Life
1993 1993
(in thousands)
Actuarial present value of
benefit obligation:
Retirees and dependents $ 7,857 $ 2,929
Employees eligible to retire 4,054 -
Other employees 14,927 5,058
Accumulated benefit obligation 26,838 7,987
Less:
Fair value of plan assets 5,638 52
Unrecognized net loss (gain) 2,653 (641)
Unrecognized transition
obligation 13,420 2,954
Accrued liability recognized
in the Balance Sheets $ 5,127 $ 5,622
The weighted average rates assumed in the actuarial calculations were:
1993 1992 1991
Discount 7.5% 8.0% 8.0%
Annual salary increase 5.0% 6.0% 6.0%
Long-term return on plan
assets 8.5% 8.5% 8.5%
An additional assumption used in measuring the accumulated
postretirement medical benefit obligation was a weighted average medical care
cost trend rate of 11.3 percent for 1993, decreasing to 6.0 percent through the
year 2000 and remaining at that level thereafter. An annual increase in the
assumed medical care cost trend rate by 1.0 percent would increase the
accumulated medical benefit obligation as of December 31, 1993, by $4.8 million
and the aggregate of the service and interest cost components of the net
retiree medical cost by $543 thousand.
Components of the plans' net cost are shown below:
Pension
1993 1992 1991
(in thousands)
Benefits earned during
the year $ 3,710 $ 3,550 $ 3,396
Interest cost on projected
benefit obligation 7,319 6,939 6,516
Actual return on plan
assets (20,672) (6,431) (35,560)
Net amortization and
deferral 8,853 (4,054) 26,322
Net pension cost (income) $ (790) $ 4 $ 674
Of the above net pension amounts, $(601) thousand in 1993, $3 thousand
in 1992, and $518 thousand in 1991, were recorded in operating expenses, and
the remainder was recorded in construction and other accounts.
Postretirement
Medical Life
1993 1993
(in thousands)
Benefits earned during the year $ 874 $ 292
Interest cost on accumulated
benefit obligation 1,714 625
Amortization of transition
obligation over 20 years 706 148
Actual return on plan assets (726) (5)
Net amortization and deferral 309 1
Net postretirement cost $2,877 $1,061
Of the above net postretirement medical and life insurance amounts
recorded in 1993, $3.0 million was recorded in operating expenses, and the
remainder was recorded in construction and other accounts.
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NOTES (CONTINUED)
Gulf Power Company 1993 Annual Report
3. LITIGATION AND REGULATORY MATTERS:
COAL BARGE TRANSPORTATION SUIT
On August 19, 1993, a complaint against the Company and Southern Company
Services, an affiliate, was filed in federal district court in Ohio by two
companies with which the Company had contracted for the transportation by barge
for certain of the Company's coal supplies. The complaint alleges breach of
the contract by the Company and seeks damages estimated by the plaintiffs to be
in excess of $85 million.
The final outcome of this matter cannot now be determined; however, in
management's opinion the final outcome will not have a material adverse effect
on the Company's financial statements.
FPSC APPROVES STIPULATION
In February 1993, the Company filed a notice with the FPSC of its intent to
obtain rate relief. On May 4, 1993, the FPSC approved a stipulation between
the Company, the Office of Public Counsel, and the Florida Industrial Power
Users Group to cancel the filing of the rate case and to allow the Company to
retain for the next four years its existing method for calculating accruals for
future power plant dismantlement costs. The stipulation also required the
reduction of the Company's allowed return on equity midpoint from 12.55 percent
to 12.0 percent. See Management's Discussion and Analysis under "Future
Earnings Potential" for further details of circumstances that contributed to
the company canceling the rate case.
FERC REVIEWS EQUITY RETURNS
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the Southern electric system's wholesale rate schedules and
contracts that have a return on common equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power and other similar contracts. Any
changes in the rate of return on common equity that may occur as a result of
this proceeding would be effective 60 days after a proper notice of the
proceeding is published. A notice was published on May 10, 1991.
In August 1992, a FERC administrative law judge issued an opinion that
changes in rate schedules and contracts were not necessary and that the FERC
staff failed to show how any changes were in the public interest. The FERC
staff has filed exceptions to the administrative law judge's opinion, and the
matter remains pending before the FERC.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the Company's financial statements.
RECOVERY OF CONTRACT BUYOUT COSTS
In July 1990, the Company filed a request for waiver of FERC's fuel adjustment
charge regulation to permit recovery of coal contract buyout costs from
wholesale customers. On April 4, 1991, the FERC issued an order granting
recovery of the buyout costs from wholesale customers from July 19, 1990,
forward, but denying retroactive recovery of the buyout costs from January 1,
1987 through July 18, 1990. The Company's request for rehearing was denied by
the FERC. The Company refunded $2.7 million (including interest) in June 1991
to its wholesale customers. On July 31, 1991, the Company filed a petition for
review of the FERC's decision to the U.S. Court of Appeals for the District of
Columbia Circuit. On January 22, 1993, the Court vacated the Commission's
order, finding FERC's denial of the Company's request for a retroactive waiver
to be arbitrary and capricious. The Court remanded the matter to FERC for
consideration consistent with its opinion. Management expects that the
commission will ultimately allow the Company to recover the amount refunded
plus interest. Accordingly, the Company recorded the reversal of the $2.7
million refund to income in 1993.
ENVIRONMENTAL COST RECOVERY
In April 1993, the Florida Legislature adopted legislation for an Environmental
Cost Recovery (ECR) clause, which allows a utility to petition the FPSC for
recovery of all prudent environmental compliance costs that are not being
recovered through base rates or any other rate-adjustment clause. Such
environmental costs include operation and maintenance expense, depreciation,
and a return on invested capital.
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NOTES (CONTINUED)
Gulf Power Company 1993 Annual Report
On January 12, 1994, the FPSC approved the Company's petition under
the ECR clause for recovery of environmental costs that were projected to be
incurred from July 1993 through September 1994. The order allows the recovery
from customers of such costs amounting to $7.8 million during the period,
February through September 1994. Thereafter, recovery under ECR will be
determined semi-annually and will include a true-up of the prior period and a
projection of the ensuing six-month period. In December 1993, the Company
recorded $2.6 million as additional revenue for the portion of costs incurred
during 1993.
4. CONSTRUCTION PROGRAM:
The Company is engaged in a continuous construction program, the cost of which
is currently estimated to total $77 million in 1994, $55 million in 1995, and
$68 million in 1996. These estimates include AFUDC of approximately $0.7
million, $0.3 million, and $0.2 million, in 1994, 1995, and 1996, respectively.
The construction program is subject to periodic review and revision, and actual
construction costs may vary from the above estimates because of numerous
factors. These factors include changes in business conditions; revised load
growth estimates; changes in environmental regulations; increasing costs of
labor, equipment and materials; and cost of capital. The Company does not have
any new baseload generating plants under construction. However, the Company
plans to construct two 80 megawatt combustion turbine peaking units. The first
is scheduled to be completed in 1998, and the second in 1999. In addition,
significant construction will continue related to transmission and distribution
facilities and the upgrading and extension of the useful lives of generating
plants.
See Management's Discussion and Analysis under "Environmental Matters"
for information on the impact of the Clean Air Act Amendments of 1990 and other
environmental matters.
5. FINANCING AND COMMITMENTS:
GENERAL
Current projections indicate that funds required for construction and other
purposes, including compliance with environmental regulations will be derived
primarily from internal sources. Requirements not met from internal sources
will be financed from the sale of additional first mortgage bonds, preferred
stock, and capital contributions from The Southern Company. In addition, the
Company may issue additional long-term debt and preferred stock primarily for
the purposes of debt maturities and redemptions of higher-cost securities.
Because of the attractiveness of current short term interest rates, the Company
may maintain a higher level of short term indebtedness than has historically
been true.
At December 31, 1993, the Company had $49 million of lines of credit
with banks of which $6.1 million was committed to cover checks presented for
payment. These credit arrangements are subject to renewal June 1 of each year.
In connection with these committed lines of credit, the Company has agreed to
pay certain fees and/or maintain compensating balances with the banks. The
compensating balances, which represent substantially all the cash of the
Company except for daily working funds and like items, are not legally
restricted from withdrawal. In addition, the Company has bid-loan facilities
with eight major money center banks that total $180 million, of which, none was
committed at December 31, 1993.
ASSETS SUBJECT TO LIEN
The Company's mortgage, which secures the first mortgage bonds issued by the
Company, constitutes a direct first lien on substantially all of the Company's
fixed property and franchises.
FUEL COMMITMENTS
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into long-term commitments for the procurement of fuel. In
most cases, these contracts contain provisions for price escalations, minimum
purchase levels and other financial commitments. Total estimated long-term
obligations were approximately $1.4 billion at December 31, 1993. Additional
commitments will be required in the future to supply the Company's fuel needs.
To take advantage of lower-cost coal supplies, agreements were reached
in 1986 to terminate two long-term contracts for the supply of coal to Plant
Daniel, which is jointly owned by the Company and Mississippi Power, an
operating affiliate. The Company's portion of
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NOTES (CONTINUED)
Gulf Power Company 1993 Annual Report
this payment was some $60 million. This amount is being amortized to expense
on a per ton basis over a nine-year period. The remaining unamortized amount
included in deferred charges, including the current portion, was $18 million at
December 31, 1993.
In 1988, the Company made an advance payment of $60 million to another
coal supplier under an arrangement to lower the cost of future coal purchased
under an existing contract. This amount is being amortized to expense on a per
ton basis over a ten-year period. The remaining unamortized amount included in
deferred charges, including the current portion, was $36 million at December
31, 1993.
Also, in 1993 the Company made a payment of $16.4 million to a coal
supplier under an arrangement to suspend the purchase of coal under an existing
contract for one year. This amount is being amortized to expense on a per ton
basis over a one year period. The remaining unamortized amount, which is
included in current assets, was $11 million at December 31, 1993.
The amortization of these payments is being recovered through the fuel
cost recovery clause discussed under "Revenues and Fuel Costs" in Note 1.
LEASE AGREEMENT
In 1989, the Company entered into a twenty-two year operating lease agreement
for the use of 495 aluminum railcars to transport coal to Plant Daniel.
Mississippi Power, as joint owner of Plant Daniel, is responsible for one half
of the lease costs. The Company's share of the lease is charged to fuel
inventory and allocated to fuel expense as the fuel is used. The lease costs
charged to inventory were $1.2 million in 1993, $1.2 million in 1992 and $1.3
million in 1991. For the year 1994, the Company's annual lease payment will be
$1.2 million. The Company's annual lease payment for 1995 will be $2.4 million
and for 1996, 1997, and 1998 the payment will be $1.2 million. Lease payments
after 1998 total approximately $17.4 million. The Company has the option,
after three years from the date of the original contract, to purchase the
railcars at the greater of termination value or fair market value.
Additionally, at the end of the lease term, the Company has the option to renew
the lease.
6. JOINT OWNERSHIP AGREEMENTS:
The Company and Mississippi Power jointly own Plant Daniel, a steam-electric
generating plant, located in Jackson County, Mississippi. In accordance with
an operating agreement, Mississippi Power acts as the Company's agent with
respect to the construction, operation, and maintenance of the plant.
The Company and Georgia Power jointly own Plant Scherer Unit No. 3, a
steam-electric generating plant, located near Forsyth, Georgia. In accordance
with an operating agreement, Georgia Power acts as the Company's agent with
respect to the construction, operation, and maintenance of the unit.
The Company's pro rata share of expenses related to both plants is
included in the corresponding operating expense accounts in the Statements of
Income.
At December 31, 1993, the Company's percentage ownership and its
amount of investment in these jointly owned facilities were as follows:
Plant Plant
Scherer Unit Daniel
No. 3 (coal-
(coal-fired) fired)
(in thousands)
Plant-In-Service $185,725(1) $208,956
Accumulated Depreciation $ 41,970 $ 91,730
Construction Work in Progress $ 643 $ 10,356
Nameplate Capacity (2)
(in megawatts) 205 500
Ownership 25% 50%
(1) Includes net plant acquisition adjustment.
(2) Total megawatt nameplate capacity:
Plant Scherer Unit No. 3: 818
Plant Daniel: 1,000
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Gulf Power Company 1993 Annual Report
7. LONG-TERM POWER SALES AGREEMENTS:
GENERAL
The Company and the other operating affiliates of The Southern Company have
contractual agreements for the sale of capacity and energy to certain
non-affiliated utilities located outside of the system's service area. Certain
of these agreements are non-firm and are based on the capacity of the system in
general. Other agreements are firm and pertain to capacity related to specific
generating units. Because the energy is generally sold at cost under these
agreements, the capacity revenues from these sales primarily affect
profitability. The Company's capacity revenues have been as follows:
Unit Other
Year Power Long-Term Total
(in thousands)
1993 $31,162 $2,643 $33,805
1992 32,679 1,501 34,180
1991 31,288 1,363 32,651
Long-term non-firm power of 400 megawatts was sold in 1993 to Florida
Power Corporation (FPC) by the Southern electric system. In 1994, this amount
decreased to 200 megawatts, and the contract will expire at year-end 1994.
Capacity and energy sales under these long-term non-firm power sales agreements
are made from available power pool capacity, and the revenues from the sales
are shared by the operating affiliates.
Unit power from specific generating plants is currently being sold to
FPC, Florida Power & Light Company (FP&L), Jacksonville Electric Authority
(JEA), and the City of Tallahassee, Florida. Under these agreements, 209
megawatts of net dependable capacity were sold by the Company during 1993, and
sales will remain at that approximate level until the expiration of the
contracts in 2010, unless reduced by FPC, FP&L and JEA after 1999.
Capacity and energy sales to FP&L, the Company's largest single
customer, provided revenues of $39.5 million in 1993, $46.2 million in 1992,
and $42.1 million in 1991, or 6.8 percent, 8.1 percent, and 7.5 percent of
operating revenues, respectively.
GULF STATES SETTLEMENT COMPLETED
On November 7, 1991, the subsidiaries of The Southern Company entered into a
settlement agreement with Gulf States Utilities Company (Gulf States) that
resolved litigation between the companies that had been pending since 1986 and
arose out of a dispute over certain unit power and other long-term power sales
contracts. In 1993, all remaining terms and obligations of the settlement
agreement were satisfied.
Based on the value of the settlement proceeds received - less the
amounts previously included in income - the Company recorded increases in net
income of approximately $0.6 million in 1992 and $12.7 million in 1991. In
1993, the Company sold all of its remaining Gulf States common stock received
in the settlement, resulting in a gain of $2.3 million after tax.
8. INCOME TAXES:
Effective January 1, 1993, Gulf Power Company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption of Statement No. 109 resulted in
cumulative adjustments that had no effect on net income. The adoption also
resulted in the recording of additional deferred income taxes and related
assets and liabilities. The related assets of $31.3 million are revenues to be
received from customers. These assets are attributable to tax benefits flowed
through to customers in prior years and to taxes applicable to capitalized
AFUDC. The related liabilities of $76.9 million are revenues to be refunded to
customers. These liabilities are attributable to deferred taxes previously
recognized at rates higher than current enacted tax law and to unamortized
investment tax credits. Additionally, deferred income taxes related to
accelerated tax depreciation previously shown as a reduction to utility plant
were reclassified.
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NOTES (CONTINUED)
Gulf Power Company 1993 Annual Report
Details of the federal and state income tax provisions are as follows:
1993 1992 1991
(in thousands)
Total provision for income taxes:
Federal --
Currently payable $24,354 $24,287 $30,721
Deferred:
Current year 26,396 18,173 18,141
Reversal of prior years (22,102) (15,506) (21,404)
28,648 26,954 27,458
State
Currently payable 3,950 4,282 5,460
Deferred:
Current year 3,838 2,662 2,688
Reversal of prior years (2,785) (2,007) (2,817)
5,003 4,937 5,331
Total 33,651 31,891 32,789
Less income taxes charged
(credited) to other
income 921 (187) (1,104)
Federal and state income
taxes charged to
operations $32,730 $32,078 $33,893
The tax effects of temporary differences between the carrying amounts
of assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities are as follows:
1993
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $146,657
Property basis differences 15,140
Coal contract buyout 15,427
Other 6,724
Total 183,948
Deferred tax assets:
Federal effect of state deferred taxes 10,136
Pension and other benefits 3,406
Property insurance 4,730
Other 6,500
Total 24,772
Net deferred tax liabilities 159,176
Portion included in current liabilities, net 7,433
Accumulated deferred income
taxes in the Balance Sheets $151,743
Deferred investment tax credits are amortized over the life of the
related property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $2.3 million in 1993, 1992 and 1991. At December 31, 1993, all
investment tax credits available to reduce federal income taxes payable had
been utilized.
A reconciliation of the federal statutory income tax rate to the
effective income tax rate is as follows:
1993 1992 1991
Federal statutory rate 35% 34% 34%
State income tax,
net of federal deduction 3 4 4
Non-deductible book
depreciation 1 1 1
Differences in prior years'
deferred and current tax rate (2) (2) (3)
Other (1) (2) (2)
Effective income tax rate 36% 35% 34%
Gulf Power Company and the other subsidiaries of The Southern Company
file a consolidated federal tax return. Under a joint consolidated income tax
agreement, each company's current and deferred tax expense is computed on a
stand-alone basis, and consolidated tax savings are allocated to each company
based on its ratio of taxable income to total consolidated taxable income.
II-163
194
NOTES (CONTINUED)
Gulf Power Company 1993 Annual Report
9. LONG-TERM DEBT:
POLLUTION CONTROL OBLIGATIONS
Obligations incurred in connection with the sale by public
authorities of tax-exempt pollution control revenue bonds are as follows:
December 31
1993 1992
(in thousands)
Collateralized -
6 3/4% due 2006 $ - $ 12,675
6% due 2006* 12,300 12,400
10% due 2013 - 20,000
8 1/4% due 2017 32,000 32,000
7 1/8% due 2021 21,200 21,200
6 3/4% due 2022 8,930 8,930
5.70% due 2023 7,875 -
5.80% due 2023 32,550 -
6.20% due 2023 13,000 -
Non-collateralized
5.9% due 1992-2003 - 7,875
10 1/2% due 2014 42,000 42,000
Total $169,855 $157,080
* Sinking fund requirement applicable to the 6 percent pollution
control bonds is $100 thousand for 1994 with increasing increments thereafter
through 2005, with the remaining balance due in 2006.
With respect to the collateralized pollution control revenue bonds,
the Company has authenticated and delivered to trustees a like principal amount
of first mortgage bonds as security for obligations under collateralized
installment agreements. The principal and interest on the first mortgage bonds
will be payable only in the event of default under the agreements.
OTHER LONG-TERM DEBT
Long-term debt also includes $17.5 million for the Company's portion of notes
payable issued in connection with the termination of Plant Daniel coal
contracts (see Note 5 for information on fuel commitments). The notes bear
interest at 8.25 percent with the principal being amortized through 1995. Also
included in long-term debt is a 30-month note payable for $25 million which was
obtained to refinance higher cost securities. The principal is due in June
1996 and bears interest at 4.69 percent which is payable quarterly beginning
March 1994. The estimated annual maturities of the notes payable through 1996
are as follows: $8.4 million in 1994, $9.1 million in 1995, and $25 million in
1996.
10. LONG-TERM DEBT DUE WITHIN ONE YEAR:
A summary of the improvement fund requirement and scheduled maturities and
redemptions of long-term debt due within one year is as follows:
December 31
1993 1992
(in thousands)
Bond improvement fund requirement $ 2,370 $ 2,450
Less: Portion to be satisfied by
bonding property additions - -
Cash improvement fund requirement 2,370 2,450
Maturities of first mortgage bonds 3,676 3,359
Redemptions of first mortgage bonds 27,000 -
Current portion of notes payable 8,406 7,736
(Note 9)
Pollution control bond maturity 100 275
(Note 9)
Total $41,552 $13,820
The first mortgage bond improvement (sinking) fund requirement amounts
to 1 percent of each outstanding series of bonds authenticated under the
indenture prior to January 1 of each year, other than those issued to
collateralize pollution control obligations. The requirement may be satisfied
by depositing cash, reacquiring bonds, or by pledging additional property equal
to 1 and 2/3 times the requirement. In 1994, $12 million of 4 5/8 percent
First Mortgage Bonds due October 1, 1994 and $15 million of 6 percent First
Mortgage Bonds due June 1, 1996 are scheduled to be redeemed.
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195
NOTES (CONTINUED)
Gulf Power Company 1993 Annual Report
11. COMMON STOCK DIVIDEND RESTRICTIONS:
The Company's first mortgage bond indenture contains various common stock
dividend restrictions which remain in effect as long as the bonds are
outstanding. At December 31, 1993, $101 million of retained earnings was
restricted against the payment of cash dividends on common stock under the
terms of the mortgage indenture.
The Company's charter limits cash dividends on common stock to 50
percent of net income available for such stock during a prior period if the
capitalization ratio is below 20 percent and to 75 percent of such net income
if such ratio is 20 percent or more but less than 25 percent. The
capitalization ratio is defined as the ratio of common stock equity to total
capitalization, including retained earnings, adjusted to reflect the payment of
the proposed dividend. At December 31, 1993, the ratio was 44.4 percent.
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial data for 1993 and 1992 are as follows:
Net Income
After
Dividends
Operating Operating on Preferred
Quarter Ended Revenues Income Stock
(in thousands)
MARCH 31, 1993 $127,036 $17,646 $10,426
JUNE 30, 1993 138,863 19,562 7,312
SEPT. 30, 1993 175,964 32,783 22,366
DEC. 31, 1993 141,279 22,596 14,207
March 31, 1992 $126,536 $20,684 $ 9,576
June 30, 1992 137,123 22,914 12,120
Sept. 30, 1992 162,785 32,446 21,442
Dec. 31, 1992 144,458 20,931 10,952
The Company's business is influenced by seasonal weather conditions
and the timing of rate changes, among other factors.
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SELECTED FINANCIAL AND OPERATING DATA
Gulf Power Company 1993 Annual Report
1993 1992 1991
OPERATING REVENUES (IN THOUSANDS) $ 583,142 $ 570,902 $ 565,207
NET INCOME AFTER DIVIDENDS
ON PREFERRED STOCK (IN THOUSANDS) $ 54,311 $ 54,090 $ 57,796
CASH DIVIDENDS ON COMMON STOCK (IN THOUSANDS) $ 41,800 $ 39,900 $ 38,000
RETURN ON AVERAGE COMMON EQUITY (PERCENT) 13.29 13.62 15.17
TOTAL ASSETS (IN THOUSANDS) $1,307,809 $1,062,699 $1,095,736
GROSS PROPERTY ADDITIONS (IN THOUSANDS) $ 78,562 $ 64,671 $ 64,323
CAPITALIZATION (IN THOUSANDS):
Common stock equity $ 414,196 $ 403,190 $ 390,981
Preferred stock 89,602 74,662 55,162
Preferred stock subject to mandatory redemption 1,000 2,000 7,500
Long-term debt 369,259 382,047 434,648
Total (excluding amounts due within one year) $ 874,057 $ 861,899 $ 888,291
CAPITALIZATION RATIOS (PERCENT):
Common stock equity 47.4 46.8 44.0
Preferred stock 10.4 8.9 7.1
Long-term debt 42.2 44.3 48.9
Total (excluding amounts due within one year) 100.0 100.0 100.0
FIRST MORTGAGE BONDS (IN THOUSANDS):
Issued 75,000 25,000 50,000
Retired 88,809 117,693 32,807
PREFERRED STOCK (IN THOUSANDS):
Issued 35,000 29,500 -
Retired 21,060 15,500 2,500
SECURITY RATINGS:
First Mortgage Bonds -
Moody's A2 A2 A2
Standard and Poor's A A A
Duff & Phelps A+ A A
Preferred Stock -
Moody's a2 a2 a2
Standard and Poor's A- A- A-
Duff & Phelps A A- A-
CUSTOMERS (YEAR-END):
Residential 274,194 267,591 261,210
Commercial 39,253 37,105 34,685
Industrial 274 270 264
Other 86 74 72
Total 313,807 305,040 296,231
EMPLOYEES (YEAR-END) 1,565 1,613 1,598
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197
SELECTED FINANCIAL AND OPERATING DATA (CONTINUED)
Gulf Power Company 1993 Annual Report
1990 1989 1988 1987 1986 1985 1984 1983
$ 567,825 $ 527,821 $ 550,827 $ 587,860 $ 542,919 $ 562,068 $ 505,812 $ 469,696
$ 38,714 $ 37,361 $ 45,698 $ 42,217 $ 46,421 $ 45,484 $ 40,336 $ 35,511
$ 37,000 $ 37,200 $ 35,400 $ 34,200 $ 33,100 $ 30,800 $ 27,200 $ 24,900
10.51 10.32 13.41 13.23 15.06 15.61 15.11 14.70
$ 1,084,579 $1,093,430 $1,097,225 $1,051,182 $1,028,864 $ 921,635 $ 892,924 $ 841,628
$ 62,462 $ 70,726 $ 67,042 $ 97,511 $ 90,160 $ 92,541 $ 156,443 $ 51,131
$ 371,185 $ 365,471 $ 358,310 $ 323,012 $ 314,995 $ 301,674 $ 280,990 $ 252,831
55,162 55,162 55,162 55,162 55,162 55,162 55,162 55,162
9,250 11,000 12,750 14,000 16,500 18,250 19,000 21,250
475,284 484,608 497,069 474,640 482,869 410,917 394,859 382,293
$ 910,881 $ 916,241 $ 923,291 $ 866,814 $ 869,526 $ 786,003 $ 750,011 $ 711,536
40.8 39.9 38.8 37.2 36.2 38.4 37.5 35.5
7.1 7.2 7.4 8.0 8.3 9.3 9.9 10.8
52.1 52.9 53.8 54.8 55.5 52.3 52.6 53.7
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
- - 35,000 - 50,000 - - -
6,455 9,344 9,369 - 46,640 2,860 10,415 -
- - - - - - - -
1,750 1,250 1,750 2,500 750 750 1,500 858
A2 A1 A1 A1 A1 A1 A1 A2
A A A A A+ A+ A+ A+
A AA- 4 4 4 4 4 4
a2 a1 a1 a1 a1 a1 a1 a2
A- A- A- A- A A A A-
A- A+ 5 5 5 5 5 5
256,111 251,341 246,450 241,138 235,329 227,845 217,138 205,292
34,019 33,678 33,030 32,139 31,142 29,603 27,939 26,217
252 240 206 206 197 183 177 179
67 67 61 61 62 62 63 62
290,449 285,326 279,747 273,544 266,730 257,693 245,317 231,750
1,615 1,614 1,601 1,603 1,544 1,509 1,460 1,463
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198
SELECTED FINANCIAL AND OPERATING DATA (CONTINUED)
Gulf Power Company 1993 Annual Report
1993 1992 1991
OPERATING REVENUES (IN THOUSANDS):
Residential $ 244,967 $ 235,296 $ 231,220
Commercial 137,308 133,071 130,691
Industrial 87,526 91,320 92,300
Other 1,882 1,784 1,860
Total retail 471,683 461,471 456,071
Sales for resale - non-affiliates 72,209 70,078 69,636
Sales for resale - affiliates 23,166 24,075 29,343
Total revenues from sales of electricity 567,058 555,624 555,050
Other revenues 16,084 15,278 10,157
Total $ 583,142 $ 570,902 $ 565,207
KILOWATT-HOUR SALES (IN THOUSANDS):
Residential 3,712,980 3,596,515 3,455,100
Commercial 2,433,382 2,369,236 2,272,690
Industrial 2,029,936 2,179,435 2,117,408
Other 16,944 16,649 17,118
Total retail 8,193,242 8,161,835 7,862,316
Sales for resale - non-affiliates 1,460,105 1,430,908 1,550,018
Sales for resale - affiliates 1,029,787 1,208,771 1,236,223
Total 10,683,134 10,801,514 10,648,557
AVERAGE REVENUE PER KILOWATT-HOUR (CENTS):
Residential 6.60 6.54 6.69
Commercial 5.64 5.62 5.75
Industrial 4.31 4.19 4.36
Total retail 5.76 5.65 5.80
Sales for resale 3.83 3.57 3.55
Total sales 5.31 5.14 5.21
AVERAGE ANNUAL KILOWATT-HOUR USE PER RESIDENTIAL CUSTOMER 13,671 13,553 13,320
AVERAGE ANNUAL REVENUE PER RESIDENTIAL CUSTOMER $ 901.96 $ 886.66 $ 891.38
PLANT NAMEPLATE CAPACITY RATINGS (YEAR-END) (MEGAWATTS) 2,174 2,174 2,174
MAXIMUM PEAK-HOUR DEMAND (MEGAWATTS):
Winter 1,571 1,533 1,418
Summer 1,898 1,828 1,740
ANNUAL LOAD FACTOR (PERCENT) 54.5 55.0 57.0
PLANT AVAILABILITY - FOSSIL-STEAM (PERCENT) 88.9 91.2 92.2
SOURCE OF ENERGY SUPPLY (PERCENT):
Coal 84.5 87.7 82.0
Oil and gas 0.5 0.1 0.1
Purchased power -
From non-affiliates 1.5 0.8 0.5
From affiliates 13.5 11.4 17.4
Total 100.0 100.0 100.0
TOTAL FUEL ECONOMY DATA:
BTU per net kilowatt-hour generated 10,390 10,347 10,636
Cost of fuel per million BTU (cents) 197.37 200.30 203.60
Average cost of fuel per net kilowatt-hour generated (cents) 2.05 2.07 2.17
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199
SELECTED FINANCIAL AND OPERATING DATA (CONTINUED)
Gulf Power Company 1993 Annual Report
1990 1989 1988 1987 1986 1985 1984 1983
$ 217,843 $ 203,781 $ 184,036 $ 199,701 $ 200,725 $ 186,415 $ 174,302 $ 169,127
124,066 118,897 107,615 116,057 116,253 109,631 98,408 95,426
91,041 84,671 72,634 80,295 79,873 81,621 83,538 77,035
1,805 1,586 1,402 1,357 1,343 1,346 1,334 1,334
434,755 408,935 365,687 397,410 398,194 379,013 357,582 342,922
73,855 67,554 117,466 134,456 106,892 126,789 106,802 84,334
38,563 39,244 48,277 55,955 27,113 43,844 35,712 36,286
547,173 515,733 531,430 587,821 532,199 549,646 500,096 463,542
20,652 12,088 19,397 39 10,720 12,422 5,716 6,154
$ 567,825 $ 527,821 $ 550,827 $ 587,860 $ 542,919 $ 562,068 $ 505,812 $ 469,696
3,360,838 3,293,750 3,154,541 3,055,041 2,963,502 2,736,432 2,560,648 2,471,714
2,217,568 2,169,497 2,088,598 1,986,332 1,913,139 1,777,418 1,559,344 1,498,762
2,177,872 2,094,670 1,968,091 1,839,931 1,745,074 1,770,587 1,771,100 1,612,393
18,866 17,209 16,257 15,241 14,903 14,702 14,555 14,637
7,775,144 7,575,126 7,227,487 6,896,545 6,636,618 6,299,139 5,905,647 5,597,506
1,775,703 1,640,355 1,911,759 2,138,390 1,609,146 2,388,591 2,183,631 1,570,598
1,435,558 1,461,036 2,326,238 2,689,487 1,078,500 1,562,452 1,308,410 1,272,906
10,986,405 10,676,517 11,465,484 11,724,422 9,324,264 10,250,182 9,397,688 8,441,010
6.48 6.19 5.83 6.54 6.77 6.81 6.81 6.84
5.59 5.48 5.15 5.84 6.08 6.17 6.31 6.37
4.18 4.04 3.69 4.36 4.58 4.61 4.72 4.78
5.59 5.40 5.06 5.76 6.00 6.02 6.05 6.13
3.50 3.44 3.91 3.94 4.99 4.32 4.08 4.24
4.98 4.83 4.64 5.01 5.71 5.36 5.32 5.49
13,173 13,173 12,883 12,763 12,729 12,221 12,057 12,254
$ 853.86 $ 815.00 $ 751.60 $ 834.31 $ 862.16 $ 832.55 $ 820.71 $ 838.45
2,174 2,174 2,174 2,174 1,969 1,969 1,969 1,969
1,310 1,814 1,395 1,354 1,406 1,517 1,209 1,292
1,778 1,691 1,613 1,617 1,678 1,448 1,381 1,341
55.2 52.6 56.5 54.4 50.5 53.4 54.9 53.2
89.2 89.1 88.2 92.8 90.5 84.8 87.7 85.8
69.8 78.3 93.2 93.5 85.8 79.7 83.9 87.1
0.5 0.2 0.4 0.4 0.5 0.2 0.2 0.6
0.6 0.4 0.4 0.4 1.9 0.4 (1.4) (2.2)
29.1 21.1 6.0 5.7 11.8 19.7 17.3 14.5
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
10,765 10,621 10,461 10,512 10,639 10,609 10,639 10,721
206.06 193.70 178.00 197.53 239.26 254.53 240.40 240.14
2.22 2.06 1.86 2.08 2.55 2.70 2.60 2.57
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200
STATEMENTS OF INCOME
Gulf Power Company
For the Years Ended December 31, 1993 1992 1991
(Thousands of Dollars)
OPERATING REVENUES:
Revenues $ 559,976 $ 546,827 $ 535,864
Revenues from affiliates 23,166 24,075 29,343
Total operating revenues 583,142 570,902 565,207
OPERATING EXPENSES:
Operation --
Fuel 170,485 182,754 176,038
Purchased power from non-affiliates 4,386 1,394 896
Purchased power from affiliates 32,273 26,788 32,579
Proceeds from settlement of disputed contracts - (920) (20,385)
Other 109,164 98,230 94,411
Maintenance 46,004 41,947 45,468
Depreciation and amortization 55,309 53,758 52,195
Taxes other than income taxes 40,204 37,898 42,359
Federal and state income taxes 32,730 32,078 33,893
Total operating expenses 490,555 473,927 457,454
OPERATING INCOME 92,587 96,975 107,753
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction 512 14 54
Interest income 1,328 2,733 2,427
Other, net (1,238) (1,487) (3,484)
Gain on sale of investment securities 3,820 - -
Income taxes applicable to other income (921) 187 1,104
INCOME BEFORE INTEREST CHARGES 96,088 98,422 107,854
INTEREST CHARGES:
Interest on long-term debt 31,344 35,792 41,665
Allowance for debt funds used during construction (454) (46) (95)
Interest on notes payable 870 1,041 280
Amortization of debt discount, premium, and expense, net 1,412 1,032 699
Other interest charges 2,877 1,410 2,272
Net interest charges 36,049 39,229 44,821
NET INCOME 60,039 59,193 63,033
DIVIDENDS ON PREFERRED STOCK 5,728 5,103 5,237
NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 54,311 $ 54,090 $ 57,796
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201
STATEMENTS OF INCOME
Gulf Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 529,262 $ 488,577 $ 502,550 $ 531,905 $ 515,806 $ 518,224 $ 470,100 $ 433,410
38,563 39,244 48,277 55,955 27,113 43,844 35,712 36,286
567,825 527,821 550,827 587,860 542,919 562,068 505,812 469,696
156,712 158,858 191,687 227,233 215,262 230,944 214,885 198,554
1,427 1,251 1,468 1,792 4,533 1,638 (3,698) (6,051)
67,729 48,972 27,267 28,326 37,172 55,119 42,967 32,476
- - - - - - - -
90,045 82,231 93,028 100,032 70,117 59,851 56,352 54,967
45,491 44,295 41,919 38,748 35,251 35,654 28,773 28,378
50,899 48,760 47,530 44,619 39,386 37,775 33,061 31,479
39,110 30,718 27,087 26,246 24,854 22,886 21,696 21,370
24,780 23,621 26,239 31,703 39,948 40,061 35,831 34,434
476,193 438,706 456,225 498,699 466,523 483,928 429,867 395,607
91,632 89,115 94,602 89,161 76,396 78,140 75,945 74,089
- (446) 457 1,013 7,809 6,893 2,877 679
4,508 3,271 2,858 4,507 2,445 3,235 8,777 7,250
(6,360) (3,800) (3,491) (1,207) (1,077) (1,131) (704) (1,191)
- - - - - - - -
1,303 779 1,001 (642) (648) (862) (3,524) (2,694)
91,083 88,919 95,427 92,832 84,925 86,275 83,371 78,133
43,215 43,265 42,538 43,689 39,479 40,769 36,952 35,719
1 242 (808) (1,004) (8,651) (7,676) (3,261) (543)
693 180 182 - 106 - 1,628 -
603 613 600 555 488 287 265 237
2,422 1,636 1,456 1,350 869 1,120 1,111 674
46,934 45,936 43,968 44,590 32,291 34,500 36,695 36,087
44,149 42,983 51,459 48,242 52,634 51,775 46,676 42,046
5,435 5,622 5,761 6,025 6,213 6,291 6,340 6,535
$ 38,714 $ 37,361 $ 45,698 $ 42,217 $ 46,421 $ 45,484 $ 40,336 $ 35,511
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202
STATEMENTS OF CASH FLOWS
Gulf Power Company
For the Years Ended December 31, 1993 1992 1991
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $ 60,039 $ 59,193 $ 63,033
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 72,111 68,021 65,584
Deferred income taxes, net 5,347 3,322 (3,392)
Deferred investment tax credits, net - - -
Allowance for equity funds used during construction (512) (14) (54)
Non-cash proceeds from settlement of disputed contracts - (920) (19,734)
Other, net (864) 185 3,079
Changes in certain current assets and liabilities --
Receivables, net 12,867 (11,041) 12,421
Inventories 5,574 23,560 (2,397)
Payables 5,386 1,580 (2,003)
Other (9,504) (13,637) 8,012
Net cash provided from operating activities 150,444 130,249 124,549
INVESTING ACTIVITIES:
Gross property additions (78,562) (64,671) (64,323)
Other (5,328) 3,970 (8,097)
Net cash used for investing activities (83,890) (60,701) (72,420)
FINANCING ACTIVITIES AND CAPITAL CONTRIBUTIONS:
Proceeds:
Preferred stock 35,000 29,500 -
First mortgage bonds 75,000 25,000 50,000
Pollution control bonds 53,425 8,930 21,200
Capital contributions from parent company 11 121 -
Other long-term debt 25,000 - -
Retirements:
Preferred stock (21,060) (15,500) (2,500)
First mortgage bonds (88,809) (117,693) (32,807)
Pollution control bonds (40,650) (9,205) (21,250)
Other long-term debt (7,736) (5,783) (7,981)
Notes payable, net (37,947) 44,000 -
Payment of preferred stock dividends (5,728) (5,103) (5,237)
Payment of common stock dividends (41,800) (39,900) (38,000)
Miscellaneous (6,888) (8,760) (3,715)
Net cash provided from (used for) financing activities (62,182) (94,393) (40,290)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 4,372 (24,845) 11,839
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 1,204 26,049 14,210
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 5,576 $ 1,204 $ 26,049
( ) Denotes use of cash.
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203
STATEMENTS OF CASH FLOWS
Gulf Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 44,149 $ 42,983 $ 51,459 $ 48,242 $ 52,634 $ 51,775 $ 46,676 $ 42,046
63,650 59,955 56,260 51,672 41,619 39,595 34,784 32,975
1,837 5,319 10,138 2,377 45,213 18,467 3,877 11,996
- - - 868 1,634 5,716 10,667 2,292
- 446 (457) (1,013) (7,809) (6,893) (2,877) (679)
- - - - - - - -
1,544 3,827 11,449 12,913 5,860 (2,535) 243 7,362
(2,468) 492 8,984 (8,849) (6,012) (5,401) 19,173 (32,356)
(11,807) 16,306 (16,160) 23,691 (1,342) 1,870 2,053 5,170
(3,440) 6,142 (5,340) 10,173 449 1,756 601 4,839
5,781 4,466 (18,432) 6,208 (113) (13,331) 11,169 4,432
99,246 139,936 97,901 146,282 132,133 91,019 126,366 78,077
(62,462) (70,726) (67,042) (97,511) (90,160) (92,541) (156,443) (51,131)
(1,597) 419 (62,782) (692) (55,652) 7,693 2,086 1,601
(64,059) (70,307) (129,824) (98,203) (145,812) (84,848) (154,357) (49,530)
- - - - - - - -
- - 35,000 - 50,000 - - -
- - 3,677 35,996 9,900 18,776 16,424 14,840
4,000 7,000 25,000 - - 6,000 15,000 12,000
- - - - 60,663 - - -
(1,750) (1,250) (1,750) (2,500) (750) (750) (1,500) (858)
(6,455) (9,344) (9,369) - (46,640) (2,860) (10,415) -
(50) (50) (50) (32,050) (50) (50) (50) (50)
(6,083) (5,611) (5,175) (4,774) - - - -
- - - - - - - -
(5,435) (5,622) (5,761) (6,025) (6,213) (6,291) (6,340) (6,535)
(37,000) (37,200) (35,400) (34,200) (33,100) (30,800) (27,200) (24,900)
5 (3) (233) (1,632) (6,064) (227) (680) (613)
(52,768) (52,080) 5,939 (45,185) 27,746 (16,202) (14,761) (6,116)
(17,581) 17,549 (25,984) 2,894 14,067 (10,031) (42,752) 22,431
31,791 14,242 40,226 37,332 23,265 33,296 76,048 53,617
$ 14,210 $ 31,791 $ 14,242 $ 40,226 $ 37,332 $ 23,265 $ 33,296 $ 76,048
II-173
204
BALANCE SHEETS
Gulf Power Company
At December 31, 1993 1992 1991
(Thousands of Dollars)
ASSETS
UTILITY PLANT:
Production-fossil $ 863,223 $ 841,489 $ 837,712
Transmission 154,304 148,824 143,275
Distribution 464,182 443,352 419,228
General 129,995 127,826 125,330
Construction work in progress 34,591 29,564 13,684
Total utility plant 1,646,295 1,591,055 1,539,229
Accumulated provision for depreciation 610,542 578,851 535,408
Total 1,035,753 1,012,204 1,003,821
Less property-related accumulated deferred income taxes - 200,904 197,138
Total 1,035,753 811,300 806,683
OTHER PROPERTY AND INVESTMENTS:
Securities received from settlement of disputed contracts - - 19,938
Miscellaneous 13,242 7,074 6,410
Total 13,242 7,074 26,348
CURRENT ASSETS:
Cash and cash equivalents 5,576 1,204 26,049
Investment securities - 22,322 -
Receivables, net 63,924 60,047 49,006
Fossil fuel stock, at average cost 20,652 29,492 52,106
Materials and supplies, at average cost 36,390 33,124 34,070
Current portion of deferred coal contract costs 12,535 3,071 4,626
Regulatory clauses under recovery 3,244 1,680 -
Prepayments 2,160 1,395 1,410
Vacation pay deferred 4,022 3,779 3,776
Total current assets 148,503 156,114 171,043
DEFERRED CHARGES:
Deferred charges related to income taxes 31,334 - -
Debt expense, being amortized 3,693 3,253 3,232
Premium on reacquired debt, being amortized 17,554 15,319 8,855
Deferred coal contract costs 52,884 63,723 74,502
Miscellaneous 4,846 5,916 5,073
Total deferred charges 110,311 88,211 91,662
TOTAL ASSETS $ 1,307,809 $ 1,062,699 $ 1,095,736
II-174
205
BALANCE SHEETS
Gulf Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 817,490 $ 807,546 $ 796,052 $ 801,600 $ 608,340 $ 599,613 $ 582,139 $ 563,381
136,813 133,926 113,177 106,352 99,507 98,683 96,686 96,356
400,016 375,521 343,421 325,037 295,052 274,656 241,557 213,403
123,059 119,779 115,273 102,664 66,092 56,427 43,539 39,480
16,868 10,166 29,572 10,113 188,966 148,969 130,027 31,711
1,494,246 1,446,938 1,397,495 1,345,766 1,257,957 1,178,348 1,093,948 944,331
501,739 464,944 425,520 388,248 350,117 318,308 287,349 259,250
992,507 981,994 971,975 957,518 907,840 860,040 806,599 685,081
192,749 186,084 178,657 166,707 152,589 135,388 112,684 103,355
799,758 795,910 793,318 790,811 755,251 724,652 693,915 581,726
- - - - - - - -
5,439 6,933 6,756 2,932 2,619 601 2,216 1,955
5,439 6,933 6,756 2,932 2,619 601 2,216 1,955
14,210 31,791 14,242 40,226 37,332 23,265 33,296 76,048
- - - - - - - -
61,427 58,959 59,451 68,435 59,586 53,574 48,173 67,346
50,469 37,526 55,286 43,290 69,785 73,890 76,039 82,389
33,310 34,446 32,992 28,828 26,024 20,577 20,298 16,001
6,212 5,534 6,194 2,642 - - - -
7,008 4,503 1,218 - - - - -
2,168 2,490 3,577 677 788 633 474 588
3,631 3,425 3,340 3,200 3,000 2,775 2,517 2,200
178,435 178,674 176,300 187,298 196,515 174,714 180,797 244,572
- - - - - - - -
2,954 3,117 3,281 3,203 2,736 2,768 2,636 2,669
6,256 6,574 6,892 7,210 - - - -
87,102 97,833 106,263 55,889 60,663 - - -
4,635 4,389 4,415 3,839 11,080 18,900 13,360 10,706
100,947 111,913 120,851 70,141 74,479 21,668 15,996 13,375
$ 1,084,579 $ 1,093,430 $ 1,097,225 $ 1,051,182 $ 1,028,864 $ 921,635 $ 892,924 $ 841,628
II-175
206
BALANCE SHEETS
Gulf Power Company
At December 31, 1993 1992 1991
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stock $ 38,060 $ 38,060 $ 38,060
Other paid-in capital 218,282 218,271 218,150
Premium on preferred stock 81 88 399
Earnings retained in the business 157,773 146,771 134,372
Total common equity 414,196 403,190 390,981
Preferred stock 89,602 74,662 55,162
Preferred stock subject to mandatory redemption 1,000 2,000 7,500
Long-term debt 369,259 382,047 434,648
Total capitalization 874,057 861,899 888,291
(excluding amount due within one year)
CURRENT LIABILITIES:
Notes payable to banks 6,053 44,000 -
Preferred stock due within one year 1,000 1,000 1,000
Long-term debt due within one year 41,552 13,820 59,111
Accounts payable 38,699 33,461 25,315
Customer deposits 15,082 15,532 15,513
Taxes accrued 13,015 11,419 19,274
Interest accrued 5,420 6,370 9,720
Regulatory clauses over recovery 840 - 1,114
Vacation pay accrued 4,022 3,779 3,776
Miscellaneous 8,527 3,950 3,545
Total current liabilities 134,210 133,331 138,368
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes 151,743 - 1,775
Deferred credits related to income taxes 76,876 - -
Accumulated deferred investment tax credits 40,770 43,117 45,446
Miscellaneous 30,153 24,352 21,856
Total deferred credits and other liabilities 299,542 67,469 69,077
TOTAL CAPITALIZATION AND LIABILITIES $ 1,307,809 $ 1,062,699 $ 1,095,736
II-176
207
BALANCE SHEETS
Gulf Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 38,060 $ 38,060 $ 38,060 $ 38,060 $ 38,060 $ 38,060 $ 38,060 $ 38,060
218,150 214,150 207,150 182,150 182,150 182,150 176,150 161,150
399 399 399 399 399 399 399 376
114,576 112,862 112,701 102,403 94,386 81,065 66,381 53,245
371,185 365,471 358,310 323,012 314,995 301,674 280,990 252,831
55,162 55,162 55,162 55,162 55,162 55,162 55,162 55,162
9,250 11,000 12,750 14,000 16,500 18,250 19,000 21,250
475,284 484,608 497,069 474,640 482,869 410,917 394,859 382,293
910,881 916,241 923,291 866,814 869,526 786,003 750,011 711,536
- - - - - - - -
1,750 1,750 1,250 1,750 1,750 750 750 -
9,452 12,588 15,005 13,225 4,823 2,910 2,910 9,965
27,447 34,764 29,595 34,500 24,014 23,565 21,809 21,208
15,551 15,752 15,316 15,565 14,715 13,753 12,624 11,078
19,610 12,388 10,683 7,850 10,986 13,240 22,038 19,462
10,820 10,105 10,247 9,584 11,024 11,783 11,707 11,566
- - - 9,330 - - - -
3,631 3,425 3,340 3,200 3,000 2,775 2,517 2,200
12,177 7,759 2,748 2,144 3,869 4,966 4,474 4,130
100,438 98,531 88,184 97,148 74,181 73,742 78,829 79,609
6,736 13,381 17,678 22,992 23,550 - - -
- - - - - - - -
47,776 50,109 52,451 54,597 55,843 55,846 53,242 43,752
18,748 15,168 15,621 9,631 5,764 6,044 10,842 6,731
73,260 78,658 85,750 87,220 85,157 61,890 64,084 50,483
$ 1,084,579 $ 1,093,430 $ 1,097,225 $ 1,051,182 $ 1,028,864 $ 921,635 $ 892,924 $ 841,628
II-177
208
GULF POWER COMPANY
OUTSTANDING SECURITIES
AT DECEMBER 31, 1993
FIRST MORTGAGE BONDS
Amount Interest Amount
Series Issued Rate Outstanding Maturity
(Thousands) (Thousands)
1964 $ 12,000 4-5/8% $ 12,000 10/1/94
1966 15,000 6% 15,000 6/1/96
1992 25,000 5-7/8% 25,000 8/1/97
1988 35,000 9.20% 19,486 4/1/98
1993 15,000 5.55% 15,000 4/1/98
1993 30,000 5.00% 30,000 7/1/98
1993 30,000 6.125% 30,000 7/1/03
1978 25,000 9% 5,050 9/1/08
1991 50,000 8-3/4% 50,000 12/1/21
$ 237,000 $ 201,536
POLLUTION CONTROL BONDS
Amount Interest Amount
Series Issued Rate Outstanding Maturity
(Thousands) (Thousands)
1976 $ 12,500 6% $ 12,300 10/1/06
1984 42,000 10.50% 42,000 12/1/14
1987 32,000 8.25% 32,000 6/1/17
1991 21,200 7.125% 21,200 4/1/21
1992 8,930 6.75% 8,930 3/1/22
1993 13,000 6.20% 13,000 4/1/23
1993 32,550 5.80% 32,550 6/1/23
1993 7,875 5.70% 7,875 11/1/23
$ 170,055 $ 169,855
PREFERRED STOCK
Shares Dividend Amount
Series Outstanding Rate Outstanding
(Thousands)
1950 51,026 4.64% $ 5,102
1960 50,000 5.16% 5,000
1966 50,000 5.44% 5,000
1969 50,000 7.52% 5,000
1972 50,000 7.88% 5,000
1980 (1) 20,000 11.36% 2,000
1992 580,000 7.00% 14,500
1992 600,000 7.30% 15,000
1993 800,000 6.72% 20,000
1993 600,000 Adjustable 15,000
2,851,026 $ 91,602
(1) Subject to mandatory redemption of 5% annually on or before February 1.
II-178
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GULF POWER COMPANY
SECURITIES RETIRED
DURING 1993
FIRST MORTGAGE BONDS
Principal Interest
Series Amount Rate
(Thousands)
1969 $ 15,000 7.75%
1971 21,000 7.50%
1972 22,000 7.50%
1973 25,000 7.50%
1978 2,450 9%
1988 3,359 9.20%
$ 88,809
POLLUTION CONTROL BONDS
Principal Interest
Series Amount Rate
(Thousands)
1973 $ 7,875 5.90%
1976 12,675 6.75%
1976 100 6.00%
1983 20,000 10%
$ 40,650
PREFERRED STOCK
Principal Dividend
Series Amount Rate
(Thousands)
1971 $ 5,060 8.52%
1977 15,000 8.28%
1980 1,000 11.36%
$ 21,060
II-179
210
MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
II-180
211
MANAGEMENT'S REPORT
Mississippi Power Company 1993 Annual Report
The management of Mississippi Power Company has prepared--and is responsible
for--the financial statements and related information included in this
report. These statements were prepared in accordance with generally
accepted accounting principles appropriate in the circumstances and
necessarily include amounts that are based on best estimates and judgments
of management. Financial information throughout this annual report is
consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that books and records
reflect only authorized transactions of the Company. Limitations exist,
however, in any system of internal control, based upon a recognition that
the cost of the system should not exceed its benefits. The Company believes
its system of internal accounting control maintains an appropriate
cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the internal audit staff. The Company's independent public
accountants also consider certain elements of the internal control system in
order to determine their auditing procedures for the purpose of expressing
an opinion on the financial statements.
The audit committee of the board of directors, composed of four directors
who are not employees, provides a broad overview of management's financial
reporting and control functions. Periodically, this committee meets with
management, the internal auditors, and the independent public accountants to
ensure that these groups are fulfilling their obligations and to discuss
auditing, internal controls, and financial reporting matters. The internal
auditors and independent public accountants have access to the members of
the audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations, and cash
flows of Mississippi Power Company in conformity with generally accepted
accounting principles.
/s/ David M. Ratcliffe
--------------------------------------------------
David M. Ratcliffe
President and Chief Executive Officer
/s/ Thomas A. Fanning
--------------------------------------------------
Thomas A. Fanning
Vice President and Chief Financial Officer
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212
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS OF
MISSISSIPPI POWER COMPANY:
We have audited the accompanying balance sheets and statements of
capitalization of Mississippi Power Company (a Mississippi corporation and a
wholly owned subsidiary of The Southern Company) as of December 31, 1993 and
1992, and the related statements of income, retained earnings, 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.
In our opinion, the financial statements (pages II-190 through II-206)
referred to above present fairly, in all material respects, the financial
position of Mississippi Power Company as of December 31, 1993 and 1992, and
the results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
As explained in Notes 2 and 9 to the financial statements, effective
January 1, 1993, Mississippi Power Company changed its methods of accounting
for postretirement benefits other than pensions and for income taxes.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
February 16 , 1994
II-182
213
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION Mississippi Power Company 1993 Annual Report
RESULTS OF OPERATIONS
EARNINGS
Mississippi Power Company's net income after dividends on preferred stock
for 1993 totaled $42.4 million, an increase of $5.6 million over the prior
year. This improvement is attributable primarily to increased energy sales
and retail rate increases. A retail rate increase under the Company's
Performance Evaluation Plan (PEP-1A) of $6.4 million annually became
effective in July 1993. Under the Environmental Compliance Overview Plan
(ECO Plan) retail rates increased by $2.6 million annually effective April
1993.
A comparison of 1992 to 1991 - excluding the events occurring in 1991
discussed below - would reflect a 1992 increase in earnings of $4.9 million
or 15.5 percent. The Company's financial performance in 1991 reflected the
after-tax operating and disposal losses of $11.9 million recorded by the
Company's former merchandise subsidiary. These losses were partially offset
by a $2.6 million positive impact on earnings from the settlement of the
contract dispute with Gulf States Utilities Company (Gulf States).
REVENUES
The following table summarizes the factors impacting operating revenues for
the past three years:
Increase (Decrease)
from Prior Year
1993 1992 1991
(in thousands)
Retail -
Change in
base rates $ 5,079* $ 6,605 $ 4,627
Sales growth 5,606 7,181 1,304
Weather 4,735 (3,915) 178
Fuel cost
recovery
and other 15,028 (2,743) (11,209)
Total retail 30,448 7,128 (5,100)
Sales for resale --
Non-affiliates 3,298 1,387 (7,368)
Affiliates 5,464 (7,989) (2,113)
Total sales for
resale 8,762 (6,602) (9,481)
Other operating
revenues 1,226 1,535 96
Total operating
revenues $ 40,436 $ 2,061 $(14,485)
Percent change 9.3% 0.5% (3.2)%
*Includes the effect of the retail rate increase approved under the ECO Plan.
Retail revenues of $368 million in 1993 increased 9.0 percent over the
prior year, compared with an increase of 2.2 percent for 1992 and a decrease
of 1.5 percent in 1991. The increase in retail revenues for 1993 was a
result of growth in energy sales and customers, the favorable impact of
weather, and retail rate increases. Changes in base rates reflect rate
changes made under the PEP plans and the ECO Plan as approved by the
Mississippi Public Service Commission (MPSC).
The increase in revenues for the recovery of fuel costs for 1993 reversed
two years of decline. Under the fuel cost recovery provision, recorded fuel
revenues are equal to recorded fuel expenses, including the fuel component
and the operation and maintenance component of purchased energy. Therefore,
changes in recoverable fuel expenses are offset with corresponding changes
in fuel revenues and have no effect on net income.
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214
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1993 Annual Report
Included in sales for resale to non-affiliates are revenues from rural
electric cooperative associations and municipalities located in southeastern
Mississippi. Energy sales to these customers in 1993 increased 9.0 percent
over the prior year with the related revenues rising 14.1 percent. The
customer demand experienced by these utilities is determined by factors very
similar to Mississippi Power's.
Sales for resale to non-affiliated non-territorial utilities are
primarily under long-term contracts consisting of capacity and energy
components. Capacity revenues reflect the recovery of fixed costs and a
return on investment under the contracts. Energy is generally sold at
variable cost. The capacity and energy components were:
1993 1992 1991
(in thousands)
Capacity $ 4,191 $ 3,573 $2,714
Energy 12,120 19,538 19,856
Total $16,311 $23,111 $22,570
Capacity revenues for Mississippi Power increased in 1993 and 1992 due to
a change in the allocation of transmission capacity revenues throughout the
Southern electric system. Most of the Company's capacity revenues are
derived from transmission charges.
Sales to affiliated companies within the Southern electric system will
vary from year to year depending on demand and the availability and cost of
generating resources at each company. These sales have no material impact
on earnings.
The increase in other operating revenues for 1993 was due to increased
rents collected from microwave equipment use and the transmission of
non-associated companies' electricity.
Below is a breakdown of kilowatt-hour sales for 1993 and the percent
change for the last three years:
(millions of Amount Percent Change
kilowatt-hours) 1993 1993 1992 1991
Residential 1,930 6.9% (1.5)% 1.5%
Commercial 1,934 6.8 2.4 2.9
Industrial 3,623 2.5 7.3 (0.4)
Other 38 0.3 (57.2) 4.0
Total retail 7,525 4.7 2.9 1.0
Sales for
resale --
Non-affiliates 2,545 (5.3) (0.7) (6.1)
Affiliates 427 52.2 (54.6) (13.5)
Total 10,497 3.3% (1.5)% (2.0)%
Total retail energy sales in 1993 increased compared to the previous
year, due primarily to weather influences and the improvement in the
economy. The increase in commercial energy sales also reflects the impact
of recently established casinos within the Company's service area.
Industrial sales increased in 1992 as a result of new contracts with two
large industrial customers.
The decrease in energy sales for resale to non-affiliates is
predominantly due to reductions in unit power sales under long-term
contracts to Florida utilities. Economy sales and amounts sold under
short-term contracts are also sold for resale to non-affiliates. Sales for
resale to non-affiliates are influenced by those utilities' own customer
demand, plant availability, and the cost of their predominant fuels -- oil
and natural gas.
EXPENSES
Total operating expenses for 1993 were higher than the previous year because
of higher production expenses, which reflects increased demand, an increase
in the federal income tax rate, and higher employee-related costs. (See
Note 2 to the financial statements for information regarding employee and
retiree benefits.) Additionally, included in other operation expenses are
increased costs associated with environmental remediation of a Southern
electric system research facility. Expenses in 1992 were lower than 1991,
excluding the Gulf States settlement, primarily because of lower production
expenses stemming from decreased demand.
II-184
215
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1993 Annual Report
Fuel costs constitute the single largest expense for Mississippi Power.
These costs increased in 1993 due to an 11.0 percent increase in generation,
which reflects higher demand. Fuel expenses in 1992, compared to 1991, were
lower because of less generation and the negotiation of new coal contracts.
Generation decreased primarily because of the availability of lower cost
generation elsewhere within the Southern electric system.
Purchased power consists primarily of energy purchases from the
affiliates of the Southern electric system. Purchased power transactions
(both sales and purchases) among Mississippi Power and its affiliates will
vary from period to period depending on demand and the availability and
variable production cost at each generating unit in the Southern electric
system.
Taxes other than income taxes increased in 1993 because of higher ad
valorem taxes, which are property based, and municipal franchise taxes,
which are revenue based. The decline in 1992 was attributable to lower
franchise taxes.
Income tax expense in 1993 increased because of the enactment of a higher
corporate income tax rate retroactive to January 1, 1993, coupled with
higher earnings. The change in income taxes for 1992 and 1991 reflected the
change in operating income.
EFFECTS OF INFLATION
Mississippi Power is subject to rate regulation and income tax laws that are
based on the recovery of historical costs. Therefore, inflation creates an
economic loss because the Company is recovering its costs of investments in
dollars that have less purchasing power. While the inflation rate has been
relatively low in recent years, it continues to have an adverse effect on
the Company because of the large investment in long-lived utility plant.
Conventional accounting for historical costs does not recognize this
economic loss nor the partially offsetting gain that arises through
financing facilities with fixed-money obligations, such as long-term debt
and preferred stock. Any recognition of inflation by regulatory authorities
is reflected in the rate of return allowed.
FUTURE EARNINGS POTENTIAL
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings
depends on numerous factors ranging from regulatory matters to growth in
energy sales. Expenses are subject to constant review and cost control
programs. Among the efforts to control costs are utilizing employees more
effectively through a functionalization program for the Southern electric
system, redesigning compensation and benefit packages, and re- engineering
work processes. Mississippi Power is also maximizing the utility of
invested capital and minimizing the need for capital by refinancing,
decreasing the average fuel stockpile, raising generating plant availability
and efficiency, and curbing the construction budget. Operating revenues
will be affected by any changes in rates under the PEP-2, the Company's
revised performance based ratemaking plan. The PEP plans have proved to be
a stabilizing force on electric rates, with only moderate changes in rates
taking place.
The ECO Plan, approved by the MPSC in 1992, provides for recovery of
costs associated with environmental projects approved by the MPSC, most of
which are required to comply with Clean Air Act Amendments of 1990
regulations. The ECO Plan is operated independently of PEP-2.
The FERC regulates wholesale rate schedules and power sales contracts
that Mississippi Power has with its sales for resale customers. The FERC is
currently reviewing the rate of return on common equity included in these
schedules and contracts and may require such returns to be lowered, possibly
retroactively. Also, pending before the FERC is the Company's request for a
$3.6 million wholesale rate increase.
Further discussion of the PEP plans, the ECO Plan, and proceedings before
the FERC is made in Note 3 to the financial statements herein.
Future earnings in the near term will depend upon growth in energy sales,
which are subject to a number of factors. Traditionally, these factors have
included changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, weather,
competition, and the rate of economic growth in Mississippi Power's service
area. However, the Energy
II-185
216
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1993 Annual Report
Policy Act of 1992 (Energy Act) will have a profound effect on the future of
the electric utility industry. The Energy Act promotes energy efficiency,
alternative fuel use, and increased competition for electric utilities. The
Energy Act allows Independent Power Producers (IPPs) to access a utility's
transmission network in order to sell electricity to other utilities, and
this may enhance the incentive of IPPs to build cogeneration plants for a
utility's large industrial and commercial customers. Although the Energy
Act does not require transmission access to retail customers, pressure for
legislation to allow retail wheeling will continue. Mississippi Power is
preparing to meet the challenge of this major change in the traditional
business practices of selling electricity. If Mississippi Power does not
remain a low-cost producer and provider of quality service, the Company's
retail energy sales growth, as well as new long-term contracts for energy
sales outside the service area, could be limited, which could significantly
reduce earnings.
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112,
Employers' Accounting for Postemployment Benefits, which must be effective
by 1994. The new standard requires that all types of benefits provided to
former or inactive employees and their families prior to retirement be
accounted for on an accrual basis. These benefits include salary
continuation, severance pay, supplemental unemployment benefits,
disability-related benefits, job training, and health and life insurance
coverage. In 1993, Mississippi Power adopted Statement No. 112, with no
material effect on the financial statements.
The FASB has issued Statement No. 115, Accounting for Certain Investments
in Debt and Equity Securities, which is effective in 1994. Statement No.
115 supersedes FASB Statement No. 12, Accounting for Certain Marketable
Securities. In January 1994, Mississippi Power adopted the new rules, with
no material effect on the financial statements.
On January 1, 1993, Mississippi Power changed its methods of accounting
for postretirement benefits other than pensions and income taxes. See Notes
2 and 9 to the financial statements regarding the impact of these changes.
FINANCIAL CONDITION
OVERVIEW
The principal changes in Mississippi Power's financial condition during 1993
were gross property additions of $140 million to utility plant, a
significant lowering of cost of capital through refinancings, and the
resolution of PEP and ratepayer litigation. Funding for gross property
additions came primarily from capital contributions from The Southern
Company, earnings and other operating cash flows. The Statements of Cash
Flows provide additional details.
FINANCING ACTIVITY
Mississippi Power continued to lower its financing costs in 1993 by issuing
new debt and equity securities and retiring high- cost issues. The Company
sold $132 million of first mortgage bonds, preferred stock and, through
public authorities, pollution control revenue bonds. Retirements, including
maturities during 1993, totaled some $101 million of such securities. (See
the Statements of Cash Flows for further details.) Composite financing
rates for the years 1991 through 1993 as of year-end were as follows:
1993 1992 1991
Composite interest rate on
long-term debt 6.57% 6.91% 7.90%
Composite preferred stock
dividend rate 6.58% 7.29% 7.32%
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1993 Annual Report
CAPITAL STRUCTURE
At year-end 1993, the Company's ratio of common equity to total
capitalization was 49.8 percent, compared to 47.3 percent in 1992 and 44.4
percent in 1991. The increase in the ratio in 1993 can be attributed
primarily to the receipt of $30 million of capital contributions from The
Southern Company.
CAPITAL REQUIREMENTS FOR CONSTRUCTION
The Company's projected construction expenditures for the next three years
total $256 million ($96 million in 1994, $62 million in 1995, and $98
million in 1996). The major emphasis within the construction program will
be on complying with Clean Air Act regulations, completion of a 78-megawatt
combustion turbine, and upgrading existing facilities. The estimates for
property additions for the three-year period include $39 million committed
to meeting the requirements of Clean Air Act regulations. Revisions may be
necessary because of factors such as revised load projections, the
availability and cost of capital, and changes in environmental regulations.
OTHER CAPITAL REQUIREMENTS
In addition to the funds required for the Company's construction program,
approximately $51 million will be required by the end of 1996 for present
sinking fund requirements and maturities of long-term debt. Mississippi
Power plans to continue, when economically feasible, to retire high-cost
debt and preferred stock and replace these obligations with lower-cost
capital.
ENVIRONMENTAL MATTERS
In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act)
were signed into law. Title IV of the Clean Air Act -- the acid rain
compliance provision of the law -- will have a significant impact on
Mississippi Power and the other operating companies of The Southern Company.
Specific reductions in sulfur dioxide and nitrogen oxide emissions from
fossil-fired generating plants will be required in two phases. Phase I
compliance must be implemented in 1995, and affects eight generating plants
-- some 10 thousand megawatts of capacity or 35 percent of total capacity --
in the Southern electric system. Phase II compliance is required in 2000,
and all fossil-fired generating plants in the Southern electric system will
be affected.
Beginning in 1995, the Environmental Protection Agency (EPA) will
allocate annual sulfur dioxide emission allowances through the newly
established allowance trading program. An emission allowance is the
authority to emit one ton of sulfur dioxide during a calendar year. The
method for allocating allowances is based on the fossil fuel consumed from
1985 through 1987 for each affected generating unit. Emission allowances
are transferable and can be bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize the
cost of compliance. The market for emission allowances is developing more
slowly than expected. However, The Southern Company's sulfur dioxide
compliance strategy is designed to take advantage of allowances as the
market develops.
The Southern Company expects to achieve Phase I sulfur dioxide compliance
at the eight affected plants by switching to low-sulfur coal, and this has
required some equipment upgrades. This compliance strategy is expected to
result in unused emission allowances being banked for later use. Additional
construction expenditures are required to install equipment for the control
of nitrogen oxide emissions at these eight plants. Also, continuous
emissions monitoring equipment would be installed on all fossil-fired units.
Under this Phase I compliance approach, additional construction expenditures
are estimated to total approximately $275 million through 1995 for The
Southern Company, of which Mississippi Power's portion is approximately $60
million.
Phase II compliance costs are expected to be higher because requirements
are stricter and all fossil-fired generating plants are affected. For
sulfur dioxide compliance, The Southern Company could use emission
allowances banked during Phase I, increase fuel switching, install flue gas
desulfurization equipment at selected plants, and/or purchase more
allowances depending on the price and availability of allowances. Also, in
Phase II, equipment to control nitrogen oxide emissions will be installed on
additional system fossil-fired plants as required to meet anticipated Phase
II limits. Therefore, during the period 1996 to 2000, compliance for The
Southern Company could require total construction expenditures ranging from
approximately $450 million to $800 million,
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1993 Annual Report
of which Mississippi Power's portion is approximately $25 million. However,
the full impact of Phase II compliance cannot now be determined with
certainty, pending the development of a market for emission allowances, the
completion of EPA regulations, and the possibility of new emission reduction
technologies.
An average increase of up to 3 percent in revenue requirements from
customers could be necessary to fully recover The Southern Company's costs
of compliance for both Phase I and II of the Clean Air Act. Compliance
costs include construction expenditures, increased costs for switching to
low-sulfur coal, and costs related to emission allowances.
Mississippi Power's ECO Plan is designed to allow recovery of costs of
compliance with the Clean Air Act, as well as other environmental statutes
and regulations. The MPSC reviews environmental projects and the Company's
environmental policy through the ECO Plan. Under the ECO Plan, any increase
in the annual revenue requirement is limited to 2 percent of retail
revenues. However, the plan also provides for carryover of any amount over
the 2 percent limit into the next year's revenue requirement. Mississippi
Power's management believes that the ECO Plan will provide for recovery of
the Clean Air Act costs.
Title III of the Clean Air Act requires a multi-year EPA study of power
plant emissions of hazardous air pollutants. The study will serve as the
basis for a decision on whether additional regulatory control of these
substances is warranted. Compliance with any new control standard could
result in significant additional costs. The impact of new standards -- if
any -- will depend on the development and implementation of applicable
regulations.
The EPA continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study
on the impact of a new standard indicate that a number of plants could be
required to install sulfur dioxide controls. These controls would be in
addition to the controls already required to meet the acid rain provisions
of the Clean Air Act. The EPA is expected to take some action on this issue
in 1994. The impact of any new standard will depend on the level chosen for
the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air
quality standards for particulate matter, nitrogen oxides, and ozone. The
impact of any new standard will depend on the level chosen for the standard
and cannot be determined at this time.
In 1994 or 1995, the EPA is expected to issue revised rules on air
quality control regulations related to stack height requirements of the
Clean Air Act. The full impact of the final rules cannot be determined at
this time, pending their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of
coal ash. However, the EPA has until 1998 to classify co-managed utility
wastes -- coal ash and other utility wastes -- as either non-hazardous or
hazardous. If the EPA classifies the co-managed wastes as hazardous, then
substantial additional costs for the management of such wastes may be
required. The full impact of any change in the regulatory status will
depend on the subsequent development of co-managed waste requirements.
The Company must comply with other environmental laws and regulations
that cover the handling and disposal of hazardous waste. Under these
various laws and regulations, the Company could incur costs to clean up
properties currently or previously owned. The Company conducts studies to
determine the extent of any required clean-up costs and has recognized in
the financial statements costs to clean up known sites.
Several major pieces of environmental legislation are in the process of
being reauthorized or amended by Congress. These include: the Clean Water
Act; the Resource Conservation and Recovery Act; and the Comprehensive
Environmental Response, Compensation, and Liability Act. Changes to these
laws could affect many areas of the Company's operations. The full impact
of these requirements cannot be determined at this time, pending the
development and implementation of applicable regulations.
Compliance with possible new legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect the Company. The impact of new legislation -- if
any -- will depend on the subsequent development and implementation of
applicable regulations. In addition, the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1993 Annual Report
potential for lawsuits alleging damages caused by electromagnetic fields
exists.
SOURCES OF CAPITAL
At December 31, 1993, the Company had $70 million of committed credit in
revolving credit agreements and also had $21 million of committed short-term
credit lines. The $40 million of notes payable outstanding at year end 1993
were apart from the committed credit facilities.
It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulations will be
derived from operations, the sale of additional first mortgage bonds,
pollution control obligations, and preferred stock, and the receipt of
additional capital contributions from The Southern Company. Mississippi
Power is required to meet certain coverage requirements specified in its
mortgage indenture and corporate charter to issue new first mortgage bonds
and preferred stock. The Company's coverage ratios are sufficiently high
enough to permit, at present interest rate levels, any foreseeable security
sales. The amount of securities which the Company will be permitted to
issue in the future will depend upon market conditions and other factors
prevailing at that time.
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STATEMENTS OF INCOME
For the Years Ended December 31, 1993, 1992, and 1991
Mississippi Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
OPERATING REVENUES (NOTES 1, 3, AND 7):
Revenues $ 459,364 $ 424,392 $ 414,342
Revenues from affiliates 15,519 10,055 18,044
Total operating revenues 474,883 434,447 432,386
OPERATING EXPENSES:
Operation --
Fuel 113,986 96,743 120,485
Purchased power from non-affiliates 2,198 1,337 851
Purchased power from affiliates 58,019 60,689 45,506
Proceeds from settlement of disputed contracts (Note 7) - (189) (4,205)
Other 100,381 90,581 86,932
Maintenance 44,001 43,165 44,166
Depreciation and amortization 33,099 32,789 32,147
Taxes other than income taxes 37,145 34,664 35,414
Federal and state income taxes (Note 9) 22,668 16,378 13,976
Total operating expenses 411,497 376,157 375,272
OPERATING INCOME 63,386 58,290 57,114
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction 1,010 642 728
Interest income 517 766 1,093
Other, net 3,971 5,501 3,845
Income taxes applicable to other income (1,158) (1,427) (863)
INCOME BEFORE INTEREST CHARGES 67,726 63,772 61,917
INTEREST CHARGES:
Interest on long-term debt 17,688 22,357 23,656
Allowance for debt funds used during construction (788) (563) (584)
Interest on notes payable 1,000 362 603
Amortization of debt discount, premium, and expense, net 1,262 630 377
Other interest charges 728 339 285
Net interest charges 19,890 23,125 24,337
NET INCOME FROM CONTINUING OPERATIONS 47,836 40,647 37,580
DISCONTINUED OPERATIONS (NOTE 1):
Loss from operations of discontinued
subsidiary, net of taxes - - (6,404)
Loss on disposal of subsidiary, net of taxes - - (5,455)
Net loss from discontinued subsidiary - - (11,859)
NET INCOME 47,836 40,647 25,721
DIVIDENDS ON PREFERRED STOCK 5,400 3,857 3,094
NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 42,436 $ 36,790 $ 22,627
The accompanying notes are an integral part of these statements.
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STATEMENTS OF CASH FLOWS
For the Years ended December 31, 1993, 1992, and 1991
Mississippi Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
OPERATING ACTIVITIES:
Net income $ 47,836 $ 40,647 $ 25,721
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 45,660 41,472 41,773
Deferred income taxes and investment tax credits 5,039 (5,473) (11,871)
Allowance for equity funds used during construction (1,010) (642) (728)
Non-cash proceeds from settlement of disputed contracts (Note 7) - (189) (4,071)
Other, net 3,005 8,093 (4,982)
Changes in certain current assets and liabilities --
Receivables, net (4,347) 1,002 35,343
Inventories 11,119 975 10,518
Payables 4,133 460 (4,949)
Other (8,033) 6,095 11,433
Net cash provided from operating activities 103,402 92,440 98,187
INVESTING ACTIVITIES:
Gross property additions (139,976) (68,189) (53,675)
Other 7,562 4,235 2,148
Net cash used for investing activities (132,414) (63,954) (51,527)
FINANCING ACTIVITIES:
Proceeds:
Capital contributions 30,036 26 -
Preferred stock 23,404 35,000 -
First mortgage bonds 70,000 40,000 50,000
Pollution control bonds 38,875 23,300 -
Other long-term debt - - 844
Retirements:
Preferred stock (23,404) - (4,118)
First mortgage bonds (51,300) (104,703) -
Pollution control bonds (25,885) (23,650) (300)
Other long-term debt (8,170) (6,212) (8,958)
Notes payable, net 9,000 26,500 (25,603)
Payment of preferred stock dividends (5,400) (3,857) (3,094)
Payment of common stock dividends (29,000) (28,000) (28,500)
Miscellaneous (5,683) (7,821) (839)
Net cash provided from (used for) financing activities 22,473 (49,417) (20,568)
NET CHANGE IN CASH AND CASH EQUIVALENTS (6,539) (20,931) 26,092
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 7,417 28,348 2,256
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 878 $ 7,417 $ 28,348
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for --
Interest (net of amount capitalized) $15,697 $22,941 $24,802
Income taxes 29,009 19,514 17,980
( ) Denotes use of cash.
The accompanying notes are an integral part of these statements.
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BALANCE SHEETS
At December 31, 1993 and 1992
Mississippi Power Company 1993 Annual Report
ASSETS 1993 1992
(in thousands)
UTILITY PLANT:
Plant in service, at original cost (Notes 1 and 6) $ 1,238,847 $ 1,180,505
Less accumulated provision for depreciation 462,725 440,777
776,122 739,728
Construction work in progress 108,063 41,692
Total 884,185 781,420
Less property-related accumulated deferred income taxes (Note 9) - 142,338
Total 884,185 639,082
OTHER PROPERTY AND INVESTMENTS (NOTE 10) 11,289 4,539
CURRENT ASSETS:
Cash and cash equivalents 878 7,417
Investment securities - 3,622
Receivables-
Customer accounts receivable 31,376 26,336
Other accounts and notes receivable 5,581 5,757
Affiliated companies 6,698 3,532
Accumulated provision for uncollectible accounts (737) (508)
Fossil fuel stock, at average cost 11,185 21,341
Materials and supplies, at average cost 21,145 22,108
Current portion of deferred fuel charges (Note 5) 440 1,861
Prepayments 7,843 5,869
Vacation pay deferred (Note 1) 4,797 4,651
Total 89,206 101,986
DEFERRED CHARGES:
Debt expense and loss, being amortized 11,666 10,906
Deferred fuel charges (Note 5) 17,520 25,255
Deferred charges related to income taxes (Note 9) 25,267 -
Miscellaneous 10,073 9,515
Total 64,526 45,676
TOTAL ASSETS $ 1,049,206 $ 791,283
The accompanying notes are an integral part of these statements.
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BALANCE SHEETS
At December 31, 1993 and 1992
Mississippi Power Company 1993 Annual Report
CAPITALIZATION AND LIABILITIES 1993 1992
(in thousands)
CAPITALIZATION (SEE ACCOMPANYING STATEMENTS):
Common stock equity $ 321,768 $ 280,640
Preferred stock 74,414 74,414
Long-term debt 250,391 238,650
Total 646,573 593,704
CURRENT LIABILITIES:
Long-term debt due within one year (Note 11) 19,345 8,878
Notes payable (Note 5) 40,000 31,000
Accounts payable-
Affiliated companies 10,197 6,202
Other 50,731 37,348
Customer deposits 2,786 2,976
Taxes accrued-
Federal and state income (Note 9) 186 6,364
Other 26,952 25,671
Interest accrued 4,237 3,961
Miscellaneous 14,120 15,614
Total 168,554 138,014
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes (Note 9) 123,206 169
Accumulated deferred investment tax credits 32,710 34,242
Deferred credits related to income taxes (Note 9) 48,228 -
Accumulated provision for property damage (Note 1) 10,538 9,294
Miscellaneous 19,397 15,860
Total 234,079 59,565
COMMITMENTS AND CONTINGENT MATTERS (NOTES 2, 3, 4, 5, AND 8)
TOTAL CAPITALIZATION AND LIABILITIES $ 1,049,206 $ 791,283
The accompanying notes are an integral part of these statements.
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STATEMENTS OF CAPITALIZATION
At December 31, 1993 and 1992
Mississippi Power Company 1993 Annual Report
1993 1992 1993 1992
(in thousands) (percent of total)
COMMON STOCK EQUITY:
Common stock, without par value --
Authorized -- 1,130,000 shares
Outstanding -- 1,121,000 shares in
1993 and 1992 $ 37,691 $ 37,691
Paid-in capital 154,362 124,326
Premium on preferred stock 372 194
Retained earnings (Note 12) 129,343 118,429
Total common stock equity 321,768 280,640 49.8 % 47.3 %
CUMULATIVE PREFERRED STOCK:
$100 par value --
Authorized -- 1,244,139 shares
Outstanding -- 744,139 shares in 1993
and 1992
4.40% 4,000 4,000
4.60% 2,010 2,010
4.72% 5,000 5,000
6.32% 15,000 -
6.65% 8,404 -
7.00% 5,000 5,000
7.25% 35,000 35,000
8.44% - 8,404
8.80% - 15,000
Total (annual dividend requirement -- $4,899,000) 74,414 74,414 11.5 12.5
LONG-TERM DEBT:
First mortgage bonds --
Maturity Interest Rates
June 1, 1994 4 5/8% 10,000 10,000
July 1, 1995 4 3/4% 11,000 11,000
August 1, 1996 6% 10,000 10,000
November 1, 1997 7 1/8% - 10,000
March 1, 1998 5 3/8% 35,000 -
2000 to 2003 6 5/8% to 7 5/8% 40,000 80,000
May 1, 2021 9 1/4% 48,700 50,000
June 1, 2023 7.45% 35,000 -
Total first mortgage bonds 189,700 171,000
Pollution control obligations (Note 10) 63,165 50,175
Other long-term debt (Note 10) 19,678 27,848
Unamortized debt premium (discount), net (2,807) (1,495)
Total long-term debt (annual interest
requirement--$17,913,000) 269,736 247,528
Less amount due within one year (Note 11) 19,345 8,878
Long-term debt excluding amount due within
one year 250,391 238,650 38.7 40.2
TOTAL CAPITALIZATION $ 646,573 $ 593,704 100.0 % 100.0 %
The accompanying notes are an integral part of these statements.
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STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1993, 1992, and 1991
Mississippi Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 118,429 $ 111,670 $ 117,543
Net income after dividends on preferred stock 42,436 36,790 22,627
Cash dividends on common stock (29,000) (28,000) (28,500)
Preferred stock transactions and other, net (2,522) (2,031) -
BALANCE AT END OF PERIOD (NOTE 12) $ 129,343 $ 118,429 $ 111,670
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1993, 1992, and 1991
1993 1992 1991
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 124,326 $ 124,300 $ 124,300
Contributions to capital by parent company 30,036 26 -
BALANCE AT END OF PERIOD $ 154,362 $ 124,326 $ 124,300
The accompanying notes are an integral part of these statements.
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NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 1993 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
GENERAL
Mississippi Power Company is a wholly owned subsidiary of The Southern
Company, which is the parent company of five operating companies, Southern
Company Services (SCS), Southern Electric International (Southern Electric),
Southern Nuclear Operating Company (Southern Nuclear), and various other
subsidiaries related to foreign utility operations and domestic non-utility
operations. The operating companies (Alabama Power Company, Georgia Power
Company, Gulf Power Company, Mississippi Power Company, and Savannah
Electric and Power Company) provide electric service in four southeastern
states. Contracts among the companies--dealing with jointly owned
generating facilities, interconnecting transmission lines, and the exchange
of electric power--are regulated by the Federal Energy Regulatory Commission
(FERC) or the Securities and Exchange Commission. SCS provides, at cost,
specialized services to The Southern Company and to the subsidiary
companies. Southern Electric designs, builds, owns, and operates power
production facilities and provides a broad range of technical services to
industrial companies and utilities in the United States and a number of
international markets. Southern Nuclear provides services to The Southern
Company's nuclear power plants.
The Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both The Southern Company and
its subsidiaries are subject to the regulatory provisions of the PUHCA.
Mississippi Power is also subject to regulation by the FERC and the
Mississippi Public Service Commission (MPSC). The Company follows generally
accepted accounting principles and complies with the accounting policies and
practices prescribed by the respective commissions.
The 1991 financial statements of the Company included the accounts of
Electric City Merchandise Company, Inc. (Electric City), which discontinued
operations in 1991. All significant intercompany transactions were
eliminated in consolidation.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
REVENUES
Mississippi Power accrues revenues for service rendered but unbilled at the
end of each fiscal period. The Company's retail and wholesale rates include
provisions to adjust billings for fluctuations in fuel and the energy
component of purchased power. Retail rates also include provisions to
adjust billings for fluctuations in costs for ad valorem taxes. Revenues
are adjusted for differences between the recoverable fuel and ad valorem
expenses and the amounts actually recovered in current rates.
DEPRECIATION
Depreciation of the original cost of depreciable utility plant in service is
provided by using composite straight-line rates which approximated 3.1
percent in 1993 and 3.3 percent in 1992 and 1991. When property subject to
depreciation is retired or otherwise disposed of in the normal course of
business, its cost -- together with the cost of removal, less salvage -- is
charged to the accumulated provision for depreciation. Minor items of
property included in the original cost of the plant are retired when the
related property unit is retired.
INCOME TAXES
Mississippi Power provides deferred income taxes for all significant income
tax temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
In years prior to 1993, income taxes were accounted for and reported
under Accounting Principles Board Opinion No. 11. Effective January 1,
1993, Mississippi Power adopted FASB Statement No. 109, Accounting for
Income Taxes. Statement No. 109 required, among other things, conversion to
the liability method of accounting for accumulated deferred income taxes.
See Note 9 to the financial statements for additional information about
Statement No. 109.
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NOTES (continued)
Mississippi Power Company 1993 Annual Report
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that
are necessary to finance the construction of new facilities. While cash is
not realized currently from such allowance, it increases the revenue
requirement over the service life of the plant through a higher rate base
and higher depreciation expense. The composite rates used to capitalize the
cost of funds devoted to construction were 6.8 percent in 1993, 8.2 percent
in 1992, and 9.8 percent in 1991. AFUDC (net of income taxes), as a percent
of net income after dividends on preferred stock, was 3.5 percent in 1993,
2.7 percent in 1992, and 4.8 percent in 1991.
UTILITY PLANT
Utility plant is stated at original cost. This cost includes: materials;
labor; minor items of property; appropriate administrative and general
costs; payroll-related costs such as taxes, pensions, and other benefits;
and the estimated cost of funds used during construction. The cost of
maintenance, repair, and replacement of minor items of property is charged
to maintenance expense except for the maintenance of coal cars and a portion
of the railway track maintenance, which are charged to fuel stock. The cost
of replacements of property (exclusive of minor items of property) is
charged to utility plant.
CASH AND CASH EQUIVALENTS
For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
FINANCIAL INSTRUMENTS
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, all financial instruments of the Company -- for which
the carrying amount does not approximate fair value -- are shown in the
table below as of December 31:
1993 1992
Carrying Fair Carrying Fair
Amount Value Amount Value
(in thousands)
Investment
securities - - $ 3,622 $ 3,745
Long-term
debt $269,736 $278,025 247,529 249,489
The fair value of investment securities was based on listed closing
market prices. The fair value for long-term debt was based on either
closing market prices or closing prices of comparable instruments.
MATERIALS AND SUPPLIES
Generally, materials and supplies include the cost of transmission,
distribution and generating plant materials. Materials are charged to
inventory when purchased and then expensed or capitalized to plant, as
appropriate, when used or installed.
VACATION PAY
Mississippi Power's employees earn their vacation in one year and take it in
the subsequent year. However, for ratemaking purposes, vacation pay is
recognized as an allowable expense only when paid. Consistent with this
ratemaking treatment, the Company accrues a current liability for earned
vacation pay and records a current asset representing the future
recoverability of this cost. Such amounts were $4.8 million and $4.7
million at December 31, 1993 and 1992, respectively. In 1994, an estimated
80 percent of the 1993 deferred vacation cost will be expensed, and the
balance will be charged to construction and other accounts.
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NOTES (continued)
Mississippi Power Company 1993 Annual Report
PROVISION FOR PROPERTY DAMAGE
Due to the significant increase in the cost of traditional insurance,
effective in 1993, Mississippi Power became self-insured for the full cost
of storm and other damage to its transmission and distribution property. As
permitted by regulatory authorities, the Company provided for the cost of
storm, fire and other uninsured casualty damage by charges to income of $1.5
million in 1993, 1992, and 1991. The cost of repairing damage resulting
from such events that individually exceed $50 thousand is charged to the
accumulated provision to the extent it is available. As of December 31,
1993, the accumulated provision amounted to $10.5 million. Regulatory
treatment by the MPSC allows a maximum accumulated provision of $10.9
million.
DISCONTINUED OPERATIONS
Electric City began operating as a subsidiary of Mississippi Power in
October 1987 and was formally dissolved as of December 31, 1991. Under an
agreement reached in October 1991, a portion of Electric City's assets,
including inventory and fixed assets, was sold to a concern independent of
Mississippi Power. The remaining assets and liabilities, which were not
material, were transferred to the Company.
The impact of Electric City on Mississippi Power's consolidated earnings
in 1991 consisted of (a) a pretax operating loss of $10.2 million ($6.4
million after income taxes) and (b) the pretax loss of $8.7 million ($5.5
million after income taxes) resulting from the disposal of Electric City.
2. RETIREMENT BENEFITS:
PENSION PLAN
Mississippi Power has a defined benefit, trusteed, non-contributory pension
plan that covers substantially all regular employees. Benefits are based on
the greater of amounts resulting from two different formulas: years of
service and final average pay or years of service and a flat-dollar benefit.
The Company uses the "entry age normal method with a frozen initial
liability" actuarial method for funding purposes, subject to limitations
under federal income tax regulations. Amounts funded to the pension fund
are primarily invested in equity and fixed-income securities. FASB
Statement No. 87, Employers' Accounting for Pensions, requires use of the
"projected unit credit" actuarial method for financial reporting purposes.
POSTRETIREMENT BENEFITS
Mississippi Power also provides certain medical care and life insurance
benefits for retired employees. Substantially all employees may become
eligible for these benefits when they retire. A qualified trust for medical
benefits has been established for funding amounts to the extent deductible
under federal income tax regulations. Amounts funded are primarily invested
in debt and equity securities. Accrued costs of life insurance benefits,
other than current cash payments for retirees, currently are not being
funded.
Effective January 1, 1993, Mississippi Power adopted FASB Statement No.
106, Employers' Accounting for Postretirement Benefits Other Than Pensions,
on a prospective basis. Statement No. 106 requires that medical care and
life insurance benefits for retired employees be accounted for on an accrual
basis using a specified actuarial method, "benefit/years-of-service."
Because the adoption of Statement No. 106 was reflected in rates, it did not
have a material impact on net income.
Prior to 1993, Mississippi Power recognized these benefit costs on an
accrual basis using the "aggregate cost" actuarial method, which spreads the
expected cost of such benefits over the remaining periods of employees'
service as a level percentage of payroll costs. The total costs of such
benefits recognized by the Company in 1992 and 1991 were $3.6 million and
$3.0 million, respectively.
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NOTES (continued)
Mississippi Power Company 1993 Annual Report
STATUS AND COST OF BENEFITS
Shown in the following tables are actuarial results and assumptions for
pension and postretirement medical and life insurance benefits as computed
under the requirements of FASB Statement Nos. 87 and 106, respectively.
Retiree medical and life insurance information is shown only for 1993
because Statement No. 106 was adopted as of January 1, 1993, on a
prospective basis. The funded status of the plans at December 31 was as
follows:
Pension
1993 1992
(in thousands)
Actuarial present value of
benefit obligation:
Vested benefits $ 73,735 $62,840
Non-vested benefits 3,245 2,773
Accumulated benefit obligation 76,980 65,613
Additional amounts related to
projected salary increases 24,434 28,721
Projected benefit obligation 101,414 94,334
Less:
Fair value of plan assets 154,224 138,507
Unrecognized net gain (49,239) (40,456)
Unrecognized prior service cost 3,590 3,809
Unrecognized transition asset (7,188) (7,741)
Prepaid asset (accrued liability)
recognized in the
Balance Sheets $ (27) $ (215)
Postretirement
Medical Life
1993 1993
Actuarial present value of
benefit obligation:
Retirees and dependents $10,408 $3,315
Employees eligible to retire 3,752 -
Other employees 19,389 4,596
Accumulated benefit
obligation 33,549 7,911
Less:
Fair value of plan assets 6,271 84
Unrecognized net loss 3,500 (632)
Unrecognized transition
obligation 16,540 3,606
Accrued liability recognized in
the Balance Sheets $ 7,238 $4,853
The weighted average rates assumed in the above actuarial calculations
were:
1993 1992 1991
Discount 7.5% 8.0% 8.0%
Annual salary increase 5.0 6.0 6.0
Long-term return on
plan assets 8.5 8.5 8.5
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend
rate of 11.3 percent for 1993, decreasing gradually to 6.0 percent through
the year 2000 and remaining at that level thereafter. An annual increase in
the assumed medical care cost trend rate by 1.0 percent would increase the
accumulated medical benefit obligation as of December 31, 1993, by $6.4
million and the aggregate of the service and interest cost components of the
net retiree medical cost by $722 thousand.
Components of the plans' net cost are shown below:
Pension
1993 1992 1991
(in thousands)
Benefits earned during
the year $ 3,792 $ 3,595 $ 3,361
Interest cost on
projected benefit
obligation 7,296 6,886 6,345
Actual return on plan
assets (20,017) (5,812) (34,773)
Net amortization and
deferral 8,741 (4,265) 25,833
Net pension cost (income) $ (188) $ 404 $ 766
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NOTES (continued)
Mississippi Power Company 1993 Annual Report
Of the above net pension amounts recorded,
($170 thousand) in 1993, $269 thousand in 1992, and $576 thousand in 1991
were recorded in operating expenses, and the remainder was recorded in
construction and other accounts.
Postretirement
Medical Life
1993 1993
(in thousands)
Benefits earned during the
year $1,149 $299
Interest cost on accumulated
benefit obligation 2,187 624
Amortization of transition
obligation over 20 years 871 180
Actual return on plan assets (808) (6)
Net amortization and deferral 343 -
Net postretirement cost $3,742 $1,097
Of the above net postretirement medical and life insurance costs recorded
in 1993, $3.9 million was charged to operating expense and the remainder was
charged to construction and other accounts.
3. LITIGATION AND REGULATORY MATTERS:
RETAIL RATE ADJUSTMENT PLANS
Mississippi Power's retail base rates have been set under a Performance
Evaluation Plan (PEP) since 1986. During 1993, all matters related to the
original PEP case were finally resolved when the Supreme Court of
Mississippi granted a joint motion to dismiss pending appeals. Also in
1993, the MPSC ordered Mississippi Power to review and propose changes to
the plan that would reduce the impact of rate changes on the customer and
provide incentives for Mississippi Power to keep customer prices low. In
response, Mississippi Power filed a revised plan and, on January 4, 1994,
the MPSC approved PEP-2. The revised plan includes a mechanism for sharing
rate adjustments based on the Company's ability to maintain low rates for
customers and on the Company's performance as measured by three performance
indicators that emphasize those factors which most directly impact the
customers. PEP-2 provides for semiannual evaluations of Mississippi's
performance-based return on investment, rather than on common equity as
previously calculated. As in previous plans, any change in rates is limited
to 2 percent of retail revenues per evaluation period before a public
hearing is required. PEP-2 will remain in effect until the MPSC modifies or
terminates the plan.
ENVIRONMENTAL COMPLIANCE OVERVIEW PLAN
The MPSC approved Mississippi Power's ECO Plan in 1992. The plan
establishes procedures to facilitate the MPSC's overview of the Company's
environmental strategy and provides for recovery of costs associated with
environmental projects approved by the MPSC. Under the ECO Plan any
increase in the annual revenue requirement is limited to 2 percent of retail
revenues. However, the plan also provides for carryover of any amount over
the 2 percent limit into the next year's revenue requirement. The ECO Plan
resulted in an annual retail rate increase of $2.6 million effective April
1993.
FERC REVIEWS EQUITY RETURNS AND OTHER REGULATORY MATTERS
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the Southern electric system's wholesale rate schedules
and contracts that have a return on equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all
of the transmission, unit power, long-term power and other similar
contracts, including the Company's Transmission Facilities Agreement (TFA)
discussed in Note 8 under "Lease Agreements." Any changes in rate of return
on common equity that may occur as a result of this proceeding would be
effective 60 days after a proper notice of the proceeding is published. A
notice was published on May 10, 1991.
In August 1992, an administrative law judge issued an opinion that
changes in rate schedules and contracts were not necessary and that the FERC
staff failed to show how any changes were in the public interest. The FERC
staff has filed exceptions to the administrative law judge's opinion, and
the matter remains pending before the FERC.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse
effect on Mississippi Power's financial statements.
In 1988, the Company and its operating affiliates filed with the FERC a
contract governing the pricing and other aspects of power transactions among
the companies. In 1989, the FERC ordered hearings on the contract and made
revenues collected under the contract subject to refund. In 1992, the
II-200
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NOTES (continued)
Mississippi Power Company 1993 Annual Report
FERC ruled that certain production costs under the contract had not been
properly classified and ordered that the contract be revised and that
refunds be made. Under reconsideration, the FERC determined that refunds
were not necessary and ordered that its mandated changes in computing
certain expenses under the system interchange contract become effective in
August 1993. The changes mandated by the FERC will not materially affect
the Company's net income.
WHOLESALE RATE FILING
On September 1, 1993, Mississippi Power filed a $3.6 million wholesale rate
increase request with the FERC. Prior to this filing, the Company conferred
and negotiated a settlement with all of its wholesale all requirements
customers, who have executed a Settlement Agreement and Certificates of
Concurrence to be included in this filing with the FERC. The Company is
awaiting a response from the FERC.
RETAIL RATEPAYERS' SUITS CONCLUDED
In 1989, three retail ratepayers of the Company filed a civil complaint in
the U.S. District Court for the Southern District of Mississippi against
Mississippi Power and other parties. The complaint alleged that Mississippi
Power obtained excessive rate increases by improper accounting for spare
parts and sought actual damages estimated to be at least $10 million, plus
treble and punitive damages, on behalf of all retail ratepayers of the
Company for alleged violations of the federal Racketeer Influenced and
Corrupt Organizations Act, federal and state antitrust laws, other federal
and state statutes, and common law fraud. Mississippi Power also was named
as a defendant, together with other parties in a similar civil action filed
in the U.S. District Court for the Northern District of Florida. The
defendants' motions for dismissal were granted by the courts, resolving
these suits.
4. CONSTRUCTION PROGRAM:
Mississippi Power is engaged in continuous construction programs, the costs
of which are currently estimated to total some $96 million in 1994, $62
million in 1995, and $98 million in 1996. These estimates include AFUDC of
$1.6 million in 1994, $1.6 million in 1995, and $2.7 million in 1996.
The construction program is subject to periodic review and revision, and
actual construction costs may vary from the above estimates because of
numerous factors. These factors include changes in business conditions;
revised load growth estimates; changes in environmental regulations;
increasing costs of labor, equipment and materials; and cost of capital.
The Company does not have any new baseload generating plants under
construction. However, the construction of a combustion turbine generation
unit of 78 megawatts was completed in February 1994. In addition,
significant construction will continue related to transmission and
distribution facilities and the upgrading and extension of the useful lives
of generating plants.
See Management's Discussion and Analysis under "Environmental Matters"
for information on the impact of the Clean Air Act and other environmental
matters.
5. FINANCING AND COMMITMENTS:
FINANCING
Mississippi Power's construction program is expected to be financed from
internal and other sources, such as the issuance of additional long-term
debt and preferred stock and the receipt of capital contributions from The
Southern Company.
The amounts of first mortgage bonds and preferred stock which can be
issued in the future will be contingent upon market conditions, adequate
earnings levels, regulatory authorizations and other factors. See
Management's Discussion and Analysis under "Sources of Capital" for
information regarding the Company's coverage requirements.
At December 31, 1993, Mississippi Power had committed credit agreements
(360 day committed lines) with banks for $21 million. Additionally,
Mississippi Power had $70 million of unused committed credit agreements in
the form of revolving credit agreements expiring December 1, 1996. These
agreements allow short-term borrowings to be converted into term loans,
payable in 12 equal quarterly installments, with the first installment due
at the end of the first calendar quarter after the applicable termination
date or at an earlier date at the Company's option. In connection with
these credit arrangements, the Company agrees to pay commitment fees based
on the unused portions of the commitments or to maintain compensating
balances with the banks.
As of December 31, 1993, Mississippi Power had $40 million in short-term
bank borrowings all of which were made apart from committed credit
arrangements.
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NOTES (continued)
Mississippi Power Company 1993 Annual Report
ASSETS SUBJECT TO LIEN
Mississippi Power's mortgage indenture dated as of September 1, 1941, as
amended and supplemented, which secures the first mortgage bonds issued by
the Company, constitutes a direct first lien on substantially all the
Company's fixed property and franchises.
FUEL COMMITMENTS
To supply a portion of the fuel requirements of its generating plants,
Mississippi Power has entered into various long-term commitments for the
procurement of fuel. In most cases, these contracts contain provisions for
price escalations, minimum production levels, and other financial
commitments. Total estimated obligations were approximately $243 million at
December 31, 1993. Additional commitments for fuel will be required in the
future to supply the Company's fuel needs.
In order to take advantage of lower cost coal supplies, agreements were
reached in December 1986 to terminate two contracts for the supply of coal
to Plant Daniel, which is jointly owned by Mississippi Power and Gulf Power,
an operating affiliate. The Company's portion of this payment was about $60
million. In accordance with the ratemaking treatment, the cost to terminate
the contracts is being amortized through 1995 to match costs with savings
achieved. The remaining unamortized amount of Mississippi Power's share of
principal payments to the suppliers including the current portion totaled
$18 million at December 31, 1993.
6. JOINT OWNERSHIP AGREEMENTS:
Mississippi Power and Alabama Power own as tenants in common Greene County
Electric Generating Plant (coal) located in Alabama; and Mississippi Power
and Gulf Power own as tenants in common Daniel Electric Generating Plant
(coal) located in Mississippi. At December 31, 1993, Mississippi Power's
percentage ownership and investment in these jointly owned facilities were
as follows:
Total Company's
Generating Megawatts Percent Gross Accumulated
Plant Capacity Ownership Investment Depreciation
(in thousands)
Greene
County 500 40% $59,897 $28,365
Daniel 1,000 50% 218,462 82,778
Mississippi Power's share of plant operating expenses is included in the
corresponding operating expenses in the Statements of Income.
7. LONG-TERM POWER SALES AGREEMENTS:
GENERAL
Mississippi Power and the other operating affiliates of The Southern Company
have entered into long-term contractual agreements for the sale of capacity
and energy to certain non-affiliated utilities located outside of the
system's service area. Some of these agreements (unit power sales) are firm
commitments and pertain to capacity related to specific generating units.
Mississippi Power's participation in firm production capacity unit power
sales ended in January 1989. However, the Company continues to participate
in transmission and energy sales under the unit power sales agreements. The
other agreements (other long-term sales) are non-firm commitments and are
based on capacity of the system in general. Because the energy is generally
sold at variable costs under these agreements, only revenues from capacity
sales affect profitability. Off-system capacity revenues for the Company
have been as follows:
Other
Year Unit Power Long-Term Total
(in thousands)
1993 $1,571 $2,620 $4,191
1992 2,168 1,405 3,573
1991 1,510 1,204 2,714
Long-term non-firm power of 400 megawatts was sold in 1993 by the
Southern electric system to Florida Power Corporation. In January 1994,
this amount decreased to 200 megawatts, and the contract will expire at
year-end.
II-202
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NOTES (continued)
Mississippi Power Company 1993 Annual Report
GULF STATES SETTLEMENT COMPLETED
On November 7, 1991, subsidiaries of The Southern Company entered into a
settlement agreement with Gulf States that resolved litigation between the
companies that had been pending since 1986 and arose out of a dispute over
certain unit power and other long-term power sales contracts. In 1993, all
remaining terms and obligations of the settlement agreement were satisfied.
Based on the value of the settlement proceeds received -- less the
amounts previously included in income -- Mississippi Power recorded an
increase in net income of approximately $2.6 million in 1991.
8. LEASE AGREEMENTS:
In 1984, Mississippi Power and Gulf States entered into a forty-year
transmission facilities agreement whereby Gulf States began paying a use fee
to the Company covering all expenses relative to ownership and operation and
maintenance of a 500 kV line, including amortization of its original $57
million cost. In 1993, 1992, and 1991 the use fees collected under the
agreement, net of related expenses, amounted to $3.9 million, $3.9 million
and $4.0 million, respectively, and are included with other income, net, in
the Statements of Income. For other information see Note 3 under "FERC
Reviews Equity Returns and Other Regulatory Matters."
In 1989, Mississippi Power entered into a twenty-two year operating lease
agreement for the use of 495 aluminum railcars to transport coal to Plant
Daniel. Gulf Power, as joint owner of Plant Daniel, is responsible for one
half of the lease costs. The Company's share of the lease is charged to
fuel inventory and allocated to fuel expense as the fuel is used. The lease
costs charged to inventory were $1.2 million in 1993, $1.2 million for 1992
and $1.3 million for 1991. For the year 1994, the Company's annual lease
payment will be $1.2 million. The Company's annual lease payment for 1995
will be $2.4 million and for 1996, 1997, and in 1998 the payment will be
$1.2 million. Lease payments after 1998 total approximately $17.4 million.
The Company has the option after three years to purchase the railcars at the
greater of termination value or fair market value. Additionally, at the end
of the lease term, Mississippi Power has the option to renew the lease.
9. INCOME TAXES:
Effective January 1, 1993, Mississippi Power adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption of Statement No. 109 resulted in
cumulative adjustments that had no effect on net income. The adoption also
resulted in the recording of additional deferred income taxes and related
assets and liabilities. The related assets of $25 million are revenues to
be received from customers. These assets are attributable to tax benefits
flowed through to customers in prior years and to taxes applicable to
capitalized AFUDC. The related liabilities of $48 million are revenues to
be refunded to customers. These liabilities are attributable to deferred
taxes previously recognized at rates higher than current enacted tax law and
unamortized investment tax credits. Additionally, deferred income taxes
related to accelerated tax depreciation previously shown as a reduction to
utility plant were reclassified.
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NOTES (continued)
Mississippi Power Company 1993 Annual Report
Details of the federal and state income tax provisions are shown below:
1993 1992 1991
(in thousands)
Total provision for
income taxes
Federal --
Currently payable $15,842 $20,286 $16,984
Deferred --current year 5,158 (1,578) (2,404)
--reversal of
prior years (820) (3,931) (8,446)
Deferred investment tax
credits - - (2)
20,180 14,777 6,132
State --
Currently payable 2,945 2,992 2,709
Deferred --current 1,339 218 (223)
--reversal of
prior years (638) (182) (796)
3,646 3,028 1,690
Total 23,826 17,805 7,822
Less income taxes
charged (credited) to: -
Disposal of subsidiary - (3,245)
Other income 1,158 1,427 (2,909)
Federal and state
income taxes charged
to operations $22,668 $16,378 $13,976
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities are as
follows:
1993
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $130,299
Basis differences 11,332
Coal contract buyouts 6,870
Other 18,719
Total 167,220
Deferred tax assets:
Other property basis differences 28,779
Pension and other benefits 4,625
Property insurance 4,031
Unbilled fuel 4,205
Other 5,562
Total 47,202
Net deferred tax liabilities
(assets) 120,018
Portion included in current assets,
net 3,188
Accumulated deferred income taxes
in the Balance Sheets $123,206
In 1989, under order of the MPSC, Mississippi Power began amortizing
deferred income taxes not covered by the Internal Revenue Service
normalization requirements, that had been recorded at rates higher than
those specified by the current statutory income tax rules. This
amortization occurred over a 60-month period, the effect of which was a
reduction of income tax expense of approximately $2.7 million per year. At
December 31, 1993, this tax rate differential was fully amortized.
Deferred investment tax credits are amortized over the life of the
related property with such amortization normally applied as a credit to
reduce depreciation in the Statements of Income. Credits amortized in this
manner amounted to $1.5 million in 1993, $1.4 million in 1992 and $1.5
million in 1991. At December 31, 1993, all investment tax credits available
to reduce federal income taxes payable had been utilized.
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NOTES (continued)
Mississippi Power Company 1993 Annual Report
The total provision for income taxes as a percentage of pre-tax income
and the differences between those effective rates and the statutory federal
tax rates were as follows:
1993 1992 1991
Total effective tax rate 33% 30% 23%
State income tax, net of
federal income tax benefit (3) (3) (3)
Tax rate differential 4 6 11
Other 1 1 3
Statutory federal tax rate 35% 34% 34%
Mississippi Power and its affiliates file a consolidated federal income
tax return. Under a joint consolidated income tax agreement, each company's
current and deferred tax expense is computed on a stand-alone basis, and
consolidated tax savings are allocated to each company based on its ratio of
taxable income to total consolidated taxable income.
10. OTHER LONG-TERM DEBT:
Details of other long-term debt are as follows:
December 31,
1993 1992
(in thousands)
Obligations incurred in
connection with the sale by
public authorities of
tax-exempt pollution control
revenue bonds:
Collateralized --
5.80% due 2007 $ 990 $19,000
Variable rate due 2020 6,550 6,550
Variable rate due 2022 16,750 16,750
6.20% due 2023 13,000 -
5.65% due 2023 25,875 -
Non-collateralized --
5.90% due 2003 - 7,875
63,165 50,175
Notes payable:
8.25% due 1993-1995 17,520 25,255
7.50% due 1993-1995 2,158 2,593
19,678 27,848
Total $82,843 $78,023
Pollution control obligations represent installment or lease purchases of
pollution control facilities financed by application of funds derived from
sales by public authorities of tax-exempt revenue bonds. Mississippi Power
has authenticated and delivered to the Trustee a like principal amount of
first mortgage bonds as security for obligations under collateralized
installment agreements. The principal and interest on the first mortgage
bonds will be payable only in the event of default under these agreements.
The 5.8% Series of pollution control obligations has a cash sinking fund
requirement of $10 thousand annually through 1997 and $20 thousand in 1998.
At December 31, 1993, under "Other Property and Investments"
approximately $6 million related to the 6.20% Series of Pollution Control
Obligations remains available for completion of certain solid waste disposal
facilities.
The 8.25 percent notes payable relate to the termination of two coal
contracts. See Note 5 under "Fuel Commitments" for information on these
coal contracts.
The annual estimated maturities of total notes payable are $8.8 million
in 1994 and $10.8 million in 1995.
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NOTES (continued)
Mississippi Power Company 1993 Annual Report
11. LONG-TERM DEBT DUE WITHIN ONE YEAR:
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year is as follows:
1993 1992
(in thousands)
Bond improvement
fund requirements $1,902 $1,710
Less:
Portion to be
satisfied by certifying
property additions 1,402 1,210
Cash improvement fund
requirements 500 500
First mortgage bond
maturities and
redemptions 10,000 -
Pollution control bond
cash sinking fund
requirements (Note 10) 10 245
Current portion of notes
payable (Note 10) 8,835 8,133
Total $19,345 $8,878
The first mortgage bond improvement fund requirement is one percent of
each outstanding series authenticated under the indenture of Mississippi
Power prior to January 1 of each year, other than first mortgage bonds
issued as collateral security for certain pollution control obligations.
The requirement must be satisfied by June 1 of each year by depositing cash
or reacquiring bonds, or by pledging additional property equal to 166-2/3
percent of such requirement.
12. COMMON STOCK DIVIDEND RESTRICTIONS:
Mississippi Power's first mortgage bond indenture and the Articles of
Incorporation contain various common stock dividend restrictions. At
December 31, 1993, $86 million of retained earnings was restricted against
the payment of cash dividends on common stock under the most restrictive
terms of the mortgage indenture or Articles of Incorporation.
13. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial data for 1993 and 1992 are as follows:
Net Income
After Dividends
Quarter Operating Operating On
Ended Revenues Income Preferred Stock
March 1993 $101,552 $ 9,529 $ 4,424
June 1993 117,764 18,147 11,852
September 1993 148,102 22,377 16,560
December 1993 107,465 13,333 9,600
March 1992 $ 94,931 $11,400 $ 6,001
June 1992 109,199 17,011 11,422
September 1992 129,018 18,911 13,008
December 1992 101,299 10,968 6,359
Mississippi Power's business is influenced by seasonal weather conditions
and the timing of rate changes.
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SELECTED FINANCIAL AND OPERATING DATA
Mississippi Power Company 1993 Annual Report
1993 1992 1991
OPERATING REVENUES (IN THOUSANDS) $ 474,883 $ 434,447 $432,386
NET INCOME AFTER DIVIDENDS
ON PREFERRED STOCK (IN THOUSANDS) $ 42,436 $ 36,790 $ 22,627
CASH DIVIDENDS ON COMMON STOCK (IN THOUSANDS) $ 29,000 $ 28,000 $ 28,500
RETURN ON AVERAGE COMMON EQUITY (PERCENT) 14.09 13.27 8.17
TOTAL ASSETS (IN THOUSANDS) $1,049,206 $ 791,283 $790,641
GROSS PROPERTY ADDITIONS (IN THOUSANDS) $ 139,976 $ 68,189 $ 53,675
CAPITALIZATION (IN THOUSANDS):
Common stock equity $ 321,768 $ 280,640 $273,855
Preferred stock 74,414 74,414 39,414
Preferred stock subject to mandatory redemption - - -
Long-term debt 250,391 238,650 304,150
Total (excluding amounts due within one year) $ 646,573 $ 593,704 $617,419
CAPITALIZATION RATIOS (PERCENT):
Common stock equity 49.8 47.3 44.4
Preferred stock 11.5 12.5 6.4
Long-term debt 38.7 40.2 49.2
Total (excluding amounts due within one year) 100.0 100.0 100.0
FIRST MORTGAGE BONDS (IN THOUSANDS):
Issued 70,000 40,000 50,000
Retired 51,300 104,703 -
PREFERRED STOCK (IN THOUSANDS):
Issued 23,404 35,000 -
Retired 23,404 - 4,118
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A+ A+ A+
Duff & Phelps A+ A+ A+
Preferred Stock -
Moody's a1 a1 a1
Standard and Poor's A A A
Duff & Phelps A A A
CUSTOMERS (YEAR-END):
Residential 151,692 150,248 148,978
Commercial 28,648 28,056 27,441
Industrial 570 573 562
Other 190 189 400
Total 181,100 179,066 177,381
EMPLOYEES (YEAR-END) 1,586 1,619 1,630
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SELECTED FINANCIAL AND OPERATING DATA
Mississippi Power Company 1993 Annual Report
1990 1989 1988 1987 1986 1985 1984 1983
$446,871 $442,650 $437,939 $455,843 $476,265 $475,610 $442,507 $414,595
$ 34,176 $ 38,576 $ 36,081 $ 35,200 $ 33,814 $ 33,330 $ 31,380 $ 35,404
$ 27,500 $ 27,000 $ 27,600 $ 24,700 $ 23,700 $ 22,600 $ 21,000 $ 18,900
12.36 14.43 14.03 14.68 15.28 15.83 15.74 19.74
$800,026 $786,570 $779,319 $764,068 $767,110 $679,577 $660,530 $649,373
$ 49,009 $ 43,916 $ 54,550 $ 53,288 $ 62,488 $ 57,791 $ 37,290 $ 72,277
$279,833 $273,157 $261,473 $252,992 $226,601 $216,087 $205,018 $193,609
39,414 39,414 39,414 39,414 39,414 39,414 39,414 39,414
3,750 4,500 5,250 6,750 8,250 9,750 10,500 11,250
270,724 277,693 287,525 294,811 299,684 261,594 267,051 267,271
$593,721 $594,764 $593,662 $593,967 $573,949 $526,845 $521,983 $511,544
47.1 45.9 44.1 42.6 39.5 41.0 39.3 37.9
7.3 7.4 7.5 7.8 8.3 9.3 9.5 9.9
45.6 46.7 48.4 49.6 52.2 49.7 51.2 52.2
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
- - - - 35,000 - - -
4,000 3,823 - 29,701 29,250 250 250 3,246
- - - - - - - -
750 750 1,500 1,500 1,500 1,111 639 750
A1 A1 A1 A1 A1 A1 A1 A3
A+ A+ A+ A+ A+ A A A
A+ A+ 5 5 5 5 5 6
a1 a1 a1 a1 a1 a1 a1 a3
A A A A A A A A
A A 6 6 6 6 6 6
147,738 147,308 146,750 146,273 145,809 145,071 142,846 140,730
27,134 26,867 26,751 26,342 26,217 25,629 25,404 24,467
574 525 478 438 393 371 348 344
411 404 399 389 363 356 356 366
175,857 175,104 174,378 173,442 172,782 171,427 168,954 165,907
1,842 1,750 1,831 1,898 1,882 1,801 1,669 1,653
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SELECTED FINANCIAL AND OPERATING DATA (continued)
Mississippi Power Company 1993 Annual Report
1993 1992 1991
OPERATING REVENUES (IN THOUSANDS):
Residential $ 118,793 $ 109,781 $ 103,820
Commercial 115,152 107,131 103,666
Industrial 130,198 117,010 116,972
Other 3,760 3,533 5,869
Total retail 367,903 337,455 330,327
Sales for resale - non-affiliates 83,511 80,213 78,826
Sales for resale - affiliates 15,519 10,055 18,044
Total revenues from sales of electricity 466,933 427,723 427,197
Other revenues 7,950 6,724 5,189
Total $ 474,883 $ 434,447 $ 432,386
KILOWATT-HOUR SALES (IN THOUSANDS):
Residential 1,929,835 1,804,858 1,832,266
Commercial 1,933,685 1,811,042 1,768,441
Industrial 3,623,543 3,536,634 3,297,247
Other 38,357 38,261 89,375
Total retail 7,525,420 7,190,795 6,987,329
Sales for resale - non-affiliates 2,544,982 2,687,917 2,706,320
Sales for resale - affiliates 426,919 280,443 617,696
Total 10,497,321 10,159,155 10,311,345
AVERAGE REVENUE PER KILOWATT-HOUR (CENTS):
Residential 6.16 6.08 5.67
Commercial 5.96 5.92 5.86
Industrial 3.59 3.31 3.55
Total retail 4.89 4.69 4.73
Total sales 4.45 4.21 4.14
RESIDENTIAL AVERAGE ANNUAL KILOWATT-HOUR USE PER CUSTOMER 12,780 12,066 12,338
RESIDENTIAL AVERAGE ANNUAL REVENUE PER CUSTOMER $ 786.71 $ 733.90 $ 699.11
PLANT NAMEPLATE CAPACITY RATINGS (YEAR-END) (MEGAWATTS) 2,011 2,011 2,011
MAXIMUM PEAK-HOUR DEMAND (MEGAWATTS):
Winter 1,401 1,386 1,267
Summer 1,872 1,755 1,682
Annual Load Factor (percent) 60.0 60.8 61.5
Plant Availability - Fossil-Steam (percent) 88.0 92.0 89.8
SOURCE OF ENERGY SUPPLY (PERCENT):
Coal 63.5 60.4 64.1
Oil and gas 7.6 5.8 8.1
Purchased power -
From non-affiliates 1.3 1.2 0.7
From affiliates 27.6 32.6 27.1
Total 100.0 100.0 100.0
TOTAL FUEL ECONOMY DATA:
BTU per net kilowatt-hour generated 10,075 9,888 10,142
Cost of fuel per million BTU (cents) 170.13 162.27 177.52
Average cost of fuel per net kilowatt-hour generated (cents) 1.71 1.60 1.80
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SELECTED FINANCIAL AND OPERATING DATA (continued)
Mississippi Power Company 1993 Annual Report
1990 1989 1988 1987 1986 1985 1984 1983
$ 102,243 $ 100,068 $ 96,711 $ 98,338 $ 101,984 $ 96,878 $ 92,955 $ 92,868
103,352 103,403 98,772 98,669 100,521 96,883 91,500 91,822
123,754 128,983 123,038 129,004 134,501 129,495 128,951 117,336
6,078 5,992 5,874 5,723 5,882 5,884 5,704 5,784
335,427 338,446 324,395 331,734 342,888 329,140 319,110 307,810
86,194 82,111 75,525 88,060 107,270 115,757 106,691 81,511
20,157 16,938 33,747 31,278 21,669 27,277 13,226 20,425
441,778 437,495 433,667 451,072 471,827 472,174 439,027 409,746
5,093 5,155 4,272 4,771 4,438 3,436 3,480 4,849
$ 446,871 $ 442,650 $ 437,939 $ 455,843 $ 476,265 $ 475,610 $ 442,507 $ 414,595
1,804,838 1,741,855 1,686,722 1,658,327 1,674,407 1,603,539 1,535,329 1,488,945
1,718,074 1,686,302 1,607,988 1,555,044 1,544,899 1,500,972 1,415,153 1,384,385
3,311,460 3,204,208 2,879,457 2,862,632 2,877,026 2,786,883 2,768,877 2,405,915
85,938 87,611 86,049 81,153 81,352 83,142 78,198 79,605
6,920,310 6,719,976 6,260,216 6,157,156 6,177,684 5,974,536 5,797,557 5,358,850
2,883,581 2,798,086 2,280,341 2,615,058 2,382,443 2,819,439 2,656,738 2,097,287
714,365 527,970 1,100,808 955,303 704,461 733,142 285,562 303,487
10,518,256 10,046,032 9,641,365 9,727,517 9,264,588 9,527,117 8,739,857 7,759,624
5.66 5.74 5.73 5.93 6.09 6.04 6.05 6.24
6.02 6.13 6.14 6.35 6.51 6.45 6.47 6.63
3.74 4.03 4.27 4.51 4.68 4.65 4.66 4.88
4.85 5.04 5.18 5.39 5.55 5.51 5.50 5.74
4.20 4.35 4.50 4.64 5.09 4.96 5.02 5.28
12,228 11,842 11,499 11,356 11,498 11,135 10,814 10,650
$ 692.70 $ 680.32 $ 659.30 $ 673.41 $ 700.32 $ 672.71 $ 654.74 $ 664.27
1,998 1,998 1,966 1,966 1,966 1,966 1,966 1,966
1,201 1,556 1,284 1,224 1,208 1,310 1,210 1,156
1,724 1,682 1,621 1,548 1,612 1,444 1,421 1,445
59.0 58.8 57.6 59.0 56.8 61.0 59.8 54.8
93.3 94.0 93.0 93.5 93.2 92.4 93.1 93.7
62.6 63.4 86.3 79.4 74.1 74.1 67.5 69.9
14.0 13.5 4.8 5.3 5.1 2.8 2.5 4.3
0.8 0.5 0.4 0.3 2.0 0.4 0.2 0.5
22.6 22.6 8.5 15.0 18.8 22.7 29.8 25.3
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
10,319 10,159 10,220 10,525 10,569 10,396 10,385 10,491
183.27 178.38 185.13 194.46 224.63 235.24 236.45 240.47
1.89 1.81 1.89 2.05 2.37 2.45 2.46 2.52
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STATEMENTS OF INCOME
Mississippi Power Company
FOR THE YEARS ENDED DECEMBER 31, 1993 1992 1991
(Thousands of Dollars)
OPERATING REVENUES:
Revenues $ 459,364 $ 424,392 $ 414,342
Revenues from affiliates 15,519 10,055 18,044
Total operating revenues 474,883 434,447 432,386
OPERATING EXPENSES:
Operation --
Fuel 113,986 96,743 120,485
Purchased power from non-affiliates 2,198 1,337 851
Purchased power from affiliates 58,019 60,689 45,506
Proceeds from settlement of disputed contracts - (189) (4,205)
Other 100,381 90,581 86,932
Maintenance 44,001 43,165 44,166
Depreciation and amortization 33,099 32,789 32,147
Taxes other than income taxes 37,145 34,664 35,414
Federal and state income taxes 22,668 16,378 13,976
Total operating expenses 411,497 376,157 375,272
OPERATING INCOME: 63,386 58,290 57,114
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction 1,010 642 728
Interest income 517 766 1,093
Other, net 3,971 5,501 3,845
Income taxes applicable to other income (1,158) (1,427) (863)
INCOME BEFORE INTEREST CHARGES 67,726 63,772 61,917
INTEREST CHARGES:
Interest on long-term debt 17,688 22,357 23,656
Allowance for debt funds used during construction (788) (563) (584)
Interest on notes payable 1,000 362 603
Amortization of debt discount, premium, and expense, net 1,262 630 377
Other interest charges 728 339 285
Net interest charges 19,890 23,125 24,337
NET INCOME FROM CONTINUING OPERATIONS 47,836 40,647 37,580
DISCONTINUED OPERATIONS:
Loss from operations of discontinued subsidiary, net of taxes - - (6,404)
Loss on disposal of discontinued subsidiary, net of taxes - - (5,455)
NET LOSS FROM DISCONTINUED OPERATIONS - - (11,859)
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN METHOD
OF RECORDING REVENUES 47,836 40,647 25,721
Cumulative effect as of January 1, 1983, of accruing
unbilled revenues--less income taxes of $6,326(000) - - -
NET INCOME 47,836 40,647 25,721
DIVIDENDS ON PREFERRED STOCK 5,400 3,857 3,094
NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 42,436 $ 36,790 $ 22,627
Pro Forma Net Income After Dividends on Preferred Stock
Assuming Change in Method of Recording
Revenues Was Applied Retroactively $ 42,436 $ 36,790 $ 22,627
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STATEMENTS OF INCOME
Mississippi Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 426,714 $ 425,712 $ 404,192 $ 424,565 $ 454,596 $ 448,333 $ 429,281 $ 394,170
20,157 16,938 33,747 31,278 21,669 27,277 13,226 20,425
446,871 442,650 437,939 455,843 476,265 475,610 442,507 414,595
138,303 133,671 165,912 167,165 183,515 188,477 158,793 153,816
1,406 1,266 1,257 1,108 4,671 1,807 836 834
49,547 47,066 19,270 36,114 46,322 56,522 70,202 49,637
- - - - - - - -
83,730 84,820 83,542 81,331 70,009 58,528 53,447 53,922
33,368 35,658 33,412 33,974 31,368 39,509 31,826 24,921
30,770 28,001 26,610 26,210 30,293 25,412 24,170 23,322
32,709 32,435 29,638 27,882 26,145 23,930 24,495 24,426
17,144 18,387 20,313 23,888 30,881 29,142 26,525 29,067
386,977 381,304 379,954 397,672 423,204 423,327 390,294 359,945
59,894 61,346 57,985 58,171 53,061 52,283 52,213 54,650
307 903 850 608 1,030 693 820 1,845
829 1,096 1,030 1,121 864 1,326 1,325 3,120
6,297 6,013 6,399 7,065 8,983 9,867 6,482 (369)
(1,666) (1,392) (1,148) (2,507) (3,517) (3,880) (2,555) (1,233)
65,661 67,966 65,116 64,458 60,421 60,289 58,285 58,013
22,221 21,685 22,271 24,139 22,707 22,684 22,678 22,816
(600) (821) (595) (652) (770) (434) (1,800) (1,858)
1,142 689 341 558 252 - 1,082 -
359 362 363 388 245 146 148 148
333 566 522 601 283 562 754 4,152
23,455 22,481 22,902 25,034 22,717 22,958 22,862 25,258
42,206 45,485 42,214 39,424 37,704 37,331 35,423 32,755
(4,669) (3,459) (2,549) (487) - - - -
- - - - - - - -
(4,669) (3,459) (2,549) (487) - - - -
37,537 42,026 39,665 38,937 37,704 37,331 35,423 32,755
- - - - - - - 6,799
37,537 42,026 39,665 38,937 37,704 37,331 35,423 39,554
3,361 3,450 3,584 3,737 3,890 4,001 4,043 4,150
$ 34,176 $ 38,576 $ 36,081 $ 35,200 $ 33,814 $ 33,330 $ 31,380 $ 35,404
$ 34,176 $ 38,576 $ 36,081 $ 35,200 $ 33,814 $ 33,330 $ 31,380 $ 28,605
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STATEMENTS OF CASH FLOWS
Mississippi Power Company
For the Years Ended December 31, 1993 1992 1991
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $ 47,836 $ 40,647 $ 25,721
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 45,660 41,472 41,773
Deferred income taxes, net 5,039 (5,473) (11,869)
Deferred investment tax credits, net - - (2)
Allowance for equity funds used during construction (1,010) (642) (728)
Non-cash proceeds from settlement of disputed contracts - (189) (4,071)
Other, net 3,005 8,093 (4,982)
Changes in certain current assets and liabilities --
Receivables, net (4,347) 1,002 35,343
Inventories 11,119 975 10,518
Payables 4,133 460 (4,949)
Other (8,033) 6,095 11,433
Net cash provided from operating activities 103,402 92,440 98,187
INVESTING ACTIVITIES:
Gross property additions (139,976) (68,189) (53,675)
Other 7,562 4,235 2,148
Net cash used for investing activities (132,414) (63,954) (51,527)
FINANCING ACTIVITIES AND CAPITAL CONTRIBUTIONS:
Proceeds:
Preferred stock 23,404 35,000 -
First mortgage bonds 70,000 40,000 50,000
Pollution control bonds 38,875 23,300 -
Other long-term debt - - 844
Capital contributions 30,036 26 -
Redemptions:
Preferred stock (23,404) - (4,118)
First mortgage bonds (51,300) (104,703) -
Pollution control bonds (25,885) (23,650) (300)
Other long-term debt (8,170) (6,212) (8,958)
Notes payable, net 9,000 26,500 (25,603)
Payment of preferred stock dividends (5,400) (3,857) (3,094)
Payment of common stock dividends (29,000) (28,000) (28,500)
Miscellaneous (5,683) (7,821) (839)
Net cash provided from (used for) financing activities 22,473 (49,417) (20,568)
NET CHANGE IN CASH AND CAHS EQUIVALENTS (6,539) (20,931) 26,092
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 7,417 28,348 2,256
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 878 $ 7,417 $ 28,348
( ) Denotes use of cash.
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STATEMENTS OF CASH FLOWS
Mississippi Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 37,537 $ 42,026 $ 39,665 $ 38,937 $ 37,704 $ 37,331 $ 35,423 $ 39,554
41,079 35,878 34,440 33,971 33,432 28,229 26,487 24,918
2,756 (294) (3,053) 10,035 41,059 11,246 10,156 6,161
(26) (38) 571 896 2,442 1,749 6,336 3,223
(307) (903) (850) (608) (1,030) (693) (820) (1,845)
- - - - - - - -
7,257 4,306 3,503 1,965 (14,162) (2,709) 3,802 10,325
(6,252) (18,506) 816 12,000 (1,708) (5,050) 8,734 (26,866)
(8,922) 3,687 283 13,708 (8,499) 12,281 (23,307) 10,092
(5,552) 1,307 (5,241) 7,487 (14,502) 4,656 (5,506) (14,378)
(1,461) 2,172 (2,294) (9,342) 11,546 (3,725) (3,651) 14,230
66,109 69,635 67,840 109,049 86,282 83,315 57,654 65,414
(49,009) (43,916) (54,550) (53,288) (62,488) (57,791) (37,290) (72,277)
4,481 1,860 8,368 (1,461) (61,162) 3,825 388 1,647
(44,528) (42,056) (46,182) (54,749) (123,650) (53,966) (36,902) (70,630)
- - - - - - - -
- - - - 35,000 - - -
- - - - - - - -
- 844 - 130 60,663 1,000 - -
- - - 16,000 400 400 1,000 12,000
(750) (750) (1,500) (1,500) (1,500) (1,111) (639) (750)
(4,000) (3,823) - (29,701) (29,250) (250) (250) (3,246)
(288) (62) (50) (50) (50) (50) (50) (50)
(6,416) (5,919) (5,401) (4,974) (200) - - -
17,146 6,457 6,500 - - - - -
(3,361) (3,450) (3,584) (3,737) (3,890) (4,001) (4,043) (4,150)
(27,500) (27,000) (27,600) (24,700) (23,700) (22,600) (21,000) (18,900)
2 - - (2,696) (2,929) (18) - -
(25,167) (33,703) (31,635) (51,228) 34,544 (26,630) (24,982) (15,096)
(3,586) (6,124) (9,977) 3,072 (2,824) 2,719 (4,230) (20,312)
5,842 11,966 21,943 18,871 21,695 18,976 23,206 43,518
$ 2,256 $ 5,842 $ 11,966 $ 21,943 $ 18,871 $ 21,695 $ 18,976 $ 23,206
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BALANCE SHEETS
Mississippi Power Company
At December 31, 1993 1992 1991
(Thousands of Dollars)
ASSETS
UTILITY PLANT:
Production-fossil $ 597,425 $ 576,848 $ 567,588
Transmission 188,375 173,278 162,379
Distribution 295,799 279,335 259,929
General 157,248 151,044 141,564
Construction work in progress 108,063 41,692 33,078
Total utility plant 1,346,910 1,222,197 1,164,538
Accumulated provision for depreciation 462,725 440,777 415,135
Total 884,185 781,420 749,403
Less property-related accumulated deferred income taxes - 142,338 138,616
Total 884,185 639,082 610,787
OTHER PROPERTY AND INVESTMENTS:
Securities received from settlement of disputed contracts - - 4,113
Miscellaneous 11,289 4,539 3,954
Total 11,289 4,539 8,067
CURRENT ASSETS:
Cash and cash equivalents 878 7,417 28,348
Investment securities - 3,622 -
Receivables, net 28,021 20,219 27,152
Accrued utility revenues 14,897 14,898 12,420
Fossil fuel stock, at average cost 11,185 21,341 22,373
Materials and supplies, at average cost 21,145 22,108 22,051
Current portion of deferred fuel commitments 440 1,861 933
Prepayments 7,843 5,869 6,137
Vacation pay deferred 4,797 4,651 4,406
Total current assets 89,206 101,986 123,820
DEFERRED CHARGES:
Debt expense, being amortized 1,103 804 981
Premium on reacquired debt, being amortized 10,563 10,102 4,676
Deferred fuel commitments 17,520 25,255 31,039
Deferred charges related to income taxes 25,267 - -
Miscellaneous 10,073 9,515 11,271
Total deferred charges 64,526 45,676 47,967
TOTAL ASSETS $1,049,206 $ 791,283 $ 790,641
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BALANCE SHEETS
Mississippi Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 560,537 $ 547,946 $ 529,742 $ 524,198 $ 509,128 $ 485,665 $ 477,618 $ 468,536
151,949 147,288 134,674 130,963 125,304 121,405 118,552 111,266
247,705 229,238 221,327 207,810 195,042 183,003 169,545 160,062
136,815 133,361 137,333 127,690 114,042 99,788 90,626 31,765
26,816 27,057 35,204 27,755 33,544 34,862 17,054 70,463
1,123,822 1,084,890 1,058,280 1,018,416 977,060 924,723 873,395 842,092
392,440 366,193 348,085 328,761 312,571 293,167 266,844 245,171
731,382 718,697 710,195 689,655 664,489 631,556 606,551 596,921
139,970 138,071 134,220 127,912 120,990 107,633 98,494 88,940
591,412 580,626 575,975 561,743 543,499 523,923 508,057 507,981
- - - - - - - -
8,631 7,792 8,153 4,122 1,738 641 630 354
8,631 7,792 8,153 4,122 1,738 641 630 354
2,256 5,842 11,966 21,943 18,871 21,695 18,976 23,206
- - - - - - - -
67,734 58,425 43,246 42,218 48,158 42,407 39,137 44,627
10,797 13,854 10,527 12,371 18,431 22,474 20,694 23,938
29,812 24,788 26,587 29,989 46,067 40,638 57,225 36,550
25,130 21,232 23,120 20,001 17,631 14,561 10,255 7,623
1,430 3,017 - - - - - -
11,392 12,512 12,341 830 973 805 497 679
3,955 3,910 3,815 3,956 3,559 3,337 2,910 2,587
152,506 143,580 131,602 131,308 153,690 145,917 149,694 139,210
824 886 949 1,012 1,212 1,208 1,260 1,329
4,919 5,161 5,404 5,647 2,800 - - -
39,020 45,103 50,714 55,889 60,663 - - -
- - - - - - - -
2,714 3,422 6,522 4,347 3,508 7,888 889 499
47,477 54,572 63,589 66,895 68,183 9,096 2,149 1,828
$ 800,026 $ 786,570 $ 779,319 $ 764,068 $ 767,110 $ 679,577 $ 660,530 $ 649,373
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BALANCE SHEETS
Mississippi Power Company
At December 31, 1993 1992 1991
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stock $ 37,691 $ 37,691 $ 37,691
Other paid-in capital 154,362 124,326 124,300
Premium on preferred stock 372 194 194
Earnings retained in the business 129,343 118,429 111,670
Total common equity 321,768 280,640 273,855
Preferred stock 74,414 74,414 39,414
Preferred stock subject to mandatory redemption - - -
Long-term debt 250,391 238,650 304,150
Total capitalization 646,573 593,704 617,419
(excluding amount due within one year)
CURRENT LIABILITIES:
Notes payable to banks 40,000 31,000 4,500
Preferred stock due within one year - - -
Long-term debt due within one year 19,345 8,878 14,650
Accounts payable 60,928 43,550 38,213
Customer deposits 2,786 2,976 3,109
Taxes accrued 27,138 32,035 29,609
Interest accrued 4,237 3,961 4,602
Vacation pay accrued 4,797 4,651 4,406
Miscellaneous 9,323 10,963 10,236
Total current liabilities 168,554 138,014 109,325
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes 123,206 169 4,117
Accumulated deferred investment tax credits 32,710 34,242 35,657
Deferred tax related to income taxes 48,228 - -
Miscellaneous 29,935 25,154 24,123
Total deferred credits and other liabilities 234,079 59,565 63,897
TOTAL CAPITALIZATION AND LIABILITIES $1,049,206 $ 791,283 $ 790,641
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BALANCE SHEETS
Mississippi Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 37,691 $ 37,691 $ 37,691 $ 37,691 $ 37,691 $ 37,691 $ 37,691 $ 37,691
124,300 124,300 124,300 124,300 108,300 107,900 107,500 106,500
299 299 299 299 299 299 360 331
117,543 110,867 99,183 90,702 80,311 70,197 59,467 49,087
279,833 273,157 261,473 252,992 226,601 216,087 205,018 193,609
39,414 39,414 39,414 39,414 39,414 39,414 39,414 39,414
3,750 4,500 5,250 6,750 8,250 9,750 10,500 11,250
270,724 277,693 287,525 294,811 299,684 261,594 267,051 267,271
593,721 594,764 593,662 593,967 573,949 526,845 521,983 511,544
30,103 12,957 6,500 - - - - -
368 368 368 368 368 368 729 618
7,039 10,717 9,789 5,451 34,724 6,532 300 300
45,763 47,019 46,937 45,659 36,490 50,992 46,336 51,842
3,430 3,906 3,904 3,857 3,720 3,521 4,240 4,167
24,935 23,843 21,130 21,351 29,029 32,015 24,850 21,631
4,315 4,280 4,016 4,474 5,064 5,502 5,577 6,928
3,955 3,910 3,815 3,956 3,559 3,337 2,910 2,587
6,833 7,746 9,347 6,005 5,746 5,464 6,453 7,786
126,741 114,746 105,806 91,121 118,700 107,731 91,395 95,859
18,992 22,085 24,556 27,411 25,922 - - -
37,187 38,752 40,435 41,427 42,183 41,311 41,063 36,135
- - - - - - - -
23,385 16,223 14,860 10,142 6,356 3,690 6,089 5,835
79,564 77,060 79,851 78,980 74,461 45,001 47,152 41,970
$ 800,026 $ 786,570 $ 779,319 $ 764,068 $ 767,110 $ 679,577 $ 660,530 $ 649,373
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MISSISSIPPI POWER COMPANY
OUTSTANDING SECURITIES
AT DECEMBER 31, 1993
FIRST MORTGAGE BONDS
Amount Interest Amount
Series Issued Rate Outstanding Maturity
(Thousands) (Thousands)
1964 $ 10,000 4-5/8% $ 10,000 6/1/94
1965 11,000 4-3/4% 11,000 7/1/95
1966 10,000 6% 10,000 8/1/96
1993 35,000 5-3/8% 35,000 3/1/98
1992 40,000 6-5/8% 40,000 8/1/00
1991 50,000 9-1/4% 48,700 5/1/21
1993 35,000 7.45% 35,000 6/1/23
$ 191,000 $ 189,700
POLLUTION CONTROL BONDS
Amount Interest Amount
Series Issued Rate Outstanding Maturity
(Thousands) (Thousands)
1977 $ 1,000 5.80% $ 990 10/1/07
1992 6,550 Variable 6,550 12/1/20
1992 16,750 Variable 16,750 12/1/22
1993 13,000 6.20% 13,000 4/1/23
1993 25,875 5.65% 25,875 11/1/23
$ 63,175 $ 63,165
PREFERRED STOCK
Shares Dividend Amount
Series Outstanding Rate Outstanding
(Thousands)
1947 20,099 4.60% $ 2,010
1956 40,000 4.40% 4,000
1965 50,000 4.72% 5,000
1968 50,000 7.00% 5,000
1992 350,000 7.25% 35,000
1993 150,000 6.32% 15,000
1993 84,040 6.65% 8,404
744,139 $ 74,414
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250
MISSISSIPPI POWER COMPANY
SECURITIES RETIRED
DURING 1993
FIRST MORTGAGE BONDS
Principal Interest
Series Amount Rate
(Thousands)
1967 $ 10,000 7.125%
1972 25,000 7.625%
1973 15,000 7.625%
1991 1,300 9.25%
$ 51,300
POLLUTION CONTROL BONDS
Principal Interest
Series Amount Rate
(Thousands)
1973 $ 7,875 5.90%
1977 18,000 5.80%
1977 10 5.80%
$ 25,885
PREFERRED STOCK
Principal Dividend
Series Amount Rate
(Thousands)
1971 $ 8,404 8.44%
1974 15,000 8.80%
$ 23,404
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SAVANNAH ELECTRIC AND
POWER COMPANY
FINANCIAL SECTION
II-221
252
MANAGEMENT'S REPORT
Savannah Electric and Power Company 1993 Annual Report
The management of Savannah Electric and Power Company has prepared -- and is
responsible for -- the financial statements and related information included in
this report. These statements were prepared in accordance with generally
accepted accounting principles appropriate in the circumstances and necessarily
include amounts that are based on the best estimates and judgments of
management. Financial information throughout this annual report is consistent
with the financial statements.
The Company maintains a system of internal accounting controls to
provide reasonable assurance that assets are safeguarded and that books and
records reflect only authorized transactions of the Company. Limitations exist
in any system of internal controls, however, based on a recognition that the
cost of the system should not exceed its benefits. The Company believes its
system of internal accounting controls maintains an appropriate cost/benefit
relationship.
The Company's system of internal accounting controls is evaluated on
an ongoing basis by the Company's internal audit staff. The Company's
independent public accountants also consider certain elements of the internal
control system in order to determine their auditing procedures for the purpose
of expressing an opinion on the financial statements.
The audit committee of the board of directors, composed of four
directors who are not employees, provides a broad overview of management's
financial reporting and control functions. Periodically, this committee meets
with management, the internal auditors and the independent public accountants
to ensure that these groups are fulfilling their obligations and to discuss
auditing, internal controls and financial reporting matters. The internal
auditors and the independent public accountants have access to the members of
the audit committee at any time.
Management believes that its policies and procedures provide
reasonable assurance that the Company's operations are conducted according to a
high standard of business ethics. In management's opinion, the financial
statements present fairly, in all material respects, the financial position,
results of operations and cash flows of Savannah Electric and Power Company in
conformity with generally accepted accounting principles.
/s/ Arthur M. Gignilliat, Jr. /s/ K. R. Willis
- -------------------------------- -------------------------------------
Arthur M. Gignilliat, Jr. K. R. Willis
President Vice-President
and Chief Executive Officer Treasurer and Chief Financial Officer
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS
OF SAVANNAH ELECTRIC AND POWER COMPANY:
We have audited the accompanying balance sheets and statements of
capitalization of Savannah Electric and Power Company (a Georgia corporation)
as of December 31, 1993 and 1992, and the related statements of income,
retained earnings, 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.
In our opinion, the financial statements (pages II-231 through
II-244) referred to above present fairly, in all material respects, the
financial position of Savannah Electric and Power Company as of December 31,
1993 and 1992, and the results of its operations and its cash flows for the
periods stated, in conformity with generally accepted accounting principles.
As explained in Notes 2 and 7 to the financial statements, effective
January 1, 1993, the Company changed its methods of accounting for
postretirement benefits other than pensions and for income taxes.
/s/ Arthur Andersen & Co.
Atlanta, Georgia,
February 16, 1994
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Savannah Electric and Power Company 1993 Annual Report
RESULTS OF OPERATIONS
Earnings
Savannah Electric and Power Company's net income after dividends on preferred
stock for 1993 totaled $21.5 million, representing a $1.0 million (4.6 percent)
increase from the prior year. The revenue impact of an increase in retail
energy sales due to exceptionally hot summer weather was partially offset by
the implementation of a work force reduction program which resulted in a
one-time charge to operating expenses of approximately $4.5 million.
In 1992, earnings were $20.5 million, representing a $3.5 million
(14.6 percent) decrease from the prior year. This decrease resulted primarily
from increases in maintenance and administrative and general expenses,
partially offset by a 4.6 percent increase in retail operating revenues.
Operating revenues increased despite the negative impact of a $2.8 million
annual reduction in retail base rates effective in June 1992, and mild weather.
REVENUES
Total revenues for 1993 were $218.4 million, reflecting a 10.5 percent increase
over 1992, primarily due to an increase in retail energy sales.
The following table summarizes the factors impacting operating
revenues compared to the prior year for the 1991-1993 period:
Increase (Decrease)
From Prior Years
1993 1992 1991
(in thousands)
Retail --
Change in base
rates $(1,450) $(1,350) $(5,232)
Sales growth 5,980 5,467 5,057
Weather 4,567 (3,116) (1,014)
Fuel cost
recovery and
other 12,404 7,270 (8,934)
Total retail 21,501 8,271 (10,123)
Sales for resale--
Non-affiliates (1,800) 8 (1,669)
Affiliates 928 75 (4,136)
Total sales for
resale (872) 83 (5,805)
Other operating
revenues 52 (239) (61)
Total operating
revenues $20,681 $8,115 $(15,989)
Percent change 10.5% 4.3% (7.8)%
Total retail revenues increased 11.5 percent in 1993, compared to a
4.6 percent increase in 1992. The increase in 1993 retail revenues
attributable to growth in both retail customers and average use per customer
was enhanced by exceptionally hot weather during the summer. The substantial
increase in fuel cost recovery and other revenues reflects increases in net
generation and the unit cost of purchased power. The increase in 1992 retail
revenues resulted from growth in both retail customers and average use per
customer, but was substantially offset by mild weather and the June 1992 base
rate reduction.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1993 Annual Report
Under the Company's fuel cost recovery provisions, fuel revenues equal
fuel expense, including the fuel and capacity components of purchased energy,
and have no effect on earnings. Revenues from sales to non-affiliated
utilities under long-term contracts consist of capacity and energy components.
Capacity revenues reflect the recovery of fixed costs and a return on
investment under the contracts. Energy is generally sold at variable cost.
The capacity and energy components were:
1993 1992 1991
(in thousands)
Capacity $ 978 $ 537 $ 516
Energy 4,262 7,040 6,729
Total $5,240 $7,577 $7,245
Sales to affiliated companies within the Southern electric system
vary from year to year depending on demand and the availability and cost of
generating resources at each company. These sales have little impact on
earnings.
Kilowatt-hour sales for 1993 and the percent change by year were
as follows:
(millions of Amount Percent Change
kilowatt-hours) 1993 1993 1992 1991
Residential 1,329 9.2% 1.8% 1.0%
Commercial 1,016 6.5 3.0 3.7
Industrial 854 (0.8) 4.3 28.1
Other 117 5.2 3.4 3.0
Total retail 3,316 5.5 2.9 8.1
Sales to non-affiliates 247 (32.7) (1.3) (15.6)
Sales to affiliates 75 100.3 15.5 (88.9)
Total 3,638 2.6% 2.6% (2.9)%
The increases in energy sales in 1993 and 1992 continue to reflect
a growing customer base, an increase in average energy sales per customer, and
improved economic conditions in the Company's service area. Sales were
enhanced in 1993 by temperature extremes in the summer months and in December.
EXPENSES
Total operating expenses for 1993 increased $20.3 million (12.4 percent) over
the prior year. This increase includes a $10.8 million increase in fuel
expense, and an $8.7 million increase in other operation expenses. Fuel
expenses increased primarily because of higher generation due to extremely hot
weather and higher cost fuel sources. In 1992 an increase in purchased power
reflected a 15.4 percent decrease in generation compared to 1991. Despite the
decrease in generation, total 1992 fuel expenses were substantially unchanged
from the prior year reflecting generation from higher cost fuel sources.
The increase in other operation expenses reflects a $4.5 million
cost associated with a one-time charge related to a work force reduction
program. The Company also recognized higher employee benefits costs under new
accounting rules adopted in 1993. See Note 2 to the financial statements for
additional information on these new rules. In 1992, the increase in other
operation expenses was primarily a result of increases in outside services and
administrative and general expenses, which reflected higher employee training
and benefits expenses. Total interest expense on long-term debt was reduced by
5.4 percent in 1992, as the Company refinanced higher-cost debt.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1993 Annual Report
The mix of energy supply is determined primarily by system load,
the unit cost of fuel consumed and the availability of units.
The amount and sources of energy supply and the average cost of
fuel per net kilowatt-hour generated and purchased power were as follows:
1993 1992 1991
Total energy supply
(millions of kilowatt-hours) 3,863 3,764 3,677
Sources of energy supply
(percent)
Coal 21 12 16
Oil 2 1 -
Gas 3 2 2
Purchased Power 74 85 82
Average cost of fuel per net
kilowatt-hour generated
(cents)
Coal 2.02 2.28 2.05
Oil 4.11 2.40 3.97
Gas 4.87 4.28 3.32
Total average cost of
energy supply 2.12 1.78 1.64
EFFECTS OF INFLATION
The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic
loss because the Company is recovering its costs of investments in dollars that
have less purchasing power. While the inflation rate has been relatively low
in recent years, it continues to have an adverse effect on the Company because
of the large investment in long-lived utility plant. Conventional accounting
for historical cost does not recognize this economic loss nor the partially
offsetting gain that arises through financing facilities with fixed-money
obligations such as long-term debt and preferred stock. Any recognition of
inflation by regulatory authorities is reflected in the rate of return allowed.
FUTURE EARNINGS POTENTIAL
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends
on numerous factors ranging from growth in energy sales to regulatory matters.
Future earnings in the near term will depend upon growth in energy
sales, which is subject to a number of factors. Traditionally, these factors
included changes in contracts with neighboring utilities, energy conservation
practiced by customers, the elasticity of demand, weather, competition, and the
rate of economic growth in the Company's service area. However, the Energy
Policy Act of 1992 (Energy Act) will have a profound effect on the future of
the electric utility industry. The Energy Act promotes energy efficiency,
alternative fuel use, and increased competition for electric utilities. The
Energy Act allows Independent Power Producers (IPPs) to access a utility's
transmission network to sell electricity to other utilities. This may enhance
the incentives for IPPs to build cogeneration plants for the Company's large
industrial and commercial customers. Although the Energy Act does not require
transmission access to retail customers, pressure for legislation to allow
retail wheeling will continue. The Company is preparing now to meet the
challenge of these major changes in the traditional business practices of
selling electricity. If the Company does not remain a low-cost producer and
provide quality service, the Company's retail energy sales growth, as well as
new long-term contracts for energy sales outside the service area, could be
limited, and this could significantly erode earnings.
Demand-side options -- programs that enable customers to lower or
alter their peak energy requirements -- have been initiated by the Company and
are a significant part of integrated resource planning. Customers can receive
cash incentives for participating in these programs in addition to reducing
their energy requirements. Expansion and increased utilization of these
programs will be contingent upon sharing of cost savings between the customers
and the Company. Besides promoting energy efficiency, another benefit of these
programs could be the ability to defer the need to construct baseload
generating facilities further into the future. The ability to defer major
construction projects, in conjunction with the precertification approval
process for such projects by the Georgia Public Service Commission (GPSC), will
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1993 Annual Report
diminish the possible exposure to prudency disallowances and the resulting
impact on earnings.
Compliance costs related to the Clean Air Act Amendments of 1990
(Clean Air Act) could reduce earnings if such costs are not fully recovered.
The Clean Air Act is discussed later under "Environmental Matters."
Rates to retail customers served by the Company are regulated by
the GPSC. In May 1992, the Company requested, and subsequently received,
approval by the GPSC to reduce annual base revenues by $2.8 million, effective
June 1992. The reduction includes a base rate reduction of approximately $2.5
million spread among all classes of retail customers. An additional $0.3
million reduction resulted from the implementation of an experimental,
time-of-use rate for certain commercial customers. As part of this rate
settlement, it was informally agreed that the Company's earned rate of return
on common equity should be 12.95 percent.
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112,
Employers' Accounting for Postemployment Benefits, which must be implemented by
1994. The new standard requires that all types of benefits provided to former
or inactive employees and their families prior to retirement be accounted for
on an accrual basis. These benefits include salary continuation, severance
pay, supplemental unemployment benefits, disability-related benefits, job
training, and health and life insurance coverage.
The FASB has issued Statement No. 115, Accounting for Certain
Investments in Debt and Equity Securities, which is effective in 1994.
Statement No. 115, supersedes FASB Statement No. 12, Accounting for Certain
Marketable Securities. The Company adopted the new rules January 1, 1994, with
no material effect on the financial statements.
On January 1, 1993, the Company changed its methods of accounting
for postretirement benefits other than pensions and for income taxes. See
notes 2 and 7 to the financial statements regarding the impact of these
changes.
FINANCIAL CONDITION
OVERVIEW
The principal change in the Company's financial condition in 1993 was additions
of $73 million to utility plant. The majority of funds needed for gross
property additions since 1990 have been provided from operating activities,
principally from earnings and non-cash charges to income such as depreciation
and deferred income taxes. See Statements of Cash Flows for additional
information.
CAPITAL STRUCTURE
As of December 31, 1993, the Company's capital structure consisted of 45.3
percent common equity, 10.3 percent preferred stock and 44.4 percent long-term
debt, excluding amounts due within one year. The Company's long-term financial
objective for capitalization ratios is to maintain a capital structure of
common equity at 45 percent, preferred stock at 10 percent and debt at 45
percent.
Maturities and retirements of long-term debt were $4 million in
1993, $53 million in 1992 and $23 million in 1991.
In November 1993, the Company issued 1,400,000 shares of 6.64
percent series preferred stock. In December 1993, the Company redeemed all
800,000 shares outstanding of its 9.5 percent series preferred stock at the
prescribed redemption price of $26.57 plus accrued dividends.
The composite interest rates for the years 1991 through 1993 as of
year-end were as follows:
1993 1992 1991
Composite interest rates
on long-term debt 8.0% 8.5% 9.7%
Composite preferred stock
dividend rate 6.6% 9.5% 9.5%
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1993 Annual Report
The Company's current securities ratings are as follows:
Standard
Moody's & Poor's
First Mortgage Bonds A1 A
Preferred Stock "a2" A-
CAPITAL REQUIREMENTS FOR CONSTRUCTION
The Company's projected construction expenditures for the next three years
total $98 million ($33 million in 1994, $32 million in 1995, and $33 million in
1996). Actual construction costs may vary from this estimate because of such
factors as changes in environmental regulations; revised load projections; the
cost and efficiency of construction labor, equipment and materials; and the
cost of capital. The largest project during this period is the addition of two
80 megawatt combustion turbine units, to be placed into service in 1994. The
estimated cost of this project is $61 million. The Company is also
constructing six combustion turbine units for Georgia Power Company.
OTHER CAPITAL REQUIREMENTS
In addition to the funds needed for the construction program, approximately
$5.9 million will be needed by the end of 1996 for present sinking fund
requirements and maturities.
ENVIRONMENTAL MATTERS
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the new law -- will have a
significant impact on the Company and other subsidiaries of the Southern
electric system. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants will be required in two phases.
Phase I compliance must be implemented in 1995, and affects eight generating
plants -- some 10,000 megawatts of capacity or 35 percent of total capacity --
in the Southern electric system. Phase II compliance is required in 2000, and
all fossil-fired generating plants in the Southern electric system will be
affected.
Beginning in 1995, the Environmental Protection Agency (EPA) will
allocate annual sulfur dioxide emission allowances through the newly
established allowance trading program. An emission allowance is the authority
to emit one ton of sulfur dioxide during a calendar year. The method for
allocating allowances is based on the fossil fuel consumed from 1985 through
1987 for each affected generating unit. Emission allowances are transferable
and can be bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to
minimize the cost of compliance. The market for emission allowances is
developing slower than expected. However, The Southern Company's sulfur
dioxide compliance strategy is designed to take advantage of allowances as the
market develops.
The Southern Company expects to achieve Phase I sulfur dioxide
compliance at the eight affected plants by switching to low-sulfur
coal, and this would require some equipment upgrades. This compliance strategy
is expected to result in unused emission allowances being banked for later use.
Additional construction expenditures are required to install equipment for the
control of nitrogen oxide emissions at these eight plants. Also, continuous
emissions monitoring equipment would be installed on all fossil-fired units.
Under this Phase I compliance approach, additional construction expenditures
are estimated to total approximately $275 million through 1995 for The Southern
Company, of which the Company's portion is approximately $2 million.
Phase II compliance costs are expected to be higher because
requirements are stricter and all fossil-fired generating plants are affected.
For sulfur dioxide compliance, The Southern Company could use emission
allowances banked during Phase I and increase fuel switching, install flue gas
desulfurization equipment at selected plants, and/or purchase more allowances
depending on the price and availability of allowances. Also, in Phase II,
equipment to control nitrogen oxide emissions will be installed on additional
system fossil-fired plants as required to meet anticipated Phase II limits.
Therefore, during the period 1996 through 2000, compliance could require total
construction expenditures ranging from approximately $450 million to $800
million of which the Company's portion is expected to be approximately $25
million. However, the full impact of
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1993 Annual Report
Phase II compliance cannot now be determined with certainty, pending the
development of a market for emission allowances, the completion of EPA
regulations, and the possibility of new emission reduction technologies.
An increase of up to 5 percent in annual revenue requirements from
customers could be necessary to fully recover the Company's costs of compliance
for both Phase I and II of the Clean Air Act. Compliance costs include
construction expenditures, increased costs for switching to low-sulfur coal,
and costs related to emission allowances.
There can be no assurance that all Clean Air Act costs will be
recovered.
Title III of the Clean Air Act requires a multi-year EPA study of
power plant emissions of hazardous air pollutants. The study will serve as the
basis for a decision on whether additional regulatory control of these
substances is warranted. Compliance with any new control standards could
result in significant additional costs. The impact of new standards -- if any
- -- will depend on the development and implementation of applicable regulations.
The EPA continues to evaluate the need for a new short-term ambient
air quality standard for sulfur dioxide. Preliminary results from an EPA study
on the impact of a new standard indicate that a number of plants could be
required to install sulfur dioxide controls. These controls would be in
addition to the controls already required to meet the acid rain provision of
the Clean Air Act. The EPA is expected to take some action on this issue in
1994. The impact of any new standard will depend on the level chosen for the
standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient
air quality standards for particulate matters, nitrogen oxides, and ozone. The
impact of any new standard will depend on the level chosen for the standard and
cannot be determined at this time.
In 1994 or 1995, the EPA is expected to issue revised rules on air
quality control regulations related to stack height requirements of the Clean
Air Act. The full impact of the final rules cannot be determined at this time,
pending their development and implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous
status of coal ash. However, the EPA has until 1998 to classify co-managed
utility wastes--coal ash and other utility wastes--as either non-hazardous or
hazardous. If the EPA classifies the co-managed wastes as hazardous, then
substantial additional costs for the management of such wastes may be required.
The full impact of any change in the regulatory status will depend on the
subsequent development of co-managed waste requirements.
Savannah Electric and Power Company must comply with other
environmental laws and regulations that cover the handling and disposal of
hazardous waste. Under these various laws and regulations, the Company could
incur costs to clean up properties currently or previously owned. The Company
conducts studies to determine the extent of any required clean-up costs and
will recognize in the financial statements any costs to clean up known sites.
Several major pieces of environmental legislation are in the
process of being reauthorized or amended by Congress. These include: the
Clean Water Act, the Comprehensive Environmental Response, Compensation, and
Liability Act, and the Resource Conservation and Recovery Act. Changes to
these laws could affect many areas of the Company's operations. The full
impact of these requirements cannot be determined at this time, pending the
development and implementation of applicable regulations.
Compliance with possible new legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect The Southern Company. The impact of new legislation
- -- if any -- will depend on the subsequent development and implementation of
applicable regulations. In addition, the potential for lawsuits alleging
damages caused by electromagnetic fields exists.
SOURCES OF CAPITAL
At December 31, 1993, the Company had $3.9 million of cash and $14.5 million of
unused credit arrangements with banks to meet its short-term cash needs. The
Company had $3 million of short-term bank borrowings at December 31, 1993. In
January 1994, the Company renegotiated a two-year revolving credit arrangement
with four of its
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1993 Annual Report
existing banks for a total credit line of $20 million. The primary purpose of
this additional credit is to provide interim funding for the Company's
combustion turbine construction program.
It is anticipated that the funds required for construction and
other purposes, including compliance with environmental regulations, will be
derived from operations and the sale of additional first mortgage bonds and
preferred stock and capital contributions from The Southern Company. The
Company is required to meet certain coverage requirements specified in its
mortgage indenture and corporate charter to issue new first mortgage bonds and
preferred stock. The Company's coverage ratios are sufficiently high enough to
permit, at present interest levels, any foreseeable security sales. The amount
of securities which the Company will be permitted to issue in the future will
depend upon market conditions and other factors prevailing at that time.
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STATEMENTS OF INCOME
For the Years Ended December 31, 1993, 1992, and 1991
Savannah Electric and Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
OPERATING REVENUES (NOTES 1, 3, AND 6):
Revenues $ 216,009 $ 196,256 $ 188,216
Revenues from affiliates 2,433 1,505 1,430
Total operating revenues 218,442 197,761 189,646
OPERATING EXPENSES:
Operation --
Fuel 24,976 14,162 14,415
Purchased power from non-affiliates 793 494 297
Purchased power from affiliates 56,274 56,492 49,007
Other (Notes 2 and 5) 45,610 36,884 32,945
Maintenance 13,516 14,232 12,475
Depreciation and amortization (Notes 1 and 7) 16,467 16,829 16,549
Taxes other than income taxes 11,136 10,231 10,122
Federal and state income taxes (Note 7) 15,436 14,566 16,195
Total operating expenses 184,208 163,890 152,005
OPERATING INCOME 34,234 33,871 37,641
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction (Note 1) 958 446 170
Interest income 209 276 589
Other, net (Note 2) (1,841) (1,450) (879)
Income taxes applicable to other income 1,117 758 722
INCOME BEFORE INTEREST CHARGES 34,677 33,901 38,243
INTEREST CHARGES:
Interest on long-term debt 10,696 10,870 11,486
Allowance for debt funds used during construction (Note 1) (699) (289) (103)
Interest on notes payable 240 15 25
Amortization of debt discount, premium, and expense, net 535 427 380
Other interest charges 340 466 525
Net interest charges 11,112 11,489 12,313
NET INCOME 23,565 22,412 25,930
DIVIDENDS ON PREFERRED STOCK 2,106 1,900 1,900
NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 21,459 $ 20,512 $ 24,030
The accompanying notes are an integral part of these statements.
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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1993, 1992, and 1991
Savannah Electric and Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
OPERATING ACTIVITIES:
Net income $ 23,565 $ 22,412 $ 25,930
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 17,482 17,757 17,501
Deferred income taxes and investment tax credits 607 5,947 1,601
Allowance for equity funds used during construction (958) (446) (170)
Other, net 2,853 (1,312) (1,876)
Changes in certain current assets and liabilities --
Receivables, net (16,839) (4,107) 5,291
Special deposits - 350 1,348
Inventories (3,947) 4,435 (1,082)
Payables 18,742 351 568
Other 3,282 2,083 3,710
Net cash provided from operating activities 44,787 47,470 52,821
INVESTING ACTIVITIES:
Gross property additions (72,858) (30,132) (19,478)
Other 1,676 (1,073) 407
Net cash provided (used) for investing activities (71,182) (31,205) (19,071)
FINANCING ACTIVITIES AND CAPITAL CONTRIBUTIONS:
Proceeds:
First mortgage bonds 45,000 30,000 30,000
Preferred stock 35,000 - -
Pollution control bonds 4,085 13,870 -
Other long-term debt 10,000 - -
Retirements:
Preferred stock (20,000) - -
First mortgage bonds - (38,750) (22,500)
Pollution control bonds (4,085) (14,550) (515)
Other long-term debt (10,356) (217) (275)
Notes payable, net (4,500) 7,500 (1,500)
Payment of preferred stock dividends (2,222) (1,900) (1,900)
Payment of common stock dividends (21,000) (22,000) (22,000)
Miscellaneous (3,400) (3,985) (477)
Net cash provided (used) for financing activities 28,522 (30,032) (19,167)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 2,127 (13,767) 14,583
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 1,788 15,555 972
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 3,915 $ 1,788 $ 15,555
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for-
Interest (net of amount capitalized) $ 10,712 $ 9,932 $ 10,506
Income taxes 13,947 6,646 15,095
( ) Denotes use of cash.
The accompanying notes are an integral part of these statements.
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BALANCE SHEETS
At December 31, 1993 and 1992
Savannah Electric and Power Company 1993 Annual Report
ASSETS 1993 1992
(in thousands)
UTILITY PLANT:
Plant in service, at original cost (Notes 1, 4, 5, 7, and 9) $ 622,521 $ 599,596
Less accumulated provision for depreciation 251,565 240,094
370,956 359,502
Construction work in progress 49,797 5,966
Total 420,753 365,468
Less property-related accumulated deferred income taxes - 65,725
Total 420,753 299,743
OTHER PROPERTY AND INVESTMENTS 1,793 1,795
CURRENT ASSETS:
Cash and cash equivalents 3,915 1,788
Receivables-
Customer accounts receivable 18,551 16,795
Other accounts and notes receivable 790 1,359
Affiliated companies 12,924 263
Accumulated provision for uncollectible accounts (762) (536)
Fuel cost under recovery 7,112 3,895
Fossil fuel stock, at average cost 8,419 4,895
Materials and supplies, at average cost (Note 1) 9,358 8,935
Prepayments 4,849 1,599
Total 65,156 38,993
DEFERRED CHARGES:
Deferred charges related to income taxes (Note 7) 24,890 -
Premium on reacquired debt, being amortized 3,792 4,236
Miscellaneous 10,803 7,408
Total 39,485 11,644
TOTAL ASSETS $ 527,187 $ 352,175
The accompanying notes are an integral part of these statements.
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BALANCE SHEETS
At December 31, 1993 and 1992
Savannah Electric and Power Company 1993 Annual Report
CAPITALIZATION AND LIABILITIES 1993 1992
(in thousands)
CAPITALIZATION (SEE ACCOMPANYING STATEMENTS):
Common stock equity $ 154,269 $ 158,376
Preferred stock 35,000 20,000
Long-term debt 151,338 110,767
Total 340,607 289,143
CURRENT LIABILITIES:
Long-term debt due within one year (Note 10) 4,499 1,319
Notes payable (Note 5) 3,000 7,500
Accounts payable-
Affiliated companies 6,041 5,136
Other 24,401 6,043
Customer deposits 4,714 4,541
Taxes accrued-
Federal and state income 342 567
Other 1,187 2,449
Interest accrued 6,730 5,733
Vacation pay accrued 1,638 1,790
Pensions accrued 1,792 1,643
Work Force Reduction Costs Accrued (Note 2) 3,926 -
Miscellaneous 2,985 3,382
Total 61,255 40,103
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes (Note 7) 66,947 -
Accumulated deferred investment tax credits 15,301 15,964
Deferred credits related to income taxes (Note 7) 26,173 -
Deferred compensation plans 6,117 4,671
Deferred under-funded accrued benefit obligation (Note 2) 5,855 -
Miscellaneous 4,932 2,294
Total 125,325 22,929
COMMITMENTS AND CONTINGENT MATTERS (NOTES 2, 4, 5, AND 9)
TOTAL CAPITALIZATION AND LIABILITIES $ 527,187 $ 352,175
The accompanying notes are an integral part of these statements.
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STATEMENTS OF CAPITALIZATION
At December 31, 1993 and 1992
Savannah Electric and Power Company 1993 Annual Report
1993 1992 1993 1992
(in thousands) (percent of total)
COMMON STOCK EQUITY (NOTES 2 AND 11):
Common stock, par value $5 per share --
Authorized -- 16,000,000 shares
Outstanding -- 10,844,635 shares in
1993 and 1992 $ 54,223 $ 54,223
Paid-in capital 23 23
Paid-in for common stock in excess of par value 8,665 8,665
Additional minimum liability
for under-funded pension obligations (2,121) -
Retained Earnings 93,479 95,465
Total common stock equity 154,269 158,376 45.3 % 54.8 %
CUMULATIVE PREFERRED STOCK (NOTE 8):
$25 par value --
Authorized -- 2,200,000 shares
6.64% Series -- Outstanding -- 1,400,000 shares 35,000 -
9.50% Series -- Outstanding -- 800,000 shares - 20,000
Total (annual dividend requirement -- $2,324,000) 35,000 20,000 10.3 6.9
LONG-TERM DEBT (NOTE 9):
First mortgage bonds --
Maturity Interest Rates
April 1, 1994 4 5/8% 3,715 3,715
July 1, 2003 6 3/8% 20,000 -
October 1, 2019 9 1/4% 30,000 30,000
July 1, 2021 9 3/8% 30,000 30,000
July 1, 2022 8.30% 30,000 30,000
July 1, 2023 7.40% 25,000 -
Total first mortgage bonds 138,715 93,715
Pollution control obligations 17,955 17,955
Other long-term debt (Note 9) 2,311 2,667
Unamortized debt premium (discount), net (3,144) (2,251)
Total long-term debt (annual interest
requirement -- $12,700,800) 155,837 112,086
Less amount due within one year (Note 10) 4,499 1,319
Long-term debt excluding amount due within one year 151,338 110,767 44.4 38.3
TOTAL CAPITALIZATION $ 340,607 $ 289,143 100.0 % 100.0 %
The accompanying notes are an integral part of these statements.
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STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1993, 1992, and 1991
Savannah Electric and Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 95,155 $ 96,643 $ 94,613
Net income after dividends on preferred stock 21,459 20,512 24,030
Cash dividends on common stock (21,000) (22,000) (22,000)
Preferred stock transactions, net (2,135) - -
BALANCE AT END OF PERIOD (NOTE 11) $ 93,479 $ 95,155 $ 96,643
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1993, 1992, and 1991
1993 1992 1991
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 23 $ - $ -
Contributions to capital by parent company - 23 -
BALANCE AT END OF PERIOD $ 23 $ 23 $ -
The accompanying notes are an integral part of these statements.
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NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 1993 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
Savannah Electric and Power Company is a wholly owned subsidiary of The
Southern Company, which is the parent company of five operating companies, a
system service company, Southern Electric International (Southern Electric),
Southern Nuclear Operating Company (Southern Nuclear), and various other
subsidiaries related to foreign utility operations and domestic non-utility
operations. At this time, the operations of the other subsidiaries are not
material. The operating companies (Alabama Power Company, Georgia Power
Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric
and Power Company) provide electric service in four Southeastern states.
Contracts among the companies -- dealing with jointly owned generating
facilities, interconnecting transmission lines and the exchange of electric
power -- are regulated by the Federal Energy Regulatory Commission (FERC) or
the Securities and Exchange Commission (SEC). The system service company
provides, at cost, specialized services to The Southern Company and to the
subsidiary companies. Southern Electric designs, builds, owns and operates
power production facilities and provides a broad range of technical services to
industrial companies and utilities in the United States and a number of
international markets. Southern Nuclear provides services to The Southern
Company's nuclear power plants.
The Southern Company is registered as a holding company under the
Public Utility Holding Company Act of 1935 (PUHCA). Both The Southern Company
and its subsidiaries are subject to the regulatory provisions of the PUHCA.
The Company also is subject to regulation by the FERC and the Georgia Public
Service Commission (GPSC). The Company follows generally accepted accounting
principles and complies with the accounting policies and practices prescribed
by the GPSC.
Certain prior years' data presented in the financial statements
have been reclassified to conform with current year presentation.
REVENUES AND FUEL COSTS
The Company accrues revenues for services rendered but unbilled at the end of
each fiscal period. Fuel costs are expensed as the fuel is used. The
Company's electric rates include provisions to adjust billings for fluctuations
in capacity and the energy components of purchased power costs. Revenues
include the actual cost of fuel and purchased power incurred.
DEPRECIATION AND AMORTIZATION
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
2.9 percent in 1993 and 3.2 percent in 1992, and 1991. The decrease in 1993
reflects the Company's implementation of new depreciation rates approved by the
GPSC. These new rates provide for a timely recovery of the investments in the
Company's depreciable properties.
When property subject to depreciation is retired or otherwise
disposed of in the normal course of business, its cost -- together with the
cost of removal, less salvage -- is charged to the accumulated provision for
depreciation. Minor items of property included in the original cost of the
plant are retired when the related property unit is retired.
INCOME TAXES
The Company, which is included in the consolidated federal income tax return
filed by The Southern Company, provides deferred income taxes for all
significant income tax temporary differences. Investment tax credits utilized
are deferred and amortized to income over the average lives of the related
property.
In years prior to 1993, income taxes were accounted for and
reported under Accounting Principles Board Opinion No. 11. Effective January
1, 1993, the Company adopted FASB Statement No. 109, Accounting for Income
Taxes. Statement No. 109 required, among other things, conversion to the
liability method of accounting for accumulated deferred income taxes. See Note
7 for additional information about Statement No. 109.
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NOTES (continued)
Savannah Electric and Power Company 1993 Annual Report
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
(AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. The composite rates used by the Company to calculate
AFUDC were 8.77 percent in 1993, 11.27 percent in 1992, and 11.38 percent in
1991.
UTILITY PLANT
Utility plant is stated at original cost, which includes materials, labor,
minor items of property, appropriate administrative and general costs,
payroll-related costs such as taxes, pensions and other benefits and the
estimated cost of funds used during construction. The cost of maintenance,
repairs, and replacement of minor items of property is charged to maintenance
expense. The cost of replacements of property (exclusive of minor items of
property) is charged to utility plant.
CASH AND CASH EQUIVALENTS
For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
FINANCIAL INSTRUMENTS
In accordance with FASB Statement No. 107, Disclosure About Fair Value
of Financial Instruments, items for which the carrying amount does not
approximate fair value must be disclosed. At December 31, 1993, the fair value
of long-term debt was $164 million and the carrying amount was $154 million.
The fair value of long-term debt was $117 million and the carrying amount was
$109 million at December 31, 1992. The fair value for long-term debt was based
on either closing market prices or closing prices of comparable instruments.
MATERIALS AND SUPPLIES
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to
inventory when purchased and then expensed or capitalized to plant, as
appropriate, when installed.
2. RETIREMENT BENEFITS
PENSION PLANS
The Company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. Benefits under this plan reflect
the employee's years of service, age at retirement and average compensation for
the three years immediately preceding retirement. The Company uses the
projected unit credit actuarial method for funding purposes, subject to
limitations under federal income tax regulations. Amounts funded to the
pension fund are primarily invested in equity and debt securities. FASB
Statement No. 87, Employers' Accounting for Pensions, requires use of the
"projected unit credit" actuarial method for financial reporting purposes.
POSTRETIREMENT BENEFITS
The Company also provides certain medical care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits when they retire. A qualified trust for medical benefits has been
established for funding amounts to the extent deductible under federal income
tax regulations. Accrued costs of life insurance benefits, other than current
cash payments for retirees, currently are not being funded.
Effective January 1, 1993, the Company adopted FASB Statement No.
106, Employers' Accounting for Postretirement Benefits Other Than Pensions, on
a prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service."
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NOTES (continued)
Savannah Electric and Power Company 1993 Annual Report
Consistent with regulatory treatment, the Company recognized these
costs on a cash basis as payments were made in 1992 and 1991. The total costs
of such benefits recognized by the Company amounted to $375 thousand in 1992
and $487 thousand in 1991.
STATUS AND COST OF BENEFITS
Shown in the following tables are actuarial results and assumptions for pension
and postretirement medical and life insurance benefits as computed under the
requirements of FASB Statements Nos. 87 and 106, respectively. Retiree medical
and life insurance information is shown for 1993 only because Statement No. 106
was adopted as of January 1, 1993, on a prospective basis. The funded status
of the plans at December 31 was as follows:
Pension
1993 1992
(in thousands)
Actuarial present value of
benefit obligations:
Vested benefits $35,818 $24,902
Non-vested benefits 1,992 1,772
Accumulated benefit obligation 37,810 26,674
Additional amounts related to
projected salary increases 5,974 6,495
Projected benefit obligation 43,784 33,169
Less:
Fair value of plan assets 26,446 23,494
Unrecognized net loss 9,449 5,546
Unrecognized prior service cost 1,685 1,823
Unrecognized net transition asset 710 799
Adjustment required to
recognize additional
minimum liability 5,871 -
Accrued pension cost recognized
in the Balance Sheets $11,365 $1,507
The weighted average rates assumed in the actuarial calculations
were:
1993 1992 1991
Discount 7.50% 8.00% 8.00%
Annual salary increase 4.75 5.00 5.00
Long-term return on plan
assets 9.25 9.25 9.50
In accordance with Statement No. 87, an additional liability
related to under-funded accumulated benefit obligations was recognized at
December 31, 1993. A corresponding net-of-tax charge of $2.1 million was
recognized as a separate component of Common Stock Equity in the Statements of
Capitalization.
Postretirement
Medical Life
1993 1993
(in thousands)
Actuarial present value of
benefit obligation:
Retirees and dependents $8,632 $2,536
Employees eligible to retire 898 -
Other employees 6,489 1,577
Accumulated benefit
obligation 16,019 4,113
Less
Fair value of plan assets - -
Unrecognized net loss 4,124 262
Unrecognized transition obligation 10,362 3,382
Accrued liability recognized in the
Balance Sheets $1,533 $469
The assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend rate
of 11.3 percent for 1993, decreasing gradually to 6.0 percent through the year
2000 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate by 1.0 percent would increase the accumulated
medical benefit obligation as of December 31, 1993, by $1.7 million and the
aggregate of the service and interest cost components of the net retiree
medical cost by $0.2 million.
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NOTES (continued)
Savannah Electric and Power Company 1993 Annual Report
Components of the plans' net costs are shown below:
Pension
1993 1992 1991
(in thousands)
Benefits earned
during the year $1,188 $1,053 $ 941
Interest cost on projected
benefit obligation 2,741 2,429 2,149
Actual return on
plan assets (2,199) (1,266) (3,027)
Net amortization
and deferral 716 (227) 1,736
Net pension cost $2,446 $1,989 $1,799
Of the above net pension amounts, $2.0 million in 1993, $1.7
million in 1992 and $1.5 million in 1991 were recorded in operating expenses,
and the remainder was recorded in construction and other accounts.
Postretirement
Medical Life
1993 1993
(in thousands)
Benefits earned during the year $ 346 $ 97
Interest cost on accumulated
benefit obligation 855 279
Amortization of transition
obligation over 20 years 545 178
Net postretirement cost $1,746 $554
Net postretirement medical and life insurance costs of $1.8
million in 1993 were charged to operating expenses.
The Company has a supplemental retirement plan for certain
executive employees. The plan is unfunded and payable from the general funds
of the Company. The Company has purchased life insurance on participating
executives, and plans to use these policies to satisfy this obligation.
Benefit costs associated with this plan for 1993, 1992 and 1991 were $980
thousand, $316 thousand and $338 thousand, respectively. The 1993 benefit
costs reflect a one-time expense related to employees who were part of the work
force reduction program.
WORK FORCE REDUCTION PROGRAM
The Company has incurred additional costs for a one-time charge related to the
implementation of a work force reduction program. In 1993, $4.5 million was
charged to operating expenses and $0.6 million was charged to other income
(expense).
3. REGULATORY MATTERS
RATE MATTERS
In May 1992, the Company filed for, and subsequently received, GPSC approval to
implement new base rates designed to decrease base operating revenues by $2.8
million annually. The reduction included a base rate reduction of
approximately $2.5 million spread among all classes of customers, effective
June 1992. An additional $0.3 million reduction resulted from the
implementation of an experimental, time-of-use rate for certain commercial
customers in August 1992.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, currently
estimated to total $33 million in 1994, $32 million in 1995 and $33 million in
1996. The estimates include AFUDC of $1.6 million in 1994, $0.6 million in
1995 and $0.7 million in 1996. The construction program is subject to periodic
review and revision, and actual construction costs may vary from the above
estimates because of numerous factors. These factors include: changes in
business conditions; revised load growth estimates; changes in environmental
regulations; increasing cost of labor, equipment and materials; and cost of
capital. The construction of two combustion turbine peaking units totaling 160
megawatts is planned to be completed in mid 1994. The Company is also
constructing six combustion turbine peaking units owned by Georgia Power
Company. The construction is to be completed in 1996.
See Management's Discussion and Analysis under
"Environmental Matters" for information on the impact of the Clean Air Act
Amendments of 1990 and other environmental matters.
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NOTES (continued)
Savannah Electric and Power Company 1993 Annual Report
5. FINANCING AND COMMITMENTS
GENERAL
To the extent possible, the Company's construction program is expected to be
financed from internal sources and from the issuance of additional long-term
debt and preferred stock and capital contributions from The Southern Company.
Should the Company be unable to obtain funds from these sources, the Company
would have to use short-term indebtedness or other alternative, and possibly
costlier, means of financing.
The amounts of long-term debt and preferred stock that can
be issued in the future will be contingent on market conditions, the
maintenance of adequate earnings levels, regulatory authorizations and other
factors. See Management's Discussion and Analysis for information regarding
the Company's earnings coverage requirements.
BANK CREDIT ARRANGEMENTS
At the beginning of 1994, unused credit arrangements with four banks totaled
$14.5 million, and expire at various times during 1994.
The Company has $20 million of revolving credit arrangements
expiring December 31, 1995. These agreements allow short-term borrowings to be
converted into term loans, payable in 12 equal quarterly installments, with the
first installment due at the end of the first calendar quarter after the
applicable termination date or at an earlier date at the Company's option. In
connection with these credit arrangements, the Company agrees to pay
commitments fees based on the unused portions of the commitments.
In connection with all other lines of credit, the Company
has the option of paying fees or maintaining compensating balances, which are
substantially all the cash of the Company except for daily working funds and
similar items. These balances are not legally restricted from withdrawal.
ASSETS SUBJECT TO LIEN
As amended and supplemented, the Company's Indenture of Mortgage, which
secures the first mortgage bonds issued by the Company, constitutes a direct
first lien on substantially all of the Company's fixed property and franchises.
OPERATING LEASES
The Company has rental agreements with various terms and expiration dates.
Rental expenses totaled $1.5 million, $1.5 million, and $1.4 million for 1993,
1992, and 1991, respectively. At December 31, 1993, estimated future minimum
lease payments for non-cancelable operating leases were as follows:
Amounts
(in millions)
1994 $1.3
1995 0.3
1996 0.1
1997 and thereafter -
6. LONG-TERM POWER SALES AGREEMENTS
The operating subsidiaries of The Southern Company, including the Company, have
entered into long-term contractual agreements for the sale of capacity and
energy to certain non-affiliated utilities located outside the system's service
area. Certain of these agreements are non-firm and are based on capacity of
the system in general. Other agreements are firm and pertain to the capacity
related to specific generating units. Because the energy is generally sold at
cost under these agreements, revenues from capacity sales primarily affect
profitability. The Company's portion of capacity revenues has been as follows:
Unit Other
Year Power Long-Term Total
(in thousands)
1993 $ 2 $976 $978
1992 3 534 537
1991 25 491 516
Long-term non-firm power of 400 megawatts was sold by the
Southern electric system in 1993 to Florida Power Corporation (FPC). In
January 1994, this amount decreased to 200 megawatts, and the contract will
expire at year-end.
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NOTES (continued)
Savannah Electric and Power Company 1993 Annual Report
7. INCOME TAXES
Effective January 1, 1993, the Company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption of Statement No. 109 resulted in
cumulative adjustments that had no material effect on net income. The adoption
also resulted in the recording of additional deferred income taxes and related
assets and liabilities. The related assets of $25 million are revenues to be
received from customers. These assets are attributable to tax benefits flowed
through to customers in prior years and to taxes applicable to capitalized
AFUDC. The related liabilities of $26 million are revenues to be refunded to
customers. These liabilities are attributable to deferred taxes previously
recognized at rates higher than current enacted tax law and unamortized
investment tax credits. Additionally, deferred income taxes related to
accelerated tax depreciation previously shown as a reduction to utility plant
were reclassified.
Details of the federal and state income tax provisions are
as follows:
1993 1992 1991
(in thousands)
Total provision for
income taxes
Federal --
Current payable $11,663 $6,630 $11,739
Deferred - current year 1,906 7,407 4,595
- reversal of
prior years (1,383) (2,347) (3,155)
12,186 11,690 13,179
State --
Current payable 2,049 1,231 2,133
Deferred - current year 119 1,079 662
- reversal of
prior years (35) (192) (501)
2,133 2,118 2,294
Total 14,319 13,808 15,473
Less income taxes charged
(credited) to
other income (1,117) (758) (722)
Federal and state
income taxes
charged to operations $15,436 $14,566 $16,195
The tax effects of temporary differences between the
carrying amounts of assets and liabilities in the financial statements and
their respective tax bases, which give rise to deferred tax assets and
liabilities are as follows:
1993
(IN THOUSANDS)
Deferred tax liabilities:
Accelerated depreciation $53,585
Property basis differences 13,871
Other 3,922
Total 71,378
Deferred tax assets:
Pension and other benefits 4,237
Other 4,616
Total 8,853
Net deferred tax liabilities 62,525
Portions included in current assets, net 4,422
Accumulated deferred income taxes
in the Balance Sheets $66,947
Deferred investment tax credits are amortized over the life
of the related property with such amortization normally applied as a credit to
reduce depreciation in the Statements of Income. Credits amortized in this
manner amounted to $0.7 million in 1993, 1992 and 1991. At December 31, 1993,
all investment tax credits available to reduce federal income taxes payable had
been utilized.
A reconciliation of the effective income tax rate to the
statutory tax rate is as follows:
1993 1992 1991
Total effective tax rate 38% 38% 37%
State income tax, net of federal
income tax benefit (4%) (4%) (4%)
Other 1% - 1%
Statutory federal tax rate 35% 34% 34%
The Southern Company and its subsidiaries file a
consolidated federal income tax return. Under a joint consolidated income tax
agreement, each company's current and deferred tax expense is computed on a
stand-alone basis, and consolidated tax savings are allocated to each company
based on its ratio of taxable income to total consolidated taxable income.
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NOTES (continued)
Savannah Electric and Power Company 1993 Annual Report
8. CUMULATIVE PREFERRED STOCK
In November 1993, the Company issued 1,400,000 shares of 6.64 percent Series
Preferred stock which has redemption provisions of $26.66 per share plus
accrued dividends if on or prior to November 1, 1998, and at $25 per share plus
accrued dividends thereafter.
In December 1993, the Company redeemed all 800,000 shares outstanding
of its 9.5 percent Series Preferred stock at the prescribed redemption price of
$26.57 plus accrued dividends. Cumulative preferred stock dividends are
preferential to the payment of dividends on common stock.
9. LONG-TERM DEBT
The Company's Indenture related to its First Mortgage Bonds is
unlimited as to the authorized amount of bonds which may be issued, provided
that required property additions, earnings and other provisions of such
Indenture are met.
On February 19, 1993, the Company refunded its $4.1 million,
6.25 percent Series Pollution Control Bonds, due 1998 with $4.1 million of
variable rate Series Pollution Control Bonds due 2016.
In 1994, there is a first mortgage bond maturity of $3.7
million. The sinking fund requirements of first mortgage bonds are being
satisfied by certification of property additions. See Note 10 "Long-Term Debt
Due Within One Year" for details.
Details of other long-term debt are as follows:
December 31,
1993 1992
(in thousands)
Collateralized obligations incurred
in connection with the sale by public
authorities of tax-exempt pollution
control revenue bonds --
6 1/4% due 1998 $ - $ 4,085
Variable rate (3.2% at 1/1/94)
due 2016 4,085 -
6 3/4% due 2022 13,870 13,870
Total pollution control obligations $17,955 $17,955
Capital lease obligations --
Combustion turbine equipment $ 1,403 $ 1,786
Transportation fleet 908 881
Total other long-term debt $ 2,311 $ 2,667
Sinking fund requirements and /or maturities through 1998
applicable to long-term debt are as follows: $4.5 million in 1994; $0.7
million in 1995; $0.7 million in 1996; $0.1 million in 1997 and no requirement
is needed for 1998.
Assets acquired under capital leases are recorded as utility plant
in service and the related obligation is classified as other long-term debt.
Leases are capitalized at the net present value of the future lease payments.
However, for ratemaking purposes, these obligations are treated as operating
leases, and as such, lease payments are charged to expense as incurred.
The Company leases combustion turbine generating equipment under a
non-cancelable lease expiring in 1995, with renewal options extending until
2010. The Company also leases a portion of its transportation fleet. Under
the terms of these leases, the Company is responsible for taxes, insurance and
other expenses.
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NOTES (continued)
Savannah Electric and Power Company 1993 Annual Report
10. LONG-TERM DEBT DUE WITHIN ONE YEAR
A summary of the improvement fund/sinking fund requirements and scheduled
maturities and redemptions of long-term debt due within one year is as follows:
1993 1992
(in thousands)
Bond sinking fund requirements $1,350 $980
Less:
Portion to be satisfied by
certifying property additions 1,350 980
Cash sinking fund requirements - -
Other long-term debt maturities 4,499 1,319
Total $4,499 $1,319
The first mortgage bond improvement (sinking) fund requirements
amount to 1 percent of each outstanding series of bonds authenticated under the
indentures prior to January 1 of each year, other than those issued to
collateralize pollution control and other obligations. The requirements may be
satisfied by depositing cash or reacquiring bonds, or by pledging additional
property equal to 1 2/3 times the requirements.
11. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's Charter and Indentures contain certain limitations on the payment
of cash dividends on the preferred and common stocks. At December 31, 1993,
approximately $55 million of retained earnings was restricted against the
payment of cash dividends on common stock under the terms of the Mortgage
Indenture.
12. QUARTERLY FINANCIAL INFORMATION
(UNAUDITED)
Summarized quarterly financial data for 1993 and 1992 are as follows (in
thousands):
Net Income After
Operating Operating Dividends on
Quarter Ended Revenue Income Preferred Stock
March 1993 $42,873 $6,123 $3,019
June 1993 52,875 9,301 6,211
September 1993 74,420 13,326 10,214
December 1993 48,274 5,484 2,015
March 1992 $41,965 $6,738 $3,200
June 1992 49,918 8,133 4,837
September 1992 63,814 14,794 11,378
December 1992 42,064 4,206 1,097
The Company's business is influenced by seasonal weather
conditions, a seasonal rate structure and the timing of rate changes, among
other factors.
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SELECTED FINANCIAL AND OPERATING DATA
Savannah Electric and Power Company 1993 Annual Report
1993 1992 1991
OPERATING REVENUES (IN THOUSANDS) $218,442 $197,761 $189,646
NET INCOME AFTER DIVIDENDS
ON PREFERRED AND PREFERENCE STOCKS (IN THOUSANDS) $ 21,459 $ 20,512 $ 24,030
CASH DIVIDENDS ON COMMON STOCK (IN THOUSANDS) $ 21,000 $ 22,000 $ 22,000
RETURN ON AVERAGE COMMON EQUITY (PERCENT) 13.73 12.89 15.13
TOTAL ASSETS (IN THOUSANDS) $527,187 $352,175 $352,505
GROSS PROPERTY ADDITIONS (IN THOUSANDS) $ 72,858 $ 30,132 $ 19,478
CAPITALIZATION (IN THOUSANDS):
Common stock equity $154,269 $158,376 $159,841
Preferred stock 35,000 20,000 20,000
Preferred and preference stock subject
to mandatory redemption - - -
Long-term debt 151,338 110,767 119,280
Total (excluding amounts due within one year) $340,607 $289,143 $299,121
CAPITALIZATION RATIOS (PERCENT):
Common stock equity 45.3 54.8 53.4
Preferred and preference stock 10.3 6.9 6.7
Long-term debt 44.4 38.3 39.9
Total (excluding amounts due within one year) 100.0 100.0 100.0
FIRST MORTGAGE BONDS (IN THOUSANDS):
Issued 45,000 30,000 30,000
Retired - 38,750 22,500
PREFERRED AND PREFERENCE STOCK (IN THOUSANDS):
Issued 35,000 - -
Retired 20,000 - -
SECURITY RATINGS:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A A A
Preferred Stock -
Moody's "a2" "a2" "a2"
Standard and Poor's A- A- A-
CUSTOMERS (YEAR-END):
Residential 101,032 99,164 97,446
Commercial 12,702 12,416 12,153
Industrial 69 73 73
Other 957 940 897
Total 114,760 112,593 110,569
EMPLOYEES (YEAR-END) 655 670 672
Note:
NR = Not Rated
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SELECTED FINANCIAL AND OPERATING DATA
Savannah Electric and Power Company 1993 Annual Report
1990 1989 1988 1987 1986 1985 1984 1983
$205,635 $201,799 $182,440 $174,707 $174,847 $158,643 $148,721 $143,562
$ 26,254 $ 25,535 $ 24,272 $ 22,086 $ 20,452 $ 15,279 $ 14,907 $ 13,967
$ 22,000 $ 20,000 $ 11,700 $ 10,741 $ 9,353 $ 8,387 $ 8,010 $ 6,607
16.85 16.88 17.03 17.03 17.52 14.41 15.31 16.80
$340,050 $349,887 $347,051 $340,109 $341,826 $323,686 $323,318 $314,773
$ 20,086 $ 18,831 $ 23,254 $ 32,276 $ 26,800 $ 30,700 $ 29,724 $ 15,786
$157,811 $153,737 $148,883 $136,207 $123,133 $110,385 $101,664 $ 93,076
20,000 22,300 22,300 2,300 2,300 2,300 2,300 2,300
- 2,884 3,075 9,665 10,256 10,848 11,446 12,043
112,377 117,522 98,285 129,329 137,821 128,850 136,709 145,900
$290,188 $296,443 $272,543 $277,501 $273,510 $252,383 $252,119 $253,319
54.4 51.9 54.6 49.1 45.0 43.7 40.3 36.7
6.9 8.5 9.3 4.3 4.6 5.2 5.5 5.7
38.7 39.6 36.1 46.6 50.4 51.1 54.2 57.6
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
- 30,000 - - 25,000 20,000 - 4,000
9,135 18,275 12,231 10,239 10,160 5,592 10,532 12,071
- - 20,000 - - - - -
5,374 6,591 553 588 610 588 525 558
A1 A1 A1 A3 A3 A3 A3 Baa2
A A A- A- A- A- BBB+ BBB-
"a2" "a2" "a2" NR NR NR NR NR
A- A- BBB+ BBB+ BBB+ BBB+ BBB+ BB+
96,452 94,766 93,486 92,094 89,951 88,101 86,366 83,456
12,045 12,298 12,135 11,812 11,405 10,985 10,659 10,293
76 69 69 67 67 66 76 72
867 856 828 762 731 699 637 620
109,440 107,989 106,518 104,735 102,154 99,851 97,738 94,441
648 643 655 655 658 653 632 624
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277
SELECTED FINANCIAL AND OPERATING DATA (continued)
Savannah Electric and Power Company 1993 Annual Report
1993 1992 1991
OPERATING REVENUES (IN THOUSANDS):
Residential $ 93,883 $ 82,670 $ 80,541
Commercial 71,320 64,756 61,827
Industrial 36,180 33,171 30,492
Other 7,810 7,095 6,561
Total retail 209,193 187,692 179,421
Sales for resale - non-affiliates 6,021 7,821 7,813
Sales for resale - affiliates 2,433 1,505 1,430
Total revenues from sales of electricity 217,647 197,018 188,664
Other revenues 795 743 982
Total $ 218,442 $ 197,761 $ 189,646
KILOWATT-HOUR SALES (IN THOUSANDS):
Residential 1,329,362 1,216,993 1,195,005
Commercial 1,015,935 953,840 925,757
Industrial 854,324 861,121 825,862
Other 115,969 110,270 106,683
Total retail 3,315,590 3,142,224 3,053,307
Sales for resale - non-affiliates 247,203 367,066 372,085
Sales for resale - affiliates 75,384 37,632 32,581
Total 3,638,177 3,546,922 3,457,973
AVERAGE REVENUE PER KILOWATT-HOUR (CENTS):
Residential 7.06 6.79 6.74
Commercial 7.02 6.79 6.68
Industrial 4.23 3.85 3.69
Total retail 6.31 5.97 5.88
Sale for resale 2.62 2.30 2.28
Total sales 5.98 5.55 5.46
RESIDENTIAL AVERAGE ANNUAL KILOWATT-HOUR USE PER
CUSTOMER 13,269 12,369 12,323
RESIDENTIAL AVERAGE ANNUAL REVENUE PER CUSTOMER $ 937.07 $ 840.23 $ 830.54
PLANT NAMEPLATE CAPACITY RATINGS (YEAR-END) (MEGAWATTS) 628 628 605
MAXIMUM PEAK-HOUR DEMAND (MEGAWATTS):
Winter 524 533 526
Summer 747 695 691
ANNUAL LOAD FACTOR (PERCENT) 54.1 55.0 54.1
PLANT AVAILABILITY - FOSSIL-STEAM (PERCENT) 90.2 89.1 78.9
SOURCE OF ENERGY SUPPLY (PERCENT):
Coal 21.5 12.0 16.3
Oil and gas 4.5 2.9 1.7
Purchased power -
From non-affiliates 0.9 1.0 0.4
From affiliates 73.1 84.1 81.6
Total 100.0 100.0 100.0
TOTAL FUEL ECONOMY DATA:
BTU per net kilowatt-hour generated 11,515 12,547 10,917
Cost of fuel per million BTU (cents) 215.97 201.50 199.42
Average cost of fuel per net kilowatt-hour generated
(cents) 2.49 2.53 2.18
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278
SELECTED FINANCIAL AND OPERATING DATA (continued)
Savannah Electric and Power Company 1993 Annual Report
1990 1989 1988 1987 1986 1985 1984 1983
$ 87,063 $ 85,113 $ 81,098 $ 79,785 $ 80,348 $ 70,377 $ 65,059 $ 62,815
65,462 65,474 62,640 60,285 59,547 53,696 50,538 47,861
30,237 28,304 26,865 27,422 27,694 28,335 27,233 27,111
6,782 6,892 6,557 6,315 6,300 5,823 5,505 5,297
189,544 185,783 177,160 173,807 173,889 158,231 148,335 143,084
9,482 8,814 808 - - - - -
5,566 6,025 3,567 - - - - -
204,592 200,622 181,535 173,807 173,889 158,231 148,335 143,084
1,043 1,177 905 900 958 412 386 478
$ 205,635 $ 201,799 $ 182,440 $ 174,707 $ 174,847 $ 158,643 148,721 143,562
1,183,486 1,109,976 1,067,411 1,044,554 1,021,905 926,988 883,498 844,353
892,931 839,756 806,687 775,643 746,133 694,168 668,309 630,160
644,704 561,063 533,604 557,281 515,544 513,270 518,118 495,914
103,539 101,164 97,072 94,949 92,471 87,238 84,798 80,454
2,824,660 2,611,959 2,504,774 2,472,427 2,376,053 2,221,664 2,154,723 2,050,881
441,090 437,943 24,168 - - - - -
294,042 303,142 156,106 - - - - -
3,559,792 3,353,044 2,685,048 2,472,427 2,376,053 2,221,664 2,154,723 2,050,881
7.36 7.67 7.60 7.64 7.86 7.59 7.36 7.44
7.33 7.80 7.77 7.77 7.98 7.74 7.56 7.60
4.69 5.04 5.03 4.92 5.37 5.52 5.26 5.47
6.71 7.11 7.07 7.03 7.32 7.12 6.88 6.98
2.05 2.00 2.43 - - - - -
5.75 5.98 6.76 7.03 7.32 7.12 6.88 6.98
12,339 11,781 11,489 11,481 11,514 10,536 10,357 10,148
$ 907.68 $ 903.37 $ 872.87 $ 876.95 $ 905.27 $ 799.90 $ 762.67 $ 754.97
605 605 605 605 605 605 605 605
428 548 471 414 464 440 360 374
648 613 574 562 565 498 481 496
53.2 52.4 53.4 53.6 51.1 54.7 54.1 50.7
89.6 94.7 77.1 81.2 86.9 92.0 86.1 86.6
52.8 63.5 79.8 74.3 81.9 87.5 91.8 87.6
3.4 1.4 5.4 4.4 6.8 2.6 2.2 5.6
0.8 1.5 5.9 19.9 11.3 9.9 6.0 6.8
43.0 33.6 8.9 1.4 - - - -
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
10,741 10,611 10,683 10,551 10,607 10,581 10,498 10,642
188.18 180.48 178.31 176.10 186.30 198.80 196.20 201.01
2.02 1.92 1.90 1.86 1.98 2.10 2.06 2.14
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279
STATEMENTS OF INCOME
Savannah Electric and Power Company
FOR THE YEARS ENDED DECEMBER 31, 1993 1992 1991
(Thousands of Dollars)
OPERATING REVENUES:
Revenues $ 216,009 $ 196,256 $ 188,216
Revenues from affiliates 2,433 1,505 1,430
Total operating revenues 218,442 197,761 189,646
OPERATING EXPENSES:
Operation --
Fuel 24,976 14,162 14,415
Purchased power from non-affiliates 793 494 297
Purchased power from affiliates 56,274 56,492 49,007
Other 45,610 36,884 32,945
Maintenance 13,516 14,232 12,475
Depreciation and amortization 16,467 16,829 16,549
Taxes other than income taxes 11,136 10,231 10,122
Federal and state income taxes 15,436 14,566 16,195
Total operating expenses 184,208 163,890 152,005
OPERATING INCOME 34,234 33,871 37,641
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction 958 446 170
Interest income 209 276 589
Other, net (1,841) (1,450) (879)
Income taxes applicable to other income 1,117 758 722
INCOME BEFORE INTEREST CHARGES 34,677 33,901 38,243
INTEREST CHARGES:
Interest on long-term debt 10,696 10,870 11,486
Allowance for debt funds used during construction (699) (289) (103)
Interest on notes payable 240 15 25
Amortization of debt discount, premium, and expense, net 535 427 380
Other interest charges 340 466 525
Net interest charges 11,112 11,489 12,313
INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE
EFFECT OF A CHANGE IN METHOD OF RECORDING REVENUES 23,565 22,412 25,930
Extraordinary item* - - -
Cumulative effect as of January 1, 1988, of accruing unbilled
revenues--less income taxes of $1,164(000) - - -
NET INCOME 23,565 22,412 25,930
DIVIDENDS ON PREFERRED AND PREFERENCE STOCK 2,106 1,900 1,900
NET INCOME AFTER DIVIDENDS ON PREFERRED AND PREFERENCE STOCK $ 21,459 $ 20,512 $ 24,030
Pro Forma Net Income After Dividends on Preferred Stock
Assuming Change in Method of Recording
Revenues Was Applied Retroactively $ 21,459 $ 20,512 $ 24,030
* Tax-free common stock/bond exchange
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280
STATEMENTS OF INCOME
Savannah Electric and Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 200,069 $ 195,774 $ 178,873 $ 174,707 $ 174,847 $ 158,643 $ 148,721 $ 143,562
5,566 6,025 3,567 - - - - 4
205,635 201,799 182,440 174,707 174,847 158,643 148,721 143,566
42,630 44,224 46,578 38,597 44,393 45,232 44,183 44,152
611 616 3,593 11,453 6,069 7,577 3,810 -
34,648 26,361 6,586 1,186 2,071 1,526 2,255 5,675
30,630 29,371 28,271 25,642 24,114 20,292 18,424 18,028
12,754 12,281 14,261 13,629 12,591 12,029 11,195 10,711
16,118 20,343 19,771 18,152 16,443 15,798 14,104 12,721
9,798 9,152 9,209 9,088 7,863 6,724 6,098 5,441
17,611 17,571 14,017 16,969 21,405 15,495 15,026 13,862
164,800 159,919 142,286 134,716 134,949 124,673 115,095 110,590
40,835 41,880 40,154 39,991 39,898 33,970 33,626 32,976
193 - 273 512 27 646 624 229
741 719 355 925 924 943 1,200 1,013
(803) (672) (1,423) (464) (553) (107) (173) (133)
187 192 459 (317) (217) (389) (548) (461)
41,153 42,119 39,818 40,647 40,079 35,063 34,729 33,624
12,052 12,287 15,603 17,127 17,415 18,089 18,237 19,484
(194) (112) (330) (459) (73) (725) (551) (328)
116 402 230 70 315 437 172 367
241 274 196 237 234 302 241 255
665 1,313 336 251 335 213 188 220
12,880 14,164 16,035 17,226 18,226 18,316 18,287 19,998
28,273 27,955 23,783 23,421 21,853 16,747 16,442 13,626
- - - - - - - 1,935
- - 1,920 - - - - -
28,273 27,955 25,703 23,421 21,853 16,747 16,442 15,561
2,019 2,420 1,431 1,335 1,401 1,468 1,535 1,594
$ 26,254 $ 25,535 $ 24,272 $ 22,086 $ 20,452 $ 15,279 $ 14,907 $ 13,967
$ 26,254 $ 25,535 $ 22,352 $ 21,865 $ 20,606 $ 15,744 $ 14,665 $ 14,103
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STATEMENTS OF CASH FLOWS
Savannah Electric and Power Company
FOR THE YEARS ENDED DECEMBER 31, 1993 1992 1991
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $ 23,565 $ 22,412 $ 25,930
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 17,482 17,757 17,501
Deferred income taxes, net 607 5,947 1,601
Deferred investment tax credits, net - - -
Allowance for equity funds used during construction (958) (446) (170)
Other, net 2,853 (1,312) (1,876)
Changes in certain current assets and liabilities --
Receivables, net (16,839) (4,107) 5,291
Special deposits - 350 1,348
Inventories (3,947) 4,435 (1,082)
Payables 18,742 351 568
Other 3,282 2,083 3,710
Net cash provided from operating activities 44,787 47,470 52,821
INVESTING ACTIVITIES:
Gross property additions (72,858) (30,132) (19,478)
Sales of property - - -
Other 1,676 (1,073) 407
Net cash provided (used) for investing activities (71,182) (31,205) (19,071)
FINANCIING ACTIVITIES:
Proceeds:
Preferred stock 35,000 - -
First mortgage bonds 45,000 30,000 30,000
Pollution control bonds 4,085 13,870 -
Other long-term debt 10,000 - -
Common Stock - - -
Redemptions:
Preferred and preference stock (20,000) - -
First mortgage bonds - (38,750) (22,500)
Pollution control bonds (4,085) (14,550) (515)
Other long-term debt (10,356) (217) (275)
Notes payable, net (4,500) 7,500 (1,500)
Payment of preferred and preference stock dividends (2,222) (1,900) (1,900)
Payment of common and class A stock dividends (21,000) (22,000) (22,000)
Miscellaneous (3,400) (3,985) (477)
Net cash provided from (used for) financing activities 28,522 (30,032) (19,167)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 2,127 (13,767) 14,583
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 1,788 15,555 972
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 3,915 $ 1,788 $ 15,555
() Denotes use of cash
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282
STATEMENTS OF CASH FLOWS
Savannah Electric and Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 28,273 $ 27,955 $ 25,703 $ 23,421 $ 21,853 $ 16,747 $ 16,442 $ 15,561
16,995 21,310 20,592 19,126 16,855 16,484 14,216 12,147
2,782 3,476 3,568 925 4,443 3,034 3,104 5,000
- - - (5) 489 3,084 2,043 6,900
(193) - (273) (512) (27) (646) (624) (229)
511 (775) 718 (1,016) 474 (1,730) 35 (1,165)
1,541 (6,949) (7,062) 1,360 1,456 (1,122) 180 (2,714)
185 2,708 (558) (587) (53) (916) (27) 966
1,246 (1,503) 3,063 (503) 663 5,563 (7,006) (172)
(228) 1,086 (1,151) (78) (1,750) 2,135 1,637 342
(319) 1,544 (1,684) (757) 1,916 2 521 1,666
50,793 48,852 42,916 41,374 46,319 42,635 30,521 38,302
(20,086) (18,831) (23,254) (32,276) (26,800) (30,700) (29,724) (15,786)
- - - - - 1,145 193 -
(120) 381 (4,042) 1,296 (824) 2,682 1,561 420
(20,206) (18,450) (27,296) (30,980) (27,624) (26,873) (27,970) (15,366)
- - 20,000 - - - - -
- 30,000 - - 25,000 20,000 - 4,000
- - - - - - - -
- - - - - - - 23,500
- - 403 1,693 1,691 1,777 1,639 12,396
(5,374) (6,591) (553) (588) (610) (588) (525) (558)
(9,135) (18,275) (12,231) (10,239) (10,160) (5,592) (10,532) (12,071)
(485) (455) (430) (405) (380) (360) (335) -
(364) (7,656) (4,401) (3,954) (3,075) (17,721) (2,965) (30,635)
1,500 - - - (4,500) (4,500) 9,000 (2,000)
(2,113) (2,318) (1,284) (1,351) (1,418) (1,485) (1,552) (1,611)
(22,000) (20,000) (14,407) (10,383) (9,114) (8,347) (7,763) (6,103)
47 (1,071) (269) - (436) (383) - (376)
(37,924) (26,366) (13,172) (25,227) (3,002) (17,199) (13,033) (13,458)
(7,337) 4,036 2,448 (14,833) 15,693 (1,437) (10,482) 9,478
8,309 4,273 1,825 16,658 965 2,402 12,884 3,406
$ 972 $ 8,309 $ 4,273 $ 1,825 $ 16,658 $ 965 $ 2,402 $ 12,884
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283
BALANCE SHEETS
Savannah Electric and Power Company
At December 31, 1993 1992 1991
(Thousands of Dollars)
ASSETS
UTILITY PLANT:
Production-fossil $ 257,708 $ 258,539 $ 247,017
Transmission 99,791 93,182 90,198
Distribution 237,012 222,024 212,576
General 28,010 25,851 24,283
Construction work in progress 49,797 5,966 4,211
Total utility plant 672,318 605,562 578,285
Accumulated provision for depreciation 251,565 240,094 225,605
Total 420,753 365,468 352,680
Less property-related accumulated deferred income taxes - 65,725 62,737
Total 420,753 299,743 289,943
OTHER PROPERTY AND INVESTMENTS 1,793 1,795 39
CURRENT ASSETS:
Cash and cash equivalents 3,915 1,788 15,555
Receivables, net 27,714 14,480 14,549
Accrued unbilled revenues 3,789 3,401 3,252
Fuel cost under recovery 7,112 3,895 -
Fossil fuel stock, at average cost 8,419 4,895 9,196
Materials and supplies, at average cost 9,358 8,935 9,069
Prepayments 4,849 1,599 4,544
Total current assets 65,156 38,993 56,165
DEFERRED CHARGES:
Deferred charges related to income taxes 24,890 - -
Miscellaneous 14,595 11,644 6,358
Total deferred charges 39,485 11,644 6,358
TOTAL ASSETS $ 527,187 $ 352,175 $ 352,505
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284
BALANCE SHEETS
Savannah Electric and Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 246,278 $ 242,988 $ 241,833 $ 236,587 $ 232,316 $ 229,765 $ 215,908 $ 212,917
73,358 72,299 71,601 69,822 65,215 61,843 55,047 49,554
217,913 204,611 192,335 177,163 160,346 147,563 136,807 126,293
22,990 22,482 21,686 17,513 14,838 13,153 10,585 9,414
1,354 2,880 1,684 7,214 5,270 1,915 10,609 2,341
561,893 545,260 529,139 508,299 477,985 454,239 428,956 400,519
211,725 198,228 178,888 161,531 144,232 130,279 116,576 102,967
350,168 347,032 350,251 346,768 333,753 323,960 312,380 297,552
58,106 54,418 51,487 49,255 46,496 41,026 32,859 30,503
292,062 292,614 298,764 297,513 287,257 282,934 279,521 267,049
39 49 49 49 39 39 52 -
972 8,309 4,273 1,825 16,658 965 2,402 12,884
14,450 14,300 15,714 14,419 13,806 14,472 12,350 11,910
3,831 4,501 3,889 - - - - -
5,662 6,881 1,838 - 787 1,524 1,609 2,249
8,071 9,706 8,455 12,359 12,642 13,615 19,554 12,855
9,112 8,723 8,471 7,630 6,844 6,534 6,157 5,850
1,492 585 1,240 2,786 978 383 117 324
43,590 53,005 43,880 39,019 51,715 37,493 42,189 46,072
- - - - - - - -
4,359 4,219 4,358 4,127 2,815 3,220 1,556 1,652
4,359 4,219 4,358 4,127 2,815 3,220 1,556 1,652
$ 340,050 $ 349,887 $ 347,051 $ 340,708 $ 341,826 $ 323,686 $ 323,318 $ 314,773
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285
BALANCE SHEETS
Savannah Electric and Power Company
At December 31, 1993 1992 1991
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
CAPTIALIZATION:
Common stock $ 54,223 $ 54,223 $ 54,223
Paid-in capital 23 23 -
Paid-in for common stock in excess of par value 8,665 8,665 8,665
Additional minimum liability
for under-funded pension obligations (2,121) - -
Retained Earnings 93,479 95,465 96,953
Total common equity 154,269 158,376 159,841
Preferred stock 35,000 20,000 20,000
Preferred and preference stock subject to mandatory redemption - - -
Long-term debt 151,338 110,767 119,280
Total capitalization 340,607 289,143 299,121
(excluding amount due within one year)
CURRENT LIABILITIES:
Notes payable to banks 3,000 7,500 -
Preferred and preference stock due within one year - - -
Long-term debt due within one year 4,499 1,319 2,442
Accounts payable 30,442 11,179 10,176
Customer deposits 4,714 4,541 4,528
Fuel cost over recovery - - 1,603
Taxes accrued 1,529 3,016 724
Interest accrued 6,730 5,733 4,657
Vacation pay accrued 1,638 1,790 1,672
Miscellaneous 8,703 5,025 4,823
Total current liabilities 61,255 40,103 30,625
DEFERED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes 66,947 - -
Accumulated deferred investment tax credits 15,301 15,964 16,628
Deferred credits related to income taxes 26,173 - -
Deferred under-funded accrued benefit obligation 5,855 - -
Miscellaneous 11,049 6,965 6,131
Total deferred credits and other liabilities 125,325 22,929 22,759
TOTAL CAPITALIZATION AND LIABILITIES $ 527,187 $ 352,175 $ 352,505
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286
BALANCE SHEETS
Savannah Electric and Power Company
1990 1989 1988 1987 1986 1985 1984 1983
$ 54,223 $ 54,223 $ 54,223 $ 54,131 $ 53,174 $ 52,332 $ 51,271 $ 49,462
- - - - - - - -
8,665 8,665 8,665 8,353 7,623 6,774 6,059 6,229
- - - - - - - -
94,923 90,849 85,995 73,723 62,336 51,279 44,334 37,385
157,811 153,737 148,883 136,207 123,133 110,385 101,664 93,076
20,000 22,300 22,300 2,300 2,300 2,300 2,300 2,300
- 2,884 3,075 9,665 10,256 10,848 11,446 12,043
112,377 117,522 98,285 129,329 137,821 128,850 136,709 145,900
290,188 296,443 272,543 277,501 273,510 252,383 252,119 253,319
1,500 - - - - 4,500 9,000 -
- 190 6,590 553 550 568 558 486
2,358 7,091 23,217 8,956 14,836 12,636 8,510 12,910
8,786 9,078 7,950 9,427 10,329 12,584 9,956 7,558
4,472 4,296 3,983 3,729 3,403 3,256 2,846 2,537
- - - 599 - - - -
1,387 1,749 1,899 3,713 4,834 3,595 8,663 7,789
3,415 4,287 4,154 4,599 4,906 4,984 5,253 5,460
1,604 1,477 1,412 1,306 1,255 1,150 1,086 997
3,398 2,880 1,705 6,257 3,650 3,356 3,336 3,107
26,920 31,048 50,910 39,139 43,763 46,629 49,208 40,844
- - - - - - - -
17,292 17,971 19,106 20,264 21,663 22,265 20,117 19,040
- - - - - - - -
- - - - - - - -
5,650 4,425 4,492 3,804 2,890 2,409 1,874 1,570
22,942 22,396 23,598 24,068 24,553 24,674 21,991 20,610
$ 340,050 $ 349,887 $ 347,051 $ 340,708 $ 341,826 $ 323,686 $ 323,318 $ 314,773
II-256
287
SAVANNAH ELECTRIC AND POWER COMPANY
OUTSTANDING SECURITIES
AT DECEMBER 31, 1993
FIRST MORTGAGE BONDS
Amount Interest Amount
Series Issued Rate Outstanding Maturity
(Thousands) (Thousands)
1964 $ 8,000 4-5/8% $ 3,715 4/1/94
1993 20,000 6-3/8% 20,000 7/1/03
1989 30,000 9-1/4% 30,000 10/1/19
1991 30,000 9-3/8% 30,000 7/1/21
1992 30,000 8.30% 30,000 7/1/22
1993 25,000 7.40% 25,000 7/1/23
$ 143,000 $ 138,715
POLLUTION CONTROL BONDS
Amount Interest Amount
Series Issued Rate Outstanding Maturity
(Thousands) (Thousands)
1993 $ 4,085 Variable $ 4,085 1/1/16
1992 13,870 6-3/4% 13,870 2/1/22
$ 17,955 $ 17,955
PREFERRED STOCK
Shares Dividend Amount
Series Outstanding Rate Outstanding
(Thousands)
1993 1,400,000 6.64% $ 35,000
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SAVANNAH ELECTRIC AND POWER COMPANY
SECURITIES RETIRED
DURING 1993
POLLUTION CONTROL BONDS
Principal Interest
Series Amount Rate
(Thousands)
1978 $ 4,085 6.25%
PREFERRED STOCK
Principal Dividend
Series Amount Rate
(Thousands)
1988 $ 20,000 9.50%
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PART III
Items 10, 11, 12 and 13 for SOUTHERN are incorporated by reference to ELECTION
OF DIRECTORS in SOUTHERN's definitive Proxy Statement relating to the 1994
annual meeting of stockholders.
Item 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANTS
ALABAMA
(a) (1) Identification of directors of ALABAMA.
ELMER B. HARRIS (1)
President and Chief Executive Officer of ALABAMA
Age 54
Served as Director since 3-1-89.
BILL M. GUTHRIE
Executive Vice President of ALABAMA
Age 60
Served as Director since 12-16-88
EDWARD L. ADDISON (2)
Age 63
Served as Director since 11-1-83
WHIT ARMSTRONG (2)
Age 46
Served as Director since 9-24-82
PHILIP E. AUSTIN (2)
Age 52
Served as Director since 1-25-91
MARGARET A. CARPENTER (2)
Age 69
Served as Director since 2-26-93
PETER V. GREGERSON, SR. (2)
Age 65
Served as Director since 10-22-93
CRAWFORD T. JOHNSON, III (2)
Age 68
Served as Director since 4-18-69
CARL E. JONES, JR. (2)
Age 53
Served as Director since 4-22-88
WALLACE D. MALONE, JR. (2)
Age 57
Served as Director since 6-22-90
WILLIAM V. MUSE (2)
Age 54
Served as Director since 2-26-93
JOHN T. PORTER (2)
Age 62
Served as Director since 10-22-93
GERALD H. POWELL (2)
Age 67
Served as Director since 2-28-86
ROBERT D. POWERS (2)
Age 43
Served as Director since 1-24-92
JOHN W. ROUSE (2)
Age 56
Served as Director since 4-22-88
WILLIAM J. RUSHTON, III (2)
Age 64
Served as Director Since 9-18-70
JAMES H. SANFORD (2)
Age 49
Served as Director since 8-1-83
JOHN C. WEBB, IV (2)
Age 51
Served as Director since 4-22-77
LOUIS J. WILLIE (2)
Age 70
Served as Director since 3-23-84
JOHN W. WOODS (2)
Age 62
Served as Director since 4-20-73
(1) Previously served as Director of ALABAMA from 1980 to 1985.
(2) No position other than Director.
Each of the above is currently a director of ALABAMA, serving a term running
from the last annual meeting of ALABAMA's stockholder (April 23, 1993) for
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290
meeting of ALABAMA's stockholder (April 23, 1993) for one year until the next
annual meeting or until a successor is elected and qualified, except for the
individuals elected in October 1993.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as a director or nominee, other than any arrangements or understandings with
directors or officers of ALABAMA acting solely in their capacities as such.
(b)(1) Identification of executive officers of ALABAMA.
ELMER B. HARRIS (1)
President, Chief Executive Officer and Director
Age 54
Served as Executive Officer since 3-1-89
BANKS H. FARRIS
Senior Vice President
Age 59
Served as Executive Officer since 12-3-91
WILLIAM B. HUTCHINS, III
Senior Vice President and Chief Financial Officer
Age 50
Served as Executive Officer since 12-3-91
T. HAROLD JONES
Senior Vice President
Age 63
Served as Executive Officer since 12-1-91
CHARLES D. MCCRARY
Senior Vice President
Age 42
Served as Executive Officer since 1-1-91
(1) Previously served as executive officer of ALABAMA from 1979 to 1985.
Each of the above is currently an executive officer of ALABAMA, serving a
term running from the last annual meeting of the directors (April 23, 1993) for
one year until the next annual meeting or until his successor is elected and
qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as an officer, other than any arrangements or understandings with officers of
ALABAMA acting solely in their capacities as such.
(c)(1) Identification of certain significant employees.
None.
(d)(1) Family relationships.
None.
(e)(1) Business experience.
ELMER B. HARRIS - Elected in 1989; Chief Executive Officer. He previously
served as Senior Executive Vice President of GEORGIA from 1986 to 1989.
Director of SOUTHERN and AmSouth Bancorporation.
BILL M. GUTHRIE - Elected in 1988; also served since 1991 as Chief Production
Officer of SOUTHERN system and Executive Vice President and Chief Production
Officer of SCS; Vice President of SOUTHERN, GULF, MISSISSIPPI and SAVANNAH and
Executive Vice President of GEORGIA. Responsible primarily for providing
overall management of materials management, fuel services, operating and
planning services, fossil, hydro and bulk power operations of the Southern
electric system.
EDWARD L. ADDISON - Elected in 1983; President of SOUTHERN from 1983 until
elected Chairman of the Board in 1994. Director of SOUTHERN, GEORGIA, Phelps
Dodge Corporation, Protective Life Corporation, Wachovia Bank of Georgia, N.A.,
Wachovia Corporation of Georgia and CSX Corporation.
WHIT ARMSTRONG - President, Chairman and Chief Executive Officer of The
Citizens Bank, Enterprise, Alabama. Also, President and Chairman of the Board
of Enterprise Capital Corporation, Inc.
PHILIP E. AUSTIN - Chancellor, The University of Alabama System. Previously
President and Chancellor of Colorado State University.
MARGARET A. CARPENTER - President, Compos-it, Inc. (typographics), Montgomery,
Alabama.
PETER V. GREGERSON, SR. - Chairman Emeritus of Gregerson's Foods, Inc. (retail
groceries), Gadsden, Alabama. Director of AmSouth Bank of Gadsden, Alabama.
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291
CRAWFORD T. JOHNSON, III - Chairman of Coca-Cola Bottling Company United, Inc.,
Birmingham, Alabama. Director of Protective Life Corporation, AmSouth
Bancorporation and Russell Corporation.
CARL E. JONES, JR. - Chairman and Chief Executive Officer of First Alabama
Bank, Mobile, Alabama.
WALLACE D. MALONE, JR. - Chairman and Chief Executive Officer of SouthTrust
Corporation, bank holding company, Birmingham, Alabama.
WILLIAM V. MUSE - President and Chief Executive Officer of Auburn University.
He previously served as President of the University of Akron from 1984 to 1992.
JOHN T. PORTER - Pastor of Sixth Avenue Baptist Church, Birmingham, Alabama.
Director of Citizen Federal Bank.
GERALD H. POWELL - President, Dixie Clay Company of Alabama, Inc. (refractory
clay producer), Jacksonville, Alabama.
ROBERT D. POWERS - President, The Eufaula Agency, Inc. (real estate and
insurance), Eufaula, Alabama.
JOHN W. ROUSE - President and Chief Executive Officer of Southern Research
Institute (non-profit research institute), Birmingham, Alabama. Director of
Protective Life Corporation.
WILLIAM J. RUSHTON, III - Chairman of the Board, Protective Life Corporation
(insurance holding company), Birmingham, Alabama. Director of SOUTHERN and
AmSouth Bancorporation.
JAMES H. SANFORD - President, HOME Place Farms Inc. (diversified farmers and
ginners), Prattville, Alabama.
JOHN C. WEBB, IV - President, Webb Lumber Company, Inc. (wholesale lumber),
Demopolis, Alabama.
LOUIS J. WILLIE - Chairman of the Board and President of Booker T. Washington
Insurance Co. Director of SOUTHERN.
JOHN W. WOODS - Chairman and Chief Executive Officer, AmSouth Bancorporation
(multi-bank holding company), Birmingham, Alabama. Director of Protective Life
Corporation.
BANKS H. FARRIS - Elected in 1991; responsible primarily for providing the
overall management of the Human Resources, Information Resources, Power
Delivery and Marketing Departments and the six geographic divisions. He
previously served as Vice President - Human Resources from 1989 to 1991 and
Division Vice President from 1985 to 1989.
WILLIAM B. HUTCHINS, III - Elected in 1991; Chief Financial Officer,
responsible primarily for providing the overall management of accounting and
financial planning activities. He previously served as Vice President and
Treasurer from 1983 to 1991.
T. HAROLD JONES - Elected in 1991; responsible primarily for providing the
overall management of the Fossil Generation, Hydro Generation, Power Generation
Services and Fuels Departments. He previously served as Vice President -
Fossil Generation from 1986 to 1991.
CHARLES D. MCCRARY - Elected in 1991; responsible for the External Relations
Department, Operating Services and Corporate Services. Also, assumes
responsibility for financial matters while Mr. Hutchins is on medical leave.
He previously served as Vice President of Administrative Services - Nuclear of
SCS from 1988 to 1991.
(f)(1) Involvement in certain legal proceedings.
None.
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GEORGIA
(a)(2) Identification of directors of GEORGIA.
H. ALLEN FRANKLIN
President and Chief Executive Officer.
Age 49
Served as Director since 1-1-94.
WARREN Y. JOBE
Executive Vice President, Treasurer and Chief Financial Officer.
Age 53
Served as Director since 8-1-82
EDWARD L. ADDISON (1)
Age 63
Served as Director since 11-1-83
BENNETT A. BROWN (1)
Age 64
Served as Director since 5-15-80
WILLIAM P. COPENHAVER (1)
Age 69
Served as Director since 6-18-86
A. W. DAHLBERG (1)
Age 53
Served as Director since 6-1-88
WILLIAM A. FICKLING, JR. (1)
Age 61
Served as Director since 4-18-73
L. G. HARDMAN, III (1)
Age 54
Served as Director since 6-25-79
JAMES R. LIENTZ, JR. (1)
Age 50
Served as Director since 7-1-93
WILLIAM A. PARKER, JR. (1)
Age 66
Served as Director since 5-19-65
G. JOSEPH PRENDERGAST (1)
Age 48
Served as Director since 1-20-93
HERMAN J. RUSSELL (1)
AGE 63
Served as Director since 5-18-88
GLORIA M. SHATTO (1)
Age 62
Served as Director since 2-20-80
ROBERT STRICKLAND (1)
Age 66
Served as Director since 11-21-79
WILLIAM JERRY VEREEN (1)
Age 53
Served as Director since 5-18-88
THOMAS R. WILLIAMS (1)
Age 65
Served as Director since 3-17-82
(1) No position other than Director.
Each of the above is currently a director of GEORGIA, serving a term running
from the last annual meeting of GEORGIA's stockholder (May 19, 1993) for one
year until the next annual meeting or until a successor is elected and
qualified, except Messrs. Franklin and Lientz.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he/she was or is to be
selected as a director or nominee, other than any arrangements or
understandings with directors or officers of GEORGIA acting solely in their
capacities as such.
(b)(2) Identification of executive officers of GEORGIA.
H. ALLEN FRANKLIN
President, Chief Executive Officer and Director
Age 49
Served as Executive Officer since 1-1-94
WARREN Y. JOBE
Executive Vice President, Treasurer, Chief Financial Officer and Director
Age 53
Served as Executive Officer since 5-19-82
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293
DWIGHT H. EVANS
Executive Vice President - External Affairs
Age 45
Served as Executive Officer since 4-19-89
GENE R. HODGES
Executive Vice President - Customer Operations
Age 55
Served as Executive Officer since 11-19-86
KERRY E. ADAMS
Senior Vice President - Fossil and Hydro Power
Age 49
Served as Executive Officer since 5-1-89
WAYNE T. DAHLKE
Senior Vice President - Power Delivery
Age 53
Served as Executive Officer since 4-19-89
JAMES K. DAVIS
Senior Vice President - Corporate Relations
Age 53
Served as Executive Officer since 10-1-93
ROBERT H. HAUBEIN
Senior Vice President - Administrative Services
Age 54
Served as Executive Officer since 2-19-92
GALE E. KLAPPA
Senior Vice President - Marketing
Age 43
Served as Executive Officer since 2-19-92
FRED D. WILLIAMS
Senior Vice President - Bulk Power Markets
Age 49
Served as Executive Officer since 11-18-92
Each of the above is currently an executive officer of GEORGIA, serving a
term running from the last annual meeting of the directors (May 19,1993) for
one year until the next annual meeting or until his successor is elected and
qualified, except Messrs. Franklin and Davis.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as an officer, other than any arrangements or understandings with officers of
GEORGIA acting solely in their capacities as such.
(c)(2) Identification of certain significant employees.
None.
(d)(2) Family relationships.
None.
(e)(2) Business experience.
H. ALLEN FRANKLIN - President and Chief Executive Officer since January 1994.
He previously served as President and Chief Executive Officer of SCS from 1988
through 1993. Director of SOUTHERN and SouthTrust Bank.
WARREN Y. JOBE - Executive Vice President and Chief Financial Officer since
1982 and Treasurer since 1992. Responsible for financial and accounting
operations and planning, internal auditing, procurement, corporate secretary
and treasury operations.
EDWARD L. ADDISON - President of SOUTHERN from 1983 until his election as
Chairman of Board in 1994. Director of SOUTHERN, ALABAMA, Wachovia Bank of
Georgia, N.A., Wachovia Corporation of Georgia, Phelps Dodge Corporation,
Protective Life Corporation and CSX Corporation.
BENNETT A. BROWN - Retired from serving as Chairman of the Board of NationsBank
on December 31, 1992. Previously Chairman of the Board and Chief Executive
Officer of C&S/Sovran Corporation. Director of Confederation Life Insurance
Company.
WILLIAM P. COPENHAVER - Director, Arcadian Fertilizer, L.P. (agricultural and
industrial chemicals). Director of SOUTHERN and Georgia Bank & Trust Company.
A. W. DAHLBERG - President of SOUTHERN effective in 1994. He previously served
as President and Chief Executive Officer of GEORGIA from 1988 through 1993.
Director of SOUTHERN, Trust Company Bank, Trust Company of Georgia, Protective
Life Corporation and Equifax, Inc.
WILLIAM A. FICKLING, JR. - Chairman of the Board, Mulberry Street Investment
Company, Macon, Georgia, and Co-chairman of Beech Street Corporation
(insurance).
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294
L. G. HARDMAN, III - Chairman of the Board of First National Bank of
Commerce, Georgia and Chairman of the Board and Chief Executive Officer of
First Commerce Bancorp. Chairman of the Board, President and Treasurer of
Harmony Grove Mills, Inc. (real estate investments). Director of SOUTHERN.
JAMES R. LIENTZ, JR. - President of NationsBank of Georgia since 1993. He
previously served as President and Chief Executive Officer of former Citizens &
Southern Bank of South Carolina (now NationsBank) from 1990 to 1993, and from
1987 to 1990, he was head of Corporate Bank Group of NationsBank of Georgia,
N.A.
WILLIAM A. PARKER, JR. - Chairman of the Board, Cherokee Investment Company,
Inc. (private investments), Atlanta, Georgia. Director of SOUTHERN, Genuine
Parts Company, Life Insurance Company of Georgia, First Union Real Estate
Investment Trust, Atlantic Realty Company, ING North America Insurance Company,
Post Properties, Inc. and Haverty Furniture Companies, Inc.
G. JOSEPH PRENDERGAST - President and Chief Executive Officer, Wachovia
Corporation of Georgia and Wachovia Bank of Georgia, N.A. since 1993. From
1988 to 1993, he served as Executive Vice President of Wachovia Corporation and
President of Wachovia Corporate Services, Inc.
HERMAN J. RUSSELL - Chairman of the Board and Chief Executive Officer, H. J.
Russell & Company (construction), Atlanta, Georgia. Chairman of the Board,
Citizens Trust Bank, and Citizens Bancshares Corporation Atlanta, Georgia.
Director of Wachovia Corporation.
GLORIA M. SHATTO - President, Berry College, Mount Berry, Georgia. Director of
SOUTHERN, Becton Dickinson & Company, Kmart Corporation and Texas Instruments,
Inc.
ROBERT STRICKLAND - Retired Chairman of the Board and Chief Executive Officer
of SunTrust Banks, Inc. Director of Georgia US Corporation, Equifax, Inc.,
Life Insurance Company of Georgia, Oxford Industries, Inc. and The Investment
Centre.
WILLIAM JERRY VEREEN - President and Chief Executive Officer of Riverside
Manufacturing Company (manufacture and sale of uniforms), Moultrie, Georgia.
Director of Gerber Garment Technology, Inc. and Textile Clothing Technology
Corp.
THOMAS R. WILLIAMS - President of The Wales Group, Inc. (investments) Atlanta,
Georgia. Director of ConAgra, Inc., BellSouth Corporation, National Life
Insurance Company of Vermont, AppleSouth, Inc., and American Software, Inc.
DWIGHT H. EVANS - Executive Vice President - External Affairs since 1989.
Senior Vice President - Public Affairs from 1988 to 1989.
GENE R. HODGES - Executive Vice President - Customer Operations since 1992.
Senior Vice President - Region/Land Operations from 1990 to 1992. Senior Vice
President - Division Operations from 1986 to 1990.
KERRY E. ADAMS - Senior Vice President - Fossil and Hydro Power since 1989.
WAYNE T. DAHLKE - Senior Vice President - Power Delivery since February 1992.
Senior Vice President - Marketing from 1989 to 1992.
JAMES K. DAVIS - Senior Vice President - Corporate Relations since October
1993. Vice President of Corporate Relations from 1988 to 1993.
ROBERT H. HAUBEIN - Senior Vice President - Administrative Services since 1992.
Vice President - Northern Region from 1990 to 1992. Division Vice President of
ALABAMA from 1985 to 1990.
GALE E. KLAPPA - Senior Vice President - Marketing since 1992. Vice President
- - Public Relations of SCS from 1981 to 1992.
FRED D. WILLIAMS - Senior Vice President - Bulk Markets since 1992. Vice
President - Bulk Power Markets from 1984 to 1992.
(f)(2) Involvement in certain legal proceedings.
None.
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295
GULF
(a)(3) Identification of directors of GULF.
D. L. MCCRARY (1)
Chairman of the Board and Chief Executive Officer
Age 64
Served as Director since 4-28-83
TRAVIS J. BOWDEN
President
Age 55
Served as Director since 2-1-94
PAUL J. DENICOLA (2)
Age 45
Served as Director since 4-19-91
REED BELL, SR., M.D. (2)
Age 67
Served as Director since 1-17-86
FRED C. DONOVAN, SR. (2)
Age 53
Served as Director since 1-18-91
W. D. HULL, JR. (2)
Age 61
Served as Director since 10-14-83
C. W. RUCKEL (2)
Age 66
Served as Director since 4-20-62
J. K. TANNEHILL (2)
Age 60
Served as Director since 7-19-85
(1) Retires May 1, 1994.
(2) No position other than Director.
Each of the above is currently a director of GULF, serving a term running
from the last annual meeting of GULF's stockholder (June 29, 1993) for one year
until the next annual meeting or until a successor is elected and qualified,
except for Mr. Bowden.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as a director or nominee, other than any arrangements or understandings with
directors or officers of GULF acting solely in their capacities as such.
(b)(3) Identification of executive officers of GULF.
D. L. MCCRARY
Chairman of the Board and Chief Executive Officer
Age 64
Served as Executive Officer since 5-1-83
TRAVIS J. BOWDEN
President
Age 55
Served as Executive Officer since 2-1-94
F. M. FISHER, JR.
Vice President - Employee and External Relations
Age 45
Served as Executive Officer since 5-19-89
JOHN E. HODGES, JR.
Vice President - Customer Operations
Age 50
Served as Executive Officer since 5-19-89
G. EDISON HOLLAND, JR.
Vice President and Corporate Counsel
Age 41
Served as Executive Officer since 4-25-92
EARL B. PARSONS, JR.
Vice President - Power Generation and Transmission
Age 55
Served as Executive Officer since 4-14-78
A. E. SCARBROUGH
Vice President - Finance
Age 57
Served as Executive Officer since 9-21-77
Each of the above is currently an executive officer of GULF, serving a term
running from the last annual meeting of the directors (July 23, 1993) for one
year until the next annual meeting or until his successor is elected and
qualified, except for Mr. Bowden.
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296
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as an officer, other than any arrangements or understandings with officers of
GULF acting solely in their capacities as such.
(c)(3) Identification of certain significant employees.
None.
(d)(3) Family relationships.
None.
(e)(3) Business experience.
D. L. MCCRARY - Elected Chairman of the Board effective February 1994. He
previously served as President and Chief Executive Officer from 1983 to 1994;
responsible primarily for formation of overall corporate policy.
TRAVIS J. BOWDEN - Elected President effective February 1994 and, upon Mr.
McCrary's retirement May 1994, Chief Executive Officer. He previously served
as Executive Vice President of ALABAMA from 1985 to 1994.
PAUL J. DENICOLA - President and Chief Executive Officer of SCS effective
January 1994. He previously served as Executive Vice President of SCS from
1991 through 1993 and President and Chief Executive Officer of MISSISSIPPI from
1989 to 1991. Director of SOUTHERN, MISSISSIPPI and SAVANNAH.
REED BELL, SR., M.D. - Medical Doctor and since 1989, employee of the State of
Florida. He serves as Medical Director of Children's Medical Services,
District 1. He previously served as Medical Director of the Escambia County
Public Health Unit until July 1992. He also previously maintained a private
medical practice and served as Medical Director of Children's Medical Services
from 1988 to 1989.
FRED C. DONOVAN, SR. - President of Baskerville - Donovan, Inc., Pensacola,
Florida, an architectural and engineering firm. Director of Baptist Health
Care, Inc.
W. D. HULL, JR. - Vice Chairman of the Sun Bank/West Florida,
Panama City, Florida. He previously served as President and Chief Executive
Officer and Director of the Sun Commercial Bank, Panama City, Florida from 1987
to 1992.
C. W. RUCKEL - Chairman of the Board of The Vanguard Bank and Trust Company,
Valparaiso, Florida. President and owner of Ruckel Properties, Inc.,
Valparaiso, Florida.
J. K. TANNEHILL - President and Chief Executive Officer of Tannehill
International Industries, Lynn Haven, Florida. He previously served as
President and Chief Executive Officer of Stock Equipment Company, Chagrin
Falls, Ohio, until 1991. Director of Sun Bank/West Florida, Panama City,
Florida.
F. M. FISHER, JR. - Elected Vice President - Employee and External Relations in
1989. He previously served as General Manager of Central Division from 1988 to
1989.
JOHN E. HODGES, JR. - Elected Vice President - Customer Operations in 1989. He
previously served as General Manager of Western Division from 1986 to 1989.
G. EDISON HOLLAND, JR. - Elected Vice President and Corporate Counsel in 1992;
responsible for all legal matters associated with GULF and serves as compliance
officer. Also served, since 1982, as a partner in the law firm, Beggs & Lane.
EARL B. PARSONS, JR. - Elected Vice President - Power Generation and
Transmission in 1989; responsible for generation and transmission of electrical
energy. He previously served as Vice President - Electric Operations from 1978
to 1989.
A. E. SCARBROUGH - Elected Vice President - Finance in 1980; responsible for
all accounting and financial services of GULF.
(f)(3) Involvement in certain legal proceedings.
None.
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297
MISSISSIPPI
(a)(4) Identification of directors of MISSISSIPPI.
DAVID M. RATCLIFFE
President and Chief Executive Officer
Age 45
Served as Director since 4-24-91
PAUL J. DENICOLA (1)
Age 45
Served as Director since 5-1-89
EDWIN E. DOWNER (1)
Age 62
Served as Director since 4-24-84
ROBERT S. GADDIS (1)
Age 62
Served as Director since 1-21-86
WALTER H. HURT, III (1)
Age 58
Served as Director since 4-6-82
AUBREY K. LUCAS (1)
Age 59
Served as Director since 4-24-84
EARL D. MCLEAN, JR. (1)
Age 68
Served as Director since 10-21-78
GERALD J. ST. Pe (1)
Age 54
Served as Director since 1-21-86
LEO W. SEAL, JR. (1)
Age 69
Served as Director since 4-4-67
N. EUGENE WARR (1)
Age 58
Served as Director since 1-21-86
(1) No position other than Director.
Each of the above is currently a director of MISSISSIPPI, serving a term
running from the last annual meeting of MISSISSIPPI's stockholder (April 6,
1993) for one year until the next annual meeting or until a successor is
elected and qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he or she was or is to be
selected as a director or nominee, other than any arrangements or
understandings with directors or officers of MISSISSIPPI acting solely in their
capacities as such.
(b)(4) Identification of executive officers of MISSISSIPPI.
DAVID M. RATCLIFFE
President, Chief Executive Officer and Director
Age 45
Served as Executive Officer since 4-24-91
H. E. BLAKESLEE
Vice President - Customer Services and Marketing
Age 53
Served as Executive Officer since 1-25-84
THOMAS A. FANNING
Vice President and Chief Financial Officer
Age 37
Served as Executive Officer since 4-1-92
DON E. MASON
Vice President - External Affairs and Corporate Services
Age 52
Served as Executive Officer since 7-27-83
Each of the above is currently an executive officer of MISSISSIPPI, serving
a term running from the last annual meeting of the directors (April 28, 1993)
for one year until the next annual meeting or until his successor is elected
and qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as an officer, other than any arrangements or understandings with officers of
MISSISSIPPI acting solely in their capacities as such.
(c)(4) Identification of certain significant employees.
None.
(d)(4) Family relationships.
None.
(e)(4) Business experience.
III-9
298
DAVID M. RATCLIFFE - President and Chief Executive Officer since 1991. He
previously served as Executive Vice President of SCS from 1989 to 1991 and Vice
President of SCS from 1985 to 1989.
PAUL J. DENICOLA - President and Chief Executive Officer of SCS effective 1994.
Executive Vice President of SCS from 1991 through 1993. He previously served
as President and Chief Executive Officer of MISSISSIPPI from 1989 to 1991.
Director of SOUTHERN, SAVANNAH and GULF.
EDWIN E. DOWNER - Business consultant specializing in economic analysis,
management controls and procedural studies since 1990. President and Chief
Executive Officer, Unifirst Bank for Savings, F.A., Midland Division, Meridian,
Mississippi from 1985 to 1990.
ROBERT S. GADDIS - President of the Trustmark National Bank - Laurel,
Mississippi.
WALTER H. HURT, III - President and Director of NPC Inc. (Investments). Vicar,
All Saints Church, Inverness, Mississippi, and St. Thomas Church, Belzoni,
Mississippi. Retired newspaper editor and publisher.
AUBREY K. LUCAS - President of the University of Southern Mississippi,
Hattiesburg, Mississippi.
EARL D. MCLEAN, JR. - Co-owner of the T. C. Griffith Insurance Agency, Inc.
(insurance and real estate), Columbia, Mississippi. Director of SOUTHERN.
GERALD J. ST. Pe - President of Ingalls Shipbuilding and Corporate Vice
President of Litton Industries, Inc. since 1985. Director of Merchants and
Marine Bank, Pascagoula, Mississippi.
LEO W. SEAL, JR. - Chairman of the Board and Chief Executive Officer of Hancock
Bank, Gulfport, Mississippi, and Chairman of the Board of Harrison Life
Insurance Company. Director of Hancock Bank and Bank of Wiggins.
N. EUGENE WARR - Retailer (Biloxi and Gulfport, Mississippi.) Chairman of the
Board of First Jefferson Corporation and the Jefferson Bank of Biloxi,
Mississippi.
H. E. BLAKESLEE - Elected Vice President in 1984. Primarily responsible
for rate design, economic analysis and revenue forecasting, economic
development, marketing and district operations.
THOMAS A. FANNING - Elected Vice President in 1992; responsible primarily for
accounting, treasury, finance, information resources and risk management. He
previously served as Treasurer of SEI from 1986 to 1992 and Director of
Corporate Finance of SCS from 1988 to 1992.
DON E. MASON - Elected Vice President in 1983. Primarily responsible for the
external affairs functions, including governmental and regulatory affairs,
corporate communications, security, materials and general services, as well as
the human resources function.
(f)(4) Involvement in certain legal proceedings.
None.
SAVANNAH
(a)(5) Identification of directors of SAVANNAH.
ARTHUR M. GIGNILLIAT, JR.
President and Chief Executive Officer
Age 61
Served as Director since 8-31-82
HELEN QUATTLEBAUM ARTLEY (1)
Age 66
Served as Director since 5-17-77
PAUL J. DENICOLA (1)
Age 45
Served as Director since 3-14-91
BRIAN R. FOSTER (1)
Age 44
Served as Director since 5-16-89
WALTER D. GNANN (1)
Age 58
Served as Director since 5-17-83
JOHN M. MCINTOSH (1)
Age 69
Served as Director since 2-27-68
III-10
299
ROBERT B. MILLER, III (1)
Age 48
Served as Director since 5-17-83
JAMES M. PIETTE (1)
Age 69
Served as Director since 6-12-73
ARNOLD M. TENEBAUM (1)
Age 57
Served as Director since 5-17-77
FREDERICK F. WILLIAMS, JR. (1)
Age 66
Served as Director since 7-2-75
(1) No Position other than Director.
Each of the above is currently a director of SAVANNAH, serving a term
running from the last annual meeting of SAVANNAH's stockholder (May 18, 1993)
for one year until the next annual meeting or until a successor is elected and
qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he/she was or is to be
selected as a director or nominee, other than any arrangements or
understandings with directors or officers of SAVANNAH acting solely in their
capacities as such.
(b)(5) Identification of executive officers of SAVANNAH.
ARTHUR M. GIGNILLIAT, JR.
President, Chief Executive Officer and Director
Age 61
Served as Executive Officer since 2-15-72
W. MILES GREER
Vice President - Marketing and Customer Services
Age 50
Served as Executive Officer since 11-20-85
LARRY M. PORTER
Vice President - Operations
Age 49
Served as Executive Officer since 7-1-91
KIRBY R. WILLIS
Vice President, Treasurer and
Chief Financial Officer
Age 42
Served as Executive Officer since 1-1-94
Each of the above is currently an executive officer of SAVANNAH, serving a
term running from the last annual meeting of the directors (May 18, 1993) for
one year until the next annual meeting or until his successor is elected and
qualified, except Mr. Willis.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as an officer, other than any arrangements or understandings with officers of
SAVANNAH acting solely in their capacities as such.
(c)(5) Identification of certain significant employees.
None.
(d)(5) Family relationships.
None.
(e)(5) Business experience.
ARTHUR M. GIGNILLIAT, JR. - Elected President and Chief Executive Officer in
1985. Director of Savannah Foods and Industries, Inc.
HELEN QUATTLEBAUM ARTLEY - Homemaker and Civic Worker.
PAUL J. DENICOLA - President and Chief Executive Officer of SCS effective
January 1994. Executive Vice President of SCS from 1991 through 1993. He
previously served as President and Chief Executive Officer of MISSISSIPPI from
1989 to 1991. Director of SOUTHERN, GULF and MISSISSIPPI.
BRIAN R. FOSTER - President of NationsBank of Georgia, N.A., in Savannah since
1988.
WALTER D. GNANN - President of Walt's TV, Appliance and Furniture Co., Inc.,
Springfield, Georgia. Past Chairman of the Development Authority of Effingham
County, Georgia.
III-11
300
JOHN M. MCINTOSH - Chairman of the Executive Committee, SAVANNAH; retired
Chairman of the Board of Directors and Chief Executive Officer, SAVANNAH from
1974 to 1984. Director of SOUTHERN.
ROBERT B. MILLER, III - President of American Builders of Savannah.
JAMES M. PIETTE - Vice President - Special Projects, Union Camp Corporation,
since 1989. Retired Vice Chairman, Board of Directors, Union Camp Corporation
from 1987 to 1989.
ARNOLD M. TENENBAUM - President of Chatham Steel Corporation. Director of
First Union National Bank of Georgia and Savannah Foods and Industries, Inc.
FREDERICK F. WILLIAMS, JR. - Retired Partner and Consultant, Hilb, Rogal and
Hamilton Employee Benefits, Incorporated (Insurance Brokers), formerly Jones,
Hill & Mercer.
W. MILES GREER - Vice President - Marketing and Customer Services effective
January 1994. Formerly served as Vice President - Economic Development and
Corporate Services from 1989 through 1993 and Vice President - Economic
Development and Governmental Affairs from 1985 to 1989.
LARRY M. PORTER - Vice President - Operations since 1991. Responsible for
managing the areas of fuel procurement, power production, transmission and
distribution, engineering and system operation. Previously he served as
Assistant Plant Manager of GEORGIA's Plant Scherer from 1984 to 1991.
KIRBY R. WILLIS - Vice President, Treasurer and Chief Financial Officer
effective January 1994. Responsible for all financial activities, Information
Resources, Human Resources, Corporate Services, and Environmental Affairs and
Safety. He previously served as Treasurer, Controller and Assistant Secretary
from 1991 to 1993 and Treasurer and Secretary from 1987 to 1991.
(f)(5) Involvement in certain legal proceedings.
None.
III-12
301
ITEM 11. EXECUTIVE COMPENSATION
(A) SUMMARY COMPENSATION TABLES. The following tables set forth
information concerning the Chief Executive Officer and the four most highly
compensated executive officers for each of the operating affiliates (ALABAMA,
GEORGIA, GULF, MISSISSIPPI and SAVANNAH), serving as of December 31, 1993 whose
total annual salary and bonus exceeded $100,000. No information is provided
for any person for any year in which such person did not serve as an executive
officer of the operating affiliate. The number of SOUTHERN common shares do
not reflect the stock distribution resulting from the two-for-one common stock
split approved by SOUTHERN's board of directors in January, 1994.
KEY TERMS used in this Item will have the following meanings:-
AME........... ABOVE-MARKET EARNINGS ON DEFERRED COMPENSATION
ESP........... EMPLOYEE SAVINGS PLAN
ESOP.......... EMPLOYEE STOCK OWNERSHIP PLAN
SBP........... SUPPLEMENTAL BENEFIT PLAN
VBP........... VEHICLE BUYOUT PROGRAM
ALABAMA
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------
NUMBER OF
SECURITIES LONG-
NAME UNDERLYING TERM
AND OTHER ANNUAL STOCK INCENTIVE ALL OTHER
PRINCIPAL COMPENSATION OPTIONS PAYOUTS COMPENSATION
POSITION YEAR SALARY($) BONUS($) ($)(1) (SHARES) ($)(2) ($)(3)
- --------------------------------------------------------------------------------------------------------------------
ELMER B. HARRIS
President,
Chief Executive 1993 418,818 117,630 23,469 13,446 198,131 39,388
Officer, 1992 397,499 96,615 9,161 15,018 147,278 24,435
Director 1991 371,491 45,147 - 18,344 107,729 -
TRAVIS J. BOWDEN(4)
Executive Vice 1993 257,089 23,161 16,118 6,119 61,524 31,271
President, 1992 244,139 35,804 1,636 6,802 44,345 13,550
Director 1991 215,002 34,593 - 5,883 34,775 -
BANKS H. FARRIS 1993 176,041 17,642 24,222 3,151 28,394 27,418
Senior Vice 1992 165,746 27,274 6,211 3,453 19,021 8,916
President 1991 141,818 21,411 - - 13,607 -
III-13
302
ALABAMA
SUMMARY COMPENSATION TABLE
(CONTINUED)
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------
NUMBER OF
SECURITIES LONG-
NAME UNDERLYING TERM
AND OTHER ANNUAL STOCK INCENTIVE ALL OTHER
PRINCIPAL COMPENSATION OPTIONS PAYOUTS COMPENSATION
POSITION YEAR SALARY($) BONUS($) ($)(1) (SHARES) ($)(2) ($)(3)
- --------------------------------------------------------------------------------------------------------------------
T. HAROLD JONES 1993 170,266 11,400 4,032 3,037 27,350 14,093
Senior Vice 1992 163,164 15,000 32,611 3,392 19,181 8,631
President 1991 146,643 15,136 - - 14,560 -
WILLIAM B.
HUTCHINS, III
Senior Vice
President, 1993 164,972 16,103 14,791 2,948 26,429 26,817
Chief Financial 1992 156,520 24,893 973 2,826 17,347 8,307
Officer 1991 - - - - - -
(1) Tax reimbursement by ALABAMA and certain personal benefits, including
membership fee of $28,402 for Mr. Jones in 1992. In accordance with the
transition rules of the SEC, information for 1991 is omitted.
(2) Payouts made in 1992, 1993 and 1994 for the four-year performance periods
ending December 31, 1991, 1992 and 1993, respectively.
(3) ALABAMA contributions to the ESP, ESOP, non-pension related accruals under
the SBP (ERISA excess plan under which accruals are made to offset Internal
Revenue Code imposed limitations under the Employee Savings and Stock Ownership
Plans), and payments under a VBP for the following:-
Name ESP ESOP SBP VBP
- ---- --- ---- --- ---
E. B. Harris $6,746 $1,709 $12,933 $18,000
T. J. Bowden 8,369 1,709 3,193 18,000
B. H. Farris 7,193 1,499 726 18,000
T. H. Jones 6,908 1,331 754 5,100
W. B. Hutchins, III 6,746 1,400 671 18,000
In accordance with the transition rules of the SEC, information for 1991 is
omitted.
(4) Effective January 31, 1994, Mr. Bowden resigned to become president of
GULF.
III-14
303
GEORGIA
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------
NUMBER OF
SECURITIES LONG-
NAME UNDERLYING TERM
AND OTHER ANNUAL STOCK INCENTIVE ALL OTHER
PRINCIPAL COMPENSATION OPTIONS PAYOUTS COMPENSATION
POSITION YEAR SALARY($)(1) BONUS($) ($)(2) (SHARES) ($)(3) ($)(4)
- --------------------------------------------------------------------------------------------------------------------
A. W. DAHLBERG(5)
President, 1993 477,967 96,331 17,707 15,322 225,406 44,547
Chief Executive 1992 469,178 110,094 6,508 17,113 171,243 26,979
Officer, Director 1991 418,968 67,958 - 20,710 126,085 -
DWIGHT H. EVANS 1993 210,544 34,763 14,642 3,749 48,282 29,519
Executive 1992 206,980 40,598 3,505 4,207 36,284 10,925
Vice President 1991 178,777 36,058 - 4,910 25,081 -
WARREN Y. JOBE
Executive
Vice President,
Treasurer, 1993 210,200 27,038 15,645 3,740 48,282 29,258
Chief Financial 1992 209,249 30,521 2,566 4,217 37,320 11,535
Officer, Director 1991 192,458 21,635 - 5,249 29,428 -
GENE R. HODGES 1993 206,727 28,228 14,903 3,439 35,285 30,629
Executive 1992 177,966 27,666 2,471 3,606 29,367 9,600
Vice President 1991 158,339 18,117 - 4,364 20,899 -
KERRY E. ADAMS 1993 183,845 24,699 15,034 3,281 35,285 28,300
Senior Vice 1992 177,919 30,652 2,206 3,630 25,736 9,539
President 1991 153,970 23,058 - 3,671 17,857 -
(1) Due to the pay schedules at GEORGIA, 1992 salary reflects one additional
pay period compared with 1991.
(2) Tax reimbursement by GEORGIA on certain personal benefits. In accordance
with the transition rules of the SEC, information for 1991 is omitted.
(3) Payouts made in 1992, 1993 and 1994 for the four-year performance periods
ending December 31, 1991, 1992 and 1993, respectively.
(4) GEORGIA contributions to the ESP, ESOP, non-pension related accruals
under the SBP (ERISA excess plan under which accruals are made to offset
Internal Revenue Code imposed limitations under the Employee Savings and Stock
Ownership Plans) and payments under a VBP for the following:-
Name ESP ESOP SBP VBP
- ---- --- ---- --- ---
A. W. Dahlberg $6,746 $1,709 $18,092 $18,000
D. H. Evans 8,592 1,709 1,218 18,000
W. Y. Jobe 7,667 1,709 1,882 18,000
G. R. Hodges 7,349 1,620 3,660 18,000
K. E. Adams 7,204 1,634 1,462 18,000
In accordance with the transition rules of the SEC, information for 1991 is
omitted.
(5) Effective December 31, 1993, Mr. Dahlberg resigned to become president of
SOUTHERN.
III-15
304
GULF
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------
NUMBER OF
SECURITIES LONG-
NAME UNDERLYING TERM
AND OTHER ANNUAL STOCK INCENTIVE ALL OTHER
PRINCIPAL COMPENSATION OPTIONS PAYOUTS COMPENSATION
POSITION YEAR SALARY($) BONUS($) ($)(1) (SHARES) ($)(2) ($)(3)
- --------------------------------------------------------------------------------------------------------------------
DOUGLAS L. MCCRARY
President, 1993 310,701 40,856 3,639 7,406 104,719 19,854
Chief Executive 1992 299,960 42,307 1,719 8,351 80,942 16,386
Officer, Director 1991 290,568 37,774 - 10,495 68,429 -
G. E. HOLLAND, JR. 1993 162,651 20,934 9,504 2,920 - 21,015
Vice President, 1992 101,725 17,980 724 2,795 n/e(4) -(5)
Corporate Counsel 1991 - - - - - -
EARL B. PARSONS, JR. 1993 160,089 19,129 9,572 - 22,072 25,430
Vice President 1992 155,495 22,050 420 - 17,875 8,460
1991 159,962 17,979 - - 16,768 -
A. E. SCARBROUGH 1993 155,565 19,129 11,582 - 22,072 24,729
Vice President 1992 147,418 23,173 185 - 17,060 7,891
1991 139,349 17,334 - - 14,422 -
JOHN E. HODGES, JR. 1993 147,144 20,934 9,726 2,289 32,206 24,327
Vice President 1992 139,296 25,360 448 2,532 23,218 7,425
1991 130,903 20,384 - 2,388 16,232 -
(1) Tax reimbursement by GULF on certain personal benefits. In accordance with
the transition rules of the SEC, information for 1991 is omitted.
(2) Payouts made in 1992, 1993 and 1994 for the four-year performance periods
ending December 31, 1991, 1992 and 1993, respectively.
(3) GULF contributions to the ESP, ESOP, non-pension related accruals under
the SBP (ERISA excess plan under which accruals are made to offset Internal
Revenue Code imposed limitations under the Employee Savings and Stock
Ownership Plans) and payments under a VBP for the following:-
Name ESP ESOP SBP VBP
- ---- --- ---- --- ---
D. L. McCrary $9,300 $1,709 $6,057 $ 2,788
G. E. Holland, Jr. 4,652 - - 16,363
E. B. Parsons, Jr 6,948 1,709 410 16,363
A. E. Scarbrough 6,746 1,338 282 16,363
J. E. Hodges, Jr. 6,651 1,313 - 16,363
In accordance with the transition rules of the SEC, information for 1991 is
omitted.
(4) Employee and executive officer of GULF since April 25, 1992. Not eligible
to participate in the Long-Term Incentive Plan until January 1, 1993.
(5) "All Other Compensation" previously reported as $4,149 for Mr. Holland
in the Form 10-K for the year ended December 31, 1992, should have been $0 since
Mr. Holland was not yet eligible to participate in ESP and ESOP.
III-16
305
MISSISSIPPI
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------
NUMBER OF
SECURITIES LONG-
NAME UNDERLYING TERM
AND OTHER ANNUAL STOCK INCENTIVE ALL OTHER
PRINCIPAL COMPENSATION OPTIONS PAYOUTS COMPENSATION
POSITION YEAR SALARY($) BONUS($) ($)(1) (SHARES) ($)(2) ($)(3)
- --------------------------------------------------------------------------------------------------------------------
DAVID M. RATCLIFFE
President, Chief 1993 226,373 45,917 8,722 4,057 75,378 17,887
Executive 1992 213,095 33,395 6,380 4,326 48,722 10,860
Officer, Director 1991 163,805 26,564 - 5,140 30,268 -
ROBERT G. DAWSON(4) 1993 154,668 14,996 4,539 2,390 25,661 15,043
Vice President 1992 147,771 14,002 10,841(5) - 15,685 20,714
1991 - - - - - -
H. E. BLAKESLEE 1993 154,332 15,271 3,528 2,384 32,206 15,650
Vice President 1992 151,176 15,558 507 2,642 23,728 7,756
1991 138,749 12,029 - 3,287 18,091 -
DON E. MASON 1993 148,305 11,016 4,321 - 22,072 15,409
Vice President 1992 146,153 9,951 1,352 - 17,060 7,505
1991 133,567 11,450 - - 14,422 -
THOMAS A. FANNING 1993 122,724 28,244 3,016 - 15,233 14,655
Vice President 1992 89,089 15,574 16,539(5) - 10,085 18,364
1991 - - - - - -
(1) Tax reimbursement by MISSISSIPPI on certain personal benefits. In
accordance with the transition rules of the SEC, information for 1991 is
omitted.
(2) Payouts made in 1992, 1993 and 1994 for the four-year performance periods
ending December 31, 1991, 1992 and 1993, respectively.
(3) MISSISSIPPI contributions to the ESP, ESOP, non-pension related accruals
under the SBP (ERISA excess plan under which accruals are made to offset
Internal Revenue Code imposed limitations under the Employee Savings and Stock
Ownership Plans) and payments under a VBP for the following:-
Name ESP ESOP SBP VBP
- ---- --- ---- --- ---
David M. Ratcliffe $7,895 $1,709 $2,774 $5,509
R. G. Dawson 6,746 1,252 - 7,045
H. E. Blakeslee 6,843 1,355 - 7,452
D. E. Mason 6,671 1,286 - 7,452
T. A. Fanning 5,520 1,019 - 8,116
In accordance with the transition rules of the SEC, information for 1991 is
omitted.
(4) Effective March 1, 1994, Mr. Dawson resigned to become a vice president of
SEI.
(5) Benefits under MISSISSIPPI's VBP for 1992 in the amounts of $13,169 and
$12,425 to Messrs. Dawson and Fanning, respectively, previously reported in the
Form 10-K for the year ended December 31, 1992, under the "Other Annual
Compensation" column have been moved to the "All Other Compensation" column.
III-17
306
SAVANNAH
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------
NUMBER OF
SECURITIES LONG-
NAME UNDERLYING TERM
AND OTHER ANNUAL STOCK INCENTIVE ALL OTHER
PRINCIPAL COMPENSATION OPTIONS PAYOUTS COMPENSATION
POSITION YEAR SALARY($) BONUS($) ($)(1) (SHARES) ($)(2) ($)(3)
- --------------------------------------------------------------------------------------------------------------------
ARTHUR M.
GIGNILLIAT, JR.
President, 1993 202,259 26,470 12,231 3,599 64,932 31,512
Chief Executive 1992 201,338 27,409 - 4,058 50,269 14,466
Officer, Director 1991 184,634 24,232 - 5,051 42,498 -
E. OLIN VEALE(4)
Senior Vice
President, 1993 174,870 12,447 299 - 21,711 14,224
Chief Financial 1992 150,349 12,803 34 - 16,410 12,282
Officer, Director 1991 137,992 10,684 - - 13,558 -
LARRY M. PORTER 1993 126,133 10,070 7,251 - 7,810 21,570
Vice President 1992 122,274 11,621 4,818 - n/e(5) 6,142
1991 105,465 8,993 - - n/e -
W. MILES GREER 1993 117,766 10,337 7,458 - 12,202 21,881
Vice President 1992 115,114 10,776 34 - 9,243 6,599
1991 104,371 7,869 - - 7,571 -
JAMES L. RAYBURN(6) 1993 113,470 - 7,467 - 11,153 20,040
Vice President 1992 109,624 8,934 34 - 7,432 4,281
1991 100,520 7,248 - - 5,278 -
(1) Tax reimbursement by SAVANNAH on certain personal benefits. In accordance
with the transition rules of the SEC, information for 1991 is omitted.
(2) Payouts made in 1992, 1993 and 1994 for the four-year performance periods
ending December 31, 1991, 1992 and 1993, respectively.
(3) SAVANNAH contributions to the ESP, under Section 401(k) of the Internal
Revenue Code, ESOP, AME and payments under a VBP for the following:-
Name ESP ESOP AME VBP
- ---- --- ---- --- ---
A. M. Gignilliat $6,746 $3,092 $7,479 $14,195
E. O. Veale 6,163 2,359 5,702 -
L. M. Porter 4,943 1,774 658 14,195
W. M. Greer 5,045 1,764 877 14,195
J. L. Rayburn 2,284 1,650 1,911 14,195
In accordance with the transition rules of the SEC, information for 1991 is
omitted.
(4) Retired effective December 31, 1993.
(5) Not eligible for Long-term Incentive Payout until January 1, 1994.
(6) Resigned effective December 31, 1993.
III-18
307
STOCK OPTION GRANTS IN 1993
(B) STOCK OPTION GRANTS. The following table sets forth all stock
option grants to the named executive officers of each operating subsidiary
during the year ending December 31, 1993. The number of SOUTHERN common shares
shown and the per share exercise price and market price do not reflect the
stock distribution resulting from the two-for-one common stock split approved
by SOUTHERN's board of directors in January, 1994.
INDIVIDUAL GRANTS GRANT DATE VALUE
# OF % OF TOTAL
SECURITIES OPTIONS EXERCISE
UNDERLYING GRANTED TO OR
OPTIONS EMPLOYEES IN BASE PRICE EXPIRATION GRANT DATE
NAME GRANTED(1) FISCAL YEAR(2) ($/SH)(1) DATE(1) PRESENT VALUE($)(3)
- ------------------------------------------------------------------------------------------------------------------------------------
ALABAMA
Elmer B. Harris 13,446 7.5% $42.4375 07/19/2003 54,187
Travis Bow 6,119 3.4% $42.4375 07/19/2003 24,660
Banks H. Farris 3,151 1.8% $42.4375 07/19/2003 12,699
T. H. Jones 3,037 1.7% $42.4375 04/01/1998 12,178
W. B. Hutchins, III 2,948 1.6% $42.4375 07/19/2003 11,880
GEORGIA
A. W. Dahlberg 15,322 8.5% $42.4375 07/19/2003 61,748
Dwight H. Evans 3,749 2.1% $42.4375 07/19/2003 15,108
Warren Y. Jobe 3,740 2.1% $42.4375 07/19/2003 15,072
Gene R. Hodges 3,439 1.9% $42.4375 07/19/2003 13,859
Kerry E. Adams 3,281 1.8% $42.4375 07/19/2003 13,222
GULF
Douglas L. McCrary 7,406 4.1% $42.4375 05/01/1997 26,736
G. E. Holland, Jr. 2,920 1.6% $42.4375 07/19/2003 11,768
Earl B. Parsons, Jr. - - - - -
A. E. Scarbrough - - - - -
John E. Hodges, Jr. 2,289 1.3% $42.4375 07/19/2003 9,225
See next page for footnotes.
III-19
308
STOCK OPTION GRANTS IN 1993
INDIVIDUAL GRANTS GRANT DATE VALUE
# OF % OF TOTAL
SECURITIES OPTIONS EXERCISE
UNDERLYING GRANTED TO OR
OPTIONS EMPLOYEES IN BASE PRICE EXPIRATION GRANT DATE
NAME GRANTED(1) FISCAL YEAR(2) ($/SH)(1) DATE(1) PRESENT VALUE($)(3)
- ------------------------------------------------------------------------------------------------------------------------------------
MISSISSIPPI
David M. Ratcliffe 4,057 2.0% $42.4375 07/19/2003 16,350
Robert G. Dawson 2,390 1.3% $42.4375 07/19/2003 9,632
H. E. Blakeslee 2,384 1.2% $42.4375 07/19/2003 9,608
Don E. Mason - - - - -
Thomas A. Fanning - - - - -
SAVANNAH
A. M. Gignilliat, Jr. 3,599 2.0% $42.4375 09/03/2000 15,080
E. Olin Veale - - - - -
Larry M. Porter - - - - -
W. Miles Greer - - - - -
James L. Rayburn - - - - -
- ----------------------------------
(1) Grants were made on July 19, 1993, and vest 25% per year on the anniversary
date of the grant. Grants fully vest upon termination incident to death,
disability, or retirement. The exercise price is the average of the high and
low fair market value of SOUTHERN's common stock on the date granted. In
accordance with the terms of the Executive Stock Plan, Mr. Jones' unexercised
options expire on April 1, 1998, three years after his normal retirement date;
Mr. McCrary's unexercised options expire on May 1, 1997, three years after his
normal retirement date; and Mr. Gignilliat's unexercised options expire on
September 3, 2000, three years after his normal retirement date.
(2) A total of 179,746 stock options were granted in 1993 to key executives
participating in SOUTHERN's Executive Stock Plan.
(3) Based on the Black-Scholes option valuation model. The actual value, if
any, an executive officer may realize ultimately depends on the market value of
SOUTHERN's common stock at a future date. This valuation is provided pursuant
to SEC disclosure rules and there is no assurance that the value realized will
be at or near the value estimated by the Black-Scholes model. Assumptions used
to calculate this value: price volatility - 12.45%; risk-free rate of return -
5.81%; dividend yield - 5.37%; and time to exercise - ten years.
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AGGREGATED STOCK OPTION EXERCISES IN 1993 AND YEAR-END OPTION VALUES
(C) AGGREGATED STOCK OPTION EXERCISES. The following table sets forth
information concerning options exercised during the year ending December 31,
1993, by the named executive officers and the value of unexercised options held
by them as of December 31, 1993. The number of SOUTHERN common shares shown
and the per share exercise price and market price do not reflect the stock
distribution resulting from the two-for-one common stock split approved by
SOUTHERN's board of directors in January, 1994.
NUMBER OF
SECURITIES VALUE OF
UNDERLYING UNEXERCISED
UNEXERCISED IN-THE-MONEY
OPTIONS AT OPTIONS AT
YEAR-END (#) YEAR-END($)(1)
SHARES ACQUIRED VALUE EXERCISABLE/ EXERCISABLE/
NAME ON EXERCISE (#) REALIZED($)(2) UNEXERCISABLE UNEXERCISABLE
- ---------------------------------------------------------------------------------------------------------
ALABAMA
Elmer B. Harris - - 14,215/37,398 211,494/330,107
Travis J. Bowden - - 5,763/15,708 84,560/128,730
Banks H. Farris - - 863/5,741 6,850/22,875
T. H. Jones - - 848/5,581 6,731/25,318
W. B. Hutchins, III - - 706/5,068 5,604/21,802
GEORGIA
A. W. Dahlberg 14,211 252,088 4,278/43,871 33,957/400,435
Dwight H. Evans 3,982 57,454 0/10,380 0/91,239
Warren Y. Jobe 4,741 75,241 0/11,934 0/101,456
Gene R. Hodges 3,449 52,973 0/9,287 0/81,520
Kerry E. Adams 3,257 49,639 0/8,742 0/75,346
GULF
D. L. McCrary - - 9,668/21,814 149,219/203,868
G. E. Holland, Jr. - - 698/5,017 5,540/21,572
Earl B. Parsons, Jr. 700 11,769 - -
A. E. Scarbrough - - - -
John E. Hodges, Jr. - - 5,429/6,008 89,119/50,535
See next page for footnotes.
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AGGREGATED STOCK OPTION EXERCISES IN 1993 AND YEAR-END OPTION VALUES
NUMBER OF
SECURITIES VALUE OF
UNDERLYING UNEXERCISED
UNEXERCISED IN-THE-MONEY
OPTIONS AT OPTIONS AT
YEAR-END (#) YEAR-END($)(1)
SHARES ACQUIRED VALUE EXERCISABLE/ EXERCISABLE/
NAME ON EXERCISE (#) REALIZED($)(2) UNEXERCISABLE UNEXERCISABLE
- ------------------------------------------------------------------------------------------------------------------------------------
MISSISSIPPI
David M. Ratcliffe 2,996 58,422 5,643/10,871 83,817/93,954
Robert G. Dawson - - 0/2,390 0/4,033
H. E. Blakeslee 2,310 36,298 660/6,677 5,239/59,535
Don E. Mason - - - -
Thomas A. Fanning - - - -
SAVANNAH
A. M. Gignilliat, Jr. - - 8,556/10,502 136,063/97,250
E. Olin Veale - - - -
Larry M. Porter - - - -
W. Miles Greer - - - -
James L. Rayburn - - - -
(1) This represents the excess of the fair market value of SOUTHERN's common
stock of $44.125 per share, as of December 31, 1993, above the exercise price
of the options. One column reports the "value" of options that are vested and
therefore could be exercised; the other "value" of options that are not vested
and therefore could not be exercised as of December 31, 1993.
(2) The "Value Realized" is ordinary income, before taxes, and represents the
amount equal to the excess of the fair market value of the shares at the time
of exercise over the exercise price.
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LONG-TERM INCENTIVE PLANS - AWARDS IN 1993
(D) LONG-TERM INCENTIVE PLANS. The following table sets forth the
long-term incentive plan awards made to the named executive officers for the
performance period January 1, 1993 through December 31, 1996.
ESTIMATED FUTURE PAYOUTS UNDER
NON-STOCK PRICE-BASED PLANS
------------------------------
NUMBER PERFORMANCE OR
OF OTHER PERIOD
UNITS UNTIL MATURATION THRESHOLD TARGET MAXIMUM
NAME (#)(1) OR PAYOUT ($)(2) ($)(2) ($)(2)
- ------------------------------------------------------------------------------------------------------------------
ALABAMA
Elmer B. Harris 234,145 4 years 117,073 234,145 292,681
Travis J. Bowden 78,536 4 years 39,268 78,536 98,170
Banks H. Farris 39,883 4 years 19,942 39,883 49,854
T. Harold Jones 36,401 4 years 18,201 36,401 45,501
W. B. Hutchins, III 36,401 4 years 18,201 36,401 45,501
GEORGIA
A. W. Dahlberg 265,675 4 years 132,838 265,675 332,094
Dwight H. Evans 54,574 4 years 27,287 54,574 68,218
Warren Y. Jobe 54,574 4 years 27,287 54,574 68,218
Gene R. Hodges 39,883 4 years 19,942 39,883 49,854
Kerry E. Adams 39,883 4 years 19,942 39,883 49,854
GULF
D. L. McCrary 118,364 4 years 59,182 118,364 147,955
G. E. Holland, Jr. 36,401 4 years 18,201 36,401 45,501
E. B. Parsons, Jr. 24,947 4 years 12,474 24,947 31,184
A. E. Scarbrough 24,947 4 years 12,474 24,947 31,184
J. E. Hodges, Jr. 36,401 4 years 18,201 36,401 45,501
See next page for footnotes.
III-23
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LONG-TERM INCENTIVE PLANS - AWARDS IN 1993
ESTIMATED FUTURE PAYOUTS UNDER
NON-STOCK PRICE-BASED PLANS
------------------------------
NUMBER PERFORMANCE OR
OF OTHER PERIOD
UNITS UNTIL MATURATION THRESHOLD TARGET MAXIMUM
NAME (#)(1) OR PAYOUT ($)(2) ($)(2) ($)(2)
- ---------------------------------------------------------------------------------------------------------------
MISSISSIPPI
D. M. Ratcliffe 100,514 4 years 50,257 100,514 125,643
Robert G. Dawson 36,401 4 years 18,201 36,401 45,501
H. E. Blakeslee 36,401 4 years 18,201 36,401 45,501
Don E. Mason 24,947 4 years 12,474 24,947 31,184
Thomas A. Fanning 22,774 4 years 11,387 22,774 28,468
SAVANNAH
A. M. Gignilliat, Jr. 73,509 4 years 36,755 73,509 91,886
E. Olin Veale 24,947 4 years 12,474 24,947 31,184
Larry M. Porter 22,774 4 years 12,387 22,774 28,468
W. Miles Greer 13,999 4 years 7,000 13,999 17,499
James L. Rayburn 12,896 4 years 6,448 12,896 16,120
(1) A performance unit is a method of asigning a dollar value to a performance
award opportunity. The actual number of units granted to a participant will be
based on an award percentage of an individual's base salary range control
mid-point over the performance period. For illustration purposes, the base
salary range mid-points have been projected at a four percent growth rate for
the four-year term.
(2) The threshold, target and maximum value of a unit is $0.50, $1.00, and
$1.25, respectively, and can vary based on SOUTHERN's return on common
equity relative to a selected group of electric and gas utilities in the
Southeastern United States. If certain minimum performance relative to the
selected group is not achieved, there will be no payout; nor is there a payout
if the current earnings of SOUTHERN are not sufficient to fund the dividend rate
paid in the last calendar year. All awards are payable in cash at the end of
the performance period.
III-24
313
PENSION PLAN TABLE
(e)(1) The following table sets forth the estimated combined annual pension
benefits under the pension and supplemental defined benefit plans in effect
during 1993 for ALABAMA, GEORGIA, GULF and MISSISSIPPI. Employee compensation
covered by the pension and supplemental benefit plans for pension purposes is
limited to the average of the highest three of the final 10 years' base salary
and wages (reported under column titled "Salary" in the Summary Compensation
Tables on pages III-13 through III-18).
The amounts shown in the table were calculated according to the final
average pay formula and are based on a single life annuity without reduction
for joint and survivor annuities (although married employees are required to
have their pension benefits paid in one of various joint and survivor annuity
forms, unless the employee elects otherwise with the spouse's consent) or
computation of the Social Security offset which would apply in most cases.
This offset amounts to one-half of the estimated Social Security benefit
(primary insurance amount) in excess of $3,000 per year times the number of
years of accredited service, divided by the total possible years of accredited
service to normal retirement age.
YEARS OF ACCREDITED SERVICE
REMUNERATION 15 20 25 30 35 40
- ------------ -------------------------------------------------------------------------------
$ 50,000 $ 12,750 $ 17,000 $ 21,250 $ 25,500 $ 29,750 $ 34,000
$100,000 25,500 34,000 42,500 51,000 59,500 68,000
$300,000 76,500 102,000 127,500 153,000 178,500 204,000
$500,000 127,500 170,000 212,500 255,000 297,500 340,000
$700,000 178,500 238,000 297,500 357,000 416,500 476,000
$850,000 216,750 289,000 361,250 433,500 505,750 578,000
As of December 31, 1993, the applicable compensation levels and years of
accredited service are presented in the following tables:
ALABAMA
COMPENSATION
NAME LEVEL YEARS OF SERVICE
---- ------------ ----------------
Harris $415,980 29
Bowden 255,180 17
Farris 174,396 34
Jones 169,116 41
Hutchins 163,644 23
III-25
314
GEORGIA
COMPENSATION
NAME LEVEL YEARS OF SERVICE
---- ------------ ----------------
Dahlberg $474,012 33
Evans 209,076 24
Jobe 208,896 22
Hodges 187,716 29
Adams 182,160 29
GULF
COMPENSATION
NAME LEVEL YEARS OF SERVICE
---- ------------ ----------------
McCrary $302,352 39
Holland 160,404 11(1)
Parsons 156,684 32
Scarbrough 149,208 30
Hodges 140,880 27
MISSISSIPPI
COMPENSATION
NAME LEVEL YEARS OF SERVICE
---- ------------ ----------------
Ratcliffe $209,352 21
Dawson 144,900 25
Blakeslee 147,576 27
Mason 142,200 27
Fanning 113,712 12
SAVANNAH has in effect a qualified, trusteed, noncontributory, defined
benefit pension plan which provides pension benefits to employees upon
retirement at the normal retirement age after designated periods of accredited
service and at a specified compensation level. The plan provides pension
benefits under a formula which includes each participant's years of service
with the Southern system and average annual earnings of the highest three of
the final ten years of service with the Southern system preceding retirement.
Plan benefits are reduced by a portion of the benefits participants are
entitled to receive under Social Security. The plan provides for reduced early
retirement benefits at age 55 and a pension for the surviving spouse equal to
one-half of the deceased retiree's pension.
The following table sets forth the estimated annual pension benefits
under the pension plan in effect during 1993 which are payable by SAVANNAH to
employees upon retirement at the normal retirement age after designated periods
of accredited service and at a specified compensation level.
(1)The number of accredited years of service includes ten years credited to Mr.
Holland pursuant to a supplemental pension agreement.
III-26
315
ANNUAL BENEFITS EXCLUSIVE OF SOCIAL SECURITY(1)
AVERAGE ANNUAL SALARY YEARS OF SERVICE
FOR LAST 36 MONTHS OF -----------------------------------------------
EMPLOYMENT 15 25 35
- --------------------- -- -- --
$ 90,000 $22,505 $37,508 $ 52,511
120,000 30,006 50,010 70,014
150,000 37,508 62,513 87,518
180,000 45,009 75,015 105,021
200,000 50,010 83,350 116,690
230,000 57,512 95,853 134,194
As of December 31, 1993, the applicable compensation levels and years of
accredited service is presented in the following table:
SAVANNAH
COMPENSATION
NAME LEVEL YEARS OF SERVICE
---- ------------- ----------------
Gignilliat $180,077 35
Veale 144,404 38
Porter 102,500 16
Greer 107,750 9
Rayburn 97,605 26
(e)(2) DEFERRED COMPENSATION PLAN; SUPPLEMENTAL EXECUTIVE
RETIREMENT PLAN.
SAVANNAH has in effect a voluntary deferred compensation plan for certain
executive employees pursuant to which such employees may defer a portion of
their respective annual salaries. In addition, SAVANNAH has a supplemental
executive retirement plan for certain of its executive employees which became
effective January 1, 1984. The deferred compensation plan is designed to
provide supplemental retirement or survivor benefit payments. The supplemental
executive retirement plan is also designed to provide retiring executives of
SAVANNAH with a supplemental retirement benefit, which, in conjunction with
social security and benefits under SAVANNAH's qualified pension plan, will
equal 70 percent of the highest three of the final ten years average annual
compensation (including deferrals under the deferred compensation plan). Both
of these plans are unfunded and the liability is payable from general funds of
SAVANNAH. The deferred compensation plan became effective December 1, 1983,
and all of SAVANNAH's executive officers are participating in the plan. In
addition, all executives are participating in the supplemental executive
retirement plan.
In order to provide for its liabilities under the deferred compensation
plan and the supplemental executive retirement plan, SAVANNAH has purchased
life insurance on participating executive employees in actuarially determined
amounts which, based upon assumptions as to mortality experience, policy
dividends, tax effects, and other factors which, if realized, along with
compensation deferred by employees and the death benefits payable to
(1) The plan benefits are subject to the maximum benefit limitations set forth
in Section 415 of the Internal Revenue Code.
III-27
316
SAVANNAH, are expected to cover all such insurance premium payments, and all
benefit payments to participants, plus a factor for the cost of funds of
SAVANNAH.
(f) COMPENSATION OF DIRECTORS.
(1) Standard Arrangements. The following table presents compensation
paid to the directors, during 1993 for service as a member of the board of
directors and any board committee(s), except that employee directors received
no fees or compensation for service as a member of the board of directors or
any board committee. All or a portion of these fees may be deferred until
membership on the board is terminated.
ALABAMA GEORGIA GULF MISSISSIPPI SAVANNAH
RETAINER FEE $15,000 $18,000 $8,000 $8,000 $8,000
MEETING FEE 800 900 500 500 500
COMMITTEES:
Audit 800 900 500 500 500(1)
Compensation 800 900 500 500 500(1)
Corporate Governance(2) - 900 - - -
Executive 800 900 - - 500(1,3)
Finance - 900 - 500 -
Nominating 800 - - - -
Nuclear Safety 800 - - - -
Nuclear
Operations
Overview - 1,800 - - -
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH also provide
retirement benefits to non-employee directors who are credited with a minimum
of 60 months of service on the board of directors of one or more system
companies, under the Outside Directors Pension Plan. Eligible directors are
entitled to benefits under the Plan upon retirement from the board on the
retirement date designated in the respective companies by-laws. The annual
benefit payable ranges from 75 to 100 percent of the annual retainer fee in
effect on the date of retirement, based upon length of service. Payments
continue for the greater of the lifetime of the participant or 10 years.
(2) Other Arrangements. No director received other compensation for
services as a director during the year ending December 31, 1993 in addition to
or in lieu of that specified by the standard arrangements specified above.
(1) Committee Chairmen receive an additional $500 per year fee.
(2) Established for period September 15, 1993 through May 31, 1994.
(3) Chairman of Executive Committee receives an additional $3,000 per month fee.
III-28
317
(g) EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE IN
CONTROL ARRANGEMENTS.
None.
(h) REPORT ON REPRICING OF OPTIONS.
None.
(i) ADDITIONAL INFORMATION WITH RESPECT TO COMPENSATION COMMITTEE
INTERLOCKS AND INSIDER PARTICIPATION IN COMPENSATION DECISION.
ALABAMA
Elmer B. Harris serves on the Compensation Committee of AmSouth
Bancorporation. John W. Woods, a director of ALABAMA is an executive
officer of AmSouth Bancorporation.
GULF
Messrs. Paul J. DeNicola and Douglas L. McCrary are ex officio
members of its Compensation Committee.
III-29
318
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(A) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS.
SOUTHERN is the beneficial owner of 100% of the outstanding common
stock of registrants ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH.
Amount and
Name and Address Nature of Percent
of Beneficial Beneficial of
Title of Class Owner Ownership Class
- -------------- ---------------- ---------- -------
Common Stock The Southern Company 100%
64 Perimeter Center East
Atlanta, Georgia 30346
REGISTRANTS:
------------
ALABAMA 5,608,955
GEORGIA 7,761,500
GULF 992,717
MISSISSIPPI 1,121,000
SAVANNAH 10,844,635
(B) SECURITY OWNERSHIP OF MANAGEMENT. The following table shows
the number of shares of SOUTHERN common stock and operating subsidiary
preferred stock owned by the directors, nominees and executive officers as of
December 31, 1993. It is based on information furnished by the directors,
nominees and executive officers. The shares owned by all directors, nominees
and executive officers as a group constitute less than one percent of the total
number of shares of the respective classes outstanding on December 31, 1993.
The number of SOUTHERN common shares shown do not reflect the stock
distribution resulting from the two-for-one common stock split approved by
SOUTHERN'S board of directors in January, 1994.
NAME OF DIRECTOR, NUMBER OF SHARES
NOMINEES AND BENEFICIALLY
EXECUTIVE OFFICERS TITLE OF CLASS OWNED 1,2
- ------------------ -------------- ---------------------------
ALABAMA
Edward L. Addison SOUTHERN Common 125,032
Whit Armstrong SOUTHERN Common 7,410
Travis Bowden SOUTHERN Common 16,185
Bill M. Guthrie SOUTHERN Common 23,003
Elmer B. Harris SOUTHERN Common 35,545
III-30
319
NAME OF DIRECTOR, NUMBER OF SHARES
NOMINEES AND BENEFICIALLY
EXECUTIVE OFFICERS TITLE OF CLASS OWNED 1,2
- ------------------ -------------- --------------------------
Crawford T. Johnson, III SOUTHERN Common 286
Carl E. Jones, Jr. SOUTHERN Common 3,945
Gerald H. Powell SOUTHERN Common 2,000
John W. Rouse, Jr. SOUTHERN Common 1,688
William J. Rushton, III SOUTHERN Common 3,000
ALABAMA Preferred 20
John C. Webb, IV SOUTHERN Common 3,660
ALABAMA Preferred 985
Louis J. Willie SOUTHERN Common 1,587
ALABAMA Preferred 391
GEORGIA Preferred 200
GULF Preferred 50
Banks H. Farris SOUTHERN Common 15,693
William B. Hutchins, III SOUTHERN Common 9,458
Thomas H. Jones SOUTHERN Common 21,029
The directors, nominees,
and executive officers
as a group SOUTHERN Common 275,837 shares
ALABAMA Preferred 1,376 shares
GEORGIA Preferred 200 shares
GULF Preferred 50 shares
GEORGIA
Edward L. Addison SOUTHERN Common 125,032
W. P. Copenhaver SOUTHERN Common 1,350
A. W. Dahlberg SOUTHERN Common 29,287
W. A. Fickling, Jr. GEORGIA Preferred 50
L. G. Hardman, III SOUTHERN Common 3,053
III-31
320
NAME OF DIRECTOR, NUMBER OF SHARES
NOMINEES AND BENEFICIALLY
EXECUTIVE OFFICERS TITLE OF CLASS OWNED 1,2
- ------------------ -------------- --------------------------
Warren Y. Jobe SOUTHERN Common 12,824
GEORGIA Preferred 203
James R. Lientz, Jr. SOUTHERN Common 21
W. A. Parker, Jr. SOUTHERN Common 16,822
GEORGIA Preferred 2
Gloria M. Shatto SOUTHERN Common 6,003
W. J. Vereen SOUTHERN Common 2,500
GEORGIA Preferred 1,701
Kerry E. Adams SOUTHERN Common 8,963
GEORGIA Preferred 200
Dwight E. Evans SOUTHERN Common 7,495
GEORGIA Preferred 100
Gene R. Hodges SOUTHERN Common 11,678
GEORGIA Preferred 800
The directors, nominees
and executive officers
as a group SOUTHERN Common 270,626 shares
GEORGIA Preferred 3,256 shares
GULF
Paul J. DeNicola SOUTHERN Common 10,846
W. Deck Hull, Jr. SOUTHERN Common 957
Douglas L. McCrary SOUTHERN Common 31,298
Joseph K. Tannehill SOUTHERN Common 2,000
J. E. Hodges, Jr. SOUTHERN Common 14,242
GULF Preferred 3
G. Edison Holland, Jr. SOUTHERN Common 807
III-32
321
NAME OF DIRECTOR, NUMBER OF SHARES
NOMINEES AND BENEFICIALLY
EXECUTIVE OFFICERS TITLE OF CLASS OWNED 1,2
- ------------------ -------------- -------------------------
Earl B. Parsons, Jr. SOUTHERN Common 7,200
A. E. Scarbrough SOUTHERN Common 9,216
GULF Preferred 100
MISSISSIPPI Preferred 5
The directors, nominees SOUTHERN Common 78,488 shares
and executive officers GULF Preferred 105 shares
as a group MISSISSIPPI Preferred 5 shares
MISSISSIPPI
Paul J. DeNicola SOUTHERN Common 10,846
Edwin E. Downer SOUTHERN Common 322
Robert S. Gaddis SOUTHERN Common 1,547
Walter H. Hurt, III SOUTHERN Common 200
MISSISSIPPI Preferred 33
Aubrey K. Lucas SOUTHERN Common 416
Earl D. McLean, Jr. SOUTHERN Common 7,051
David M. Ratcliffe SOUTHERN Common 11,363
Leo W. Seal, Jr. SOUTHERN Common 1,000
Gerald J. St. Pe SOUTHERN Common 8,000
H. E. Blakeslee SOUTHERN Common 4,102
Robert G. Dawson SOUTHERN Common 7,660
Thomas A. Fanning SOUTHERN Common 1,827
Don E. Mason SOUTHERN Common 8,499
The directors, nominees
and executive officers SOUTHERN Common 62,834 shares
as a group MISSISSIPPI Preferred 33 shares
III-33
322
NAME OF DIRECTOR, NUMBER OF SHARES
NOMINEES AND BENEFICIALLY
EXECUTIVE OFFICERS TITLE OF CLASS OWNED 33,34
- ------------------ -------------- ------------------------
SAVANNAH
Helen Quattlebaum Artley SOUTHERN Common 1,209
Paul J. DeNicola SOUTHERN Common 10,846
A. M. Gignilliat, Jr. SOUTHERN Common 18,134
Walter D. Gnann SOUTHERN Common 735
Robert B. Miller, III SOUTHERN Common 982
John C. Monroe SOUTHERN Common 420
John M. McIntosh SOUTHERN Common 7,016
James M. Piette SOUTHERN Common 563
Arnold M. Tenenbaum SOUTHERN Common 177
E. Olin Veale SOUTHERN Common 5,319
Fred F. Williams SOUTHERN Common 1,079
W. Miles Greer SOUTHERN Common 504
Larry M. Porter SOUTHERN Common 5,244
The directors, nominees
and executive officers
as a group SOUTHERN Common 52,228 shares
(1) As used in this table, "beneficial ownership" means the sole or shared
power to vote, or to direct the voting of, a security and/or investment power
with respect to a security (i.e., the power to dispose of, or to direct the
disposition of, a security).
(2) The shares shown include shares of common stock of which certain
directors and executive officers have the right to acquire beneficial
ownership within 60 days pursuant to the Executive Stock Plan, as follows:
Mr. Addison, 86,357 shares; Mr. Blakeslee, 660 shares; Mr. Bowden, 5,763
shares; Mr. Dahlberg, 4,278 shares; Mr. Farris, 863 shares; Mr. Gignilliat,
8,556 shares; Mr. Guthrie 15,720 shares; Mr. Harris, 14,215 shares; Mr.
Haubein, 835 shares; Mr. Hodges, 5,429 shares; Mr. Holland, 698 shares; Mr.
Hutchins, 706 shares; Mr. Jones, 848 shares; Mr. Klappa, 671 shares, Mr. C. D.
McCrary, 691 shares; Mr. D. L. McCrary, 9,668 shares; and Mr. Ratcliffe,
5,643 shares. Also included are shares of SOUTHERN common stock held by
the spouses of the following directors: Mr. Addison, 670 shares; Mr.
Copenhaver, 350 shares; Mr. Harris, 155 shares; Mr. Parker, 22 shares; and Dr.
Shatto, 5,067 shares.
III-34
323
(C) CHANGES IN CONTROL. The operating affiliates know of no
arrangements which may at a subsequent date result in any change in control.
GEORGIA'S Mr. Russell failed to file on a timely basis a single report
disclosing one transaction on Form 4 as required by Section 16 of the
Securities Exchange Act of 1934.
MISSISSIPPI'S Messrs. McLean, Jr., Hurt and Seal, Jr. each failed to
file on a timely basis a single report disclosing one transaction on Form 4 as
required by Section 16 of the Securities Exchange Act of 1934.
SAVANNAH'S Mr. Gnann failed to file on a timely basis a single report
disclosing one transaction on Form 4 as required by Section 16 of the
Securities Exchange Act of 1934.
MR. DENICOLA, a director of GULF, MISSISSIPPI and SAVANNAH, failed to
file on a timely basis a single report, disclosing one transaction on Form 4 as
required by Section 16 of the Securities Exchange Act of 1934.
III-35
324
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ALABAMA
(a) Transactions with management and others.
During 1993, ALABAMA, in the ordinary course of business, paid premiums
amounting to approximately $400,000 for various types of insurance policies
purchased from Protective Life Insurance Company, a subsidiary of Protective
Life Corporation, a company in which Mr. William J. Rushton, III, a director of
ALABAMA, owns an interest and of which he serves as Chairman.
The firm of Inzer, Stivender, Haney & Johnson, P.A., performed certain legal
services for ALABAMA during 1993. Mr. James C. Inzer, Jr., partner in this
firm, is also a director of ALABAMA.
ALABAMA purchased automobiles and parts in the amount of approximately
$200,000 from companies in which Mr. Blount, a director of ALABAMA, owns 85%
interests.
ALABAMA purchased electrical supplies in the amount of approximately
$200,000 from L & K Electric Supply Company, Ltd. during 1993. Mr. Willie,
director of ALABAMA and SOUTHERN, owns an interest in and serves as president
of this firm.
ALABAMA believes that these transactions have been on terms representing
competitive market prices that are no less favorable than those available from
others.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
None.
GEORGIA
(a) Transactions with management and others.
In 1993, GEORGIA was indebted in a maximum amount of $105 million to
Wachovia Bank and its affiliates, of which G. Joseph Prendergast serves as
President and Chief Executive Officer of Wachovia Corporation of Georgia and
Wachovia Bank of Georgia, N.A.
In 1993, GEORGIA was indebted in a maximum amount of $285 million to
NationsBank and its affiliates of which Mr. James R. Lientz, Jr. serves as
President of NationsBank of Georgia.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
None.
GULF
(a) Transactions with management and others.
The firm of Beggs & Lane, P.A. serves as local counsel for GULF and received
from GULF approximately $800,000 for services rendered. Mr. G. Edison Holland,
Jr. is a partner in the firm and also serves as Vice President and Corporate
Counsel of GULF.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
None.
MISSISSIPPI
(a) Certain business relationships.
During 1993, MISSISSIPPI was indebted in a maximum amount of $12.4 million
to Hancock Bank, of which Leo W. Seal, Jr. serves as Chairman of the Board and
Chief Executive Officer.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
III-36
325
(d) Transactions with promoters.
None.
SAVANNAH
(a) Transactions with management and others.
Mr. Tenenbaum is a Director of First Union national Bank of Georgia, and Mr.
Foster is President of NationsBank of Georgia, N.A., in Savannah. During 1993,
these banks furnished a number of regular banking services in the ordinary
course of business to SAVANNAH. SAVANNAH intends to maintain normal banking
relations with all of the aforesaid banks in the future.
(b) Certain business relationships.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
None.
III-37
326
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report on this
Form 10-K:
(1) Financial Statements:
Reports of Independent Public Accountants on the financial
statements for SOUTHERN and Subsidiary Companies, ALABAMA,
GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed under Item
8 herein.
The financial statements filed as a part of this report for
SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF,
MISSISSIPPI and SAVANNAH are listed under Item 8 herein.
(2) Financial Statement Schedules:
Reports of Independent Public Accountants as to Schedules for
SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF,
MISSISSIPPI and SAVANNAH are included herein on pages IV-12
through IV-17.
Financial Statement Schedules for SOUTHERN and Subsidiary
Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
are listed in the Index to the Financial Statement Schedules
at page S-1.
(3) Exhibits:
Exhibits for SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH are listed in the Exhibit Index at page E-1.
(b) Reports on Form 8-K: During the fourth quarter of 1993 the
registrants filed Current Reports on Form 8-K as follows:
ALABAMA filed Forms 8-K dated October 27, 1993, and November 16,
1993, to facilitate security sales.
GEORGIA filed a Form 8-K dated October 20, 1993, to facilitate a
security sale.
GULF filed a Form 8-K dated November 3, 1993, to facilitate a
security sale.
SAVANNAH filed a Form 8-K dated November 9, 1993, to facilitate a
security sale.
IV-1
327
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.
THE SOUTHERN COMPANY
By Edward L. Addison, Chairman
By Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 25, 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.
Edward L. Addison
Chairman of the Board
(Principal Executive Officer)
W. L. Westbrook
Financial Vice President
(Principal Financial and Accounting Officer)
Directors:
W. P. Copenhaver John M. McIntosh.
A. W. Dahlberg Earl D. McLean, Jr.
Paul J. DeNicola William A. Parker
Jack Edwards William J. Rushton, III
H. Allen Franklin Gloria M. Shatto
L. G. Hardman, III Herbert Stockham
Elmer B. Harris Louis J. Willie
By Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
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.
ALABAMA POWER COMPANY
By Elmer B. Harris, President
By Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 25, 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.
Elmer B. Harris
President, Chief Executive Officer and Director
(Principal Executive Officer)
Charles D. McCrary
Senior Vice President
(Principal Financial Officer)
David L. Whitson
Vice President and Comptroller
(Principal Accounting Officer)
Directors:
Edward L. Addison William V. Muse
Whit Armstrong John T. Porter
Philip E. Austin Gerald H. Powell
Margaret A. Carpenter Robert D. Powers
Peter V. Gregerson, Sr. John W. Rouse
Bill M. Guthrie James H. Sanford
Crawford T. Johnson, III John Cox Webb, IV
Carl E. Jones, Jr. Louis J. Willie
Wallace D. Malone, Jr. John W. Woods
By Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
IV-2
328
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.
GEORGIA POWER COMPANY
By H. Allen Franklin, President
By Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 25, 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.
H. Allen Franklin
President, Chief Executive Officer and Director
(Principal Executive Officer)
Warren Y. Jobe
Executive Vice President,
Treasurer, Chief Financial Officer and Director
(Principal Financial Officer)
C. B. Harreld
Vice President and Comptroller
(Principal Accounting Officer)
Directors:
Edward L. Addison G. Joseph Prendergast
Bennett A. Brown Herman J. Russell
William P. Copenhaver Gloria M. Shatto
A. W. Dahlberg Robert Strickland
William A. Fickling, Jr. William Jerry Vereen
L. G. Hardman, III Thomas R. Williams
James R. Lientz, Jr.
By Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
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 POWER COMPANY
By D. L. McCrary, Chairman of the Board
By Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 25, 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.
D. L. McCrary
Chairman of the Board and Chief Executive Officer
(Principal Executive Officer)
A. E. Scarbrough
Vice President - Finance
(Principal Financial and Accounting Officer)
Directors:
Reed Bell
Travis J. Bowden
Paul J. DeNicola
Fred C. Donovan
W. D. Hull, Jr.
C. W. Ruckel
J. K. Tannehill
By Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 25,1994
IV-3
329
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 COMPANY
By David M. Ratcliffe, President
By Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 25, 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.
David M. Ratcliffe
President, Chief Executive Officer and Director
(Principal Executive Officer)
Thomas A. Fanning
Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
Directors:
Paul J. DeNicola
Edwin E. Downer
Robert S. Gaddis
Walter H. Hurt, III
Aubrey K. Lucas
Earl D. McLean, Jr.
Gerald J. St. Pe'
Leo W. Seal, Jr.
N. Eugene Warr
By Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
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.
SAVANNAH ELECTRIC AND POWER COMPANY
By Arthur M. Gignilliat, Jr., President
By Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 25, 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.
Arthur M. Gignilliat, Jr.
President, Chief Executive Officer and Director
(Principal Executive Officer)
Kirby R. Willis
Vice President, Treasurer and
Chief Financial Officer
(Principal Financial and Accounting Officer)
Directors:
Helen Q. Artley
Paul J. DeNicola
Brian R. Foster
Walter D. Gnann
John M. McIntosh
Robert B. Miller, III
James M. Piette
Arnold M. Tenenbaum
Frederick F. Williams, Jr.
By Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 25, 1994
IV-4
330
EXHIBIT 21. SUBSIDIARIES OF THE REGISTRANTS.
Common Stock
Jurisdiction of Owned by
Name of Company Organization Southern
--------------------------------------------------- --------------- ------------
ALABAMA POWER COMPANY Alabama 100%
Alabama Property Company Alabama (1)
Columbia Fuels, Inc. Alabama (1)
GEORGIA POWER COMPANY Georgia 100
Piedmont-Forrest Corporation Georgia (2)
GULF POWER COMPANY Maine 100
MISSISSIPPI POWER COMPANY Mississippi 100
SAVANNAH ELECTRIC AND POWER COMPANY Georgia 100
SEI HOLDINGS, INC. Delaware 100
Asociados de Electricidad, S. A. Argentina (3)
SEI y Asociados de Argentina, S. A. Argentina (4)
Hidroelectrica Alicura, S. A. Argentina (5)
SEI HOLDINGS III, INC. Delaware 100
SEI Chile, S.A. Chile (6)
Empressa Electricia del Norte Grande, S.A. Chile (7)
SEI HOLDINGS IV, INC. Delaware 100
Inversores de Electricidad, S.A. Argentina (8)
SEI Inversora, S.A. Argentina (9)
SEI Bahamas Argentina I, Inc. Bahamas (8)
SEI Bahamas Argentina II, Inc. Bahamas (8)
Tesro Holding B.V. Netherlands (8)
SOUTHERN COMPANY SERVICES, INC. Alabama 100
SOUTHERN ELECTRIC BAHAMAS HOLDINGS, LTD. Bahamas 100
Southern Electric Bahamas, Ltd. Bahamas (10)
Freeport Power Company Limited Bahamas (11)
SOUTHERN ELECTRIC GENERATING COMPANY Alabama (12)
SOUTHERN ELECTRIC INTERNATIONAL, INC. Delaware 100
SEI Operadora de Argentina, S.A. Argentina (13)
SOUTHERN ELECTRIC RAILROAD COMPANY Delaware 100
SOUTHERN ELECTRIC WHOLESALE GENERATORS, INC. Delaware 100
Birchwood Development Corp. Delaware (14)
Birchwood Power Partners, L.P. Delaware (14)
SEI Birchwood, Inc. Delaware (14)
SEI Hawaiian Cogenerators, Inc. Delaware (14)
SOUTHERN NUCLEAR OPERATING COMPANY, INC. Delaware 100
THE SOUTHERN DEVELOPMENT AND INVESTMENT GROUP, INC. Georgia 100
(1) Owned by Alabama Power Company.
(2) Owned by Georgia Power Company.
(3) Owned by SEI Holdings, Inc.
(4) 94% owned jointly by Asociados de Electricidad, S. A. (14%) and SEI
Holdings, Inc. (80%)
(5) 59% owned by SEI y Asociados de Argentina, S. A.
(6) Owned by SEI Holdings III, Inc.
(7) 36% owned by SEI Chile, S. A.
(8) Owned by SEI Holdings IV, Inc.
(9) Owned jointly by Inversores de Electricidad, S. A. (15%) and SEI
Bahamas Argentina I, Inc. (85%)
(10) Owned by Southern Electric Bahamas Holdings, Ltd.
(11) 50% owned by Southern Electric Bahamas, Ltd.
(12) Owned equally by Alabama Power Company and Georgia Power Company.
(13) Owned by Southern Electric International, Inc.
(14) Owned by Southern Electric Wholesale Generators, Inc.
IV-5
331
ARTHUR ANDERSEN & CO.
Exhibit 23(a)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 1994 on the financial statements of The
Southern Company and its subsidiaries and the related financial statement
schedules, included in this Form 10-K, into The Southern Company's previously
filed Registration Statement File Nos. 2-78617, 33-3546, 33-23152, 33-30171,
33-23153 and 33-51433.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
March 25, 1994
IV-6
332
ARTHUR ANDERSEN & CO.
Exhibit 23(b)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 1994 on the financial statements of Alabama
Power Company and the related financial statement schedules, included in this
Form 10-K, into Alabama Power Company's previously filed Registration Statement
File No. 33-49653.
/s/ Arthur Andersen & Co.
Birmingham, Alabama
March 25, 1994
IV-7
333
ARTHUR ANDERSEN & CO.
Exhibit 23(c)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 1994 on the financial statements of Georgia
Power Company and the related financial statement schedules, included in this
Form 10-K, into Georgia Power Company's previously filed Registration Statement
File No. 33-49661.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
March 25, 1994
IV-8
334
ARTHUR ANDERSEN & CO.
Exhibit 23(d)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 1994 on the financial statements of Gulf
Power Company and the related financial statement schedules, included in this
Form 10-K, into Gulf Power Company's previously filed Registration Statement
File No. 33-50165.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
March 25, 1994
IV-9
335
ARTHUR ANDERSEN & CO.
Exhibit 23(e)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 1994 on the financial statements of
Mississippi Power Company and the related financial statement schedules,
included in this Form 10-K, into Mississippi Power Company's previously filed
Registration Statement File Nos. 33-49320 and 33-49649.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
March 25, 1994
IV-10
336
ARTHUR ANDERSEN & CO.
Exhibit 23(f)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 1994 on the financial statements of Savannah
Electric and Power Company and the related financial statement schedules,
included in this Form 10-K, into Savannah Electric and Power Company's
previously filed Registration Statement File Nos. 33-45757 and 33-52509.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
March 25, 1994
IV-11
337
ARTHUR ANDERSEN & CO.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To The Southern Company:
We have audited in accordance with generally accepted auditing standards,
the consolidated financial statements of The Southern Company and its
subsidiaries included in this Form 10-K, and have issued our report thereon
dated February 16, 1994. Our report on the consolidated financial statements
includes an explanatory paragraph which states that an uncertainty exists with
respect to the actions of the regulators regarding recoverability of the
investment in the Rocky Mountain pumped storage hydroelectric project, as
discussed in Note 4 to The Southern Company's consolidated financial
statements. Our audits were made for the purpose of forming an opinion on
those statements taken as a whole. The schedules listed under Item 14(a)(2)
herein as it relates to The Southern Company and its subsidiaries (pages S-2
and S-3, S-11 through S-14, S-35 through S-37, S-53, and S-59) are the
responsibility of The Southern Company's management and are presented for
purposes of complying with the Securities and Exchange Commission's rules and
are not part of the basic consolidated financial statements. These schedules
have been subjected to the auditing procedures applied in the audits of the
basic consolidated financial statements and, in our opinion, fairly state in
all material respects the financial data required to be set forth therein in
relation to the basic consolidated financial statements taken as a whole.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
February 16, 1994
IV-12
338
ARTHUR ANDERSEN & CO.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Alabama Power Company:
We have audited in accordance with generally accepted auditing standards,
the financial statements of Alabama Power Company included in this Form 10-K,
and have issued our report thereon dated February 16, 1994. Our audits were
made for the purpose of forming an opinion on those statements taken as a
whole. The schedules listed under Item 14(a)(2) herein as it relates to
Alabama Power Company (pages S-4, S-15 through S-18, S-38 through S-40, S-54,
and S-60) are the responsibility of Alabama Power Company's management and are
presented for purposes of complying with the Securities and Exchange
Commission's rules and are not part of the basic financial statements. These
schedules have been subjected to the auditing procedures applied in the audits
of the basic financial statements and, in our opinion, fairly state in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen & Co.
Birmingham, Alabama
February 16, 1994
IV-13
339
ARTHUR ANDERSEN & CO.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Georgia Power Company:
We have audited in accordance with generally accepted auditing standards,
the financial statements of Georgia Power Company included in this Form 10-K,
and have issued our report thereon dated February 16, 1994. Our report on the
financial statements includes an explanatory paragraph which states that an
uncertainty exists with respect to the actions of the regulators regarding the
recoverability of Georgia Power Company's investment in the Rocky Mountain
pumped storage hydroelectric project, as discussed in Note 4 to Georgia Power
Company's financial statements. Our audits were made for the purpose of
forming an opinion on those statements taken as a whole. The schedules listed
under Item 14(a)(2) herein as it relates to Georgia Power Company (pages S-5,
S-19 through S-22, S-41 through S-43, S-55, and S-61) are the responsibility
of Georgia Power Company's management and are presented for purposes of
complying with the Securities and Exchange Commission's rules and are not part
of the basic financial statements. These schedules have been subjected to the
auditing procedures applied in the audits of the basic financial statements
and, in our opinion, fairly state in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
February 16, 1994
IV-14
340
ARTHUR ANDERSEN & CO.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Gulf Power Company:
We have audited in accordance with generally accepted auditing standards,
the financial statements of Gulf Power Company included in this Form 10-K, and
have issued our report thereon dated February 16, 1994. Our audits were made
for the purpose of forming an opinion on those statements taken as a whole.
The schedules listed under Item 14(a)(2) herein as it relates to Gulf Power
Company (pages S-6, S-23 through S-26, S-44 through S-46, S-56, and S-62) are
the responsibility of Gulf Power Company's management and are presented for
purposes of complying with the Securities and Exchange Commission's rules and
are not part of the basic financial statements. These schedules have been
subjected to the auditing procedures applied in the audits of the basic
financial statements and, in our opinion, fairly state in all material respects
the financial data required to be set forth therein in relation to the basic
financial statements taken as a whole.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
February 16, 1994
IV-15
341
ARTHUR ANDERSEN & CO.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Mississippi Power Company:
We have audited in accordance with generally accepted auditing standards,
the financial statements of Mississippi Power Company included in this Form
10-K, and have issued our report thereon dated February 16, 1994. Our audits
were made for the purpose of forming an opinion on those statements taken as a
whole. The schedules listed under Item 14(a)(2) herein as it relates to
Mississippi Power Company (pages S-7 and S-8, S-27 through S-30, S-47 through
S-49, S-57, and S-63) are the responsibility of Mississippi Power Company's
management and are presented for purposes of complying with the Securities and
Exchange Commission's rules and are not part of the basic financial statements.
These schedules have been subjected to the auditing procedures applied in the
audits of the basic financial statements and, in our opinion, fairly state in
all material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
February 16, 1994
IV-16
342
ARTHUR ANDERSEN & CO.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Savannah Electric and Power Company:
We have audited in accordance with generally accepted auditing standards,
the financial statements of Savannah Electric and Power Company included in
this Form 10-K, and have issued our report thereon dated February 16, 1994.
Our audits were made for the purpose of forming an opinion on those statements
taken as a whole. The schedules listed under Item 14(a)(2) herein as it
relates to Savannah Electric and Power Company (pages S-9 and S-10, S-31
through S-34, S-50 through S-52, S-58, and S-64) are the responsibility of
Savannah Electric and Power Company's management and are presented for purposes
of complying with the Securities and Exchange Commission's rules and are not
part of the basic financial statements. These schedules have been subjected to
the auditing procedures applied in the audits of the basic financial statements
and, in our opinion, fairly state in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
February 16, 1994
IV-17
343
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page
- -------- ----
V Utility Plant, Including Intangibles
1993, 1992 and 1991
The Southern Company and Subsidiary Companies . . . . . . . . . . . . . . . . . . . . . . . . . S-2
Alabama Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-4
Georgia Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-5
Gulf Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-6
Mississippi Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-7
Savannah Electric and Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-9
VI Accumulated Provision for Depreciation of Utility Plant
1993, 1992 and 1991
The Southern Company and Subsidiary Companies . . . . . . . . . . . . . . . . . . . . . . . . . S-11
Alabama Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-15
Georgia Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-19
Gulf Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-23
Mississippi Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-27
Savannah Electric and Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-31
VIII Valuation and Qualifying Accounts and Reserves
1993, 1992 and 1991
The Southern Company and Subsidiary Companies . . . . . . . . . . . . . . . . . . . . . . . . . S-35
Alabama Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-38
Georgia Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-41
Gulf Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-44
Mississippi Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-47
Savannah Electric and Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-50
IX Short-Term Borrowings
1993, 1992 and 1991
The Southern Company and Subsidiary Companies . . . . . . . . . . . . . . . . . . . . . . . . . S-53
Alabama Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-54
Georgia Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-55
Gulf Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-56
Mississippi Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-57
Savannah Electric and Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-58
X Supplementary Income Statement Information
1993, 1992 and 1991
The Southern Company and Subsidiary Companies . . . . . . . . . . . . . . . . . . . . . . . . . S-59
Alabama Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-60
Georgia Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-61
Gulf Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-62
Mississippi Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-63
Savannah Electric and Power Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-64
Schedules I through XIV not listed above are omitted as not applicable or
not required. Columns omitted from schedules filed have been omitted because
the information is not applicable or not required.
S-1
344
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES
(STATED IN THOUSANDS OF DOLLARS)
Column F Column F Column F Column F
- -----------------------------------------------------------------------------------------------------
Balance at Balance at Balance at Balance at
End of End of End of End of
Classification 1990 1991 1992 1993
- -----------------------------------------------------------------------------------------------------
ELECTRIC PLANT-IN-SERVICE
Intangibles:
Organization $ 2,334 $ 2,101 $ 2,889 $ 4,665
Franchises & Consents 71 71 71 71
Miscellaneous 25,689 27,142 30,422 30,746
Production Plant:
Steam 7,511,289 7,848,674 7,882,552 7,854,330
Nuclear 5,820,402 5,902,360 5,911,852 5,930,141
Hydraulic 1,221,735 1,246,975 1,252,704 1,262,736
Other 149,372 148,151 150,490 151,378
Transmission Plant 2,824,596 2,954,395 3,092,940 3,224,009
Distribution Plant 5,737,724 6,091,816 6,430,557 6,847,653
General Plant:
Coal Mine Plant 5,866 5,865 5,865 5,865
Other 1,848,629 1,974,669 2,064,594 2,165,114
Nuclear Fuel, at Unamortized Cost:
Assemblies in Reactor 564,356 534,545 502,997 473,830
In-Process 93,559 54,838 34,226 24,171
Materials & Assemblies 9,611 23,154 17,557 2,663
Spent Nuclear Fuel 645,857 731,245 749,908 786,314
Construction Work in Progress 1,091,712 603,508 665,203 1,031,197
Plant Leased to Others 56,962 56,975 56,975 56,975
Plant Held for Future Use 41,977 38,419 40,136 40,152
Electric Plant Acquisition 59,289 52,835 52,612 44,391
Other Miscellaneous Plant 37,619 37,557 37,754 47,387
- -----------------------------------------------------------------------------------------------------
Total Electric Plant 27,748,649 28,335,295 28,982,304 29,983,788
STEAM HEAT PLANT:
Plant-in-Service 20,091 20,214 20,924 20,926
Work-in-Progress 74 181 33 43
- -----------------------------------------------------------------------------------------------------
TOTAL UTILITY PLANT $ 27,768,814 $28,355,690 $29,003,261 $30,004,757
=====================================================================================================
See Summary of Transactions and Notes on Page S-3
S-2
345
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES
(STATED IN THOUSANDS OF DOLLARS)
Total additions and total retirements for 1991, 1992 and 1993, as summarized
below, were each less than 10% of the total balances as of the respective
year-ends. Retirements include non-depreciable plant retirements and
unamortized portions of retirements to acquisition adjustments. There were no
additions to individual accounts in excess of two percent of total assets
other than transfers from Construction Work in Progress.
1991 1992 1993
------------------------------------------------
Gross Property Additions $ 1,123,021 $ 1,104,840 $ 1,440,603
Retirements 532,461 382,885 596,259
Other Changes (Note 1) (3,684) (74,384) 157,152
(NOTE 1) OTHER CHANGES INCLUDE THE FOLLOWING (STATED IN THOUSANDS OF DOLLARS)
1993
Acquisition of Freeport Power Company $ 112,793
GEORGIA adjustment to plant for taxes applicable to capitalized AFUDC debt 46,473
Miscellaneous amortizations, property reclassifications and adjustments (2,114)
------------
157,152
============
1992
Partial Sale of ALABAMA's Miller Steam Plant $ (61,960)
Miscellaneous amortizations, property reclassifications and adjustments (12,424)
------------
(74,384)
============
1991
Miscellaneous amortizations, property reclassifications and adjustments (3,684)
============
S-3
346
ALABAMA POWER COMPANY
SCHEDULE V -- UTILITY PLANT, INCLUDING INTANGIBLES
(STATED IN THOUSANDS OF DOLLARS)
- ---------------------------------------------------------------------------------------------------
Column F Column F Column F Column F
- ---------------------------------------------------------------------------------------------------
Balance at Balance at Balance at Balance at
End of End of End of End of
Classification 1990 1991 1992 1993
- ---------------------------------------------------------------------------------------------------
ELECTRIC PLANT-IN-SERVICE:
Intangibles:
Organization $ 342 $ 342 $ 1,213 $ 3,339
Production Plant:
Steam 2,462,098 2,991,874 2,953,681 2,987,008
Nuclear 1,794,540 1,851,317 1,860,832 1,860,842
Hydraulic 809,578 814,301 818,363 819,848
Other 2 2 2 2
Transmission Plant 925,368 977,239 1,013,464 1,051,130
Distribution Plant 1,815,265 1,947,972 2,072,165 2,206,834
General Plant:
Coal Mine Plant 3,636 3,635 3,635 3,635
Transportation Equipment 114,117 120,915 124,953 127,057
Other 526,170 572,832 601,445 647,876
Nuclear Fuel, at Unamortized Cost:
Assemblies in Reactor 225,067 220,083 198,486 192,392
In-Process 45,959 27,879 11,221 14,918
Spent Nuclear Fuel 591,866 638,114 716,722 758,110
Construction Work in Progress 654,055 148,564 164,555 225,743
Plant Held for Future Use 11,095 11,793 16,378 25,019
Electric Plant Acquisition Adjustment 4,857 4,431 4,028 3,625
- ---------------------------------------------------------------------------------------------------
Total Electric Plant 9,984,015 10,331,293 10,561,143 10,927,378
STEAM HEAT PLANT:
Plant-in-Service 20,091 20,214 20,924 20,926
Work-in-Progress 74 181 33 43
- ---------------------------------------------------------------------------------------------------
TOTAL UTILITY PLANT $ 10,004,180 $10,351,688 $10,582,100 $10,948,347
===================================================================================================
Total additions and total retirements for 1991, 1992 and 1993, as summarized
below, were each less than 10% of the total balances as of the respective
year-ends. Retirements below include non-depreciable plant retirements. There
were no additions to individual accounts in excess of two percent of total
assets other than transfers from Construction Work in Progress. Other changes
include a reduction to utility plant of $61,960,000 for the partial sale of
Miller Steam Plant in 1992.
1991 1992 1993
-----------------------------------------
Gross Property Additions $ 397,011 $ 367,463 $ 435,843
Retirements 53,739 66,477 65,353
Other Changes 4,236 (70,574) (4,243)
S-4
347
GEORGIA POWER COMPANY
SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES
(STATED IN THOUSANDS OF DOLLARS)
- -----------------------------------------------------------------------------------------------
Column F Column F Column F Column F
- -----------------------------------------------------------------------------------------------
Balance at Balance at Balance at Balance at
End of End of End of End of
Classification 1990 1991 1992 1993
- -----------------------------------------------------------------------------------------------
ELECTRIC PLANT-IN-SERVICE:
Intangibles:
Organization $ 214 $ 214 $ 364 $ 214
Franchises & Consents 70 70 70 70
Miscellaneous 22,989 24,049 27,018 27,232
Production Plant:
Steam 3,235,069 3,013,435 3,028,094 2,860,896
Nuclear 4,025,862 4,051,043 4,051,020 4,069,299
Hydraulic 412,157 432,674 434,341 442,888
Other 114,949 115,159 116,311 115,910
Transmission Plant 1,522,157 1,566,173 1,646,904 1,713,122
Distribution Plant 3,056,825 3,252,111 3,413,681 3,600,115
General Plant 744,488 772,839 798,784 823,534
Nuclear Fuel, at Unamortized Cost:
Assemblies in Reactor 339,289 314,462 304,511 281,438
In-Process 47,600 26,959 23,005 9,253
Materials & Assemblies 9,611 23,154 17,557 2,663
Spent Nuclear Fuel 53,991 93,131 33,186 28,204
Construction Work in Progress 370,243 390,732 405,606 584,013
Plant Held for Future Use 25,080 20,697 17,829 9,225
Electric Plant Acquisition 46,529 40,756 41,191 33,629
Other Miscellaneous Plant 37,619 37,557 37,754 47,387
- -----------------------------------------------------------------------------------------------
TOTAL UTILITY PLANT $ 14,064,742 $14,175,215 $14,397,226 $14,649,092
===============================================================================================
Total additions and total retirements for 1991, 1992 and 1993, as summarized
below, were each less than 10% of the total balances as of the respective
year-ends. Retirements include non-depreciable plant retirements and
unamortized portions of Plant Scherer acquisition adjustment retired for sales
in 1991 and 1993. There were no additions to individual accounts in excess
of two percent of total assets other than transfers from Construction Work in
Progress. Other changes for 1993, include an increase to plant of $46,473,000
for the taxes applicable to capitalized AFUDC debt.
1991 1992 1993
------------------------------------------
Gross Property Additions $ 548,051 $ 508,444 $ 674,432
Retirements 432,828 284,948 468,926
Other Changes (4,750) (1,485) 46,360
S-5
348
GULF POWER COMPANY
SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES
(STATED IN THOUSANDS OF DOLLARS)
- ----------------------------------------------------------------------------------------------
Column F Column F Column F Column F
- ----------------------------------------------------------------------------------------------
Balance at Balance at Balance at Balance at
End of End of End of End of
Classification 1990 1991 1992 1993
- ----------------------------------------------------------------------------------------------
ELECTRIC PLANT-IN-SERVICE:
Intangibles:
Organization $ 7 $ 7 $ 7 $ 7
Franchises & Consents 1 1 1 1
Production Plant:
Steam 813,266 833,496 837,280 858,972
Other 4,224 4,216 4,209 4,251
Transmission Plant 136,813 143,275 148,822 154,304
Distribution Plant 400,016 419,228 443,352 464,182
General Plant:
Transportation 16,216 16,530 17,865 20,474
Other 94,429 96,455 97,873 97,687
Construction Work in Progress 16,868 13,684 29,564 34,591
Plant Held for Future Use 4,503 4,689 4,689 4,689
Electric Plant Acquisition Adjustment 7,903 7,648 7,393 7,137
- ----------------------------------------------------------------------------------------------
TOTAL UTILITY PLANT $ 1,494,246 $1,539,229 $1,591,055 $ 1,646,295
==============================================================================================
Total additions and total retirements for 1991, 1992 and 1993, as summarized
below, were each less than 10% of the total balances as of the respective
year-ends. There were no additions to individual accounts in excess of two
percent of total assets other than transfers from Construction Work in
Progress.
1991 1992 1993
----------------------------------------
Gross Property Additions $ 64,323 $ 64,671 $ 78,562
Retirements 19,174 12,159 23,114
Other Changes (166) (686) (208)
S-6
349
MISSISSIPPI POWER COMPANY
SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES
(STATED IN THOUSANDS OF DOLLARS)
- ---------------------------------------------------------------------------------------
Column F Column F Column F Column F
- ---------------------------------------------------------------------------------------
Balance at Balance at Balance at Balance at
End of End of End of End of
Classification 1990 1991 1992 1993
- ---------------------------------------------------------------------------------------
ELECTRIC PLANT-IN-SERVICE:
Production Plant:
Steam $ 536,901 $ 545,058 $ 552,775 $ 571,722
Other 23,636 22,530 24,073 25,703
Transmission Plant 151,949 162,379 173,278 188,375
Distribution Plant 247,705 259,929 279,335 295,799
General Plant:
Transportation 13,970 14,144 14,056 13,566
Other 65,249 69,870 79,438 86,153
Construction Work in Progress 26,816 33,078 41,692 108,063
Plant Leased to Others 56,962 56,975 56,975 56,975
Plant Held for Future Use 634 575 575 554
- ---------------------------------------------------------------------------------------
TOTAL UTILITY PLANT $ 1,123,822 $1,164,538 $1,222,197 $1,346,910
=======================================================================================
Total additions and total retirements for 1991 and 1992, as summarized below,
were each less than 10% of the total balances as of the respective year-ends.
Additions for 1993 were greater than 10% of the year-end balance and,
consequently, 1993 is reported in full detail on page S-8. There were no
additions to individual accounts in excess of two percent of total assets
other than transfers from Construction Work in Progress.
1991 1992 1993
---------------------------------------
Gross Property Additions $ 53,675 $ 68,189 $ 139,976
Retirements 12,918 10,530 15,386
Other Changes (41) - 123
S-7
350
MISSISSIPPI POWER COMPANY
SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES
FOR THE YEAR ENDED DECEMBER 31,1993
(STATED IN THOUSANDS OF DOLLARS)
- ---------------------------------------------------------------------------------------------------
Balance at Balance at
Beginning Additions Other End of
Classification of Period at Cost Retirements Changes Period
- ---------------------------------------------------------------------------------------------------
ELECTRIC PLANT-IN-SERVICE:
Production Plant:
Steam $ 552,775 $ 24,746 $ 5,980 $ 181 $ 571,722
Other 24,073 1,820 194 4 25,703
Transmission Plant 173,278 15,861 821 57 188,375
Distribution Plant 279,335 22,306 5,783 (59) 295,799
General Plant:
Transportation 14,056 903 1,463 70 13,566
Other 79,438 7,968 1,145 (108) 86,153
Construction Work in Progress 41,692 66,372 - (1) 108,063
Plant Leased to Others 56,975 - - - 56,975
Plant Held for Future Use 575 - - (21) 554
- ---------------------------------------------------------------------------------------------------
TOTAL UTILITY PLANT $ 1,222,197 $ 139,976 $ 15,386 $ 123 $1,346,910
===================================================================================================
S-8
351
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES
(STATED IN THOUSANDS OF DOLLARS)
- -----------------------------------------------------------------------------------
Column F Column F Column F Column F
- -----------------------------------------------------------------------------------
Balance at Balance at Balance at Balance at
End of End of End of End of
Classification 1990 1991 1992 1993
- -----------------------------------------------------------------------------------
ELECTRIC PLANT-IN-SERVICE:
Intangibles:
Organization $ 1,755 $ 1,522 $ 1,289 $ 1,055
Miscellaneous 2,700 3,093 3,404 3,514
Production Plant:
Steam 241,391 242,447 254,318 253,870
Other 4,887 4,570 4,221 3,838
Transmission Plant 73,358 90,198 93,182 99,791
Distribution Plant 217,913 212,576 222,024 237,012
General Plant 17,870 19,003 20,493 22,776
Construction Work in Progress 1,354 4,211 5,966 49,797
Plant Held for Future Use 665 665 665 665
- -----------------------------------------------------------------------------------
TOTAL UTILITY PLANT $ 561,893 $ 578,285 $ 605,562 $ 672,318
===================================================================================
Total additions and total retirements for 1991 and 1992, as summarized below,
were each less than 10% of the total balances as of the respective year-ends.
Additions for 1993 were greater than 10% of the year-end balance and,
consequently, 1993 is reported in full detail on page S-10. There were no
additions to individual accounts in excess of two percent of total assets
other than transfers from Construction Work in Progress.
1991 1992 1993
-----------------------------------
Gross Property Additions $ 19,478 $ 30,132 $ 72,858
Retirements 2,435 2,404 5,513
Other Changes (651) (451) (589)
S-9
352
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE V - UTILITY PLANT, INCLUDING INTANGIBLES
FOR THE YEAR ENDED DECEMBER 31, 1993
(STATED IN THOUSANDS OF DOLLARS)
- ---------------------------------------------------------------------------------------------
Balance at Balance at
Beginning Additions Other End of
Classification of Period at Cost Retirements Changes Period
- ---------------------------------------------------------------------------------------------
ELECTRIC PLANT-IN-SERVICE:
Intangibles:
Organization $ 1,289 $ - $ - $ (234) $ 1,055
Miscellaneous 3,404 110 - - 3,514
Production Plant:
Steam 254,318 2,058 2,506 - 253,870
Other 4,221 - - (383) 3,838
Transmission Plant 93,182 6,771 162 - 99,791
Distribution Plant 222,024 17,266 2,278 - 237,012
General Plant 20,493 2,822 567 28 22,776
Construction Work in Progress 5,966 43,831 - - 49,797
Plant Held for Future Use 665 - - - 665
- ---------------------------------------------------------------------------------------------
TOTAL UTILITY PLANT $ 605,562 $ 72,858 $ 5,513 $ (589) $ 672,318
=============================================================================================
S-10
353
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1993
(STATED IN THOUSANDS OF DOLLARS)
- ----------------------------------------------------------------------------------------------------------------------
Additions Deductions
-------------------------------- ---------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacements Cost Changes Period
- ----------------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam (Note 6) $ 2,884,892 $ 226,064 $ 224 $199,231 $262,552 $13,013 $(27,495) $3,062,341
Nuclear 1,622,060 191,278 - 11,545 17,496 4,141 499 1,802,747
Hydraulic 269,821 15,216 - 7 284 137 (5) 284,628
Other 118,812 2,007 - 1,378 2,194 105 1,023 118,875
Transmission Plant 889,731 85,834 - 8,752 26,397 7,560 (4,987) 955,347
Distribution Plant 1,768,771 242,520 - 22,216 89,464 31,737 (25,518) 1,937,824
General Plant 701,236 60,216 50,374 10,199 82,178 2,086 (6,992) 744,753
Plant Acquisition
Adjustment 3,774 910 133 - 739 - - 4,078
Nuclear Fuel (Note 5) 1,048,366 - 111,384 - 102,065 - - 1,057,685
Plant Leased to Others 11,874 - 1,404 - - - - 13,278
- ----------------------------------------------------------------------------------------------------------------------
Total Electric Plant 9,319,337 824,045 163,519 253,328 583,369 58,779 (63,475) 9,981,556
STEAM HEAT PLANT 9,211 - 736 - 93 8 - 9,846
- ----------------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $ 9,328,548 $ 824,045 $164,255 $253,328 $583,462 $58,787 $(63,475) $9,991,402
======================================================================================================================
See Notes on Page S-14
S-11
354
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1992
(STATED IN THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------------------------------
Additions Deductions
----------------------------------- --------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacements Cost Changes Period
- ------------------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 7) (Note 7) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $2,708,765 $227,091 $ 528 $ 43,799 $ 56,259 $13,502 $25,530 $2,884,892
Nuclear 1,447,771 190,589 - 19,380 29,928 2,002 3,750 1,622,060
Hydraulic 256,126 15,126 - 40 1,245 226 - 269,821
Other 117,194 1,919 - - 249 60 (8) 118,812
Transmission Plant 828,289 83,143 - 2,685 20,786 8,773 (5,173) 889,731
Distribution Plant 1,657,122 228,465 - 12,657 94,858 29,702 4,913 1,768,771
General Plant 646,976 55,211 50,011 8,346 58,173 990 145 701,236
Plant Acquisition
Adjustment 2,651 1,003 120 - - - - 3,774
Nuclear Fuel (Note 5) 1,042,797 - 124,198 - 118,671 - (42) 1,048,366
Plant Leased to Others 10,470 - 1,404 - - - - 11,874
- ------------------------------------------------------------------------------------------------------------------------
Total Electric Plant 8,718,161 802,547 176,261 86,907 380,169 55,255 29,115 9,319,337
STEAM HEAT PLANT 8,492 - 719 - - - - 9,211
========================================================================================================================
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $8,726,653 $802,547 $176,980 $ 86,907 $380,169 $55,255 $29,115 $9,328,548
========================================================================================================================
See Notes on Page S-14
S-12
355
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1991
(STATED IN THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------------------------
Additions Deductions
----------------------------- -------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacements Cost Changes Period
- ------------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam (Note 6) $ 2,533,546 $ 229,553 $ 966 $219,727 $266,722 $15,220 $ (6,915) $2,708,765
Nuclear 1,266,341 194,459 - 497 10,900 3,431 (805) 1,447,771
Hydraulic 239,072 17,016 - (22) 473 148 (681) 256,126
Other 116,713 1,886 - 142 1,454 93 - 117,194
Transmission Plant 765,117 79,979 - 16,922 35,154 6,931 (8,356) 828,289
Distribution Plant 1,562,262 219,116 - 11,245 104,167 28,410 2,924 1,657,122
General Plant 585,525 58,641 49,272 3,936 47,341 576 2,481 646,976
Plant Acquisition
Adjustment 1,863 1,089 85 - 386 - - 2,651
Nuclear Fuel (Note 5) 959,352 - 136,891 - 53,991 - (545) 1,042,797
Plant Leased to Others 9,079 - 1,391 - - - - 10,470
- ------------------------------------------------------------------------------------------------------------------
Total Electric Plant 8,038,870 801,739 188,605 252,447 520,588 54,809 (11,897) 8,718,161
STEAM HEAT PLANT 7,861 - 716 (68) 17 - - 8,492
- ------------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $ 8,046,731 $ 801,739 $189,321 $252,379 $520,605 $54,809 $(11,897) $8,726,653
==================================================================================================================
See Notes on Page S-14
S-13
356
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
NOTES TO SCHEDULE VI -ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEARS ENDING DECEMBER 31, 1993, 1992 AND 1991
(STATED IN THOUSANDS OF DOLLARS)
- -------------------------------------------------------------------------------------------------------------------------
Explanation 1993 1992 1991
- -------------------------------------------------------------------------------------------------------------------------
1. See Note 1 to SOUTHERN's financial statements in Item 8 herein for the policy of SOUTHERN with respect to depreciation.
2. Amounts charged to electric operations as "Depreciation and Amortization" on the statements of income are as follows:
Depreciation (Schedule VI) $ 824,045 $ 802,547 $801,739
Investment Tax Credits (24,611) (35,092) (39,355)
Regulatory Assets and Liabilities (13,482) (347) -
Alicura Investment Amortization 7,186 - -
Other 344 1,418 753
------------------------------------
$ 793,482 $ 768,526 $763,137
====================================
3. Depreciation and Amortization charged to Other Accounts are as follows:
Nuclear Fuel $ 111,384 $ 124,198 $136,891
Transportation Expense 25,141 25,353 25,591
SCS - Depreciation 19,571 19,151 18,377
Fuel Stock 2,213 2,316 2,788
SNC - Depreciation 1,577 1,685 1,620
Leasehold Improvements 1,836 1,773 1,598
Plant Leased to Others 1,469 1,463 1,453
Steam Heat 736 719 716
Other 328 322 287
------------------------------------
$ 164,255 $ 176,980 $189,321
====================================
4. Other Changes include the following:
Freeport Power Company Acquisition $ (61,295) $ - $ -
Retirement Adjustments - - (8,263)
Santee-Cooper Refund (2,002) - -
Partial Sale of Miller Steam Plant - 19,187 -
Reclassification of Spare Parts Inventory - 12,506 -
Property received from the City of Dalton - - (4,606)
Likekind Exchange - - 2,400
Nuclear Decommissioning Trust Fund Earnings (3,303) (1,875) (688)
Retirement Unit Conversion 8,931 - -
Functional Gross-up of AFUDC Debt (6,656) - -
Miscellaneous Adjustments 850 (703) (740)
------------------------------------
$ (63,475) $ 29,115 $(11,897)
====================================
5. The accumulated amortization of nuclear fuel is netted against original cost of such fuel on the balance sheet.
6. Retirements and Salvage in 1991 and 1993 include the sale of a portion of Plant Scherer Unit 4. See Note 7 to SOUTHERN's
financial statements in Item 8 herein for a discussion of this transaction.
7. Retirements and Salvage in 1992 include GEORGIA'S reclassification of capitalized spare parts to inventory. See Note 1 to
GEORGIA's financial statements in Item 8 herein for a discussion of this transaction.
S-14
357
ALABAMA POWER COMPANY
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1993
(STATED IN THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------------------------------
Additions Deductions
------------------------------ -----------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacement Cost Changes Period
- ------------------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $ 882,321 $ 87,163 $ - $ 64 $ 12,422 $ 3,974 $ - $ 953,152
Nuclear 878,472 71,230 - 3,164 4,707 215 (606) 948,550
Hydraulic 169,144 11,038 - - 233 48 - 179,901
Other - - - - - - - -
Transmission Plant 325,425 32,227 - 4,327 4,862 2,868 (74) 354,323
Distribution Plant 662,444 80,143 - 14,240 23,217 12,808 - 720,802
General Plant
Coal Mine Plant 1,981 - 60 - - - - 2,041
Transportation 45,634 - 9,393 2,075 13,593 - - 43,509
Other 156,911 20,120 1,115 336 6,216 452 (218) 172,032
- ------------------------------------------------------------------------------------------------------------------------
Total Electric Plant 3,122,332 301,921 10,568 24,206 65,250 20,365 (898) 3,374,310
STEAM HEAT PLANT 9,211 - 736 - 93 8 - 9,846
- ------------------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $ 3,131,543 $ 301,921 $ 11,304 $ 24,206 $ 65,343 $ 20,373 $ (898) $3,384,156
========================================================================================================================
ACCUMULATED
PROVISION FOR
AMORTIZATION OF
NUCLEAR FUEL (NOTE 5) $ 825,301 $ - $ 46,568 $ - $ - $ - $ - $ 871,869
========================================================================================================================
See Notes on Page S-18
S-15
358
ALABAMA POWER COMPANY
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1992
(STATED IN THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------------------------------
Additions Deductions
------------------------------- ------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacement Cost Changes Period
- ------------------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $ 830,914 $ 86,773 $ - $ 706 $ 11,058 $ 6,182 $18,832 $ 882,321
Nuclear 815,216 70,492 - 234 8,096 225 (851) 878,472
Hydraulic 159,389 11,015 - 17 1,121 156 - 169,144
Other - - - - - - - -
Transmission Plant 300,904 32,310 - 601 5,806 2,584 - 325,425
Distribution Plant 616,777 76,473 - 3,911 23,856 10,861 - 662,444
General Plant
Coal Mine Plant 1,886 - 95 - - - - 1,981
Transportation 44,862 - 9,012 1,933 10,173 - - 45,634
Other 143,437 17,248 888 2,026 6,349 339 - 156,911
- ------------------------------------------------------------------------------------------------------------------------
Total Electric Plant 2,913,385 294,311 9,995 9,428 66,459 20,347 17,981 3,122,332
STEAM HEAT PLANT 8,492 - 719 - - - - 9,211
- ------------------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $ 2,921,877 $ 294,311 $ 10,714 $ 9,428 $ 66,459 $20,347 $17,981 $3,131,543
========================================================================================================================
ACCUMULATED
PROVISION FOR
AMORTIZATION OF
NUCLEAR FUEL (NOTE 5) $ 776,817 $ - $ 48,442 $ - $ - $ - $ (42) $ 825,301
========================================================================================================================
See Notes on Page S-18
S-16
359
ALABAMA POWER COMPANY
SCHEDULE VI --ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1991
(STATED IN THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------------------------------
Additions Deductions
-------------------------------- ---------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacements Cost Changes Period
- ------------------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $ 752,908 $ 83,837 $ - $ 172 $ 6,674 $ 6,571 $(7,242) $ 830,914
Nuclear 747,079 69,294 - - 51 1,294 (188) 815,216
Hydraulic 148,287 10,956 - 1 411 125 (681) 159,389
Other - - - - - - - -
Transmission Plant 278,609 30,095 - 424 5,244 2,942 38 300,904
Distribution Plant 579,911 71,348 - 4,908 29,162 10,269 (41) 616,777
General Plant
Coal Mine Plant 1,832 - 54 - - - - 1,886
Transportation 42,044 - 8,666 1,050 6,898 - - 44,862
Other 126,287 21,053 1,237 316 5,280 172 4 143,437
- ------------------------------------------------------------------------------------------------------------------------
Total Electric Plant 2,676,957 286,583 9,957 6,871 53,720 21,373 (8,110) 2,913,385
STEAM HEAT PLANT 7,861 - 716 (68) 17 - - 8,492
- ------------------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $ 2,684,818 $ 286,583 $ 10,673 $ 6,803 $ 53,737 $21,373 $(8,110) $2,921,877
========================================================================================================================
ACCUMULATED
PROVISION FOR
AMORTIZATION OF
NUCLEAR FUEL (Note 5) $ 719,181 $ - $ 57,091 $ - $ - $ - $ (545) $ 776,817
========================================================================================================================
See Notes on Page S-18
S-17
360
ALABAMA POWER COMPANY
NOTES TO SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEARS ENDING DECEMBER 31, 1993, 1992 AND 1991
(STATED IN THOUSANDS OF DOLLARS)
- -------------------------------------------------------------------------------------------------------------------------
Explanation 1993 1992 1991
- -------------------------------------------------------------------------------------------------------------------------
1.See Note 1 to ALABAMA's financial statements in Item 8 herein for the policy of ALABAMA with respect to depreciation.
2.Amounts charged to electric operations as "Depreciation and Amortization" on the statements of income are as follows:
Depreciation $ 301,921 $ 294,311 $ 286,583
Investment Tax Credits (12,014) (13,833) (15,552)
Plant Acquisition Adjustment 403 403 402
-------------------------------------
$ 290,310 $ 280,881 $ 271,433
=====================================
3.Depreciation and Amortization charged to Other Accounts are as follows:
Fuel Stock $ 1,092 $ 898 $ 1,203
Transportation Expense 9,393 9,012 8,666
Shop Expense 83 85 88
Steam Heat Plant 736 719 716
-------------------------------------
$ 11,304 $ 10,714 $ 10,673
=====================================
Nuclear Fuel $ 46,568 $ 48,442 $ 57,091
=====================================
4.Other Changes include the following:
Retirement Adjustments $ - $ - $ (7,923)
Partial sale of Miller Steam Plant - 19,187 -
Nuclear Decommissioning Trust Fund Earnings (1,485) (851) (188)
Miscellaneous Adjustments 587 (355) 1
--------------------------------------
$ (898) $ 17,981 $ (8,110)
=====================================
Westinghouse Settlement (Nuclear Fuel) $ - $ (42) $ (545)
=====================================
5.The accumulated amortization of nuclear fuel is netted against original cost of such fuel on the balance sheet.
S-18
361
GEORGIA POWER COMPANY
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1993
(STATED IN THOUSANDS OF DOLLARS)
- ----------------------------------------------------------------------------------------------------------------
Additions Deductions
------------------------------ --------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Retirements Cost Changes Period
- ----------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam (Note 6) $ 1,141,658 $ 76,528 $ 46 $ 193,746 $ 232,941 $ 4,343 $ 5,395 $ 1,169,299
Nuclear 743,588 120,048 - 8,381 12,789 3,926 1,105 854,197
Hydraulic 100,677 4,178 - 7 51 89 (5) 104,727
Other 98,764 1,263 - 1,023 1,986 97 1,023 97,944
Transmission Plant 404,818 41,658 - 4,404 19,338 3,756 (4,870) 432,656
Distribution Plant 817,555 126,419 - 4,256 50,366 12,818 (2,641) 887,687
General Plant 258,883 29,943 14,920 7,004 38,507 1,603 (1,116) 271,756
Plant Acquisition
Adjustment 3,774 910 133 - 739 - - 4,078
Nuclear Fuel (Note 5) 223,065 - 64,816 - 102,065 - - 185,816
- ----------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $ 3,792,782 $ 400,947 $ 79,915 $ 218,821 $ 458,782 $ 26,632 $ (1,109)$ 4,008,160
================================================================================================================
See Notes on Page S-22
S-19
362
GEORGIA POWER COMPANY
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1992
(STATED IN THOUSANDS OF DOLLARS)
- -----------------------------------------------------------------------------------------------------------------
Additions Deductions
----------------------------- ------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacement Cost Changes Period
- -----------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 7) (Note 7) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $ 1,096,340 $ 77,508 $ 348 $ 15,827 $ 39,871 $ 1,910 $ 6,584 $ 1,141,658
Nuclear 632,555 120,097 - 19,146 21,832 1,777 4,601 743,588
Hydraulic 96,737 4,111 - 23 124 70 - 100,677
Other 97,771 1,264 - - 211 60 - 98,764
Transmission Plant 376,536 39,198 - 2,012 12,617 5,321 (5,010) 404,818
Distribution Plant 766,710 120,321 - 4,996 56,883 12,970 4,619 817,555
General Plant 245,947 27,284 15,399 3,732 32,717 610 152 258,883
Plant Acquisition
Adjustment 2,651 1,003 120 - - - - 3,774
Nuclear Fuel (Note 5) 265,980 - 75,756 - 118,671 - - 223,065
- -----------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $ 3,581,227 $ 390,786 $ 91,623 $ 45,736 $ 282,926 $ 22,718 $ 10,946 $ 3,792,782
=================================================================================================================
See Notes on Page S-22
S-20
363
GEORGIA POWER COMPANY
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1991
(STATED IN THOUSANDS OF DOLLARS)
- ----------------------------------------------------------------------------------------------------------------------
Additions Deductions
--------------------------------- ----------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacement Cost Changes Period
- ----------------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam (Note 6) $1,038,054 $ 84,195 $ 787 $ 218,246 $ 240,052 $ 4,543 $ 347 $1,096,340
Nuclear 519,262 125,165 - 497 10,849 2,137 (617) 632,555
Hydraulic 90,785 6,060 - (23) 62 23 - 96,737
Other 96,858 1,232 - 12 251 80 - 97,771
Transmission Plant 351,316 39,372 - 16,397 27,887 3,281 (619) 376,536
Distribution Plant 715,631 117,284 - 4,479 62,297 12,993 (4,606) 766,710
General Plant 226,529 27,351 15,831 2,428 25,721 379 92 245,947
Plant Acquisition
Adjustment 1,863 1,089 85 - 386 - - 2,651
Nuclear Fuel (Note 5) 240,171 - 79,800 - 53,991 - - 265,980
- ----------------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $3,280,469 $401,748 $96,503 $ 242,036 $ 421,496 $23,436 $(5,403) $3,581,227
======================================================================================================================
See Notes on Page S-22
S-21
364
GEORGIA POWER COMPANY
NOTES TO SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEARS ENDING DECEMBER 31, 1993, 1992 AND 1991
(STATED IN THOUSANDS OF DOLLARS)
- ---------------------------------------------------------------------------------------------------------------------
Explanation 1993 1992 1991
- ---------------------------------------------------------------------------------------------------------------------
1.See Note 1 to GEORGIA's financial statements in Item 8 herein for the policy of GEORGIA with respect to depreciation.
2.Amounts charged to electric operations as "Depreciation and Amortization" on the statements of income are as follows:
Depreciation $ 400,947 $ 390,786 $ 401,748
Investment Tax Credits (8,293) (17,039) (19,501)
Nuclear Study Costs 562 519 396
Write-off of Future Use Property (51) 1,634 -
Regulatory Liability (13,154) (347) -
Transfer Reserve from Non-Utility Property (43) - -
Charge Off Consulting Fees (412) - -
Deferred Depreciation - Demand Side Options (40) - -
Deferred Expense (Rome Headquarters) (91) (93) (94)
----------- ---------- ----------
$ 379,425 $ 375,460 $ 382,549
=========== ========== ==========
3.Depreciation and Amortization charged to Other Accounts are as follows:
Nuclear Fuel $ 64,816 $ 75,756 $ 79,800
Transportation Expense 13,068 13,610 14,217
Leasehold Improvements 1,836 1,773 1,598
Amortization Of Rail Cars 46 348 787
Plant Acquisition Expense 133 120 85
Rental Expense 16 16 16
----------- ---------- ----------
$ 79,915 $ 91,623 $ 96,503
=========== ========== ==========
4.Other Changes include the following:
Property Received from City of Dalton $ - $ - $ (4,606)
Santee-Cooper Refund (2,002) - -
Nuclear Decommissioning Trust Fund Earnings (1,818) (1,024) (500)
Reclassification of Spare Parts - 12,392 -
Retirement Unit Conversion 8,931 - -
Functional Gross-up of AFUDC Debt (6,656) - -
Plant Transfers 22 (422) (297)
Scherer and Hatch Material Retirements 414 - -
----------- ---------- ----------
$ (1,109) $ 10,946 $ (5,403)
=========== ========== ==========
5.The accumulated amortization of nuclear fuel is netted against original cost of such fuel on the balance sheet.
6.Retirements and Salvage in 1991 and 1993 include the sale of a portion of Plant Scherer Unit 4. See Note 5 to GEORGIA's
financial statements in Item 8 herein for a discussion of this transaction.
7.Retirements and Salvage in 1992 include GEORGIA'S reclassification of capitalized spare parts to inventory. See Note 1
to GEORGIA's financial statements in Item 8 herein for a discussion of this transaction.
S-22
365
GULF POWER COMPANY
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1993
(STATED IN THOUSANDS OF DOLLARS)
- -------------------------------------------------------------------------------------------------------------------
Additions Deductions
------------------------------ -------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacements Cost Changes Period
- -------------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $344,354 $30,490 $ 93 $ 395 $ 7,485 $ 2,863 $ (146) $ 365,130
Other 3,513 79 - - 14 3 - 3,575
Transmission Plant 53,556 4,412 - (2) 1,214 475 (43) 56,320
Distribution Plant 137,965 17,194 - 1,689 7,821 3,622 60 145,345
General Plant
Transportation 5,983 - 1,451 385 1,562 - - 6,257
Other 33,480 5,377 96 2 5,018 25 (3) 33,915
- -------------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $578,851 $57,552 $1,640 $ 2,469 $23,114 $ 6,988 $ (132) $ 610,542
===================================================================================================================
See Notes on Page S-26
S-23
366
GULF POWER COMPANY
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1992
(STATED IN THOUSANDS OF DOLLARS)
- -----------------------------------------------------------------------------------------------------------------
Additions Deductions
------------------------------- ---------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacements Cost Changes Period
- -----------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $315,782 $30,054 $ 93 $ 204 $ 1,251 $ 414 $ 114 $344,354
Other 3,426 79 - - - - (8) 3,513
Transmission Plant 50,627 4,215 - 22 920 551 (163) 53,556
Distribution Plant 131,174 16,301 - 1,879 7,699 3,396 294 137,965
General Plant
Transportation 5,827 - 1,320 269 1,433 - - 5,983
Other 28,572 5,618 101 80 856 41 (6) $ 33,480
- -----------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $535,408 $56,267 $1,514 $2,454 $12,159 $4,402 $ 231 $578,851
=================================================================================================================
See Notes on Page S-26
S-24
367
GULF POWER COMPANY
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1991
(STATED IN THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------------------------
Additions Deductions
------------------------------- ------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacements Cost Changes Period
- ------------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $295,757 $29,592 $ 93 $ 108 $ 8,790 $ 999 $ (21) $ 315,782
Other 3,355 79 - - 8 - - 3,426
Transmission Plant 47,761 3,996 - 9 947 332 (140) 50,627
Distribution Plant 125,116 15,460 - 620 7,117 3,035 (130) 131,174
General Plant
Transportation 5,809 - 1,285 197 1,464 - - 5,827
Other 23,941 5,309 98 7 848 8 (73) 28,572
- ------------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $501,739 $54,436 $1,476 $ 941 $ 19,174 $4,374 $ (364) $ 535,408
==================================================================================================================
See Notes on Page S-26
S-25
368
GULF POWER COMPANY
NOTES TO SCHEDULE VI -ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEARS ENDING DECEMBER 31, 1993, 1992 AND 1991
(STATED IN THOUSANDS OF DOLLARS)
- ----------------------------------------------------------------------------------------------------------------------------
Explanation 1993 1992 1991
- ----------------------------------------------------------------------------------------------------------------------------
1. See Note 1 to GULF's financial statements in Item 8 herein for the policy of GULF with respect
to depreciation.
2. Amounts charged to electric operations as "Depreciation and Amortization" on the statements
are as follows:
Depreciation $ 57,552 $56,267 $ 54,436
Investment Tax Credits (2,241) (2,241) (2,241)
Reclassification of Spare Parts - (114) -
Adjustment (2) (154) -
-------------------------------------
$ 55,309 $53,758 $ 52,195
=====================================
3.Depreciation and Amortization charged to Other
Accounts are as follows:
Transportation Expense $ 1,451 $ 1,320 $ 1,285
Merchandise and Appliance Service 96 101 98
Railroad Track System 93 93 93
-------------------------------------
$ 1,640 $ 1,514 $ 1,476
=====================================
4.Other Changes include the following:
Retirement Adjustment $ - $ (8) $ (340)
Reclassification of Spare Parts - 114 -
Miscellaneous Adjustments and Property Reclassifications (132) 125 (24)
-------------------------------------
$ (132) $ 231 $ (364)
=====================================
S-26
369
MISSISSIPPI POWER COMPANY
SCHEDULE VI --ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1993
(STATED IN THOUSANDS OF DOLLARS)
- -------------------------------------------------------------------------------------------------------------------
Additions Deductions
---------------------------- --------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacements Cost Changes Period
- -------------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $ 225,455 $ 15,199 $ 85 $ 281 $ 5,980 $ 1,193 $ - $233,847
Other 13,064 634 - 355 194 5 - 13,854
Transmission Plant 61,424 4,547 - 26 821 308 - 64,868
Distribution Plant 98,221 10,675 - 1,805 5,783 1,442 - 103,476
General Plant
Transportation 6,751 - 1,108 268 1,463 - - 6,664
Other 23,988 3,825 65 5 1,145 - - 26,738
Plant Leased to Others 11,874 - 1,404 - - - - 13,278
- -------------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $ 440,777 $ 34,880 $ 2,662 $ 2,740 $ 15,386 $ 2,948 $ - $462,725
===================================================================================================================
See Notes on Page S-30
S-27
370
MISSISSIPPI POWER COMPANY
SCHEDULE VI --ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1992
(STATED IN THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------------------
Additions Deductions
---------------------------- ------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacements Cost Changes Period
- ------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $ 214,123 $ 15,853 $ 87 $ 283 $ 3,402 $ 1,489 $ - $225,455
Other 12,626 476 - - 38 - - 13,064
Transmission Plant 58,197 4,669 - 42 1,261 223 - 61,424
Distribution Plant 93,084 9,858 - 1,552 4,453 1,820 - 98,221
General Plant
Transportation 6,242 - 1,128 136 755 - - 6,751
Other 20,393 4,130 59 51 621 - 24 23,988
Plant Leased to Others 10,470 - 1,404 - - - - 11,874
- -------------------------------------------- --------- ----------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $ 415,135 $ 34,986 $ 2,678 $ 2,064 $ 10,530 $ 3,532 $ 24 $440,777
============================================================================================================
See Notes on Page S-30
S-28
371
MISSISSIPPI POWER COMPANY
SCHEDULE VI --ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1991
(STATED IN THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------------------------------------------
Additions Deductions
--------------------------------- --------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacements Cost Changes Period
- --------------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $ 204,605 $ 15,743 $ 86 $ 396 $ 5,939 $ 767 $ 1 $214,123
Other 13,229 475 - 130 1,195 13 - 12,626
Transmission Plant 55,263 4,260 - 89 1,050 365 - 58,197
Distribution Plant 87,819 9,310 - 970 3,737 1,278 - 93,084
General Plant
Transportation 5,635 - 1,126 145 666 - (2) 6,242
Other 16,810 3,815 62 41 331 4 - 20,393
Plant Leased to Others 9,079 - 1,391 - - - - 10,470
- -----------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISIONS FOR
DEPRECIATION $ 392,440 $ 33,603 $ 2,665 $ 1,771 $ 12,918 $ 2,427 $ (1) $415,135
=================================================================================================================
See Notes on Page S-30
S-29
372
MISSISSIPPI POWER COMPANY
NOTES TO SCHEDULE VI -ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PL
FOR THE YEARS ENDING DECEMBER 31, 1993, 1992 AND 1991
(STATED IN THOUSANDS OF DOLLARS)
- -------------------------------------------------------------------------------------------------------
Explanation 1993 1992 1991
- -------------------------------------------------------------------------------------------------------
1.See Note 1 to MISSISSIPPI's financial statements in Item 8 herein for the policy of MISSISSIPPI
with respect to depreciation.
2.Amounts charged to electric operation as "Depreciation and Amortization" on the statements of
income are as follows:
Depreciation $34,880 $34,986 $ 33,603
Investment Tax Credits (1,270) (1,186) (1,272)
Property Losses (183) (988) (184)
Regulatory Asset (328) - -
Other - (23) -
-----------------------------------
$33,099 $32,789 $ 32,147
===================================
3.Depreciation and Amortization charged to Other Accounts are as follows:
Plant Leased To Others $ 1,469 $ 1,463 $ 1,453
Transportation Expense 1,108 1,128 1,126
Fuel Stock 85 87 86
-----------------------------------
$ 2,662 $ 2,678 $ 2,665
===================================
4.Other Changes include the following:
Miscellaneous Adjustments $ - $ 24 $ (1)
===================================
S-30
373
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE VI --ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1993
(STATED IN THOUSANDS OF DOLLARS)
- -----------------------------------------------------------------------------------------------------------
Additions Deductions
-------------------------- ---------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Account Recoveries Replacement Cost Changes Period
- -----------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $ 141,795 $ 6,293 $ - $ 889 $ 2,506 $ 120 $ - $146,351
Other 1,797 31 - - - - - 1,828
Transmission Plant 34,756 2,591 - (3) 162 98 - 37,084
Distribution Plant 52,586 7,241 - 226 2,277 1,047 - 56,729
General Plant 9,160 742 121 124 568 6 - 9,573
- ------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $ 240,094 $ 16,898 $ 121 $ 1,236 $ 5,513 $ 1,271 $ - $251,565
===========================================================================================================
See Notes on Page S-34
S-31
374
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1992
(STATED IN THOUSANDS OF DOLLARS)
- -------------------------------------------------------------------------------------------------------------
Additions Deductions
----------------------------- -------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacements Cost Changes Period
- -------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $134,137 $ 8,335 $ - $ 26 $ 331 $ 372 $ - $ 141,795
Other 1,697 100 - - - - - 1,797
Transmission Plant 32,507 2,381 - 8 46 94 - 34,756
Distribution Plant 49,377 5,512 - 319 1,967 655 - 52,586
General Plant 7,887 931 283 119 60 - - 9,160
- -------------------------------------------------------------------------------------------------------------
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $225,605 $17,259 $ 283 $ 472 $ 2,404 $ 1,121 $ - $ 240,094
=============================================================================================================
See Notes on Page S-34
S-32
375
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1991
(STATED IN THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------------------------
Additions Deductions
--------------------------------- --------------------------------
Balance at Retirements, Balance at
Beginning Operating Other Salvage Renewals and Removal Other End of
Classification of Period Expenses Accounts Recoveries Replacements Cost Changes Period
- ------------------------------------------------------------------------------------------------------------------
(Note 2) (Note 3) (Note 4)
ELECTRIC PLANT
Production Plant
Steam $ 126,380 $ 8,152 $ - $ 5 $ 62 $ 338 $ - $ 134,137
Other 1,597 100 - - - - - 1,697
Transmission Plant 23,000 1,900 - 3 26 5 (7,635) 32,507
Distribution Plant 53,785 5,714 - 268 1,854 835 7,701 49,377
General Plant 6,963 1,113 297 20 493 13 - 7,887
TOTAL ACCUMULATED
PROVISION FOR
DEPRECIATION $ 211,725 $ 16,979 $ 297 $ 296 $ 2,435 $ 1,191 $ 66 $ 225,605
==================================================================================================================
See Notes on Page S-34
S-33
376
SAVANNAH ELECTRIC AND POWER COMPANY
NOTES TO SCHEDULE VI -- ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEARS ENDING DECEMBER 31, 1993, 1992 AND 1991
(STATED IN THOUSANDS OF DOLLARS)
- -------------------------------------------------------------------------------------------------------------------------
Explanation 1993 1992 1991
- -------------------------------------------------------------------------------------------------------------------------
1.See Note 1 to SAVANNAH's financial statements in Item 8 herein for the policy of SAVANNAH with respect
to depreciation
2.Amounts charged to electric operation as "Depreciation and Amortization" on the statements of income
are as follows:
Depreciation $ 16,898 $17,259 $ 16,979
Amortization of Investment Tax Credits (664) (664) (663)
Amortization of Intangible Plant (Merger Cost) 233 234 233
----------------------------------
$ 16,467 $16,829 $ 16,549
==================================
3.Depreciation and Amortization charged to Other Accounts are as follows:
Transportation Expense $ 121 $ 283 $ 297
==================================
4.Other Changes include the following:
Miscellaneous Adjustments $ - $ - $ 66
==================================
S-34
377
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
Additions
----------------------------
Balance at Charged to Balance at
Beginning Charged to Other End of
Description of Period Income Accounts Deductions Period
- ------------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $ 7,255 $24,040 $ 2 $ 22,230(1) $ 9,067
Deferred credit
Provision for property
insurance $23,594 $ 4,164 - $ 5,711 $22,047
Other property and
investments
Nuclear
decommissioning
trust (3) $52,701 $15,759 $19,351(4) $ 324 $87,487
Deferred charges
Uranium enrichment,
decontamination
and decommissioning
fund (5) $90,099 - $ 1,219 $ 4,976 $86,342
- -------------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible,
less recoveries of amounts previously written off.
(2) Insurance recoveries net of charges to reserve for purposes for
which reserve was created.
(3) See Note 1 to SOUTHERN's financial statements under "Nuclear
Decommissioning" in Item 8 herein for further information.
(4) Represents additional funding to reserve.
(5) See Note 1 to SOUTHERN's financial statements under "Revenues and
Fuel Costs" in Item 8 herein for further information.
S-35
378
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
Additions
----------------------------
Balance at Charged to Balance at
Beginning of Charged to Other End of
Description Period Income Accounts Deductions Period
- ------------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $12,568 $18,366 - $23,679(1) $ 7,255
Deferred credit
Provision for property
insurance $20,928 $ 3,298 $ 25(4) $ 657 $23,594
Other property and investments
Nuclear
decommissioning
trust (2) $25,871 $14,782 $12,189 $ 141 $52,701
Deferred charges
Uranium enrichment,
decontamination and
decommissioning - - $90,099 - $90,099
fund (3)
- -----------------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible,
less recoveries of amounts previously written off.
(2) See Note 1 to SOUTHERN's financial statements under "Depreciation
and Nuclear Decommissioning" in Item 8 herein for further
information.
(3) See Note 1 to SOUTHERN's financial statements under "Revenues and
Fuel Costs" in Item 8 herein for further information.
(4) Capitalized.
S-36
379
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VIII--VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Stated in Thousands of Dollars)
<Captions>
Additions
---------------------------
Balance at Charge to Balance at
Beginning of Charged to Other End
Description Period Income Accounts Deductions of Period
- ----------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts
Gulf States $ 259,068 $ (256,067)(1) - $ 3,001 $ -
Nu South 5,858 - - 5,858 -
Other 12,759 - 33,172(2) 12,568
--------- ----------- -------- --------
32,981
-----------
$ 277,685 $ (223,086) - $ 42,031 $ 12,568
========= =========== ======== ========
Deferred credits
Provision for property
insurance $ 17,712 $ 3,945 - $ 729(3) $ 20,928
Other property and investments
Nuclear
decommissioning
trust (4) $ 2,387 $ 14,173 $9,367 $ 56 $ 25,871
- ------------------
Notes:
(1) See Note 8 to SOUTHERN's financial statements in Item 8 herein for a
description of the Gulf States settlement.
(2) Represents write-off of accounts considered to be uncollectible,
less recoveries of amounts previously written off.
(3) Insurance recoveries net of charges to reserve for purposes for
which reserve was created.
(4) See Note 1 to SOUTHERN's financial statements under "Depreciation
and Nuclear Decommissioning" in Item 8 herein for further
information.
S-37
380
ALABAMA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
Additions
---------------------------
Balance at Charged to Balance at
Beginning of Charged to Other End of
Description Period Income Accounts Deductions Period
- ------------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $ 1,482 $ 7,157 - $6,007(1) $ 2,632
Other property and investments
Nuclear
decommissioning
trust (2) $ 32,390 $ 13,617 $ 3,543(3) - $ 49,550
Deferred charges
Uranium enrichment,
decontamination and
decommissioning
fund (4) $ 47,730 - $ 1,873 $4,049 $ 45,554
- ------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible,
less recoveries of amounts previously written off.
(2) See Note 1 to ALABAMA's financial statements under "Depreciation
and Nuclear Decommissioning" in Item 8 herein for further
information.
(3) Represents additional funding to reserve.
(4) See Note 1 to ALABAMA's financial statements under "Revenues and
Fuel Costs" in Item 8 herein for further information.
S-38
381
ALABAMA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
Additions
----------------------------
Balance at Charged to Balance at
Beginning of Charged to Other End of
Description Period Income Accounts Deductions Period
- -----------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $ 1,721 $ 4,878 - $ 5,117 (1) $ 1,482
Other property and investments
Nuclear
decommissioning
trust (2) $ 15,864 $ 13,617 $ 2,909 - $ 32,390
Deferred charges
Uranium enrichment,
decontamination and
decommissioning
fund (3) - - $ 47,730 - $ 47,730
- -----------------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible,
less recoveries of amounts previously written off.
(2) See Note 1 to ALABAMA's financial statements under "Depreciation
and Nuclear Decommissioning" in Item 8 herein for further
information.
(3) See Note 1 to ALABAMA's financial statements under "Revenues and
Fuel Costs" in Item 8 herein for further Information.
S-39
382
ALABAMA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Stated in Thousands of Dollars)
Additions
-----------------------------
Balance at Charged to Balance at
Beginning of Charged to Other End
Description Period Income Accounts Deductions of Period
- -----------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts
Gulf States $73,324 $(73,324) - $ - $ -
Other 1,656 4,020 - 3,955(2) 1,721
------- -------- ------- -------
$74,980 $(69,304) - $ 3,955 $ 1,721
======= ======== ======= =======
Other property and investments
Nuclear
decommissioning
trust (3) - $ 13,617 $2,247 - $15,864
- -----------------------
Notes:
(1) See Note 7 to the financial statements in Item 8 herein for a
description of the Gulf States settlement. The provision for
uncollectible was reversed.
(2) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(3) See Note 1 to ALABAMA's financial statements under "Depreciation and
Nuclear Decommissioning" in Item 8 herein for further information.
S-40
383
GEORGIA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
Additions
----------------------------
Balance at Charged to Balance at
Beginning Charged to Other End of
Description of Period Income Accounts Deductions Period
- ----------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $ 4,121 $ 14,310 - $ 14,131(1) $ 4,300
Other property and investments
Nuclear
decommissioning
trust (2) $ 20,311 $ 2,142 $ 15,808(3) $ 324 $ 37,937
Deferred charges
Uranium enrichment,
decontamination and
decommissioning
fund (4) $ 42,369 - $ (654) $ 927 $ 40,788
- --------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) See Note 1 to GEORGIA's financial statements under "Nuclear
Decommissioning" in Item 8 herein for further information.
(3) Represents additional funding to reserve.
(4) See Note 1 to GEORGIA's financial statements under "Revenues and Fuel
Costs" in Item 8 herein for further information.
S-41
384
GEORGIA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
Additions
-----------------------------
Balance Charged to Balance at
at Beginning Charged to Other End of
Description of Period Income Accounts Deductions Period
- -----------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $ 7,519 $ 11,440 - $14,838(1) $ 4,121
Other property and investments
Nuclear decommissioning
trust (2) $ 10,007 $ 1,165 $ 9,280 $ 141 $20,311
Deferred charges
Uranium enrichment,
decontamination and
decommissioning
fund (3) - - $42,369 - $42,369
- -----------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) See Note 1 to GEORGIA's financial statements under "Nuclear
Decommissioning" in Item 8 herein for further information.
(3) See Note 1 to GEORGIA's financial statements under "Revenues and Fuel
Costs" in Item 8 herein for further information.
S-42
385
GEORGIA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Stated in Thousands of Dollars)
Additions
-----------------------------
Balance at Charged to Balance at
Beginning of Charged to Other End of
Description Period Income Accounts Deductions Period
- ------------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts
Gulf States $148,383 $(145,382)(1) - $ 3,001 $ -
Other 8,063 22,492 - 23,036(2) 7,519
-------- --------- -------- --------
$156,446 $(122,890) - $ 26,037 $ 7,519
======== ========= ======== ========
Other property and investments
Nuclear
decommissioning
trust (3) $ 2,387 $ 556 $7,120 $ 56 $ 10,007
- ------------------
Note:
(1) See Note 3 to GEORGIA's financial statements in Item 8 herein for a
description of the Gulf States settlement. The provision for
uncollectible accounts was reversed.
(2) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(3) See Note 1 to GEORGIA's financial statements under "Nuclear
Decommissioning" in Item 8 herein for further information.
S-43
386
GULF POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
Additions
--------------------------
Balance at Charged to Balance at
Beginning of Charged to Other End of
Description Period Income Accounts Deductions Period
- ----------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $ 356 $ 875 - $784 (Note) $ 447
Deferred credit
Provision for property
insurance $9,692 $1,200 - $383 $10,509
- ---------------
Note: Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
S-44
387
GULF POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
Additions
--------------------------
Balance at Charged to Balance at
Beginning Charged to Other End of
Description of Period Income Accounts Deductions Period
- -----------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $ 660 $ 356 - $600 (Note) $ 356
Deferred credit
Provision for property
insurance $8,492 $1,200 - - $9,692
- --------------------
Note: Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
S-45
388
GULF POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Stated in Thousands of Dollars)
Additions
---------------------------
Balance at Charged to Balance at
Beginning of Charged to Other End of
Description Period Income Accounts Deductions Period
- ---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts
Gulf States $30,375 $(30,375)(1) - $ - $ -
Other 635 1,180 - 1,155(2) 660
------- -------- ------ -------
$31,010 $(29,195) - $1,155 $ 660
======= ======== ====== =======
Deferred credit
Provision for property
insurance $ 7,292 $ 1,200 - - $ 8,492
- ------------------
Notes:
(1) See Note 7 to GULF's financial statements in Item 8 herein for a
description of the Gulf States settlement. The provision for
uncollectible was reversed.
(2) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
S-46
389
MISSISSIPPI POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
Additions
-----------------------------
Balance at Charged to Balance at
Beginning of Charged to Other End of
Description Period Income Accounts Deductions Period
- ------------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $ 508 $1,326 $2 $1,099 (Note) $ 737
Deferred credit
Provision for property
insurance $9,294 $1,244 - - $10,538
- ---------------
Note: Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
S-47
390
MISSISSIPPI POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
Additions
---------------------------
Balance at Charged to Balance at
Beginning of Charged to Other End of
Description Period Income Accounts Deductions Period
- ----------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $2,102 $1,173 - $2,767 (Note) $ 508
Deferred credit
Provision for property
insurance $8,216 $1,078 - - $9,294
- ------------------
Note: Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
S-48
391
MISSISSIPPI POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Stated in thousands of Dollars)
Additions
----------------------------
Balance at Charged to Balance at
Beginning of Charged to Other End of
Description Period Income Accounts Deductions Period
- -----------------------------------------------------------------------------------------------------------------------------------
Provision for
uncollectible accounts
Gulf States $ 6,986 $(6,986)(1) - $ - $ -
Nu South 5,858 - - 5,858 (2) -
Other 1,839 4,577 - 4,314 (2) 2,102
------- -------- ------- -------
$14,683 $(2,409) - $10,172 $ 2,102
======= ======== ======= =======
Deferred credit
Provision for property
insurance $ 6,716 $ 1,500 - - $ 8,216
- -----------------
Notes:
(1) See Note 7 to MISSISSIPPI's financial statements in Item 8 herein for
a description of the Gulf States settlement. The provision for
uncollectible was reversed.
(2) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
S-49
392
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
Additions
---------------------------
Balance at Charged to Balance at
Beginning Charged to Other End of
Description of Period Income Accounts Deductions Period
- ----------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $536 $330 - $104 (Note) $ 762
Deferred credit
Provision for property
insurance $300 $700 - - $1,000
- --------------------------
Note: Represents write-off of accounts receivable considered to be
uncollectible, less recoveries of amounts previously written off.
S-50
393
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
Additions
----------------------------
Balance at Charged to Balance at
Beginning Charged to Other End of
Description of Period Income Accounts Deduction Period
- -----------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $339 $455 - $258 (Note) $536
Deferred credit
Provision for property
insurance $300 - - - $300
- ----------------------
Note: Represents write-off of accounts receivable considered to be
uncollectible, less recoveries of amounts previously written off.
S-51
394
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Stated in Thousands of Dollars)
Additions
---------------------------
Balance at Charged to Balance at
Beginning Charged to Other End of
Description of Period Income Accounts Deductions Period
- -----------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $367 $454 - $482 (Note) $339
Deferred credit
Provision for property
insurance $325 $225 - $250 $300
Note: Represents write-off of accounts receivable considered to be
uncollectible, less recoveries of amounts previously written off.
S-52
395
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE IX - SHORT-TERM BORROWINGS
DECEMBER 31, 1993, 1992 AND 1991
(Stated in Thousands of Dollars)
Weighted
Maximum Average Average
Category of Weighted Amount Amount Interest
Aggregate Balance Average Outstanding Outstanding Rate
Short-term At End of Interest During This During This During the
Borrowings Period Rate Period (1) Period (2) Period (2)
- ------------------------------------------------------------------------------------------------------------------------------
1993
Notes payable
to banks $735,953
Commercial paper 75,527
Other notes payable (3) 129,428
--------
$940,908 4.35% $1,122,489 $766,030 3.92%
========
1992
Notes payable
to banks $567,200
Commercial paper 259,388
--------
$826,588 3.92% $ 826,588 $394,575 4.06%
========
1991
Notes payable
to banks $301,500
Other notes payable (3) 188
--------
$301,688 5.18% $ 513,518 $322,249 6.50%
========
- ----------------------
Notes:
(1) At month-end.
(2) Average based on daily borrowings during period (averages and rates
quoted on an actual day year basis).
(3) This note payable is an obligation of SEI and does not include
borrowings from SOUTHERN.
(4) See Note 5 to SOUTHERN's financial statements in Item 8 herein for
details regarding SOUTHERN's and its subsidiaries lines
of credit and general terms of commitment agreements.
S-53
396
ALABAMA POWER COMPANY
SCHEDULE IX - SHORT -TERM BORROWINGS
DECEMBER 31, 1993, 1992, 1991
(Stated in Thousands of Dollars)
Weighted
Maximum Average Average
Category of Weighted Amount Amount Interest
Aggregate Balance Average Outstanding Outstanding Rate
Short-term At End of Interest During the During the During the
Borrowings Period Rate Period (1) Period (2) Period (2)
- -------------------------------------------------------------------------------------------------------------------------------
1993
Notes payable
to banks(3) $ 40,000 3.37% $257,319 $117,683 3.20%
1992
Notes payable
to banks $ 71,000
Commercial 125,917
---------
paper $ 196,917 3.57% $196,917 $ 96,682 3.83%
=========
1991
Notes payable
to banks $ 76,000 5.07% $337,000 $210,579 6.36%
- -----------------
Notes:
(1) At month-end.
(2) Average based on daily borrowings during the period (averages and
rates quoted on an actual day year basis).
(3) ALABAMA also issued commercial paper during 1993, although none was
outstanding at year-end. The data shown reflects the issuance of
commercial paper.
(4) See Note 5 to ALABAMA's financial statements in Item 8 herein for
details regarding ALABAMA's lines of credit.
S-54
397
GEORGIA POWER COMPANY
SCHEDULE IX - SHORT -TERM BORROWINGS
DECEMBER 31, 1993, 1992 AND 1991
(Stated in Thousands of Dollars)
Weighted
Maximum Average Average
Category of Weighted Amount Amount Interest
Aggregate Balance Average Outstanding Outstanding Rate
Short-Term At End of Interest During This During This During the
Borrowings Period Rate Period (1) Period (2) Period (2)
- ------------------------------------------------------------------------------------------------------------------------------
1993
Notes payable
to banks $406,700
Commercial
paper 75,527
--------
$482,227 3.52% $661,498 $425,180 3.65%
========
1992
Notes payable
to banks $400,200
Commercial
paper 133,471
--------
$533,671 4.10% $533,671 $232,755 4.16%
========
1991
Notes payable
to banks $199,000 5.15% $199,000 $ 75,245 6.52%
- --------------------
Notes:
(1) At month-end
(2) Average based on daily borrowings during period (averages and rates
quoted on an actual day year basis).
(3) See Note 8 to GEORGIA's financial statements in Item 8 herein for
details regarding GEORGIA's lines of credit and general terms of its
commitment agreements.
S-55
398
GULF POWER COMPANY
SCHEDULE IX - SHORT -TERM BORROWINGS
DECEMBER 31, 1993, 1992 AND 1991
(Stated in Thousands of Dollars)
Weighted
Maximum Average Average
Category Weighted Amount Amount Interest
Aggregate Balance Average Outstanding Outstanding Rate
Short-Term At End of Interest During This During This During the
Borrowings Period Rate Period (1) Period (2) Period (2)
- ----------------------------------------------------------------------------------------------------------------------------------
1993
Notes payable
to banks $ 6,053(3) 0.00% $61,500 $25,873 3.37%
1992
Notes payable
to banks $44,000 3.63% $44,000 $26,045 4.00%
1991
Notes payable
to banks - - $23,000 $ 4,511 6.21%
- ----------------------
Notes:
(1) At month-end
(2) Average based on daily borrowings during period (averages and rates
quoted on an actual day year basis).
(3) See Note 5 to GULF's financial statements in Item 8 herein for a
description of this short-term indebtedness.
(4) See Note 5 to GULF's financial statements in Item 8 herein for
details regarding GULF's lines of credit and general terms of its
commitment agreements.
S-56
399
MISSISSIPPI POWER COMPANY
SCHEDULE IX - SHORT -TERM BORROWINGS
DECEMBER 31, 1993, 1992 AND 1991
(Stated in Thousands of Dollars)
Weighted
Maximum Average Average
Category Weighted Amount Amount Interest
Aggregate Balance Average Outstanding Outstanding Rate
Short-Term At End of Interest During This During This During the
Borrowings Period Rate Period (1) Period (2) Period
- ----------------------------------------------------------------------------------------------------------------------------------
1993
Notes payable
to banks $40,000 3.43% $56,000 $30,208 3.31%
1992
Notes payable
to banks $31,000 3.48% $31,000 $10,086 3.60%
1991
Notes payable
to banks $ 4,500 6.78% $48,161 $19,327 8.28%
- ----------------------
Notes:
(1) At month-end
(2) Average based on daily borrowings during period (averages and rates
quoted on an actual day year basis).
(3) See Note 5 to MISSISSIPPI's financial statements in Item 8 herein for
details regarding MISSISSIPPI's lines of credit and general terms of
its commitment agreements.
S-57
400
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE IX - SHORT -TERM BORROWINGS
DECEMBER 31, 1993, 1992 AND 1991
(Stated in Thousands of Dollars)
Weighted
Maximum Average Average
Category Weighted Amount Amount Interest
Aggregate Balance Average Outstanding Outstanding Rate
Short-Term At End of Interest During This During This During the
Borrowings Period Rate Period (1) Period (2) Period (2)
- --------------------------------------------------------------------------------------------------------------------------------
1993
Notes payable
to banks $3,000 3.30% $17,500 $7,738 3.44%
1992
Notes payable
to banks $7,500 3.85% $ 7,500 $ 387 3.86%
1991
Notes payable
to banks - - $ 5,000 $ 386 6.45%
Notes:
(1) At month-end
(2) Average based on daily borrowings during period (averages and rates
quoted on an actual day year basis).
(3) See Note 5 to SAVANNAH's financial statements in Item 8 herein for
details regarding SAVANNAH's lines of credit and general terms of its
commitment agreements.
S-58
401
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Item Charged to Costs and Expenses
---- -----------------------------
Taxes, other than payroll and income taxes:
1993
Real and personal property taxes $186,373
Municipal and state taxes on gross receipts 204,371
Other 12,544
--------
$403,288
========
1992
Real and personal property taxes $172,106
Municipal and state taxes on gross receipts 194,726
Other 12,553
--------
$379,385
========
1991
Real and personal property taxes $162,227
Municipal and state taxes on gross receipts 194,179
Other 13,514
--------
$369,920
========
S-59
402
ALABAMA POWER COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Item Charged to Costs and Expenses
---- -----------------------------
Taxes, other than payroll and income taxes:
1993
Real and personal property taxes $ 55,921
Municipal and state taxes on gross receipts 96,933
Other 8,598
--------
$161,452
========
1992
Real and personal property taxes $ 51,043
Municipal and state taxes on gross receipts 95,031
Other 9,231
--------
$155,305
========
1991
Real and personal property taxes $ 48,600
Municipal and state taxes on gross receipts 91,656
Other 9,440
--------
$149,696
========
S-60
403
GEORGIA POWER COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Item Charged to Costs and Expenses
---- -----------------------------
Taxes, other than payroll and income taxes:
1993
Real and personal property taxes $ 84,587
Municipal and state taxes on gross receipts 76,352
Other 1,210
--------
$162,149
========
1992
Real and personal property taxes $ 77,940
Municipal and state taxes on gross receipts 71,010
Other 902
--------
$149,852
========
1991
Real and personal property taxes $ 70,482
Municipal and state taxes on gross receipts 68,861
Other 1,186
--------
$140,529
========
S-61
404
GULF POWER COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Item Charged to Costs and Expenses
---- -----------------------------
Taxes, other than payroll and income taxes:
1993
Real and personal property taxes $16,211
Municipal and state taxes on gross receipts 18,907
Other 988
-------
$36,106
=======
1992
Real and personal property taxes $15,383
Municipal and state taxes on gross receipts 17,710
Other 790
-------
$33,883
=======
1991
Real and personal property taxes $14,868
Municipal and state taxes on gross receipts 22,425
Other 1,185
-------
$38,478
=======
S-62
405
MISSISSIPPI POWER COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Item Charged to Costs and Expenses
---- -----------------------------
Taxes, other than payroll and income taxes:
1993
Real and personal property taxes $23,279
Municipal and state taxes on gross receipts 8,160
Other 1,477
-------
$32,916
=======
1992
Real and personal property taxes $21,987
Municipal and state taxes on gross receipts 7,316
Other 1,388
-------
$30,691
=======
1991
Real and personal property taxes $22,701
Municipal and state taxes on gross receipts 7,451
Other 1,432
-------
$31,584
=======
S-63
406
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Item Charged to Costs and Expenses
---- -----------------------------
Taxes, other than payroll and income taxes:
1993
Real and personal property taxes $5,285
Municipal and state taxes on gross receipts 4,019
Other 84
------
$9,388
======
1992
Real and personal property taxes $4,735
Municipal and state taxes on gross receipts 3,659
Other 64
------
$8,458
======
1991
Real and personal property taxes $4,653
Municipal and state taxes on gross receipts 3,786
Other 112
------
$8,551
======
S-64
407
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. 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 601 of Regulation S-K of the SEC, immediately
precedes the exhibits being physically filed with this Form 10-K.
(3) ARTICLES OF INCORPORATION AND BY-LAWS
SOUTHERN
(a) 1 - Composite Certificate of Incorporation of SOUTHERN,
reflecting all amendments to date. (Designated in
Registration No. 33-3546 as Exhibit 4(a), in Certificate
of Notification, File No. 70-7341, as Exhibit A and in
Certificate of Notification, File No. 70-8181, as Exhibit
A.)
(a) 2 - By-laws of SOUTHERN as amended effective October 21, 1991,
and as presently in effect. (Designated in Form U-1, File
No. 70-8181 as Exhibit A-2.)
ALABAMA
(b) 1 - Charter of ALABAMA and amendments thereto through November
19, 1993. (Designated in Registration Nos. 2-59634 as
Exhibit 2(b), 2-60209 as Exhibit 2(c), 2-60484 as Exhibit
2(b), 2-70838 as Exhibit 4(a)-2, 2-85987 as Exhibit 4(a)-2,
33-25539 as Exhibit 4(a)-2, 33-43917 as Exhibit 4(a)-2, in
Form 8-K dated February 5, 1992, File No. 1-3164, as
Exhibit 4(b)-3, in Form 8-K dated July 8, 1992, File No.
1-3164, as Exhibit 4(b)-3, in Form 8-K dated October 27,
1993, File No. 1-3164, as Exhibits 4(a) and 4(b) and in
Form 8-K dated November 16, 1993, File No. 1-3164, as
Exhibit 4(a).)
(b) 2 - By-laws of ALABAMA as amended effective April 24, 1992,
and as presently in effect. (Designated in Registration
No. 33-48885 as Exhibit 4(c).)
GEORGIA
(c) 1 - Charter of GEORGIA and amendments thereto through October
25, 1993. (Designated in Registration Nos. 2-63392 as
Exhibit 2(a)-2, 2-78913 as Exhibits 4(a)-(2) and 4(a)-(3),
2-93039 as Exhibit 4(a)-(2), 2-96810 as Exhibit 4(a)-2,
33-141 as Exhibit 4(a)-(2), 33-1359 as Exhibit 4(a)(2),
33-5405 as Exhibit 4(b)(2), 33-14367 as Exhibits 4(b)-(2)
and 4(b)-(3), 33-22504 as Exhibits 4(b)-(2), 4(b)-(3) and
4(b)-(4), in GEORGIA's Form 10-K for the year ended
December 31, 1991, File No. 1-6468, as Exhibits 4(a)(2)
and 4(a)(3), in Registration No. 33-48895 as Exhibits
4(b)-(2) and 4(b)-(3), in Form 8-K dated December 10, 1992,
File No. 1-6468 as Exhibit 4(b), in Form 8-K dated June 17,
1993, File No. 1-6468, as Exhibit 4(b) and in Form 8-K
dated October 20, 1993, File No. 1-6468, as Exhibit 4(b).)
E-1
408
(c) 2 - By-laws of GEORGIA as amended effective July 18, 1990, and
as presently in effect. (Designated in GEORGIA's Form
10-K for the year ended December 31, 1990, File No.1-6468,
as Exhibit 3.)
GULF
(d) 1 - Restated Articles of Incorporation of GULF and amendments
thereto through November 8, 1993. (Designated in
Registration No. 33-43739 as Exhibit 4(b)-1, in Form 8-K
dated January 15, 1992, File No. 0-2429, as Exhibit 1(b),
in Form 8-K dated August 18, 1992, File No. 0-2429, as
Exhibit 4(b)-2, in Form 8-K dated September 22, 1993, File
No. 0-2429, as Exhibit 4 and in Form 8-K dated November 3,
1993, File No. 0-2429, as Exhibit 4.)
*(d) 2 - By-laws of GULF as amended effective February 25, 1994, and
as presently in effect.
MISSISSIPPI
(e) 1 - Articles of incorporation of MISSISSIPPI, articles of
merger of Mississippi Power Company (a Maine corporation)
into MISSISSIPPI and articles of amendment to the articles
of incorporation of MISSISSIPPI through August 19, 1993.
(Designated in Registration No. 2-71540 as Exhibit 4(a)-1,
in Form U5S for 1987, File No. 30-222-2, as Exhibit B-10,
in Registration No. 33-49320 as Exhibit 4(b)-(1), in Form
8-K dated August 5, 1992, File No. 0-6849, as Exhibits
4(b)-2 and 4(b)-3, in Form 8-K dated August 4, 1993, File
No. 0-6849, as Exhibit 4(b)-3 and in Form 8-K dated August
18, 1993, File No. 0-6849, as Exhibit 4(b)-3.)
(e) 2 - By-laws of MISSISSIPPI as amended effective August 22,
1989, and as presently in effect. (Designated in
MISSISSIPPI's Form 10-K for the year ended December 31,
1989, as Exhibit 3(b).)
SAVANNAH
(f) 1 - Charter of SAVANNAH and amendments thereto through
November 10, 1993. (Designated in Registration Nos.
33-25183 as Exhibit 4(b)-(1), 33-45757 as Exhibit 4(b)-(2)
and in Form 8-K dated November 9, 1993, File No. 1-5072,
as Exhibit 4(b).)
*(f) 2 - By-laws of SAVANNAH as amended effective February 16, 1994,
and as presently in effect.
(4) INSTRUMENTS DESCRIBING RIGHTS OF SECURITY HOLDERS, INCLUDING INDENTURES
ALABAMA
(b) - Indenture dated as of January 1, 1942, between ALABAMA and
Chemical Bank, as Trustee, and indentures supplemental
thereto through that dated as of January 1, 1994.
(Designated in Registration Nos. 2-59843 as Exhibit 2(a)-2,
2-60484 as Exhibits 2(a)-3 and 2(a)-4, 2-60716 as Exhibit
2(c), 2-67574 as
E-2
409
Exhibit 2(c), 2-68687 as Exhibit 2(c), 2-69599 as Exhibit
4(a)-2, 2-71364 as Exhibit 4(a)-2, 2- 73727 as Exhibit
4(a)-2, 33-5079 as Exhibit 4(a)-2, 33-17083 as Exhibit
4(a)-2, 33-22090 as Exhibit 4(a)-2, in ALABAMA's Form 10-K
for the year ended December 31, 1990, File No. 1-3164, as
Exhibit 4(c), in Registration Nos. 33-43917 as Exhibit
4(a)-2, 33-45492 as Exhibit 4(a)-2, 33- 48885 as Exhibit
4(a)-2, 33-48917 as Exhibit 4(a)-2, in Form 8-K dated
January 20, 1993, File No. 1-3436, as Exhibit 4(a)-3, in
Form 8-K dated February 17, 1993, File No.1-3436, as
Exhibit 4(a)-3, in Form 8-K dated March 10, 1993, File No.
1-3436, as Exhibit 4(a)-3, in Certificate of Notification,
File No. 70-8069, as Exhibits A and B, in Form 8-K dated
June 24, 1993, File No. 1- 3436, as Exhibit 4, in
Certificate of Notification, File No. 70-8069, as Exhibit A,
in Form 8-K dated November 16, 1993, File No. 1-3436, as
Exhibit 4(b) and in Certificate of Notification, File No.
70-8069, as Exhibits A and B.)
GEORGIA
(d) - Indenture dated as of March 1, 1941, between GEORGIA and
Chemical Bank, as Trustee, and indentures supplemental
thereto dated as of March 1, 1941, March 3, 1941 (3
indentures), March 6, 1941 (139 indentures), March 1, 1946
(88 indentures) and December 1, 1947, through January 1,
1994. (Designated in Registration Nos. 2-4663 as Exhibits B-3
and B-3(a), 2-7299 as Exhibit 7(a)-2, 2- 61116 as Exhibit
2(a)-3 and 2(a)-4, 2-62488 as Exhibit 2(a)-3, 2-63393 as
Exhibit 2(a)-4, 2-63705 as Exhibit 2(a)-3, 2-68973 as Exhibit
2(a)-3, 2-70679 as Exhibit 4(a)-(2), 2-72324 as Exhibit
4(a)-2, 2-73987 as Exhibit 4(a)-(2), 2-77941 as Exhibits
4(a)-(2) and 4(a)-(3), 2-79336 as Exhibit 4(a)-(2), 2-81303
as Exhibit 4(a)-(2), 2-90105 as Exhibit 4(a)-(2), 33-5405 as
Exhibit 4(a)-(2), 33-14367 as Exhibits 4(a)-(2) and 4(a)-(3),
33-22504 as Exhibits 4(a)-(2), 4(a)-(3) and 4(a)-(4),
33-32420 as Exhibit 4(a)-(2), 33-35683 as Exhibit 4(a)-(2),
in GEORGIA's Form 10-K for the year ended December 31, 1990,
File No. 1-6468, as Exhibit 4(a)(3), in Form 10-K for the
year ended December 31, 1991, File No. 1-6468, as Exhibit
4(a)(5), in Registration No. 33-48895 as Exhibit 4(a)-(2), in
Form 8-K dated August 26, 1992, File No. 1-6468, as Exhibit
4(a)-(3), in Form 8-K dated September 9, 1992, File No.
1-6468, as Exhibits 4(a)-(3) and 4(a)-(4), in Form 8-K dated
September 23, 1992, File No. 1-6468, as Exhibit 4(a)-(3), in
Form 8-A dated October 12, 1992, as Exhibit 2(b), in Form 8-K
dated January 27, 1993, File No. 1-6468, as Exhibit 4(a)-(3),
in Registration No. 33-49661 as Exhibit 4(a)-(2), in Form 8-K
dated July 26, 1993, File No. 1-6468, as Exhibit 4, in
Certificate of Notification, File No. 70-7832, as Exhibit M
and in Certificate of Notification, File No. 70-7832, as
Exhibit C.)
GULF
(e) - Indenture dated as of September 1, 1941, between GULF and
The Chase Manhattan Bank (National Association) and The
Citizens & Peoples National Bank of Pensacola, as Trustees,
and indentures supplemental thereto through
E-3
410
November 1, 1993. (Designated in Registration Nos.
2-4833 as Exhibit B-3, 2-62319 as Exhibit 2(a)-3, 2-63765 as
Exhibit 2(a)-3, 2-66260 as Exhibit 2(a)-3, 33-2809 as
Exhibit 4(a)-2, 33-43739 as Exhibit 4(a)-2, in GULF's Form
10-K for the year ended December 31, 1991, File No. 0-2429,
as Exhibit 4(b), in Form 8-K dated August 18, 1992, File No.
0-2429, as Exhibit 4(a)-3, in Registration No. 33-50165 as
Exhibit 4(a)-2, in Form 8-K dated July 12, 1993, File No.
0-2429, as Exhibit 4 and in Certificate of Notification,
File No. 70-8229, as Exhibit A.)
MISSISSIPPI
(f) - Indenture dated as of September 1, 1941, between
MISSISSIPPI and Morgan Guaranty Trust Company of New York,
as Trustee, and indentures supplemental thereto through
November 1, 1993. (Designated in Registration Nos.
2-4834 as Exhibit B-3, 2-62965 as Exhibit 2(b)-2, 2-66845 as
Exhibit 2(b)-2, 2-71537 as Exhibit 4(a)-(2), 33-5414 as
Exhibit 4(a)-(2), 33-39833 as Exhibit 4(a)-2, in
MISSISSIPPI's Form 10-K for the year ended December 31,
1991, File No. 0-6849, as Exhibit 4(b), in Form 8-K dated
August 5, 1992, File No. 0-6849, as Exhibit 4(a)-2, in
Second Certificate of Notification, File No. 70-7941, as
Exhibit I, in MISSISSIPPI's Form 8-K dated February 26,
1993, File No. 0-6849, as Exhibit 4(a)-2, in Certificate of
Notification, File No. 70-8127, as Exhibit A, in Form 8-K
dated June 22, 1993, File No. 0-6849, as Exhibit 1 and in
Certificate of Notification, File No. 70-8127, as Exhibit
A.)
SAVANNAH
(g) - Indenture dated as of March 1, 1945, between SAVANNAH and
NationsBank of Georgia, National Association, as
Trustee, and indentures supplemental thereto through July 1,
1993. (Designated in Registration Nos. 33-25183 as Exhibit
4(a)-(1), 33-41496 as Exhibit 4(a)-(2), 33-45757 as Exhibit
4(a)-(2), in SAVANNAH's Form 10-K for the year ended
December 31, 1991, File No. 1-5072, as Exhibit 4(b), in Form
8-K dated July 8, 1992, File No. 1-5072, as Exhibit 4(a)-3,
in Registration No. 33-50587 as Exhibit 4(a)-(2) and in Form
8-K dated July 22, 1993, File No. 1-5072, as Exhibit 4.)
(10) MATERIAL CONTRACTS
SOUTHERN
(a) 1 - Service contracts dated as of January 1, 1984 and Amendment
No. 1 dated as of September 6, 1985, between SCS and
ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1984, File No. 1-3526, as Exhibit 10(a) and in
SOUTHERN's Form 10-K for the year ended December 31, 1985,
File No. 1-3526, as Exhibit 10(a)(3).)
(a) 2 - Service contract dated as of July 17, 1981, between SCS and
SEI. (Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1985, File No. 1-3526, as Exhibit 10(a)(2).)
E-4
411
(a) 3 - Service contract dated as of March 3, 1988, between SCS and
SAVANNAH. (Designated in SAVANNAH's Form 10-K for the year
ended December 31, 1987, File No. 1-5072, as Exhibit 10-p.)
(a) 4 - Service contract dated as of January 15, 1991, between SCS
and Southern Nuclear. (Designated in SOUTHERN's Form 10-K
for the year ended December 31, 1991, File No. 1-3526, as
Exhibit 10(a)(4).)
(a) 5 - Interchange contract dated October 28, 1988, effective
January 1, 1989, between ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. (Designated in SAVANNAH's Form 10-K for
the year ended December 31, 1988, File No. 1-5072, as
Exhibit 10(b).)
(a) 6 - Agreement dated as of January 27, 1959 and Amendment No. 1
dated as of October 27, 1982, among SEGCO, ALABAMA and
GEORGIA. (Designated in Registration No. 2-59634 as Exhibit
5(c) and in GEORGIA's Form 10-K for the year ended December
31, 1982, File No. 1-6468, as Exhibit 10(d)(2).)
(a) 7 - Joint Committee Agreement dated as of August 27, 1976, among
GEORGIA, OPC, MEAG and Dalton. (Designated in Registration
No. 2-61116 as Exhibit 5(d).)
(a) 8 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of January 6, 1975, between
GEORGIA and OPC. (Designated in Form 8-K for January, 1975,
File No. 1-6468, as Exhibit (b)(1).)
(a) 9 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of
January 6, 1975, between GEORGIA and OPC. (Designated in
Form 8-K for January, 1975, File No. 1-6468, as Exhibit
(b)(3).)
(a) 10 - Revised and Restated Integrated Transmission System
Agreement dated as of November 12, 1990, between GEORGIA and
OPC. (Designated in GEORGIA's Form 10-K for the year ended
December 31, 1990, File No. 1-6468, as Exhibit 10(g).)
(a) 11 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of March 26, 1976, between GEORGIA and
OPC. (Designated in Certificate of Notification, File No.
70-5592, as Exhibit A.)
(a) 12 - Plant Hal Wansley Operating Agreement dated as of March 26,
1976, between GEORGIA and OPC. (Designated in Certificate of
Notification, File No. 70-5592, as Exhibit B.)
(a) 13 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of August 27, 1976, between
GEORGIA, MEAG and Dalton. (Designated in Form 8-K dated as
of June 13, 1977, File No. 1-6468, as Exhibit (b)(1).)
E-5
412
(a) 14 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of
August 27, 1976, between GEORGIA, MEAG and Dalton.
(Designated in Form 8-K for February, 1977, File No. 1-6468,
as Exhibit (b)(2).)
(a) 15 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase and
Ownership Participation Agreement dated as of August 27, 1976
and Amendment No. 1 dated as of January 18, 1977, among
GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1,
File No. 70-5792, as Exhibit B-1 and in Form 8-K for
January 1977, File No. 1-6468, as Exhibit (B)(3).)
(a) 16 - Alvin W. Vogtle Nuclear Units Number One and Two Operating
Agreement dated as of August 27, 1976, among GEORGIA, OPC,
MEAG and Dalton. (Designated in Form U-1, File No. 70-5792,
as Exhibit B-2.)
(a) 17 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase,
Amendment, Assignment and Assumption Agreement dated as of
November 16, 1983, between GEORGIA and MEAG. (Designated in
GEORGIA's Form 10-K for the year ended December 31, 1983,
File No. 1-6468, as Exhibit 10(k)(4).)
(a) 18 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of August 27, 1976, between GEORGIA and
MEAG. (Designated in Form 8-K dated as of July 5, 1977,
File No. 1-6468, as Exhibit (b)(2).)
(a) 19 - Plant Hal Wansley Operating Agreement dated as of August 27,
1976, between GEORGIA and MEAG. (Designated in Form 8-K dated
as of July 5, 1977, File No. 1-6468, as Exhibit (b)(4).)
(a) 20 - Integrated Transmission System Agreement dated as of August
27, 1976, between GEORGIA and Dalton. (Designated in Form
8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit
(b)(8).)
(a) 21 - Integrated Transmission System Agreement dated as of August
27, 1976, between GEORGIA and MEAG. (Designated in Form 8-K
for February, 1977, File No. 1-6468, as Exhibit (b)(4).)
(a) 22 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of April 19, 1977, between GEORGIA and
Dalton. (Designated in Form 8-K dated as of June 13, 1977,
File No. 1-6468, as Exhibit (b)(3).)
(a) 23 - Plant Hal Wansley Operating Agreement dated as of April 19,
1977, between GEORGIA and Dalton. (Designated in Form 8-K
dated as of June 13, 1977, File No. 1-6468, as Exhibit
(b)(7).)
(a) 24 - Plant Robert W. Scherer Units Number One and Two Purchase
and Ownership Participation Agreement dated as of May 15,
1980, Amendment No. 1 dated as of December 30, 1985,
Amendment No. 2 dated as of July 1, 1986 and Amendment No. 3
dated as of August 1, 1988, among GEORGIA, OPC, MEAG and
Dalton. (Designated in Form U-1, File No. 70-6481, as
Exhibit B-3, in SOUTHERN's Form 10-K for the year ended
December 31, 1987, File
E-6
413
No. 1-3526, as Exhibit 10(o)(2) and in SOUTHERN's Form
10-K for the year ended December 31, 1989, File No.
1-3526, as Exhibit 10(n)(2).)
(a) 25 - Plant Robert W. Scherer Units Number One and Two Operating
Agreement dated as of May 15, 1980 and Amendment No. 1
dated as of December 3, 1985, among GEORGIA, OPC, MEAG and
Dalton. (Designated in Form U-1, File No. 70-6481, as
Exhibit B-4 and in SOUTHERN's Form 10-K for the year ended
December 31, 1987, File No. 1-3526, as Exhibit 10(o)(4).)
(a) 26 - Plant Robert W. Scherer Purchase, Sale and Option
Agreement dated as of May 15, 1980, between GEORGIA and
MEAG. (Designated in Form U-1, File No. 70-6481, as
Exhibit B-1.)
(a) 27 - Plant Robert W. Scherer Purchase and Sale Agreement dated
as of May 16, 1980, between GEORGIA and Dalton.
(Designated in Form U-1, File No. 70-6481, as Exhibit
B-2.)
(a) 28 - Plant Robert W. Scherer Unit Number Three Purchase and
Ownership Participation Agreement dated as of March 1,
1984, Amendment No. 1 dated as of July 1, 1986 and
Amendment No. 2 dated as of August 1, 1988, between
GEORGIA and GULF. (Designated in Form U-1, File No.
70-6573, as Exhibit B-4, in SOUTHERN's Form 10-K for the
year ended December 31, 1987, as Exhibit 10(o)(2) and in
SOUTHERN's Form 10-K for the year ended December 31, 1989,
as Exhibit 10(n)(2).)
(a) 29 - Plant Robert W. Scherer Unit Number Three Operating
Agreement dated as of March 1, 1984, between GEORGIA
and GULF. (Designated in Form U-1, File No. 70-6573, as
Exhibit B-5.)
(a) 30 - Plant Robert W. Scherer Unit No. Four Amended and Restated
Purchase and Ownership Participation Agreement by and
among GEORGIA, FP&L and JEA, dated as of December 31,
1990. (Designated in Form U-1, File No. 70-7843, as
Exhibit B-1.)
(a) 31 - Plant Robert W. Scherer Unit No. Four Operating Agreement
by and among GEORGIA, FP&L and JEA, dated as of
December 31, 1990. (Designated in Form U-1, File No.
70-7843, as Exhibit B-2.)
(a) 32 - Amended and Restated Unit Power Sales Agreement dated
February 18, 1982 and Amendment No. 1 dated May 18,
1982, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI
and SCS. (Designated in MISSISSIPPI's Form 10-K for the
year ended December 31, 1981, File No. 0-6849, as Exhibit
10(c)(2) and in GEORGIA's Form 10-K for the year ended
December 31, 1982, File No. 1-6468, as Exhibit 10(r)(3).)
(a) 33 - Amended and Restated Unit Power Sales Agreement dated May
19, 1982, Amendment No. 1 dated August 30, 1984 and
Amendment No. 2 dated October 30, 1987, between JEA and
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. (Designated
in GEORGIA's Form 10-K for the year
E-7
414
ended December 31, 1982, File No. 1-6468, as Exhibit
10(s)(2), in SOUTHERN's Form 10-K for the year ended
December 31, 1984, File No. 1-3526, as Exhibit 10(r)(2)
and in GEORGIA's Form 10-K for the year ended December 31,
1990, File No. 1-6468 as Exhibit 10(s)(2).)
(a) 34 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. (Designated in SAVANNAH's Form 10-K for the year
ended December 31, 1988, File No. 1-5072, as Exhibit
10(d).)
(a) 35 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. (Designated in SAVANNAH's Form 10-K for
the year ended December 31, 1988, File No. 1-5072, as
Exhibit 10(e).)
(a) 36 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. (Designated in SAVANNAH's Form 10-K for
the year ended December 31, 1988, File No. 1-5072, as
Exhibit 10(f).)
(a) 37 - Unit Power Sales Agreement dated December 8, 1990, between
Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. (Designated in GEORGIA's Form 10-K for
the year ended December 31, 1990, File No. 1-6468, as
Exhibit 10(x).)
(a) 38 - The Southern Company Executive Stock Plan For the Southern
Electric System and the First Amendment thereto.
(Designated in Registration No. 33-30171 as Exhibit 4(c).)
(a) 39 - Transition Energy Agreement dated December 31, 1990,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. (Designated in GULF's Form 10-K for the
year ended December 31, 1991, File No. 0-2429, as Exhibit
10(1).)
(a) 40 - Transition Energy Agreement dated December 31, 1990,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. (Designated in GULF's Form 10-K for the
year ended December 31, 1991, File No. 0-2429, as Exhibit
10(m).)
(a) 41 - Rocky Mountain Pumped Storage Hydroelectric Project
Ownership Participation Agreement dated November 18,
1988, between OPC and GEORGIA. (Designated in GEORGIA's
Form 10-K for the year ended December 31, 1988, File No.
1-6468, as Exhibit 10(x).)
(a) 42 - Rocky Mountain Pumped Storage Hydroelectric Project
Operating Agreement dated November 18, 1988, between
OPC and GEORGIA. (Designated in GEORGIA's Form 10-K for
the year ended December 31, 1988, File No. 1-6468, as
Exhibit 10(y).)
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415
(a) 43 - Purchase and Ownership Agreement for Joint Ownership
Interest in the James H. Miller, Jr. Steam Electric
Generating Plant Units One and Two dated November 18,
1988, between ALABAMA and AEC. (Designated in Form U-1,
File No. 70-7609, as Exhibit B-1.)
(a) 44 - Operating Agreement for Joint Ownership Interest in the
James H. Miller, Jr. Steam Electric Generating Plant
Units One and Two dated November 18, 1988, between ALABAMA
and AEC. (Designated in Form U-1, File No. 70-7609, as
Exhibit B-2.)
(a) 45 - Transmission Facilities Agreement dated February 25, 1982,
Amendment No. 1 dated May 12, 1982 and Amendment No. 2
dated December 6, 1983, between Gulf States and
MISSISSIPPI. (Designated in MISSISSIPPI's Form 10-K for
the year ended December 31, 1981, File No. 0-6849, as
Exhibit 10(f), in MISSISSIPPI's Form 10-K for the year
ended December 31, 1982, File No. 0-6849, as Exhibit
10(f)(2) and in MISSISSIPPI's Form 10-K for the year ended
December 31, 1983, File No. 0-6849, as Exhibit 10(f)(3).)
(a) 46 - Form of commitment agreement, Amendment No. 1 and
Amendment No. 2 with respect to SOUTHERN, ALABAMA,
GEORGIA and MISSISSIPPI revolving credits. (Designated in
Form U-1, File No. 70-7738, as Exhibit A-5 and in Form
U-1, File No. 70-7937, as A-5(b).)
(a) 47 - Block Power Sale Agreement between GEORGIA and OPC dated
as of November 12, 1990. (Designated in GEORGIA's Form
10-K for the year ended December 31, 1990, File No.
1-6468, as Exhibit 10(cc).)
(a) 48 - Coordination Services Agreement between GEORGIA and OPC
dated as of November 12, 1990. (Designated in GEORGIA's
Form 10-K for the year ended December 31, 1990, File No.
1-6468, as Exhibit 10(dd).)
*(a) 49 - Amended and Restated Nuclear Managing Board Agreement for
Plant Hatch and Plant Vogtle among GEORGIA, OPC, MEAG
and Dalton dated as of July 1, 1993.
(a) 50 - Integrated Transmission System Agreement, Power Sale and
Coordination Umbrella Agreement between GEORGIA and OPC
dated as of November 12, 1990. (Designated in GEORGIA's
Form 10-K for the year ended December 31, 1990, File No.
1-6468, as Exhibit 10(ff).)
(a) 51 - Revised and Restated Integrated Transmission System
Agreement between GEORGIA and Dalton dated as of
December 7, 1990. (Designated in GEORGIA's Form 10-K for
the year ended December 31, 1990, File No. 1-6468, as
Exhibit 10(gg).)
(a) 52 - Revised and Restated Integrated Transmission System
Agreement between GEORGIA and MEAG dated as of December
7, 1990. (Designated in GEORGIA's Form 10-K for the year
ended December 31, 1990, File No. 1-6468, as Exhibit
10(hh).)
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416
(a) 53 - Long Term Transmission Service Agreement between Entergy
Power, Inc. and ALABAMA, MISSISSIPPI and SCS.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1992, File No. 1-3526, as Exhibit 10(a)53.)
*(a) 54 - Amendment No. 4 to the Plant Robert W. Scherer Units
Number One and Two Purchase and Ownership Participation
Agreement dated as of December 31, 1990.
*(a) 55 - Amendment No. 2 to the Plant Robert W. Scherer Units
Number One and Two Operating Agreement dated as of
December 31, 1990.
*(a) 56 - Plant Scherer Managing Board Agreement dated as of
December 31, 1990 among GEORGIA, OPC, MEAG, Dalton,
GULF, FP&L and JEA.
*(a) 57 - Plant McIntosh Combustion Turbine Purchase and Ownership
Participation Agreement between GEORGIA and SAVANNAH
dated as of December 15, 1992.
*(a) 58 - Plant McIntosh Combustion Turbine Operating Agreement
between GEORGIA and SAVANNAH dated as of December 15,
1992.
*(a) 59 - Power Purchase Agreement dated as of December 3, 1993
between GEORGIA and FPC.
ALABAMA
(b) 1 - Indenture dated as of June 1, 1959, between SEGCO and
Citibank, N.A., as Trustee, and indentures supplemental
thereto through December 1, 1962. (Designated in
Registration No. 2-59843 as Exhibit 2(a)-8.)
(b) 2 - Service contracts dated as of January 1, 1984 and
Amendment No. 1 dated as of September 6, 1985, between
SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and
SOUTHERN. See Exhibit 10(a)1 herein.
(b) 3 - Interchange contract dated October 28, 1988, effective
January 1, 1989, between ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)5 herein.
(b) 4 - Agreement dated as of January 27, 1959 and Amendment No.
1 dated as of October 27, 1982, among SEGCO, ALABAMA
and GEORGIA. See Exhibit 10(a)6 herein.
(b) 5 - Amended and Restated Unit Power Sales Agreement dated
February 18, 1982 and Amendment No. 1 dated May 18,
1982, between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI
and SCS. See Exhibit 10(a)32 herein.
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417
(b) 6 - Amended and Restated Unit Power Sales Agreement dated May
19, 1982, Amendment No. 1, dated August 30, 1984 and
Amendment No. 2, dated October 30, 1987, between JEA and
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit
10(a)33 herein.
(b) 7 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. See Exhibit 10(a)34 herein.
(b) 8 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)35 herein.
(b) 9 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(b) 10 - Unit Power Sales Agreement dated December 8, 1990,
between Tallahassee and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)37
herein.
(b) 11 - Transition Energy Agreement dated December 31, 1990,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(b) 12 - Transition Energy Agreement dated December 31, 1990,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)40 herein.
(b) 13 - Firm Power Purchase Contract between ALABAMA and AMEA.
(Designated in Certificate of Notification, File No.
70-7212, as Exhibit B.)
(b) 14 - 1991 Firm Power Purchase Contract between ALABAMA and
AMEA. (Designated in Form U-1, File No. 70- 7873, as
Exhibit B-1.)
(b) 15 - Purchase and Ownership Agreement for Joint Ownership
Interest in the James H. Miller, Jr. Steam Electric
Generating Plant Units One and Two dated November 18,
1988, between ALABAMA and AEC. See Exhibit 10(a)43
herein.
(b) 16 - Operating Agreement for Joint Ownership Interest in the
James H. Miller, Jr. Steam Electric Generating Plant
Units One and Two dated November 18, 1988, between ALABAMA
and AEC. See Exhibit 10(a)44 herein.
(b) 17 - Form of commitment agreement, Amendment No. 1 and
Amendment No. 2 with respect to SOUTHERN, ALABAMA,
GEORGIA and MISSISSIPPI revolving credits. See Exhibit
10(a)46 herein.
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418
(b) 18 - Long Term Transmission Service Agreement between
Entergy Power, Inc. and ALABAMA, MISSISSIPPI and
SCS. See Exhibit 10(a)53 herein.
GEORGIA
(c) 1 - Indenture dated as of June 1, 1959, between
SEGCO and Citibank, N.A., as Trustee, and
indentures supplemental thereto through December
1, 1962. See Exhibit 10(b)1 herein.
(c) 2 - Service contracts dated as of January 1, 1984 and
Amendment No. 1 dated as of September 6, 1985,
between SCS and ALABAMA, GEORGIA, GULF, MISSISSIP
PI, SEGCO and SOUTHERN. See Exhibit 10(a)1
herein.
(c) 3 - Interchange contract dated October 28, 1988,
effective January 1, 1989, between ALABAMA,
GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)5 herein.
(c) 4 - Agreement dated as of January 27, 1959 and
Amendment No. 1 dated as of October 27, 1982,
among SEGCO, ALABAMA and GEORGIA. See Exhibit
10(a)6 herein.
(c) 5 - Joint Committee Agreement dated as of August 27,
1976, among GEORGIA, OPC, MEAG and Dalton. See
Exhibit 10(a)7 herein.
(c) 6 - Edwin I. Hatch Nuclear Plant Purchase and
Ownership Participation Agreement dated as of
January 6, 1975, between GEORGIA and OPC. See
Exhibit 10(a)8 herein.
(c) 7 - Edwin I. Hatch Nuclear Plant Operating Agreement
dated as of January 6, 1975, between GEORGIA and
OPC. See Exhibit 10(a)9 herein.
(c) 8 - Revised and Restated Integrated Transmission
System Agreement dated as of November 12, 1990,
between GEORGIA and OPC. See Exhibit 10(a)10
herein.
(c) 9 - Plant Hal Wansley Purchase and Ownership
Participation Agreement dated as of March 26,
1976, between GEORGIA and OPC. See Exhibit 10(a)
11 herein.
(c) 10 - Plant Hal Wansley Operating Agreement dated as of
March 26, 1976, between GEORGIA and OPC. See
Exhibit 10(a)12 herein.
(c) 11 - Edwin I. Hatch Nuclear Plant Purchase and
Ownership Participation Agreement dated as of
August 27, 1976, between GEORGIA, MEAG and
Dalton. See Exhibit 10(a)13 herein.
(c) 12 - Edwin I. Hatch Nuclear Plant Operating Agreement
dated as of August 27, 1976, between GEORGIA,
MEAG and Dalton. See Exhibit 10(a)14 herein.
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419
(c) 13 - Alvin W. Vogtle Nuclear Units Number One and Two
Purchase and Ownership Participation Agreement
dated as of August 27, 1976 and Amendment No. 1
dated as of January 18, 1977, among GEORGIA, OPC,
MEAG and Dalton. See Exhibit 10(a)15 herein.
(c) 14 - Alvin W. Vogtle Nuclear Units Number One and Two
Operating Agreement dated as of August 27, 1976,
among GEORGIA, OPC, MEAG and Dalton. See Exhibit
10(a)16 herein.
(c) 15 - Alvin W. Vogtle Nuclear Units Number One and Two
Purchase, Amendment, Assignment and Assumption
Agreement dated as of November 16, 1983, between
GEORGIA and MEAG. See Exhibit 10(a)17 herein.
(c) 16 - Plant Hal Wansley Purchase and Ownership
Participation Agreement dated as of August 27,
1976, between GEORGIA and MEAG. See Exhibit
10(a)18 herein.
(c) 17 - Plant Hal Wansley Operating Agreement dated as
of August 27, 1976, between GEORGIA and MEAG. See
Exhibit 10(a)19 herein.
(c) 18 - Integrated Transmission System Agreement dated
as of August 27, 1976, between GEORGIA and Dalton.
See Exhibit 10(a)20 herein.
(c) 19 - Integrated Transmission System Agreement dated
as of August 27, 1976, between GEORGIA and MEAG.
See Exhibit 10(a)21 herein.
(c) 20 - Plant Hal Wansley Purchase and Ownership
Participation Agreement dated as of April 19,
1977, between GEORGIA and Dalton. See Exhibit
10(a)22 herein.
(c) 21 - Plant Hal Wansley Operating Agreement dated as of
April 19, 1977, between GEORGIA and Dalton. See
Exhibit 10(a)23 herein.
(c) 22 - Plant Robert W. Scherer Units Number One and Two
Purchase and Ownership Participation Agreement
dated as of May 15, 1980, Amendment No. 1 dated
as of December 30, 1985, Amendment No. 2 dated as
of July 1, 1986 and Amendment No. 3 dated as of
August 1, 1988, among GEORGIA, OPC, MEAG and
Dalton. See Exhibit 10(a)24 herein.
(c) 23 - Plant Robert W. Scherer Units Number One and Two
Operating Agreement dated as of May 15, 1980 and
Amendment No. 1 dated as of December 3, 1985,
among GEORGIA, OPC, MEAG and Dalton. See Exhibit
10(a)25 herein.
(c) 24 - Plant Robert W. Scherer Purchase, Sale and Option
Agreement dated as of May 15, 1980, between
GEORGIA and MEAG. See Exhibit 10(a)26 herein.
(c) 25 - Plant Robert W. Scherer Purchase and Sale
Agreement dated as of May 16, 1980, between
GEORGIA and Dalton. See Exhibit 10(a)27 herein.
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420
(c) 26 - Plant Robert W. Scherer Unit Number Three
Purchase and Ownership Participation Agreement
dated as of March 1, 1984, Amendment No. 1 dated
as of July 1, 1986 and Amendment No. 2 dated as
of August 1, 1988, between GEORGIA and GULF. See
Exhibit 10(a)28 herein.
(c) 27 - Plant Robert W. Scherer Unit Number Three
Operating Agreement dated as of March 1, 1984,
between GEORGIA and GULF. See Exhibit 10(a)29
herein.
(c) 28 - Plant Robert W. Scherer Unit No. Four Amended and
Restated Purchase and Ownership Participation
Agreement by and among GEORGIA, FP&L and JEA
dated as of December 31, 1990. See Exhibit 10(a)
30 herein.
(c) 29 - Plant Robert W. Scherer Unit No. Four Operating
Agreement by and among GEORGIA, FP&L and JEA dated
as of December 31, 1990. See Exhibit 10(a)31
herein.
(c) 30 - Amended and Restated Unit Power Sales Agreement
dated February 18, 1982 and Amendment No. 1 dated
May 18, 1982, between FP&L and ALABAMA, GEORGIA,
GULF, MISSISSIPPI and SCS. See Exhibit 10(a)32
herein.
(c) 31 - Amended and Restated Unit Power Sales Agreement
dated May 19, 1982, Amendment No. 1, dated August
30, 1984 and Amendment No. 2 dated October 30,
1987, between JEA and ALABAMA, GEORGIA, GULF,
MISSISSIPPI and SCS. See Exhibit 10(a)33 herein.
(c) 32 - Unit Power Sales Agreement dated July 19, 1988,
between FPC and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
34 herein.
(c) 33 - Amended Unit Power Sales Agreement dated July 20,
1988, between FP&L and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
35 herein.
(c) 34 - Amended Unit Power Sales Agreement dated August
17, 1988, between JEA and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
36 herein.
(c) 35 - Unit Power Sales Agreement dated December 8,
1990, between Tallahassee and ALABAMA, GEORGIA,
GULF, MISSISSIPPI, SAVANNAH and SCS. See
Exhibit 10(a)37 herein.
*(c) 36 - Power Purchase Agreement dated as of December 3,
1993 between GEORGIA and FPC. See Exhibit 10(a)
59 herein.
(c) 37 - Transition Energy Agreement dated December 31,
1990, between JEA and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
39 herein.
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421
(c) 38 - Transition Energy Agreement dated December 31,
1990, between FP&L and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
40 herein.
(c) 39 - Rocky Mountain Pumped Storage Hydroelectric
Project Ownership Participation Agreement dated
November 18, 1988, between OPC and GEORGIA. See
Exhibit 10(a)41 herein.
(c) 40 - Rocky Mountain Pumped Storage Hydroelectric
Project Operating Agreement dated November 18,
1988, between OPC and GEORGIA. See Exhibit
10(a)42 herein.
(c) 41 - Form of commitment agreement, Amendment No. 1
and Amendment No. 2 with respect to SOUTHERN,
ALABAMA, GEORGIA and MISSISSIPPI revolving
credits. See Exhibit 10(a)46 herein.
(c) 42 - Block Power Sale Agreement between GEORGIA and
OPC dated as of November 12, 1990. See Exhibit
10(a)47 herein.
(c) 43 - Coordination Services Agreement between GEORGIA
and OPC dated as of November 12, 1990. See
Exhibit 10(a)48 herein.
*(c) 44 - Amended and Restated Nuclear Managing Board
Agreement for Plant Hatch and Plant Vogtle among
GEORGIA, OPC, MEAG and Dalton dated as of July 1,
1993. See Exhibit 10(a)49 herein.
(c) 45 - Integrated Transmission System Agreement, Power
Sale and Coordination Umbrella Agreement between
GEORGIA and OPC dated as of November 12, 1990.
See Exhibit 10(a)50 herein.
(c) 46 - Revised and Restated Integrated Transmission
System Agreement between GEORGIA and Dalton dated
as of December 7, 1990. See Exhibit 10(a)51
herein.
(c) 47 - Revised and Restated Integrated Transmission
System Agreement between GEORGIA and MEAG dated
as of December 7, 1990. See Exhibit 10(a)52
herein.
*(c) 48 - Amendment No. 4 to the Plant Robert W. Scherer
Units Number One and Two Purchase and Ownership
Participation Agreement dated as of December 31,
1990. See Exhibit 10(a)54 herein.
*(a) 49 - Amendment No. 2 to the Plant Robert W. Scherer
Units Number One and Two Operating Agreement dated
as of December 31, 1990. See Exhibit 10(a)55
herein.
*(c) 50 - Plant Scherer Managing Board Agreement dated as
of December 31, 1990 among GEORGIA, OPC, MEAG,
Dalton, GULF, FP&L and JEA. See Exhibit 10(a)56
herein.
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422
*(c) 51 - Plant McIntosh Combustion Turbine Purchase and
Ownership Participation Agreement between GEORGIA
and SAVANNAH dated as of December 15, 1992. See
Exhibit 10(a)57 herein.
*(c) 52 - Plant McIntosh Combustion Turbine Operating
Agreement between GEORGIA and SAVANNAH dated as of
December 15, 1992. See Exhibit 10(a)58 herein.
GULF
(d) 1 - Service contracts dated as of January 1, 1984 and
Amendment No. 1 dated as of September 6, 1985,
between SCS and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SEGCO and SOUTHERN. See Exhibit
10(a)1 herein.
(d) 2 - Interchange contract dated October 28, 1988,
effective January 1, 1989, between ALABAMA,
GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)5 herein.
(d) 3 - Plant Robert W. Scherer Unit Number Three
Purchase and Ownership Participation Agreement
dated as of March 1, 1984, Amendment No. 1 dated
as of July 1, 1986 and Amendment No. 2 dated as
of August 1, 1988, between GEORGIA and GULF.
See Exhibit 10(a)28 herein.
(d) 4 - Plant Robert W. Scherer Unit Number Three
Operating Agreement dated as of March 1, 1984,
between GEORGIA and GULF. See Exhibit 10(a)29
herein.
(d) 5 - Amended and Restated Unit Power Sales Agreement
dated February 18, 1982 and Amendment No. 1 dated
May 18, 1982, between FP&L and ALABAMA, GEORGIA,
GULF, MISSISSIPPI and SCS. See Exhibit 10(a)32
herein.
(d) 6 - Amended and Restated Unit Power Sales Agreement
dated May 19, 1982, Amendment No. 1 dated August
30, 1984 and Amendment No. 2 dated October 30,
1987, between JEA and ALABAMA, GEORGIA, GULF,
MISSISSIPPI and SCS. See Exhibit 10(a)33 herein.
(d) 7 - Unit Power Sales Agreement dated July 19, 1988,
between FPC and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
34 herein.
(d) 8 - Amended Unit Power Sales Agreement dated July 20,
1988, between FP&L and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
35 herein.
(d) 9 - Amended Unit Power Sales Agreement dated August
17, 1988, between JEA and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
36 herein.
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423
(d) 10 - Agreement between GULF and AEC, effective August
1, 1985. (Designated in GULF's Form 10-K for the
year ended December 31, 1985, File No. 0-2429, as
Exhibit 10(g).)
(d) 11 - Unit Power Sales Agreement dated December 8,
1990, between Tallahassee and ALABAMA, GEORGIA,
GULF, MISSISSIPPI, SAVANNAH and SCS. See
Exhibit 10(a)37 herein.
(d) 12 - Transition Energy Agreement dated December 31,
1990, between JEA and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
39 herein.
(d) 13 - Transition Energy Agreement dated December 31,
1990, between FP&L and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
40 herein.
MISSISSIPPI
(e) 1 - Service contracts dated as of January 1, 1984 and
Amendment No. 1 dated September 6, 1985, between
SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SEGCO and SOUTHERN. See Exhibit 10(a)1 herein.
(e) 2 - Interchange contract dated October 28, 1988,
effective January 1, 1989, between ALABAMA,
GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)5 herein.
(e) 3 - Amended and Restated Unit Power Sales Agreement
dated February 18, 1982 and Amendment No. 1 dated
May 18, 1982, between FP&L and ALABAMA, GEORGIA,
GULF, MISSISSIPPI and SCS. See Exhibit 10(a)32
herein.
(e) 4 - Amended and Restated Unit Power Sales Agreement
dated May 19, 1982, Amendment No. 1 dated August
30, 1984, and Amendment No. 2 dated October 30,
1987, between JEA and ALABAMA, GEORGIA, GULF,
MISSISSIPPI and SCS. See Exhibit 10(a)33 herein.
(e) 5 - Unit Power Sales Agreement dated July 19, 1988,
between FPC and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
34 herein.
(e) 6 - Amended Unit Power Sales Agreement dated July 20,
1988, between FP&L and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
35 herein.
(e) 7 - Amended Unit Power Sales Agreement dated August
17, 1988, between JEA and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
36 herein.
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424
(e) 8 - Unit Power Sales Agreement dated December 8,
1990, between Tallahassee and ALABAMA, GEORGIA,
GULF, MISSISSIPPI, SAVANNAH and SCS. See
Exhibit 10(a)37 herein.
(e) 9 - Transition Energy Agreement dated December 31,
1990, between JEA and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
39 herein.
(e) 10 - Transition Energy Agreement dated December 31,
1990, between FP&L and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
40 herein.
(e) 11 - Transmission Facilities Agreement dated February
25, 1982, Amendment No. 1 dated May 12, 1982 and
Amendment No. 2 dated December 6, 1983, between
Gulf States and MISSISSIPPI. See Exhibit 10(a)45
herein.
(e) 12 - Form of commitment agreement, Amendment No. 1 and
Amendment No. 2 with respect to SOUTHERN,
ALABAMA, GEORGIA and MISSISSIPPI revolving
credits. See Exhibit 10(a)46 herein.
(e) 13 - Long Term Transmission Service Agreement between
Entergy Power, Inc. and ALABAMA MISSISSIPPI and
SCS. See Exhibit 10(a)53 herein.
SAVANNAH
(f) 1 - Service contract dated as of March 3, 1988,
between SCS and SAVANNAH. See Exhibit 10(a)3
herein.
(f) 2 - Interchange contract dated October 28, 1988,
effective January 1, 1989, between ALABAMA,
GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)5 herein.
(f) 3 - Unit Power Sales Agreement dated July 19, 1988,
between FPC and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
34 herein.
(f) 4 - Amended Unit Power Sales Agreement dated July 20,
1988, between FP&L and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
35 herein.
(f) 5 - Amended Unit Power Sales Agreement dated August
17, 1988, between JEA and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
36 herein.
(f) 6 - Unit Power Sales Agreement dated December 8,
1990, between Tallahassee and ALABAMA, GEORGIA,
GULF, MISSISSIPPI, SAVANNAH and SCS. See
Exhibit 10(a)37 herein.
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425
(f) 7 - Transition Energy Agreement dated December 31,
1990, between JEA and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
39 herein.
(f) 8 - Transition Energy Agreement dated December 31,
1990, between FP&L and ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)
40 herein.
*(f) 9 - Plant McIntosh Combustion Turbine Purchase and
Ownership Participation Agreement between GEORGIA
and SAVANNAH dated as of December 15, 1992. See
Exhibit 10(a) 57 herein.
*(f) 10 - Plant McIntosh Combustion Turbine Operating
Agreement between GEORGIA and SAVANNAH dated
December 15, 1992. See Exhibit 10(a)58 herein.
(21) *SUBSIDIARIES OF REGISTRANTS - Contained herein at page IV-5.
(23) CONSENTS OF EXPERTS AND COUNSEL
SOUTHERN
*(a) - The consent of Arthur Andersen & Co. is contained
herein at page IV-6.
ALABAMA
*(b) - The consent of Arthur Andersen & Co. is contained
herein at page IV-7.
GEORGIA
*(c) - The consent of Arthur Andersen & Co. is contained
herein at page IV-8.
GULF
*(d) - The consent of Arthur Andersen & Co. is contained
herein at page IV-9.
MISSISSIPPI
*(e) - The consent of Arthur Andersen & Co. is contained
herein at page IV-10.
SAVANNAH
*(f) - The consent of Arthur Andersen & Co. is contained
herein at page IV-11.
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(24) POWERS OF ATTORNEY AND RESOLUTIONS
SOUTHERN
*(a) - Power of Attorney and resolution.
ALABAMA
*(b) - Power of Attorney and resolution.
GEORGIA
*(c) - Power of Attorney and resolution.
GULF
*(d) - Power of Attorney and resolution.
MISSISSIPPI
*(e) - Power of Attorney and resolution.
SAVANNAH
*(f) - Power of Attorney and resolution.
E-20